As filed with the Securities and Exchange Commission on June
21, 2010
Registration No. 333-165833
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Amendment No. 3
to
Form S-1
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
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ECA Marcellus Trust I
(Exact name of co-registrant
as specified in its charter)
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Energy Corporation of America
(Exact name of co-registrant
as specified in its charter)
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Delaware
(State or other jurisdiction
of incorporation or organization)
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West Virginia
(State or other jurisdiction
of incorporation or organization)
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1311
(Primary Standard Industrial
Classification Code Number)
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1311
(Primary Standard Industrial
Classification Code Number)
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27-6522024
(I.R.S. Employer
Identification No.)
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84-1235822
(I.R.S. Employer
Identification No.)
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919 Congress Avenue
Suite 500
Austin, Texas 78701
(512) 236-6599
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4643 South Ulster Street
Suite 1100
Denver, Colorado 80237
(303) 694-2667
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(Address, including zip code,
and telephone number,
including area code, of agent of service)
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(Address, including zip code,
and telephone number,
including area code, of agent of service)
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The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue
Suite 500
Austin, Texas 78701
(512) 236-6599
Attention: Michael J. Ulrich
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Donald C. Supcoe
4643 South Ulster Street
Suite 1100
Denver, Colorado 80237
(303) 694-2667
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(Name, address, including zip
code, and telephone number,
including area code, of agent for service)
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(Name, address, including zip
code, and telephone number,
including area code, of agent for service)
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Approximate date of commencement of proposed sale to the
public:
As soon as practicable after this Registration Statement becomes
effective.
Copies to:
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David P. Oelman
Vinson & Elkins L.L.P.
First City Tower
1001 Fannin Street, Suite 2500
Houston, Texas
77002-6760
(713) 758-2222
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Thomas R. Goodwin
Tammy J. Owen
Goodwin & Goodwin, LLP
300 Summers Street
Suite 1500
Charleston, West Virginia 25301
(304) 346-7000
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Joshua Davidson
Baker Botts L.L.P.
One Shell Plaza
910 Louisiana St.
Houston, Texas 77002
(713) 229-1234
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If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following
box. o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
check the following box and list the Securities Act registration
statement number of the earlier effective registration statement
for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the
Exchange Act. (Check one):
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Large accelerated
filer o
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller reporting
company o
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(Do not check if a smaller reporting company)
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CALCULATION OF REGISTRATION
FEE
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Proposed Maximum
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Proposed Maximum
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Amount of
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Title Of Each Class Of
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Amount to be
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Offering Price
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Aggregate
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Registration
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Securities To Be Registered
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Registered(1)
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Per Share
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Offering Price(1)(2)
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Fee(3)
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Common Units of Beneficial Interest in ECA Marcellus Trust I
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10,122,875
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$21.00
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$212,580,375
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$15,157
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(1) |
Includes trust units issuable upon exercise of the
underwriters over-allotment option.
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(2) |
Estimated solely for the purpose of calculating the registration
fee pursuant to Rule 457(o).
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(3) |
A registration fee of $15,498 was paid previously based on an
estimate of the aggregate offering price.
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The Registrants hereby amend this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the Registrants shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act, or until this Registration Statement
shall become effective on such date as the Securities and
Exchange Commission (or the SEC), acting pursuant to
said Section 8(a), may determine.
The information in
this preliminary prospectus is not complete and may be changed.
These securities may not be sold until the registration
statement filed with the Securities and Exchange Commission is
effective. This preliminary prospectus is not an offer to sell
these securities, and we are not soliciting an offer to buy
these securities, in any jurisdiction where the offer or sale is
not permitted.
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Subject to Completion dated June
21, 2010
PRELIMINARY PROSPECTUS
ECA
Marcellus Trust I
8,802,500 Common
Units
This is an initial public offering of common units representing
beneficial interests in ECA Marcellus Trust I. The trust is
selling all of the units offered hereby. Energy Corporation of
America (ECA) has formed the trust and will convey,
or cause to be conveyed, certain royalty interests and certain
hedging contracts established for the benefit of the trust in
exchange for all of the net proceeds of this offering as well as
common and subordinated units representing a 50% beneficial
interest in the trust.
Prior to this offering, there has been no public market for the
common units. ECA expects that the public offering price will be
between $19.00 and $21.00 per common unit. The common units have
been approved for listing on the New York Stock Exchange under
the symbol ECT, subject to official notice of
issuance.
The Trust Units. Trust units, consisting of the
common and subordinated units, are units of beneficial interest
in the trust and represent undivided interests in the trust.
They do not represent any interest in ECA.
The Trust. The trust will own term and perpetual royalty
interests in natural gas properties owned by ECA in the
Marcellus Shale formation in Greene County, Pennsylvania. These
royalty interests will entitle the trust to receive 90% of the
proceeds attributable to ECAs interest in the sale of
production from 14 horizontal Marcellus Shale natural gas wells
(eight of which are currently producing and the remaining six
are expected to be producing by August 15, 2010) located in
Greene County, Pennsylvania and 50% of the proceeds attributable
to ECAs interest in the sale of production from 52
horizontal Marcellus Shale natural gas development wells to be
drilled on drill sites included within approximately 9,300 acres
held by ECA, of which it owns substantially all of the working
interests, in Greene County, Pennsylvania. The trust will be
treated as a partnership for federal income tax purposes.
The Trust Unitholders. As a trust unitholder, you
will receive quarterly distributions of cash from the proceeds
that the trust receives from ECAs sale of natural gas
subject to the royalty interests held by the trust.
Ownership of Trust Units by ECA. After the
completion of this offering, ECA will own 3,296,683 common units
and 4,401,250 subordinated units representing 43.7% of trust
units. If the underwriters exercise their over-allotment option
in full, ECA will own 1,976,308 common units and 4,401,250
subordinated units representing 36.2% of trust units. Certain
Private Investors will own 1,104,567 common units representing
6.3% of trust units. For more information on the Private
Investors, please read Certain Transactions.
ECAs Right to Incentive Distributions. ECA will be
entitled to receive incentive distributions equal to 50% of the
amount, if any, by which the cash available for distribution on
all of the trust units in any quarter exceeds certain target
distribution levels. ECA will be entitled to reimbursement for
approximately $5 million in expenses incurred in connection
with establishing floor price contracts to be transferred to the
trust from the remaining 50% of cash available for distribution
in excess of these thresholds. Please see Target
distributions and subordination and incentive thresholds.
Investing in the common units involves a high degree of risk.
Before buying any common units, you should read the discussion
of material risks of investing in the common units in Risk
factors beginning on page 19 of this prospectus.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed upon the adequacy or accuracy of this
prospectus. Any representation to the contrary is a criminal
offense.
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Per Common Unit
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Total
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Price to the public
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$
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$
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Underwriting discounts and commissions (1)
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$
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$
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Proceeds to the trust (before expenses)
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$
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$
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(1)
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Excludes a structuring fee equal to
0.50% of the gross proceeds of this offering, or approximately
$ million, payable to Raymond
James & Associates, Inc.
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The underwriters may also purchase up to an additional
1,320,375 common units at the initial public offering price,
less underwriting discounts and commissions, to cover
over-allotments, if any, within 30 days of the date of this
prospectus. If the underwriters exercise this option in full,
the total underwriting discounts and commissions will be
$ ,
and the trusts total proceeds, after deducting
underwriting discounts and commissions and before expenses, will
be
$ .
The net proceeds of any exercise of the underwriters
over-allotment option will be used to redeem an equal number of
common units held by ECA.
The underwriters are offering the common units as set forth
under Underwriting. Delivery of the common units
will be made on or
about ,
2010.
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OPPENHEIMER
& CO. |
RBC CAPITAL MARKETS |
BAIRD
, 2010
TABLE OF
CONTENTS
Important
Notice About Information in This Prospectus
You should rely only on the information contained in this
prospectus or in any free writing prospectus we may authorize to
be delivered to you.
Until ,
2010 (25 days after the date of this prospectus), federal
securities laws may require all dealers that effect transactions
in the common units, whether or not participating in this
offering, to deliver a prospectus. This is in addition to the
dealers obligation to deliver a prospectus when acting as
underwriters and with respect to their unsold allotments or
subscriptions.
ECA and the trust have not, and the underwriters have not,
authorized anyone to provide you with additional or different
information. If anyone provides you with additional, different
or inconsistent information, you should not rely on it. This
prospectus is not an offer to sell or a solicitation of an offer
to buy the common units in any jurisdiction where such offer and
sale would be unlawful. You should not assume that the
information contained in this prospectus is accurate as of any
date other than the date on the front of this document. The
trusts business, financial condition, results of
operations and prospects may have changed since such dates.
i
SUMMARY
This summary provides a brief overview of information
contained elsewhere in this prospectus. To understand this
offering fully, you should read the entire prospectus carefully,
including the risk factors and the financial statements and
notes to those statements. Definitions for terms relating to the
natural gas business can be found in Glossary of certain
oil and natural gas terms and terms related to the trust.
Ryder Scott Company, L.P., an independent engineering firm,
provided the estimates of proved natural gas reserves as of
March 31, 2010 included in this prospectus. These estimates
are contained in a summary prepared by Ryder Scott of its
reserve report as of March 31, 2010 for the Underlying
Properties held by ECA described below and for the royalty
interests in the Underlying Properties held by the trust, which
royalty interests are referred to herein as the trust
properties. This summary is located at the back of this
prospectus as Annex A and is referred to in this prospectus
as the reserve report. References to Energy
Corporation of America or ECA in this
prospectus are to Energy Corporation of America and its
subsidiaries and, when discussing unit ownership and historical
ownership of the royalty interests, includes the private
investors listed in Certain transactions (such
private investors being referred to herein as the Private
Investors). Unless otherwise indicated, all information in
this prospectus assumes an initial public offering price of
$20.00 per common unit and no exercise of the underwriters
over-allotment option.
ECA
MARCELLUS TRUST I
ECA Marcellus Trust I is a Delaware statutory trust formed
in March 2010 by Energy Corporation of America to own royalty
interests in eight producing horizontal natural gas wells
producing from the Marcellus Shale formation, together with six
additional wells that are undergoing completion operations and
are expected to be online by August 15, 2010, all of which
are located in Greene County, Pennsylvania (the Producing
Wells), and royalty interests in 52 horizontal natural gas
development wells to be drilled to the Marcellus Shale formation
(the PUD Wells) within the Area of Mutual
Interest, or AMI, in which ECA presently holds
approximately 9,300 acres, of which it owns substantially all of
the working interests, in Greene County, Pennsylvania. The Area
of Mutual Interest consists of the Marcellus shale formation in
approximately 121 square miles and is depicted by the area
identified on the inside front cover of this prospectus. ECA is
obligated to drill the 52 development wells from drill sites on
approximately 9,300 leased acres in the AMI. Until ECA has
satisfied its drilling obligation, it will not be permitted to
drill and complete any well in the Marcellus Shale formation on
lease acreage included within the AMI for its own account. Also,
ECA will grant to the trust a lien on ECAs interest in the
Marcellus Shale formation in the AMI (except currently producing
wells) in order to secure its drilling obligation to the Trust.
The royalty interests will be conveyed from ECAs working
interest in the Producing Wells and the PUD Wells limited to the
Marcellus Shale formation (the Underlying
Properties). The royalty interest in the Producing Wells
(the PDP Royalty Interest) entitles the trust to
receive 90% of the proceeds (exclusive of any production or
development costs but after deducting post-production costs and
any applicable taxes) from the sale of production of natural gas
attributable to ECAs interest in the Producing Wells. The
royalty interest in the PUD Wells (the PUD Royalty
Interest) entitles the trust to receive 50% of the
proceeds (exclusive of any production or development costs but
after deducting post-production costs and any applicable taxes)
from the sale of production of natural gas attributable to
ECAs interest in the PUD Wells. Approximately 50% of the
estimated natural gas production attributable to the
trusts royalty interests will be hedged with a combination
of floors and swaps from April 1, 2010 to March 31,
2014. The floor price contracts will be transferred to the trust
by ECA, while ECA will enter into a back-to-back swap agreement
with the trust to provide the trust with the benefit of swap
contracts entered into between ECA and third parties. ECA will
be entitled to recoup the costs of establishing the floor price
contracts only if and to the extent cash
1
available for distribution by the trust exceeds certain levels.
Please see Target distributions and subordination and
incentive thresholds.
ECA is obligated to drill all of the PUD Wells by March 31,
2013. In the event of delays, ECA will have until March 31,
2014 to fulfill its drilling obligation. ECA will grant to the
trust a lien on ECAs interest in the Marcellus Shale
formation in the AMI (except the Producing Wells and any other
wells which are already producing and not subject to the Royalty
Interests) in order to secure the estimated amount of the
drilling costs for the trusts interests in the PUD Wells
(the Drilling Support Lien). The amount obtained by
the trust pursuant to the Drilling Support Lien may not exceed
$91 million. As ECA fulfills its drilling obligation over
time, the total dollar amount that may be recovered will be
proportionately reduced and the drilled PUD Wells will be
released from the lien.
The trust will not be responsible for any costs related to the
drilling of development wells or any other development or
operating costs. The trusts cash receipts in respect of
the royalties will be determined after deducting post-production
costs and any applicable taxes associated with the PDP and PUD
Royalty Interests, and the trusts cash available for
distribution will include cash receipts from its hedging
contracts and will be reduced by trust administrative expenses
and expenses incurred as a result of being a publicly traded
entity. Post-production costs will generally consist of costs
incurred to gather, compress, transport, process, treat,
dehydrate and market the natural gas produced. Any charge
payable to ECA for such
post-production
costs on its Greene County Gathering System will be limited to
$0.52 per MMBtu gathered until ECA has fulfilled its drilling
obligation (the Post-Production Services Fee);
thereafter, ECA may increase the
Post-Production
Services Fee to the extent necessary to recover certain capital
expenditures in the Greene County Gathering System.
As of March 31, 2010 and after giving effect to the
conveyance of the PDP Royalty Interest and the PUD Royalty
Interest, the total gas reserves estimated to be attributable to
the trust interests were 108.6 Bcf. This amount includes
73.5 Bcf attributable to the PUD Royalty Interest and
35.1 Bcf attributable to the PDP Royalty Interest.
ECAs retained interest in the Underlying Properties
entitles it to 10% of the proceeds from the sale of natural gas
from the Producing Wells as well as 50% of the proceeds from the
sale of future production from the PUD Wells. ECA initially will
own 43.7% of the trust units. By virtue of ECAs retained
interest in the Producing Wells and the PUD Wells and its
ownership of 43.7% of the trust units, it will have a
significant economic interest in the Underlying Properties. ECA
on average owns an 81.53% net revenue interest in the Producing
Wells. Please read Description of the royalty
interests below. ECA operates all of the Producing Wells
and will agree to operate not less than 90% of the PUD Wells
during the subordination period as defined below. In addition,
ECA has agreed to operate the gas properties to which the PDP
Royalty Interest and the PUD Royalty Interest relate and to
cause to be marketed natural gas produced from these properties
in the same manner it would if such properties were not burdened
by the trusts royalty interests.
Generally, the percentage of production proceeds to be received
by the trust with respect to a well will equal the product of
(i) the percentage of proceeds to which the trust is
entitled under the terms of the conveyances (90% for the
Producing Wells and 50% for the PUD Wells) multiplied by
(ii) ECAs net revenue interest in the well. ECA on
average owns an 81.53% net revenue interest in the Producing
Wells. Therefore, the trust will be entitled to receive on
average 73.37% of the proceeds of production from the Producing
Wells. With respect to a PUD Well, the conveyance related to the
PUD Royalty Interest provides that the proceeds from the PUD
Wells will be calculated on the basis that the underlying PUD
Wells are burdened only by interests that in total would not
exceed 12.5% of the revenues from such properties, regardless of
whether the
2
royalty interest owners are actually entitled to a greater
percentage of revenues from such properties. As the applicable
net revenue interest of a well is calculated by multiplying
ECAs percentage working interest in such well by the
unburdened interest percentage (87.5%), assuming ECA owns a 100%
working interest in a PUD Well, such well would have a minimum
87.5% net revenue interest. Accordingly, the trust would be
entitled to 43.75% of the production proceeds from such well. To
the extent ECAs working interest in a PUD Well is less
than 100%, the trusts share of proceeds would be
proportionately reduced. Pursuant to the Development Agreement,
however, ECA will only satisfy its drilling obligation when it
has drilled 52 equivalent wells. Therefore, any reduction
in production proceeds attributable to a PUD Well caused by ECA
having less than a 100% working interest in the well will be
offset by the requirement to drill additional wells to achieve a
total of 52 equivalent wells.
The trust will make quarterly cash distributions of
substantially all of its cash receipts, after deducting trust
administrative expenses and the costs incurred as a result of
being a publicly traded entity and reserves therefor, on or
about 60 days following the completion of each quarter
through (and including) the quarter ending March 31, 2030
(the Termination Date). The first quarterly
distribution is expected to be made on or about August 31,
2010 to record unitholders as of August 15, 2010. The trust
will begin to liquidate on the Termination Date and will soon
thereafter wind up its affairs and terminate. At the Termination
Date, 50% of each of the PDP Royalty Interest and the PUD
Royalty Interest will revert automatically to ECA. The remaining
50% of each of the PDP Royalty Interest and the PUD Royalty
Interest will be sold, and the net proceeds therefrom will be
distributed pro rata to the unitholders soon after the
Termination Date. ECA will have a right of first refusal to
purchase the remaining 50% of the royalty interests at the
Termination Date. Because payments to the trust will be
generated by depleting assets and the trust has a finite life
with the production from the Underlying Properties diminishing
over time, a portion of each distribution will represent a
return of your original investment.
The business and affairs of the trust will be managed by The
Bank of New York Mellon Trust Company, N.A. as trustee. Although
ECA will operate all of the Producing Wells and substantially
all of the PUD Wells, ECA has no ability to manage or influence
the management of the trust.
TARGET
DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE
THRESHOLDS
Subordination
and Incentive Thresholds
ECA has calculated quarterly target levels of cash distributions
for the life of the trust as set forth on Annex B to this
prospectus. The amount of the quarterly distributions may
fluctuate from quarter to quarter, depending on the proceeds
received by the trust, among other factors. Annex B
reflects that while target distributions increase as ECA
completes its drilling obligations and production attributable
to the trust increases, over time these target distributions
decline as a result of the depletion of the reserves in the
Underlying Properties. These target distributions do
not represent the actual distributions you should expect to
receive with respect to your common units. Rather, ECA has
established the target distributions in part to calculate the
subordination and incentive thresholds described in more detail
below. The target distributions were derived by assuming that
natural gas production from the trust properties will equal the
volumes reflected in the reserve report attached as Annex A
to this prospectus and the prices received for such production
will be consistent with NYMEX pricing for April, May and
June 2010 of $3.842, $4.271 and $4.155 per MMBtu,
respectively, and NYMEX forward pricing for the thirty three
month period ending March 31, 2013 and increased thereafter
by a 2.5% annual escalator (as adjusted for a basis differential
of $0.15 per MMBtu), capped at $9.00 per MMBtu. Using these
assumptions, the price per MMBtu would reach the $9.00 per
MMBtu cap starting in 2027. The target distributions also give
effect to post-production expenses projected in the reserve
reports and projected trust administrative expenses, including
the expenses incurred as a result
3
of being a publicly traded entity. For more information on
subordination and incentive thresholds, please read
Target distributions below.
In order to provide support for cash distributions on the common
units, ECA has agreed to subordinate 4,401,250 of the trust
units it will retain following this offering, which will
constitute 25% of the outstanding trust units. While the
subordinated units will be entitled to receive pro rata
distributions from the trust each quarter if and to the extent
there is sufficient cash to provide a cash distribution on the
common units which is no less than the applicable quarterly
subordination threshold, if there is not sufficient cash to fund
such a distribution on all trust units, the distribution to be
made with respect to the subordinated units will be reduced or
eliminated for such quarter in order to make a distribution, to
the extent possible, of up to the subordination threshold amount
on the common units. Each applicable quarterly subordination
threshold is equal to 80% of the target distribution level for
the corresponding quarter as reflected on Annex B (each, a
subordination threshold). In exchange for agreeing
to subordinate these trust units, and in order to provide
additional financial incentive to ECA to perform its drilling
obligation and operations on the Underlying Properties in an
efficient and cost-effective manner, ECA will be entitled to
receive incentive distributions (the incentive
distributions) equal to 50% of the amount by which the
cash available for distribution on all of the trust units in any
quarter exceeds 150% of the subordination threshold for such
quarter (which is 120% of the target distribution for such
quarter) (each, an incentive threshold).
ECA has incurred costs of approximately $5 million in
establishing the floor price contracts being transferred to the
trust. ECA will be entitled to reimbursement for these
expenditures only if and to the extent distributions to trust
unitholders would otherwise exceed the incentive threshold. This
reimbursement will be deducted, over time, from the 50% of cash
available for distribution in excess of the incentive thresholds
otherwise payable to the trust unitholders. ECAs right to
receive the remaining 50% of such cash in the form of incentive
distributions would not be affected.
The subordinated units will automatically convert into common
units on a
one-for-one
basis and ECAs right to receive incentive distributions
and to recoup the reimbursement amount will terminate, at the
end of the fourth full calendar quarter following ECAs
satisfaction of its drilling obligation to the trust.
Accordingly, ECA bears the risk that it will not be partially or
fully reimbursed for the floor price contracts to be transferred
to the trust. ECA currently expects that it will complete its
drilling obligation on or before March 31, 2013 and that,
accordingly, the subordinated units will convert into common
units on or before March 31, 2014. In the event of delays,
it will have until March 31, 2014 under its contractual
obligation to drill all the PUD Wells, in which event the
subordinated units would convert into common units on or before
March 31, 2015. The period during which the subordinated
units are outstanding is referred to as the subordination
period.
4
The table below sets forth the target distributions and
subordination and incentive thresholds for each calendar quarter
through the first quarter of 2015. The effective date of the
trust is April 1, 2010, meaning it will receive the
proceeds of production attributable to the PDP Royalty Interest
from that date even though the PDP Royalty Interest will not be
conveyed to the trust until the closing of this offering.
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Subordination
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Target
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Incentive
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Period
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Threshold
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Distribution
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Threshold
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(per unit)
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2010:
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Second Quarter
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$
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0.181
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$
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0.227
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$
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0.272
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Third Quarter
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0.334
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0.417
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0.501
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Fourth Quarter
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0.478
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0.597
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0.716
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2011:
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First Quarter
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0.446
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|
0.558
|
|
|
|
0.669
|
|
Second Quarter
|
|
|
0.451
|
|
|
|
0.564
|
|
|
|
0.676
|
|
Third Quarter
|
|
|
0.550
|
|
|
|
0.688
|
|
|
|
0.825
|
|
Fourth Quarter
|
|
|
0.565
|
|
|
|
0.706
|
|
|
|
0.847
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.574
|
|
|
|
0.717
|
|
|
|
0.861
|
|
Second Quarter
|
|
|
0.602
|
|
|
|
0.752
|
|
|
|
0.903
|
|
Third Quarter
|
|
|
0.624
|
|
|
|
0.780
|
|
|
|
0.937
|
|
Fourth Quarter
|
|
|
0.701
|
|
|
|
0.876
|
|
|
|
1.051
|
|
2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
0.756
|
|
|
$
|
0.945
|
|
|
$
|
1.135
|
|
Second Quarter
|
|
|
0.754
|
|
|
|
0.942
|
|
|
|
1.131
|
|
Third Quarter
|
|
|
0.701
|
|
|
|
0.876
|
|
|
|
1.052
|
|
Fourth Quarter
|
|
|
0.659
|
|
|
|
0.824
|
|
|
|
0.989
|
|
2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.610
|
|
|
|
0.763
|
|
|
|
0.915
|
|
Second Quarter
|
|
|
0.589
|
|
|
|
0.736
|
|
|
|
0.883
|
|
Third Quarter
|
|
|
0.571
|
|
|
|
0.713
|
|
|
|
0.856
|
|
Fourth Quarter
|
|
|
0.549
|
|
|
|
0.687
|
|
|
|
0.824
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.519
|
|
|
|
0.649
|
|
|
|
0.779
|
|
For additional information with respect to the subordination and
incentive thresholds, please see Target distributions and
subordination and incentive thresholds and
Description of the royalty interests.
5
Target
Distributions
The table below presents the calculation of the target
distributions for each quarter through and including the quarter
ending June 30, 2011. The target distributions were
prepared by ECA on an accrual basis based on production volumes,
pricing and other assumptions. As used herein, accrual basis
means ECA will pay to the trust each quarter an amount equal to
the estimated proceeds of production from the trust properties
during the calendar quarter most recently ended before the
distribution (after deducting post-production costs and any
applicable taxes), regardless of whether such amounts have
actually been received by ECA from the purchaser of the natural
gas produced. Any difference between the payment made by ECA to
the trust with respect to a calendar quarter and the actual cash
production payments relative to the trust properties received by
ECA will be netted against future payments by ECA to the trust.
Actual cash distributions to the trust unitholders will
fluctuate quarterly based on the quantity of natural gas
produced from the Underlying Properties, the prices received for
natural gas production and other factors. Please read
Target distributions and subordination and incentive
thresholds Significant assumptions used to prepare
the target distributions.
ECA does not as a matter of course make public projections as to
future sales, earnings or other results. However, the management
of ECA has prepared the projected operational and financial
information set forth below in order to present the target
distributions attributable to the natural gas sales volumes
reflected in Ryder Scotts reserve report attached hereto
as Annex A.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ending
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(In thousands, except well number, volumetric and per unit
data)
|
|
|
Number of Wells Expected to be Producing at Quarter End
|
|
|
8
|
|
|
|
17
|
|
|
|
22
|
|
|
|
25
|
|
|
|
31
|
|
Estimated Production from Trust Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas PDP Sales Volumes (MMcf)
|
|
|
675
|
|
|
|
1,318
|
|
|
|
1,464
|
|
|
|
1,204
|
|
|
|
1,073
|
|
Natural Gas PUD Sales Volumes (MMcf)
|
|
|
|
|
|
|
81
|
|
|
|
514
|
|
|
|
553
|
|
|
|
770
|
|
Total Sales Volumes (MMcf)
|
|
|
675
|
|
|
|
1,399
|
|
|
|
1,979
|
|
|
|
1,757
|
|
|
|
1,843
|
|
Daily Sales Volumes (MMcf/d)
|
|
|
7.4
|
|
|
|
15.2
|
|
|
|
21.5
|
|
|
|
19.5
|
|
|
|
20.2
|
|
Commodity Prices and Hedging Positions (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumed NYMEX Price ($/MMBtu) (2)
|
|
$
|
4.15
|
|
|
$
|
4.84
|
|
|
$
|
5.21
|
|
|
$
|
5.59
|
|
|
$
|
5.29
|
|
Assumed Price ($/Mcf) (2)
|
|
|
4.27
|
|
|
|
4.99
|
|
|
|
5.36
|
|
|
|
5.76
|
|
|
|
5.45
|
|
Realized Unhedged Price after Basis Differential ($/Mcf) (3)
|
|
|
4.43
|
|
|
|
5.14
|
|
|
|
5.52
|
|
|
|
5.91
|
|
|
|
5.61
|
|
Daily Hedged Volumes (MMcf/d)
|
|
|
7.3
|
|
|
|
7.3
|
|
|
|
9.7
|
|
|
|
9.0
|
|
|
|
9.5
|
|
Percent of Total Volumes Swapped
|
|
|
98
|
%
|
|
|
48
|
%
|
|
|
34
|
%
|
|
|
37
|
%
|
|
|
36
|
%
|
Swap Price ($/MMBtu)
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
Percent of Total Volumes Floored
|
|
|
|
|
|
|
|
|
|
|
11
|
%
|
|
|
9
|
%
|
|
|
11
|
%
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ending
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(In thousands, except well number, volumetric and per unit
data)
|
|
|
Floor Price ($/MMBtu)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5.00
|
|
|
$
|
5.00
|
|
|
$
|
5.00
|
|
Realized Hedged Weighted Average Price ($/Mcf) (3)
|
|
$
|
7.06
|
|
|
$
|
6.08
|
|
|
$
|
6.06
|
|
|
$
|
6.36
|
|
|
$
|
6.15
|
|
Estimated Cash Available for Distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Revenues
|
|
$
|
2,988
|
|
|
$
|
7,193
|
|
|
$
|
10,920
|
|
|
$
|
10,386
|
|
|
$
|
10,332
|
|
Swap and Floor Hedge Revenues
|
|
|
1,772
|
|
|
|
1,313
|
|
|
|
1,061
|
|
|
|
781
|
|
|
|
991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
4,760
|
|
|
$
|
8,506
|
|
|
$
|
11,981
|
|
|
$
|
11,167
|
|
|
$
|
11,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Production Services Fee (4)
|
|
$
|
361
|
|
|
$
|
749
|
|
|
$
|
1,060
|
|
|
$
|
941
|
|
|
$
|
987
|
|
Trust Expenses
|
|
|
200
|
|
|
|
200
|
|
|
|
200
|
|
|
|
200
|
|
|
|
201
|
|
Franchise Taxes
|
|
|
207
|
|
|
|
207
|
|
|
|
211
|
|
|
|
211
|
|
|
|
211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Available for Distribution
|
|
$
|
3,991
|
|
|
$
|
7,350
|
|
|
$
|
10,510
|
|
|
$
|
9,815
|
|
|
$
|
9,924
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust Units Outstanding
|
|
|
17,605
|
|
|
|
17,605
|
|
|
|
17,605
|
|
|
|
17,605
|
|
|
|
17,605
|
|
Target Distribution Per Trust Unit
|
|
$
|
0.227
|
|
|
$
|
0.417
|
|
|
$
|
0.597
|
|
|
$
|
0.558
|
|
|
$
|
0.564
|
|
Subordination Threshold Per Trust Unit
|
|
$
|
0.181
|
|
|
$
|
0.334
|
|
|
$
|
0.478
|
|
|
$
|
0.446
|
|
|
$
|
0.451
|
|
Incentive Threshold Per Trust Unit
|
|
$
|
0.272
|
|
|
$
|
0.501
|
|
|
$
|
0.716
|
|
|
$
|
0.669
|
|
|
$
|
0.676
|
|
|
|
|
(1)
|
|
For a more detailed description of
the natural gas hedging contracts established for the benefit of
the trust, please see Description of the royalty
interests.
|
|
|
|
(2)
|
|
Based on settled NYMEX pricing for
April, May and June 2010 of $3.842, $4.271 and $4.155 per MMBtu,
respectively, and NYMEX forward pricing as of June 4, 2010
for the 33 month period ending March 31, 2013. Assumed
price per Mcf calculated based on an assumed conversion rate of
1.03 MMBtu
per Mcf.
|
|
(3)
|
|
Adjusted for an assumed basis
differential of $0.15 per MMBtu.
|
|
(4)
|
|
Consists of a fee of $0.52 per
MMBtu.
|
ENERGY
CORPORATION OF AMERICA
ECA is a privately held energy company engaged in the
exploration, development, production, gathering, aggregation and
sale of natural gas and oil, primarily in the Appalachian Basin,
Gulf Coast and Rocky Mountain regions in the United States and
in New Zealand. ECA or its predecessors have owned and operated
natural gas properties in the Appalachian Basin for more than
45 years, and ECA is one of the largest natural gas
operators in the Appalachian Basin. As of December 31,
2009, ECA operated approximately 5,100 wells in the
Appalachian Basin and had an aggregate net leasehold position of
approximately one million acres, with 85% of this acreage held
by production. ECA sells gas from its own wells as well as
third-party wells to local gas distribution companies,
industrial end users located in the Northeast, other gas
marketing entities and into the spot market for gas delivered
into interstate pipelines. ECA owns and operates approximately
5,000 miles of gathering lines and intrastate pipelines
that are used in connection with its gas aggregation activities.
During the fiscal year ended June 30, 2009, ECA aggregated
and sold 22.5 Bcf of gas for an average of 62 MMcf of
gas per day, of which 20.7 Bcf, or 57 MMcf per day,
represented sales of gas produced from wells operated by ECA.
7
ECA was formed in September 1992 as a Colorado corporation and
subsequently reincorporated in West Virginia through a merger
with ECAs predecessor in June 1995. ECAs predecessor
began operating in the Appalachian Basin in 1963. ECAs
principal offices are located at 4643 South Ulster Street,
Suite 1100, Denver, Colorado 80237, and its telephone
number is
(303) 694-2667.
For additional information concerning ECA, see Information
about Energy Corporation of America beginning on
page ECA-1
of this prospectus. ECA will be required to deliver to the
trustee a statement of the computation of the proceeds for each
computation period, as well as quarterly drilling and production
results. ECA will not be a reporting company following this
offering and will not file periodic reports with the SEC.
Therefore, as a trust unitholder, you will not have access to
financial information of ECA.
The trust
units do not represent interests in or obligations of
ECA.
FORMATION
TRANSACTIONS
At or prior to the closing of this offering, the following
transactions, which are referred to as the formation
transactions, will occur:
|
|
|
|
|
ECA will convey to a wholly owned subsidiary a term royalty
interest entitling the holder of the interest to receive 45% of
the proceeds from the sale of production of natural gas
attributable to ECAs interest in the Producing Wells
(after deducting post-production costs and any applicable taxes)
for a period of 20 years commencing on April 1, 2010
(the Term PDP Royalty) and a term royalty interest
entitling such holder of the interest to receive 25% of the
proceeds from the sale of the production of natural gas
attributable to ECAs interest in the PUD Wells (after
deducting
post-production
costs and any applicable taxes) for a period of 20 years
commencing on April 1, 2010 (the Term PUD
Royalty) in exchange for a demand note in the principal
amount of approximately $161 million. The Term PDP Royalty
and the Term PUD Royalty are collectively referred to as the
Term Royalties.
|
|
|
|
ECA and the Private Investors will convey to the trust perpetual
royalty interests entitling the trust to receive, in the
aggregate, 45% of the proceeds from the sale of production of
natural gas attributable to the interests of ECA in the
Producing Wells (after deducting post-production costs and any
applicable taxes) (the Perpetual PDP Royalty) and
ECA will convey to the trust a perpetual royalty interest
entitling the trust to receive an additional 25% of the proceeds
from the sale of production of natural gas attributable to
ECAs interest in the PUD Wells (after deducting
post-production
costs and any applicable taxes) (the Perpetual PUD
Royalty) in exchange for, in the case of ECA,
3,087,371 common units constituting 17.5% of the trust
units outstanding and 4,401,250 subordinated units
constituting 25% of the trust units outstanding, and in the case
of the Private Investors, 1,313,879 common units
constituting 7.5% of the trust units outstanding. The Perpetual
PDP Royalty and the Perpetual PUD Royalty are collectively
referred to as the Perpetual Royalties.
|
|
|
|
The trust will sell the 8,802,500 common units offered
hereby to the public, representing a 50% interest in the trust.
|
|
|
|
ECA will convey to the trust the natural gas floor price
contracts and will enter into a back-to-back swap agreement with
the trust to provide the trust with the benefit of the swap
contracts entered into between ECA and third parties.
|
8
|
|
|
|
|
ECAs subsidiary will convey the Term Royalties to the
trust in exchange for a payment from the net proceeds of this
offering and will use the net proceeds to repay all or a portion
of the demand note to ECA and the remaining net proceeds, if
any, will be distributed to ECA.
|
|
|
|
|
|
ECA will purchase 209,312 common units from the Private
Investors at the initial offering price.
|
|
|
|
|
|
ECA and the trust will enter into an Administrative Services
Agreement outlining the provision of administrative services to
the trust and its compensation therefor and a Development
Agreement outlining ECAs drilling obligation to the trust
with respect to the PUD Wells. Please see The
trust Administrative services agreement and
development agreement.
|
|
|
|
|
|
ECA will grant to the trust the Drilling Support Lien.
|
|
|
|
ECA will grant to the trust a lien on the PDP Royalty Interest
and the PUD Royalty Interest (the Royalty Interest
Lien) to provide protection to the trust, in the event of
a bankruptcy of ECA, against the risk that the PDP Royalty
Interest or PUD Royalty Interest were not considered a real
property interest.
|
STRUCTURE
OF THE TRUST
The following chart shows the relationship of ECA, the trust and
the public unitholders.
9
KEY
INVESTMENT CONSIDERATIONS
The following are some key investment considerations related to
the Underlying Properties, the royalty interests, and the common
units:
|
|
|
|
|
Royalty interests not burdened by operating or capital
costs. The trust will not be responsible for any
operating or capital costs associated with the Underlying
Properties, including the costs to drill the PUD Wells. As a
result, the trusts burden to pay costs associated with any
particular well will not arise until such well is producing
natural gas attributable to the trusts interest. The
principal costs the trust will bear are the Post-Production
Services Fee; property, ad valorem, production, severance,
excise, franchise and similar taxes, if any; and trust
administrative expenses including costs incurred as a result of
being a publicly traded entity. In addition, the trust will be
obligated to reimburse ECA for approximately $5 million
incurred in establishing the floor price contracts transferred
to the trust if and to the extent cash available for
distribution by the trust exceeds certain levels.
|
|
|
|
Downside protection against natural gas price volatility
through natural gas hedging contracts for approximately 50% of
estimated production through March 31, 2014. ECA
has established for the benefit of the trust certain floor price
and swap hedging contracts covering approximately 50% of the
expected production volumes attributable to the trust from
April 1, 2010 through March 31, 2014. The swap
contracts will relate to approximately 7,500 MMBtu per day
at a weighted average price of $6.78 per MMBtu for the period
from April 1, 2010 through June 2012. The price of the
floor price hedging contracts will be $5.00 per MMBtu.
These hedging contracts should reduce commodity price risks
inherent in holding interests in natural gas through the end of
March 31, 2014.
|
|
|
|
Alignment of interests between ECA and the trust
unitholders. ECA is significantly incentivized to
complete its drilling obligation, to increase production from
the Underlying Properties and to obtain the best prices for the
natural gas production from the Underlying Properties as a
result of the following factors:
|
|
|
|
|
-
|
ECA will have a significant economic interest in the Underlying
Properties through its retained interest in the Underlying
Properties and its ownership of approximately 43% of the trust
units.
|
|
|
-
|
A portion of the trust units that ECA will own, constituting 25%
of the outstanding trust units, will be subordinated units that
will not be entitled to receive distributions unless there is
sufficient cash to pay the subordination threshold to the common
units. These subordinated units will only convert into common
units upon completion of the subordination period.
|
|
|
-
|
To the extent that the trust has cash available for distribution
in excess of the incentive thresholds during the subordination
period, ECA will be entitled to receive 50% of such cash as
incentive distributions and 50% of such cash as recoupment of
its costs for establishing the floor price contracts until it
has recouped approximately $5 million.
|
|
|
|
|
-
|
ECA will not be permitted to drill and complete any development
wells in the Marcellus Shale formation on the lease acreage
within the AMI for its own account or sell the Underlying
Properties until it has satisfied its drilling obligation.
|
10
|
|
|
|
|
Potential for initial depletion to be offset by results of
development drilling. ECA is obligated to drill the PUD
Wells by March 31, 2014. Furthermore, ECA is incentivized
to increase production in the near term in order to receive
incentive distributions. While production from the trust
properties will decline in the long term, production from the
PUD Wells will offset depletion of the Producing Wells in the
near term.
|
|
|
|
ECAs experience and position as Marcellus Shale
operator. Since January 1, 2006, ECA has drilled
over 160 Marcellus Shale wells throughout the Appalachian Basin
and operates Marcellus Shale wells in New York, Pennsylvania and
West Virginia. ECA was one of the earliest operators in the
Marcellus Shale region, having drilled test wells in this play
in the late 1970s in partnership with the U.S. Department
of Energy, and on April 18, 2008, it drilled and completed
the Consol USX-13 well, which was one of the first
horizontal Marcellus Shale wells in Greene County, Pennsylvania.
ECA has drilled 141 gross vertical development wells and
20 gross horizontal wells in the Marcellus Shale formation,
and it has successfully completed 100% of these wells. ECA is
currently the operator of all of the Producing Wells and will
agree to operate not less than 90% of the PUD Wells during the
subordination period, allowing ECA to control the timing and
amount of discretionary expenditures for operational and
development activities with respect to substantially all of the
PUD Wells. ECAs senior managers possess an average of
27.5 years of industry experience with an extensive focus
on operations in the Appalachian Basin and Marcellus Shale.
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ECAs prior experience sponsoring a royalty
trust. In 1993, ECA sponsored the formation of the
Eastern American Natural Gas Trust (NYSE: NGT), a publicly
traded Delaware trust (NGT), to which it contributed
term net profits interests in Appalachian Basin natural gas
properties. In connection with the formation of this trust, ECA
agreed to drill 65 development wells over five years from which
NGT would be entitled to a specified percentage of the proceeds
from the natural gas production. ECA completed its obligation
within the stipulated period. The historical results of
operations and performance of NGT should not be relied on as an
indicator of how the trust will perform.
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In mid-2005, ECA entered into a term royalty transaction with a
private investor. ECA conveyed to the private investor a 90%
royalty interest in 312 producing gas wells located in the
Appalachian Basin in West Virginia, Pennsylvania and Kentucky,
as well as a 50% royalty interest in 180 development wells that
were subsequently drilled by ECA in Kentucky and West Virginia.
Although the parties originally contemplated that ECA would
drill relatively shallow wells, 105 of the 180 development wells
were completed to the deeper Marcellus Shale formation.
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Experience of ECA marketing natural gas
production. As the operator of all of the Producing
Wells and substantially all the PUD Wells, ECA will have the
responsibility to market or cause to be marketed the natural gas
production related to the Underlying Properties. During the
fiscal year ended June 30, 2009, ECA and its affiliates
aggregated and sold domestically an average of 62 MMcf of
gas per day, of which 57 MMcf per day represented sales of
natural gas produced from wells operated by ECA.
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Proximity of the Appalachian Basin to major
markets. The Appalachian Basin is located close to a
substantial number of large commercial and industrial gas
markets, including natural gas powered electricity plants, and
major residential markets in the northeastern United States.
This proximity, together with the stable nature of Appalachian
Basin production and the availability of transportation
facilities, has resulted in generally higher realized prices for
Appalachian Basin natural gas (including Marcellus Shale
formation natural gas) than realized prices available in other
regions of the United States.
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11
The average realized sales prices for gas gathered and sold on
ECAs Greene County Gathering System (prior to any
deduction for post-production costs) for each year in the three
year period ended June 30, 2009 and the average NYMEX price
for the same period are detailed in the table below:
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Average Greene County
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Average NYMEX
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Year
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Gathering Price/MMBtu
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Price/MMBtu
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2007
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$
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7.17
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$
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6.86
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2008
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8.46
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8.02
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2009
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6.85
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6.39
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During this three year period, ECAs Greene County
Gathering System received an average price that was $0.40 per
MMBtu higher than the average NYMEX price for the same period.
In establishing the subordination and incentive thresholds, ECA
has assumed a basis differential of $0.15 per MMBtu.
KEY RISK
FACTORS
Below is a summary of certain key risk factors for consideration
related to the Underlying Properties, the royalty interests and
the common units. This list is not exhaustive, please also read
carefully the full discussion of these risks and other risks
described under Risk factors on page 19.
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Drilling and completion of PUD Wells on the Underlying
Properties are high risk activities with many uncertainties that
could delay ECAs anticipated drilling schedule and
adversely affect future production from the Underlying
Properties. Any such delays or reductions in production could
decrease future revenues that are available for distribution to
unitholders.
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Natural gas prices fluctuate due to a number of factors that
are beyond the control of the trust and ECA, and lower prices
could reduce proceeds to the trust and cash distributions to
unitholders.
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Actual reserves and future production may be less than
current estimates, which could reduce cash distributions by the
trust and the value of the trust units.
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Recently proposed severance taxes in Pennsylvania could, if
enacted, materially increase the applicable taxes that are borne
by the trust.
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The generation of proceeds for distribution by the trust
depends in part on gathering, transportation and processing
facilities owned by ECA and others. Any limitation in the
availability of those facilities could interfere with sales of
natural gas production from the Underlying Properties.
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Due to the trusts lack of industry and geographic
diversification, adverse developments in the trusts
existing area of operation could adversely impact its financial
condition, results of operations and cash flows and reduce its
ability to make distributions to the unitholders.
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The natural gas reserves estimated to be attributable to the
Underlying Properties of the trust are depleting assets and
production from those reserves will diminish over time.
Furthermore, the trust is precluded from acquiring other oil and
gas properties or royalty interests to replace the depleting
assets and production.
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12
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The amount of cash available for distribution by the trust
will be reduced by the amount of post-production costs,
applicable taxes associated with the trusts interest,
trust expenses, incentive distributions and reimbursement
obligations payable to ECA.
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The trusts tax treatment depends on its status as a
partnership for federal income tax purposes. If the IRS were to
treat the trust as a corporation for federal income tax
purposes, then its cash available for distribution to you would
be substantially reduced.
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The ability of ECA to satisfy its obligations to the trust
depends on the financial position of ECA, and in the event of a
default by ECA in its obligation to drill the PUD Wells, or in
the event of ECAs bankruptcy, it may be expensive and
time-consuming for the trust to exercise its remedies.
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Federal and state legislative and regulatory initiatives
relating to hydraulic fracturing or drilling operations
generally could result in increased costs and additional
operating restrictions or delays as well as adversely affect
ECAs services.
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If the trust were subjected to a material amount of
additional entity-level taxation by Pennsylvania or any other
states, the trusts cash available for distribution to you
would be reduced.
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The trust will adopt positions that may not conform to all
aspects of existing Treasury Regulations. If the IRS contests
the federal income tax positions the trust takes, the value of
the trust units may be adversely affected, the cost of any IRS
contest will reduce the trusts cash available for
distribution to you and income, gain, loss and deduction may be
reallocated among trust unitholders.
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13
PROVED
RESERVES
Proved reserves of Underlying Properties and royalty
interests. The following table, effective as of
March 31, 2010, sets forth certain estimated proved
reserves, estimated future net revenues and the discounted
present value thereof attributable to the Underlying Properties,
the PDP Royalty Interest and the PUD Royalty Interest, in each
case derived from the reserve report. The reserve report was
prepared by Ryder Scott in accordance with criteria established
by the Securities and Exchange Commission, or SEC.
In accordance with the SECs new rules, the reserves
presented below were determined using the twelve month
unweighted arithmetic average of the
first-day-of-the-month
price for the period from April 1, 2009 through
March 1, 2010, without giving effect to the derivative
transactions, and were held constant for the life of the
properties. This yielded a price for natural gas of $3.984 per
MMBtu. Proved reserve quantities attributable to the royalty
interests are calculated by multiplying the gross reserves for
each property by the royalty interest assigned to the trust in
each property. The net revenues attributable to the trusts
reserves are net of the trusts obligation to reimburse ECA
for post-production costs. The reserves related to the
Underlying Properties include all proved reserves expected to be
economically produced from the Marcellus Shale formation during
the life of the properties. The reserves and revenues
attributable to the trusts interests include only the
reserves attributable to the Underlying Properties that are
expected to be produced within the 20-year period in which the
trust owns the royalty interest as well as the 50% residual
interest in the reserves that the trust will own on the
Termination Date. A summary of the reserve report is included as
Annex A to this prospectus.
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Proved Gas
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Discounted
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Reserves
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Estimated Future
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Estimated Future
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Proved Reserves
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(Bcf)
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Net Revenues
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Net Revenues (1)
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(Dollars in thousands)
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Underlying Properties
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202.0
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$
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535,435
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$
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175,400
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Royalty Interests:
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PDP Royalty Interest (90%) (2)
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35.1
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$
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130,690
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$
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72,560
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PUD Royalty Interest (50%)
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73.5
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$
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273,267
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$
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133,315
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Total
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108.6
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$
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403,957
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$
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205,875
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(1)
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The present values of future net
revenues for the Underlying Properties and the royalty interests
were determined using a discount rate of 10% per annum.
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(2)
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Includes reserves currently behind
pipe in existing wells which are in the process of being
completed.
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14
Annual production attributable to royalty
interests. The following bar graph shows estimated
annual production from the Underlying Properties attributable to
the royalty interests based on the pricing and other assumptions
set forth in the reserve report. The production estimates
include the impact of additional production that is expected as
a result of the drilling of the PUD Wells. The net production
for 2010 only includes the nine months from April 1, 2010.
15
THE
OFFERING
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Common units offered to public |
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8,802,500 common units |
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10,122,875 common units, if the underwriters exercise their
over-allotment option in full |
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Trust units owned by ECA after the offering |
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3,296,683 common units and 4,401,250 subordinated units |
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1,976,308 common units and 4,401,250 subordinated
units, if the underwriters exercise their over-allotment option
in full |
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Common units owned by the Private Investors |
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1,104,567 common units. For more information on the common units
owned by the Private Investors, please read Certain
transactions. |
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Total units outstanding after the offering |
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13,203,750 common units and 4,401,250 subordinated
units |
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Use of proceeds |
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The trust is offering the common units to be sold in this
offering. Assuming no exercise of the underwriters
over-allotment option and an initial public offering price of
$20.00 per common unit, the estimated net proceeds of this
offering will be approximately $161 million, after
deducting underwriting discounts and commissions and offering
expenses. The trust will use the net proceeds to pay a
wholly-owned subsidiary of ECA for the conveyance of the Term
Royalties and the remaining net proceeds, if any, will be
distributed to ECA. In turn, such subsidiary will use such
amount to repay all or a portion of an approximately
$161 million demand note payable to ECA to be issued as
consideration for the transfer of the Term Royalties thereto. |
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The trust will use the net proceeds from any exercise of the
underwriters over-allotment option to repurchase an equal
number of common units from ECA at the initial public offering
price after deducting underwriting discounts and commissions. |
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ECA intends to use the proceeds received both from the repayment
of the demand note by ECAs subsidiary and from any
exercise of the underwriters over-allotment option to
purchase 209,312 common units from the Private Investors at the
initial offering price, to reduce borrowings under its revolving
credit facility and for general corporate purposes. Please read
Use of proceeds. |
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NYSE symbol |
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ECT |
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Trustee |
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The Bank of New York Mellon Trust Company, N.A. |
16
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Quarterly cash distributions |
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Actual cash distributions to the trust unitholders will
fluctuate quarterly based on the quantity of natural gas
produced from the Underlying Properties, the prices received for
natural gas production and other factors. Because payments to
the trust will be generated by depleting assets and the trust
has a finite life with the production from the Underlying
Properties initially increasing and subsequently diminishing
over time, a portion of each distribution will represent a
return of your original investment and the target distributions
will decline over time. Production declines are expected to be
offset in the near term by production realized from the drilling
and successful completion of the PUD Wells. |
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Quarterly cash distributions during the term of the trust will
be made by the trustee on or about the 60th day following the
end of each calendar quarter to the trust unitholders of record
on or about the 45th day following each calendar quarter. The
first distribution from the trust to the trust unitholders will
be made on or about August 31, 2010. The first distribution
to the trust unitholders will be based upon amounts to be
received from ECA for estimated production attributable to the
royalty interests and proceeds attributable to the hedging
contracts for the period commencing on April 1, 2010 and
ending on June 30, 2010, regardless or whether such amounts
have actually been received by ECA from the purchaser of the
natural gas produced. |
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Termination of the trust |
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The trust will begin to liquidate on the Termination Date and
will soon thereafter wind up its affairs and terminate. The Term
Royalties will automatically revert to ECA at the Termination
Date, while the Perpetual Royalties will be sold and the
proceeds thereof will be distributed to the unitholders at the
Termination Date or soon thereafter. ECA will have a right of
first refusal to purchase the Perpetual Royalties at the
Termination Date. |
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Summary of income tax considerations |
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The trust will be treated as a partnership for federal income
tax purposes. Consequently, the trust will not incur any federal
income tax liability. Instead, trust unitholders will be
allocated an amount of the trusts income, gain, loss, or
deductions corresponding to their interest in the trust, which
amounts may differ in timing or amount from actual
distributions. The Term PDP Royalty will and the Term PUD
Royalty should be treated as debt instruments for federal income
tax purposes, and the trust will be required to treat a portion
of each payment it receives with respect to each such royalty
interest as interest income in accordance with the
noncontingent bond method under the original issue
discount rules contained in the Internal Revenue Code of 1986,
as amended, and the corresponding |
17
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regulations. The Perpetual PDP Royalty will and the Perpetual
PUD Royalty should be treated as mineral royalty interests for
federal income tax purposes, which generates ordinary income
subject to depletion. Please read Federal income tax
considerations. |
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Estimated ratio of taxable income to distributions |
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The trust estimates that if you own the units you purchase in
this offering through the record date for distributions for the
period ending December 31, 2012, you will be allocated, on
a cumulative basis, an amount of federal taxable income for that
period that will be approximately 65% or less of the cash
distributed to you with respect to that period. For example, if
you receive an annual distribution of $2.50 per unit, the
trust estimates that your average allocable federal taxable
income per year will be no more than approximately
$1.63 per unit. Please read Federal income tax
considerations. |
18
RISK
FACTORS
Drilling and completion of the PUD Wells on the Underlying
Properties are high risk activities with many uncertainties that
could delay ECAs anticipated drilling schedule and
adversely affect future production from the Underlying
Properties. Any such delays or reductions in production could
decrease future revenues that are available for distribution to
unitholders.
The drilling and completion of the PUD Wells on the Underlying
Properties are subject to numerous risks beyond ECAs and
the trusts control, including risks that could delay
ECAs current drilling schedule for the PUD Wells and the
risk that drilling will not result in commercially viable
natural gas production. ECAs decisions to develop or
otherwise exploit certain areas within the AMI will depend in
part on the evaluation of data obtained through geophysical and
geological analyses, production data and engineering studies,
the results of which are often inconclusive or subject to
varying interpretations. ECAs costs of drilling,
completing and operating wells are often uncertain before
drilling commences. Overruns in budgeted expenditures are common
risks that can make a particular project uneconomical. Further,
ECAs future business, financial condition, results of
operations, liquidity or ability to finance planned capital
expenditures could be materially and adversely affected by any
factor that may curtail, delay or cancel drilling, including the
following:
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delays imposed by or resulting from compliance with regulatory
requirements including permitting;
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unusual or unexpected geological formations;
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shortages of or delays in obtaining equipment and qualified
personnel;
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equipment malfunctions, failures or accidents;
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lack of available gathering facilities or delays in construction
of gathering facilities;
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lack of available capacity on interconnecting transmission
pipelines;
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unexpected operational events and drilling conditions;
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pipe or cement failures;
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casing collapses;
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lost or damaged drilling and service tools;
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loss of drilling fluid circulation;
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uncontrollable flows of natural gas and fluids;
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fires and natural disasters;
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environmental hazards, such as natural gas leaks, pipeline
ruptures and discharges of toxic gases;
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adverse weather conditions;
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19
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reductions in natural gas prices;
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natural gas property title problems; and
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market limitations for natural gas.
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In the event that drilling of development wells is delayed or
development wells have lower than anticipated production due to
one of the factors above or for any other reason, estimated
future distributions to unitholders may be reduced.
Natural gas prices fluctuate due to a number of factors
that are beyond the control of the trust and ECA, and lower
prices could reduce proceeds to the trust and cash distributions
to unitholders.
The trusts reserves and quarterly cash distributions are
highly dependent upon the prices realized from the sale of
natural gas. Natural gas prices can fluctuate widely on a
month-to-month
basis in response to a variety of factors that are beyond the
control of the trust and ECA. These factors include, among
others:
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weather conditions and seasonal trends;
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regional, domestic and foreign supply and perceptions of supply
of natural gas;
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availability of imported liquefied natural gas, or LNG;
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the level of demand and perceptions of demand for natural gas;
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anticipated future prices of natural gas, LNG and other
commodities;
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technological advances affecting energy consumption and energy
supply;
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U.S. and worldwide political and economic conditions;
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the price and availability of alternative fuels;
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the proximity, capacity, cost and availability of gathering and
transportation facilities;
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the volatility and uncertainty of regional pricing differentials;
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acts of force majeure;
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governmental regulations and taxation; and
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energy conservation and environmental measures.
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From 2006 through 2009 the highest monthly NYMEX settled price
was $13.11 per MMBtu and the lowest was $2.84 per MMBtu. In
addition, the market price of natural gas is generally higher in
the winter months than during other months of the year due to
increased demand for natural gas for heating purposes during the
winter season.
Lower natural gas prices will reduce proceeds to which the trust
is entitled and may ultimately reduce the amount of natural gas
that is economic to produce from the Underlying Properties. As a
result, the operator of any of the Underlying Properties could
determine during
20
periods of low gas prices to shut in or curtail production from
wells on the Underlying Properties. In addition, the operator of
the Underlying Properties could determine during periods of low
gas prices to plug and abandon marginal wells that otherwise may
have been allowed to continue to produce for a longer period
under conditions of higher prices. Specifically, ECA may abandon
any well or property if it reasonably believes that the well or
property can no longer produce natural gas in commercially
economic quantities. This could result in termination of the
portion of the royalty interest relating to the abandoned well
or property, and ECA would have no obligation to drill a
replacement well. In making such decisions, ECA is required
under the applicable conveyance to act as a reasonably prudent
operator in the AMI under the same or similar circumstances as
it would act if it were acting with respect to its own
properties, disregarding the existence of the royalty interests
as burdens affecting such property. As a result, the volatility
of natural gas prices also reduces the accuracy of estimates of
future cash distributions to trust unitholders.
Actual reserves and future production may be less than
current estimates, which could reduce cash distributions by the
trust and the value of the trust units.
The value of the trust units and the amount of future cash
distributions to the trust unitholders will depend upon, among
other things, the accuracy of the reserves estimated to be
attributable to the trusts royalty interests. The
trusts reserve quantities and revenues are based on
estimates of reserve quantities and revenues for the Underlying
Properties. See The underlying properties
Natural gas reserves for a discussion of the method of
allocating proved reserves to the trust. It is not possible to
measure underground accumulations of natural gas in an exact
way, and estimating reserves is inherently uncertain.
Ultimately, actual production and revenues for the Underlying
Properties could vary negatively and in material amounts from
estimates and those variations could be material. Petroleum
engineers are required to make subjective estimates of
underground accumulations of natural gas based on factors and
assumptions that include:
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historical production from the area compared with production
rates from other producing areas;
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natural gas prices, production levels, Btu content, production
expenses, transportation costs, severance and excise taxes and
capital expenditures; and
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the assumed effect of governmental regulation.
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Changes in these assumptions or actual production costs incurred
and results of actual development and production costs could
materially decrease reserve estimates.
In particular, reserve estimates for fields that do not have a
lengthy production history are less reliable than estimates for
fields with lengthy production histories. A lack of production
history may contribute to inaccuracy in estimates of proved
reserves, future production rates and the timing of development
expenditures. The Producing Wells have been operational for less
than one year. Also, Pennsylvania oil and gas production data is
kept confidential for five years, and the first Marcellus Shale
production in the state was in 2005. Furthermore, the use of
horizontal drilling methods on the Underlying Properties is a
recent development in the Marcellus Shale, with ECA commencing
the drilling of its first horizontal well in the Marcellus Shale
in 2007. The lack of operational history for horizontal wells in
the Marcellus Shale formation may also contribute to the
inaccuracy of estimates of proved reserves. A material and
adverse variance of actual production, revenues and expenditures
from those underlying reserve estimates, including variances
attributable to a lack of production history within the
Marcellus Shale formation,
21
would have a material adverse effect on the financial condition,
results of operations and cash flows of the trust and would
reduce cash distributions to trust unitholders.
Recently proposed severance taxes in Pennsylvania could,
if enacted, materially increase the applicable taxes that are
borne by the trust.
While Pennsylvania has historically not imposed a severance tax
on the production of natural gas, legislation known as Senate
Bill No. 1254 was introduced in the Pennsylvania Senate
Finance Committee on March 4, 2010 and House Bill 1489
was introduced in the House Energy and Environmental Resources
Committee on May 13, 2009. These bills, if enacted, would
provide for a severance tax of 5% of the value of the natural
gas at the wellhead plus $0.047 per thousand cubic feet of
natural gas severed. Additionally, a severance tax, with tax
rates equal to those of Senate Bill No. 1254 and House
Bill 1489, is included in the governors proposed
2010-2011
budget, dated February 9, 2010. If adopted, any such
severance tax would be a post-production cost that would be
borne by the trust and may materially reduce distributions to
unitholders.
The generation of proceeds for distribution by the trust
depends in part on gathering, transportation and processing
facilities owned by ECA and others. Any limitation in the
availability of those facilities could interfere with sales of
natural gas production from the Underlying Properties.
The amount of natural gas that may be produced and sold from any
well to which the Underlying Properties relate is subject to
curtailment in certain circumstances, such as by reason of
weather conditions, pipeline interruptions due to scheduled and
unscheduled maintenance, failure of tendered gas to meet quality
specifications of gathering lines or downstream transporters,
excessive line pressure which prevents delivery of gas, physical
damage to the gathering system or transportation system or lack
of contracted capacity on such systems. The curtailments may
vary from a few days to several months. In many cases, ECA is
provided limited notice, if any, as to when production will be
curtailed and the duration of such curtailments. If ECA is
forced to reduce production due to such a curtailment, the
revenues of the trust and the amount of cash distributions to
the trust unitholders would similarly be reduced due to the
reduction of proceeds from the sale of production.
Some of the wells on the underlying PUD properties will be
drilled in locations that currently are not serviced by
gathering and transportation pipelines or locations in which
existing gathering and transportation pipelines do not have
sufficient capacity to transport additional production. As a
result, ECA may not be able to sell the natural gas production
from certain PUD Wells until the necessary gathering systems
and/or
transportation pipelines are constructed or until the necessary
transportation capacity on an interstate pipeline is obtained.
Any delay in the construction or expansion of these gathering
systems beyond the currently estimated construction schedules,
or a delay in the procurement of additional transportation
capacity would delay the receipt of any proceeds that may be
associated with natural gas production from the PUD Wells. If
transportation capacity is not available, either directly from a
pipeline or pipelines or in the secondary capacity market, ECA
would be required to request that the pipeline or pipelines
construct additional facilities or expand their existing
facilities to provide additional transportation capacity. The
pipelines are not required to undertake such construction or
expansion. If the pipeline refuses to construct additional
transportation capacity or expand its existing transportation
capacity, ECA may not be able to receive proceeds that may be
associated with natural gas production from wells on the
underlying PUD properties. Any delay in the construction or
expansion of pipeline transportation facilities will delay the
receipt of any proceeds that may be associated with natural gas
production from wells on the underlying PUD properties.
22
The generation of proceeds for distribution by the trust
depends in part on the ability of ECA and/or its customers to
obtain service on transportation facilities owned by third party
pipelines; any limitation in the availability of those
facilities and/or any increase in the cost of service on those
facilities could interfere with sales of natural gas production
from the Underlying Properties.
Natural gas that is gathered on Greene County Gathering System,
including natural gas produced from the Underlying Properties,
is currently shipped on two interstate natural gas
transportation pipelines. ECAs purchasers have contracted
with those pipelines for firm or interruptible transportation
service. The rates for service on the transportation pipelines
are regulated by the Federal Energy Regulatory Commission
(FERC) and are subject to increase if the pipeline
demonstrates that the existing rates are unjust and unreasonable.
ECA may, in the future, seek to obtain firm transportation
capacity, but there can be no assurance that capacity will be
available. In addition, to the extent ECAs customers or
ECA became dependent on interruptible service, and to the extent
that either pipeline receives requests for service that exceed
the capacity of the pipeline, the pipeline will honor requests
by its firm customers first, and will then allocate remaining
capacity, if any, to interruptible shippers. As a result, ECA or
its customers may be unable to obtain all or a part of any
requested interruptible capacity service on the transportation
pipelines. Any inability of ECA or its customers to procure
sufficient capacity to transport the natural gas gathered on its
Greene County Gathering System will decrease
and/or delay
the receipt of any proceeds that may be associated with natural
gas production from wells on the Underlying Properties. In
addition, any increase in transportation rates paid by ECA for
production attributable to the trusts interests will
decrease the proceeds received by the trust.
Shortages or increases in costs of equipment, services and
qualified personnel could delay the drilling of the PUD Wells
and result in a reduction in the amount of cash available for
distribution.
The demand for qualified and experienced personnel to conduct
field operations, geologists, geophysicists, engineers and other
professionals in the natural gas industry can fluctuate
significantly, often in correlation with oil and natural gas
prices, causing periodic shortages. Historically, there have
been shortages of drilling rigs and other equipment as demand
for rigs and equipment has increased along with the number of
wells being drilled. These factors also cause significant
increases in costs for equipment, services and personnel. Higher
natural gas prices generally stimulate demand and result in
increased prices for drilling rigs, crews and associated
supplies, equipment and services. Shortages of field personnel
and equipment or price increases could significantly hinder
ECAs ability to perform the drilling obligations and delay
completion of the development wells, which would reduce future
distributions to trust unitholders.
Due to the trusts lack of industry and geographic
diversification, adverse developments in the trusts
existing area of operation could adversely impact its financial
condition, results of operations and cash flows and reduce its
ability to make distributions to the unitholders.
The Underlying Properties will be operated for natural gas
production only and are focused exclusively in the Marcellus
Shale formation in Greene County, Pennsylvania. In particular,
the concentration of the Underlying Properties in the Marcellus
Shale formation in Greene County, Pennsylvania could
disproportionately expose the trusts interests to
operational and regulatory risk in that area. Due to the lack of
diversification in industry type and location of the
trusts interests, adverse developments in the natural gas
market or the area of the Underlying Properties could have a
significantly greater impact on the trusts financial
condition, results of operations and cash flows than if the
trusts royalty interests were more diversified.
23
The trust units may lose value as a result of title
deficiencies with respect to the Underlying Properties.
The existence of a material title deficiency with respect to the
Underlying Properties can reduce the value or render a property
worthless, thus adversely affecting the distributions to
unitholders. ECA does not obtain title insurance covering
mineral leaseholds. Additionally, undeveloped acreage has
greater risk of title defects than developed acreage.
Consistent with industry practice, ECA has not obtained a
preliminary title review on the PUD Wells. Prior to the drilling
of a PUD Well, ECA intends to obtain a preliminary title review
to ensure there are no obvious defects in title to the
leasehold. Frequently, as a result of such examinations, certain
curative work must be done to correct defects in the
marketability of the title, and such curative work entails
expense. ECAs failure to cure any title defects may render
some locations undrillable and cause ECA to lose its rights to
production from the Underlying Properties. In the event of such
a material title problem, proceeds available for distribution to
unitholders and the value of the trust units may be reduced.
The trust is passive in nature and will have no
stockholder voting rights in ECA, managerial, contractual or
other ability to influence ECA, or control over the field
operations of, sale of natural gas from, or development of, the
Underlying Properties.
Trust unitholders have no voting rights with respect to ECA and
therefore will have no managerial, contractual or other ability
to influence ECAs activities or operations of the gas
properties. In addition, pursuant to the Administrative Services
Agreement and the Development Agreement, up to 10% of the PUD
Wells may be operated by third parties unrelated to ECA until
completion of ECAs drilling obligation, after which ECA
may transfer operations of any or all of the trust properties.
Such third party operators may not have the operational
expertise of ECA within the AMI. Gas properties are typically
managed pursuant to an operating agreement among the working
interest owners in the properties. The typical operating
agreement contains procedures whereby the owners of the working
interests in the property designate one of the interest owners
to be the operator of the property. Under these arrangements,
the operator is typically responsible for making all decisions
relating to drilling activities, sale of production, compliance
with regulatory requirements and other matters that affect the
property. Neither the trustee nor the trust unitholders has any
contractual ability to influence or control the field operations
of, sale of natural gas from, or future development of, the
Underlying Properties. The trust units are a passive investment
that entitle the trust unitholder to only receive cash
distributions from the royalty interests and hedging contracts
that have been established for the benefit of the trust.
ECA may sell all or a portion of the Underlying
Properties, subject to and burdened by the royalty interests,
after satisfying its drilling obligations to the trust; any such
purchaser could have a weaker financial position and/or be less
experienced in natural gas development and production than
ECA.
You will not be entitled to vote on any sale of the Underlying
Properties if the Underlying Properties are sold subject to and
burdened by the royalty interests and the trust will not receive
any proceeds from any such sale. The purchaser would be
responsible for all of ECAs obligations relating to the
royalty interests on the portion of the Underlying Properties
sold, and ECA would have no continuing obligation to the trust
for those properties. Additionally, ECA may enter into farmout
or joint venture arrangements with respect to the wells burdened
by the trusts royalty interest. Any purchaser, farmout
counterparty or joint venture partner could have a weaker
financial position
and/or be
less experienced in natural gas development and production than
ECA.
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The natural gas reserves estimated to be attributable to
the Underlying Properties of the trust are depleting assets and
production from those reserves will diminish over time.
Furthermore, the trust is precluded from acquiring other oil and
gas properties or royalty interests to replace the depleting
assets and production.
The proceeds payable to the trust from the royalty interests are
derived from the sale of the production of natural gas from the
Underlying Properties. The natural gas reserves attributable to
the Underlying Properties are depleting assets, which means that
the reserves of natural gas attributable to the Underlying
Properties will decline over time. As a result, the quantity of
natural gas produced from the Underlying Properties will decline
over time. Based on the estimated production volumes in the
reserve report, the gas production from proved producing
reserves attributable to the PDP Royalty Interest is projected
to decline at an average rate of approximately 8.5% per
year over the life of the trust. As a PUD Well is drilled and
placed on production, the production rate is expected to decline
approximately 37.3% during the first year of production,
approximately 14.7% during the next three to five years of
production and approximately 8.0% per year for the
remainder of the economically productive life of the well. These
production characteristics are generally consistent with other
development wells in the AMI. The anticipated rate of decline is
an estimate and actual decline rates may vary from those
estimated.
Future maintenance may affect the quantity of proved reserves
that can be economically produced from the Underlying Properties
to which the wells relate. The timing and size of these projects
will depend on, among other factors, the market prices of
natural gas. With the exception of ECAs commitment to
drill the PUD Wells, ECA has no contractual obligation to make
capital expenditures on the Underlying Properties in the future.
Furthermore, for properties on which ECA is not designated as
the operator, ECA has no control over the timing or amount of
those capital expenditures. ECA also has the right to
non-consent and not participate in the capital expenditures on
properties for which it is not the operator, in which case ECA
and the trust will not receive the production resulting from
such capital expenditures. If ECA or other operators of the
wells to which the Underlying Properties relate do not implement
maintenance projects when warranted, the future rate of
production decline of proved reserves may be higher than the
rate currently expected by ECA or estimated in the reserve
report.
The trust agreement will provide that the trusts business
activities will be limited to owning the royalty interests and
any activity reasonably related to such ownership, including
activities required or permitted by the terms of the conveyances
related to the royalty interests. As a result, the trust will
not be permitted to acquire other oil and gas properties or
royalty interests to replace the depleting assets and production
attributable to the trust.
The amount of cash available for distribution by the trust
will be reduced by the amount of
post-production
costs, applicable taxes associated with the trusts
interest, trust expenses, incentive distributions and
reimbursement obligations payable to ECA.
The royalty interests and the trust will bear certain costs and
expenses that will reduce the amount of cash received by or
available for distribution by the trust to the holders of the
trust units. These costs and expenses include those described
below.
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Substantially all of the production from the Producing Wells and
the PUD Wells will utilize ECAs Greene Country Gathering
System. The trust will pay the initial Post-Production Services
Fee to ECA for use of such system, which includes ECAs
costs to gather, compress, transport, process, treat, dehydrate
and market the gas. This fee is fixed
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until ECAs obligation to drill the PUD Wells is satisfied;
thereafter, ECA may increase this fee to the extent necessary to
recover certain capital expenditures on the Greene County
Gathering System, provided the resulting charge does not exceed
the prevailing charges in the area for similar services.
Additionally, the trust will be charged for the cost of fuel
used in the compression process or equivalent electricity
charges when electric compressors are used.
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There currently are no third party post-production costs;
however, any third party post-production costs incurred in the
future and associated with the trusts interests will
reduce cash received by or available for distribution, including
any amounts paid by ECA for transportation on downstream
interstate pipelines.
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Taxes allocated to or imposed on the trust will include
Pennsylvania franchise tax and any applicable property, ad
valorem, production, severance, excise and other similar taxes.
Currently, there are no taxes in Pennsylvania related to the
production or severance of oil and natural gas in Pennsylvania,
but there are currently proposals pending in both the
Pennsylvania Senate Finance and the House Energy and
Environmental Resources Committees to enact a severance tax, and
lawmakers may propose other taxes in the future. If adopted,
such taxes would be a post-production cost that is borne by the
trust.
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The trust will bear 100% of trust administrative expenses,
including fees paid to the trustee and the Delaware trustee and
an annual administrative services fee of $60,000 payable to ECA.
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The trust will also be responsible for paying other expenses
incurred as a result of being a publicly traded entity,
including costs associated with annual and quarterly reports to
unitholders, tax return and Schedule K-1 preparation and
distribution, independent auditor fees and registrar and
transfer agent fees.
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ECA will be entitled, during the subordination period, to
receive a quarterly incentive distribution from the trust in an
amount equal to 50% of the amount by which distributions paid to
all unitholders exceed the incentive thresholds described
herein. A more detailed description of these distributions is
set forth under the caption Description of the trust
agreement Fees and expenses Fees to
ECA.
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ECA has incurred costs of approximately $5 million in
establishing the floor price contracts to be transferred to the
trust. ECA will be entitled to reimbursement for these
expenditures only if and to the extent distributions to trust
unitholders would otherwise exceed the incentive threshold. This
reimbursement will be deducted, over time, from the 50% of cash
available for distribution in excess of the incentive thresholds
otherwise payable to the common and subordinated unitholders.
ECAs reimbursement right will terminate at the end of the
subordination period.
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The amount of costs and expenses that will be borne by the trust
may vary materially from
quarter-to-quarter.
The extent by which the costs and expenses described above are
higher or lower in any quarter will directly decrease or
increase the amount received by the trust and available for
distribution to the unitholders. For a further summary of
post-production costs and applicable taxes for the producing
lives of the Producing Wells and PUD Wells, see The
underlying properties. Historical post-production costs
and taxes, however, may not be indicative of future
post-production costs and taxes.
26
A decrease in the differential between the price realized
by ECA for natural gas produced from the Underlying Properties
and the NYMEX or other benchmark price of natural gas could
reduce the proceeds to the trust and therefore the cash
distributions by the trust and the value of trust units.
The prices received for ECAs natural gas production
usually exceed the relevant benchmark prices, such as NYMEX,
that are used for calculating hedge positions. The difference
between the price received and the benchmark price is called a
basis differential. The differential may vary significantly due
to market conditions, the quality and location of production and
other factors. ECA cannot accurately predict natural gas
differentials. Decreases in the differential between the
realized price of natural gas and the benchmark price for
natural gas could reduce the proceeds to the trust and therefore
the cash distributions by the trust and the value of the trust
units.
ECA has entered into natural gas floor price contracts for
the benefit of the trust and will enter into a back-to-back swap
agreement with the trust that cover only a portion of the
estimated natural gas production attributable to the
trusts royalty interests, and such hedging arrangements
will terminate after March 31, 2014. The trusts
receipt of any payments due based on these natural gas hedging
contracts depends upon the financial position of the hedge
contract counterparties. A default by any of the hedge contract
counterparties could reduce the amount of cash available for
distribution to the trust unitholders.
Fifty percent of the estimated natural gas production
attributable to the trusts royalty interests will be
hedged from April 1, 2010 through March 31, 2014. As a
result, the remaining 50% of estimated production through
March 31, 2014 and all production after such date will not
be hedged to protect against the price risks inherent in holding
interests in natural gas, a commodity that is frequently
characterized by significant price volatility. Furthermore,
while the use of hedging transactions limits the downside risk
of price declines, swaps may also limit the trusts ability
to realize cash flow from natural gas price increases on the
portion of the production attributable to the trusts
royalty interests that is hedged. The trust will not have any
ability to terminate the swaps before the expiration date.
The trusts counterparties under the natural gas floor
price contracts are Wells Fargo Foothill, Inc. and BP Energy
Company, and its counterparty under the back-to-back swap
agreement is ECA, whose counterparties are also Wells Fargo
Foothill, Inc. and BP Energy Company. In the event that any of
the counterparties to the natural gas hedging contracts default
on their obligations to make payments to the trust under the
hedge contracts, the cash distributions to the trust unitholders
would likely be materially reduced as the hedge payments are
intended to provide additional cash to the trust during periods
of lower natural gas prices. ECA will have no continuing
obligation with respect to the natural gas floor price
contracts. However, ECA will be the trusts counterparty
under the back-to-back swap agreement and will have continuing
obligations with respect to this agreement.
Natural gas wells are subject to operational hazards that
can cause substantial losses. ECA maintains insurance; however,
ECA may not be adequately insured for all such hazards.
There are a variety of operating risks inherent in natural gas
production and associated activities, such as fires, leaks,
explosions, mechanical problems, major equipment failures,
blow-outs, uncontrollable flow of natural gas, water or drilling
fluids, casing collapses, abnormally pressurized formations and
natural disasters. The occurrence of any of these or similar
accidents that temporarily or permanently halt the production
and sale of natural gas at any of the Underlying Properties will
reduce trust distributions by reducing the amount of proceeds
available for distribution.
Additionally, if any of such risks or similar accidents occur,
ECA could incur substantial losses as a result of injury or loss
of life, severe damage or destruction of property, natural
27
resources and equipment, regulatory investigation and penalties
and environmental damage and
clean-up
responsibility. If ECA experiences any of these problems, its
ability to conduct operations and perform its obligations to the
trust could be adversely affected. While ECA intends to obtain
and maintain insurance coverage it deems appropriate for these
risks with respect to the Underlying Properties, ECAs
operations may result in liabilities exceeding such insurance
coverage or liabilities not covered by insurance. If a well is
damaged, ECA would have no obligation to drill a replacement
well or make the trust whole for the loss.
The subordination of certain trust units held by ECA does
not assure that you will in fact receive any specified return on
your investment in the trust.
Although ECA will not be entitled to receive any distribution on
its subordinated units unless there is enough cash for all of
the common units to receive a distribution equal to the
subordination threshold for such quarter (which is equal to 80%
of the target distribution level for the corresponding quarter),
the subordinated units constitute only a 25% interest in the
trust, and this feature does not guarantee that common units
will receive a distribution equal to the subordination
threshold, or any distribution at all. Additionally, the
subordination period will terminate and the subordinated units
will convert into common units four quarters following
ECAs completion of its drilling obligation. Depending on
the prices at which ECA is able to sell volumes attributable to
the trust, the common units may receive a distribution that is
below the subordination threshold.
Estimates of future cash distributions to unitholders,
subordination thresholds and incentive thresholds are based on
assumptions that are inherently subjective and are subject to
significant business, economic, financial, legal, regulatory and
competitive risks and uncertainties that could cause actual cash
distributions to differ materially from those estimated.
The estimates of target distributions to unitholders,
subordination thresholds and incentive thresholds, as set forth
in Target distributions and subordination and incentive
thresholds, are based on ECAs calculations, and ECA
has not received an opinion or report on such calculations from
any independent accountants. Such calculations are based on
assumptions about drilling, production, natural gas prices,
hedging activities, capital expenditures, expenses, and other
matters that are inherently uncertain and are subject to
significant business, economic, financial, legal, regulatory and
competitive risks and uncertainties that could cause actual
results to differ materially from those estimated. In
particular, these estimates have assumed that natural gas
production is sold at prices consistent with settled NYMEX
pricing for April, May and June 2010 of $3.842, $4.271 and
$4.155 per MMBtu, respectively, and NYMEX forward pricing as of
June 4, 2010 for the thirty three month period ending
March 31, 2013 and increased thereafter by a 2.5% annual
escalator (as adjusted for a basis differential of
$0.15 per MMBtu escalated at 2.5% annually starting in the
second quarter of 2013), capped at $9.00 per MMBtu starting
in 2027; however, actual sales prices may be significantly
lower. Additionally, these estimates assume that the PUD Wells
will be drilled on ECAs current anticipated schedule and
the related Underlying Properties will achieve production
volumes set forth in the reserve report; however, the drilling
of the development wells may be delayed and actual production
volumes may be significantly lower.
Furthermore, the subordination thresholds for each quarter
during the subordination period do not represent distributions
you should expect to receive. To the extent actual cash
distributions differ materially from those set forth in the
estimates underlying target distributions, the actual
distributions you receive may be lower than the target
distribution and the subordination threshold for the applicable
quarter. A cash distribution to trust unitholders below the
target distribution amount or the subordination threshold may
materially adversely affect the market price of the trust units.
28
The trustee may, under certain circumstances, sell the
royalty interests and dissolve the trust. The trust will begin
to terminate following the end of the
20-year
period in which the trust owns the Term Royalties.
The trustee must sell the royalty interests if unitholders
approve the sale or vote to dissolve the trust. The trustee must
also sell the royalty interests if the gross proceeds to the
trust attributable to the Royalty Interests and hedge agreements
(after deducting any amounts owed to ECA pursuant to the natural
gas swap agreements) are less than $1.5 million for any
four consecutive quarters. Sale of all the royalty interests
will result in the dissolution of the trust. The net proceeds of
any such sale will be distributed to the trust unitholders. The
trust will begin to liquidate on the Termination Date. The trust
unitholders will not be entitled to receive any proceeds from
the sale of production from the Underlying Properties following
such date. The Term Royalties will automatically revert to ECA
at the Termination Date, while the Perpetual Royalties will be
sold and the proceeds will be distributed to the unitholders
(including ECA to the extent of any trust units it owns) at the
Termination Date or soon thereafter. ECA will have a right of
first refusal to purchase the Perpetual Royalties at the
Termination Date. A more detailed description of this right of
first refusal is set forth under the caption The
trust.
ECA and the Private Investors may sell trust units in the
public or private markets, and such sales could have an adverse
impact on the trading price of the common units.
After the closing of the offering, ECA will hold an aggregate of
3,296,683 common units and 4,401,250 subordinated
units. In addition, the Private Investors will hold
1,104,567 common units. All of the subordinated units will
automatically convert into common units at the end of the
subordination period, which is currently expected to occur on
April 1, 2014. ECA and the Private Investors have agreed
not to sell any trust units for a period of 180 days after
the date of this prospectus without the consent of Raymond
James & Associates, Inc. and Citigroup Global Markets
Inc., acting as representatives of the several underwriters. See
Underwriting. After such period, ECA and the Private
Investors may sell trust units in the public or private markets,
and any such sales could have an adverse impact on the price of
the common units or on any trading market that may develop. The
trust has granted registration rights to ECA and the Private
Investors which, if exercised, would facilitate sales of common
units by such holders.
There has been no public market for the common units and
no independent appraisal of the value of the royalty interests
has been performed.
The initial public offering price of the common units will be
determined by negotiation among ECA and the underwriters. Among
the factors to be considered in determining the initial public
offering price, in addition to prevailing market conditions,
will be current and historical natural gas prices, current and
prospective conditions in the supply and demand for natural gas,
reserve and production quantities estimated for the royalty
interests and the trusts cash distributions prospects.
None of ECA, the trust or the underwriters will obtain any
independent appraisal or other opinion of the value of the
royalty interests other than the reserve report prepared by
Ryder Scott.
Conflicts of interest could arise between ECA and the
trust unitholders.
As a working interest owner in the Underlying Properties, ECA
could have interests that conflict with the interests of the
trust and the trust unitholders. For example:
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Notwithstanding its drilling obligation to the trust, ECAs
interests may conflict with those of the trust and the trust
unitholders in situations involving the development,
maintenance, operation or abandonment of the Underlying
Properties. Additionally, ECA may abandon a well which is
uneconomic to it while such well is still generating revenue
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for the trust unitholders. Subsequent to fulfilling its drilling
obligation, ECA may make decisions with respect to expenditures
and decisions to allocate resources on projects in other areas
that adversely affect the Underlying Properties, including
reducing expenditures on these properties, which could cause gas
production to decline at a faster rate and thereby result in
lower cash distributions by the trust in the future. In making
such decisions, ECA is required under the applicable conveyance
to act as a reasonably prudent operator in the AMI under the
same or similar circumstances as it would act if it were acting
with respect to its own properties, disregarding the existence
of the royalty interests as burdens affecting such property.
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ECA may sell some or all of the Underlying Properties, subject
to its obligation not to sell any of the underlying PUD
properties prior to satisfying its obligation to drill the PUD
Wells. Such sale may not be in the best interests of the trust
unitholders. Any purchaser may lack ECAs experience in the
Marcellus Shale or its credit worthiness.
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ECA may, without the consent of the trust unitholders, require
the trust to release royalty interests with an aggregate value
to the trust of up to $5.0 million during any
12-month
period. These releases will be made only in connection with the
sale by ECA of the Underlying Properties and are conditioned
upon the trust receiving an amount equal to the fair value to
the trust of such royalty interests. See The underlying
properties Sale and abandonment of underlying
properties.
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After it has completed its drilling obligation, ECA may in its
discretion increase its Post-Production Services Fee for
post-production costs on its Greene County Gathering System to
the extent necessary to recover certain capital expenditures on
the Greene County Gathering System.
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ECA is permitted under the conveyance agreements creating the
royalty interests to enter into new processing and
transportation contracts without obtaining bids from or
otherwise negotiating with any independent third parties, and
ECA will deduct from the trusts proceeds any charges under
such contracts attributable to production from the trust
properties. Provisions in the conveyance agreements, however,
require that charges under future contracts with affiliates of
ECA relating to processing or transportation of natural gas must
be comparable to charges prevailing in the area for similar
services.
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ECA has registration rights and can sell its units without
considering the effects such sale may have on common unit prices
or on the trust itself. Additionally, ECA can vote its trust
units in its sole discretion.
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The trust is managed by a trustee who cannot be replaced
except at a special meeting of trust unitholders.
The business and affairs of the trust will be managed by the
trustee. Your voting rights as a trust unitholder are more
limited than those of stockholders of most public corporations.
For example, there is no requirement for annual meetings of
trust unitholders or for an annual or other periodic re-election
of the trustee. The trust agreement provides that the trustee
may only be removed and replaced by the holders of a majority of
the outstanding trust units, including trust units held by ECA,
at a special meeting of trust unitholders called by either the
trustee or the holders of not less than 10% of the outstanding
trust units. As a result, it will be difficult for public
unitholders to remove or replace the trustee without the
cooperation of ECA (so long as it holds a significant percentage
of total trust units) or other holders of a substantial
percentage of the outstanding trust units.
30
Trust unitholders have limited ability to enforce
provisions of the royalty interests, and ECAs liability to
the trust is limited.
The trust agreement permits the trustee and the trust to sue ECA
or any other future owner of the Underlying Properties to
enforce the terms of the conveyances creating the PDP and PUD
Royalty Interests. If the trustee does not take appropriate
action to enforce provisions of these conveyances, trust
unitholders recourse would be limited to bringing a
lawsuit against the trustee to compel the trustee to take
specified actions. The trust agreement expressly limits a trust
unitholders ability to directly sue ECA or any other third
party other than the trustee. As a result, trust unitholders
will not be able to sue ECA or any future owner of the
Underlying Properties to enforce these rights. Furthermore, the
royalty interest conveyances provide that, except as set forth
in the conveyances, ECA will not be liable to the trust for the
manner in which it performs its duties in operating the
Underlying Properties as long as it acts in good faith.
Courts outside of Delaware may not recognize the limited
liability of the trust unitholders provided under Delaware
law.
Under the Delaware Statutory Trust Act, trust unitholders
will be entitled to the same limitation of personal liability
extended to stockholders of corporations under the General
Corporation Law of the State of Delaware. No assurance can be
given, however, that the courts in jurisdictions outside of
Delaware will give effect to such limitation.
ECA is subject to complex federal, state, local and other
laws and regulations that could adversely affect the cost,
manner or feasibility of conducting its operations or expose ECA
to significant liabilities.
ECAs natural gas exploration, production and
transportation operations are subject to complex and stringent
laws and regulations. In order to conduct its operations in
compliance with these laws and regulations, ECA must obtain and
maintain numerous permits, drilling bonds, approvals and
certificates from various federal, state and local governmental
authorities and engage in extensive reporting. ECA may incur
substantial costs in order to maintain compliance with these
existing laws and regulations. Further, in light of the
explosion and fire on the drilling rig Deepwater Horizon in the
Gulf of Mexico, as well as recent incidents involving the
release of natural gas and fluids as a result of drilling
activities in the Marcellus Shale, there has been a variety of
regulatory initiatives at the federal and state level to
restrict oil and gas drilling operations in certain locations.
Any increased regulation or suspension of oil and gas
exploration and production, or revision or reinterpretation of
existing laws and regulations, that arises out of these
incidents or otherwise could result in delays and higher
operating costs. Such costs or significant delays could have a
material adverse effect on ECAs business, financial
condition and results of operations. ECA must also comply with
laws and regulations prohibiting fraud and market manipulations
in energy markets. To the extent ECA is a shipper on interstate
pipelines, it must comply with the tariffs of such pipelines and
with federal policies related to the use of interstate capacity.
Laws and regulations governing natural gas exploration and
production may also affect production levels. ECA is required to
comply with federal and state laws and regulations governing
conservation matters, including provisions related to the
unitization or pooling of the natural gas properties; the
establishment of maximum rates of production from natural gas
wells; the spacing of wells; the plugging and abandonment of
wells; and removal of related production equipment. These and
other laws and regulations can limit the amount of natural gas
ECA can produce from its wells, limit the number of wells it can
drill, or limit the locations at which it can conduct drilling
operations, which in turn could negatively impact trust
distributions,
31
estimated and actual future net revenues to the trust and
estimates of reserves attributable to the trusts interests.
New laws or regulations, or changes to existing laws or
regulations may unfavorably impact ECA, could result in
increased operating costs and have a material adverse effect on
ECAs financial condition and results of operations. For
example, Congress is currently considering legislation that, if
adopted in its proposed form, would subject companies involved
in natural gas and oil exploration and production activities to,
among other items, additional regulation of and restrictions on
hydraulic fracturing of wells, the elimination of most
U.S. federal tax incentives and deductions available to
natural gas exploration and production activities, and the
prohibition or additional regulation of private energy commodity
derivative and hedging activities.
Additionally, state and federal regulatory authorities may
expand or alter applicable pipeline safety laws and regulations,
compliance with which may require increased capital costs on the
part of ECA and third party downstream natural gas transporters.
These and other potential regulations could increase ECAs
operating costs, reduce ECAs liquidity, delay ECAs
operations, increase direct and third party post production
costs associated with the Trusts interests or otherwise
alter the way ECA conducts its business, which could have a
material adverse effect on ECAs financial condition,
results of operations and cash flows and which could reduce cash
received by or available for distribution, including any amounts
paid by ECA for transportation on downstream interstate
pipelines.
The ability of ECA to satisfy its obligations to the trust
depends on the financial position of ECA, and in the event of a
default by ECA in its obligation to drill the PUD Wells, or in
the event of ECAs bankruptcy, it may be expensive and
time-consuming for the trust to exercise its remedies.
ECA is a privately held, independent energy company engaged in
the exploration, development, production, gathering and
aggregation and sale of natural gas and oil, primarily in the
Appalachian Basin, Gulf Coast and Rocky Mountain regions in the
United States and in New Zealand. Pursuant to the terms of the
Development Agreement, ECA will be obligated to drill the PUD
Wells at its own expense. ECA is also the operator of all of the
Producing Wells and will agree to operate substantially all of
the PUD Wells until completion of its drilling obligation. The
conveyances also provide that ECA will be obligated to market,
or cause to be marketed, the natural gas production related to
the Underlying Properties. Additionally, ECA will be the
counterparty to the trusts swap agreement and will have
continuing obligations with respect to this agreement. Due to
the trusts reliance on ECA to fulfill these numerous
obligations, the value of the trusts royalty interest and
its ultimate cash available for distribution will be highly
dependent on ECAs performance. ECA will not be a reporting
company following this offering and will not file periodic
reports with the SEC. Therefore, as a trust unitholder, you will
not have access to financial information of ECA.
The ability of ECA to perform these obligations will depend on
ECAs future financial condition and economic performance
and access to capital, which in turn will depend upon the supply
and demand for natural gas and oil, prevailing economic
conditions and financial, business and other factors, many of
which are beyond the control of ECA. See Information about
Energy Corporation of America found on
page ECA-1
for additional information relating to ECA, including
information relating to the business of ECA, historical
financial statements of ECA and other financial information
relating to ECA.
In the event that ECA defaults on its obligation to drill the
PUD Wells, the trusts remedy would be to foreclose on the
trusts Drilling Support Lien on all of ECAs
remaining interests in the AMI to recover the security interest
in the amount of $91 million, which amount will be
32
reduced proportionately as each PUD Well is drilled. The process
of foreclosing on such collateral may be expensive and
time-consuming and delay the drilling and completion of the PUD
Wells; such delays and expenses would reduce trust distributions
by reducing the amount of proceeds available for distribution.
The amount of the security interest recovered is required to be
applied to completion of the drilling obligations of ECA, will
not result in any distribution to the trust unitholders and may
be insufficient to drill the number of wells needed for the
trust to realize the full value of the PUD Royalty Interest.
Furthermore, the trust would have to seek a new party to perform
the drilling and operations of the wells. The trust may not be
able to find a replacement driller or operator, and it may not
be able to enter into a new agreement with such replacement
party on favorable terms within a reasonable period of time.
Due to uncertainty under the laws of Pennsylvania, there is a
risk that the royalty interests conveyed by ECA to the trust
would not be treated as real property interests, or interests in
hydrocarbons in place or to be produced. As a result, the
royalty interests might be treated as unsecured claims of the
trust against ECA in the event of ECAs bankruptcy. The
Royalty Interest Lien is intended to provide security to the
trust should the royalty interests be subject to such a
challenge. If the PDP Royalty Interest or the PUD Royalty
Interest were determined not to be a real property interest
owned by the trust, the trusts remedy would be to
foreclose on the trusts Royalty Interest Lien to cause the
trust to receive a volume of natural gas production from the
trust properties calculated in accordance with the provisions of
the conveyances of the royalty interests to the trust.
Foreclosure on the Royalty Interest Lien is exercisable only
following a bankruptcy filing of ECA or its successor and based
on an uncured payment default occurring under the conveyances of
the royalty interests to the trust existing at the time of, or
occurring after, such bankruptcy filing. Similar to the Drilling
Support Lien, the process of foreclosing to enforce the Royalty
Interest Lien may be expensive and time-consuming; and the
resulting delays and expenses would reduce trust distributions
by reducing the amount of proceeds available for distribution.
The proceeds of the royalty interests may be commingled, for a
period of time, with proceeds of ECAs retained interest.
It is possible that the trust may not have adequate facts to
trace its entitlement to funds in the commingled pool of funds
and that other persons may, in asserting claims against
ECAs retained interest, be able to assert claims to the
proceeds that should be delivered to the trust. In addition,
during a bankruptcy of ECA, it is possible that payments of the
royalties may be delayed or deferred. It is also possible that
the obligation to pay royalties will be disaffirmed or
cancelled. In either situation, the trust may need to look to
the Royalty Interest Lien to replace its rights under the
royalty interests. During the pendency of ECAs bankruptcy
proceedings, the trusts ability to foreclose on the
Drilling Support Lien or the Royalty Interest Lien, and the
ability to collect cash payments from customers being held in
ECAs accounts that are attributable to production from the
trust properties, may be stayed by the bankruptcy court. Delay
in realizing on the collateral for the Drilling Support Lien and
the Royalty Interest Lien is possible, and it cannot be
guaranteed that a bankruptcy court would permit such
foreclosure. It is possible that the bankruptcy would also delay
the execution of a new agreement with another driller or
operator. If the trust enters into a new agreement with a
drilling or operating partner, the new partner might not achieve
the same levels of production or sell natural gas at the same
prices as ECA was able to achieve.
ECAs performance of its drilling obligations to the
trust and the financial results of the trust may not be as
successful as the drilling and financial results of Eastern
American Natural Gas Trust or ECAs other royalty interest
ventures.
As disclosed in this prospectus, ECA previously sponsored the
formation of Eastern American Natural Gas Trust, and ECA has
previously sold term royalty interests in a separate transaction
to private investors. The historical results of operations and
performance of the
33
Eastern American Natural Gas Trust should not be relied on as an
indicator of how this trust will perform.
The operations of ECA are subject to environmental laws
and regulations that may result in significant costs and
liabilities.
The natural gas exploration and production operations of ECA in
the Marcellus Shale are subject to stringent and comprehensive
federal, state and local laws and regulations governing the
discharge of materials into the environment or otherwise
relating to environmental protection. These laws and regulations
may impose numerous obligations that are applicable to
ECAs operations including the acquisition of a permit
before conducting drilling; water withdrawal or waste disposal
activities; the restriction of types, quantities and
concentration of materials that can be released into the
environment; the limitation or prohibition of drilling
activities on certain lands lying within wilderness, wetlands
and other protected areas; and the imposition of substantial
liabilities for pollution resulting from operations. Numerous
governmental authorities, such as the U.S. Environmental
Protection Agency (EPA) and analogous state
agencies, have the power to enforce compliance with these laws
and regulations and the permits issued under them, often
requiring difficult and costly actions. Failure to comply with
these laws and regulations may result in the assessment of
administrative, civil or criminal penalties; the imposition of
investigatory or remedial obligations; and the issuance of
injunctions limiting or preventing some or all of ECAs
operations.
There is inherent risk of incurring significant environmental
costs and liabilities in the performance of ECAs
operations due to its handling of petroleum hydrocarbons and
wastes, because of air emissions and wastewater discharges
related to its operations, and as a result of historical
industry operations and waste disposal practices. Under certain
environmental laws and regulations, ECA could be subject to
joint and several strict liability for the removal or
remediation of previously released materials or property
contamination regardless of whether ECA was responsible for the
release or contamination or if the operations were not in
compliance with all applicable laws at the time those actions
were taken. Private parties, including the owners of properties
upon which ECAs wells are drilled and facilities where
ECAs petroleum hydrocarbons or wastes are taken for
reclamation or disposal may also have the right to pursue legal
actions to enforce compliance, as well as to seek damages for
non-compliance, with environmental laws and regulations or for
personal injury or property damage. In addition, the risk of
accidental spills or releases could expose ECA to significant
liabilities that could have a material adverse effect on its
financial condition or results of operations. Changes in
environmental laws and regulations occur frequently, and any
changes that result in more stringent or costly waste handling,
storage, transport, disposal or cleanup requirements could
require ECA to make significant expenditures to attain and
maintain compliance and may otherwise have a material adverse
effect on its results of operations, competitive position or
financial condition. ECA may not be able to recover some or any
of these costs from insurance. As a result of the increased cost
of compliance, ECA may decide to discontinue drilling.
Additionally, permitting delays may inhibit ECAs ability
to drill the PUD Wells on schedule.
Climate change laws and regulations restricting emissions
of greenhouse gases could result in increased
operating costs and reduced demand for the natural gas that ECA
produces while the physical effects of climate change could
disrupt ECAs production and cause ECA to incur significant
costs in preparing for or responding to those effects.
On December 15, 2009, the EPA published its findings that
emissions of carbon dioxide, methane and other greenhouse gases
(GHGs) present a danger to public health and the
environment. These findings allow the agency to adopt and
implement regulations that would restrict emissions of GHGs
under existing provisions of the federal Clean Air Act.
Accordingly,
34
the EPA has proposed regulations that would require a reduction
in emissions of GHGs from motor vehicles and adopted regulations
that could trigger permit review for GHG emissions from certain
stationary sources. In addition, on October 30, 2009, the
EPA published a final rule requiring the reporting of GHG
emissions from specified large GHG emission sources in the
United States, beginning in 2011 for emissions occurring in
2010. Only very recently, on March 23, 2010, the EPA
announced a proposed rulemaking that would expand its final rule
on reporting of GHG emissions to include owners and operators of
onshore oil and natural gas production. If the proposed rule is
finalized in its current form, monitoring of those newly covered
sources would commence on January 1, 2011. Also, on
June 26, 2009, the U.S. House of Representatives
passed the American Clean Energy and Security Act of
2009 (ACESA), which would establish an
economy-wide
cap-and-trade
program to reduce U.S. emissions of GHGs. Under this
legislation, the EPA would issue a capped and steadily declining
number of tradable emissions allowances authorizing emissions of
GHGs into the atmosphere. These reductions would be expected to
cause the cost of allowances to escalate significantly over
time. The net effect of ACESA would be to impose increasing
costs on the combustion of carbon-based fuels such as oil,
refined petroleum products and natural gas. The U.S. Senate
has begun work on its own legislation for restricting domestic
GHG emissions and the Obama Administration has indicated its
support for legislation to reduce GHG emissions through an
emission allowance system. At the state level, more than
one-third of the states, either individually or through
multi-state regional initiatives, already have begun
implementing legal measures to reduce emissions of GHGs. The
adoption and implementation of any regulations imposing
reporting obligations on, or limiting emissions of GHGs from,
ECAs equipment and operations could require ECA to incur
costs to reduce emissions of GHGs associated with its operations
or could adversely affect demand for the natural gas that it
produces. Finally, it should be noted that some scientists have
concluded that increasing concentrations of greenhouse gases in
the Earths atmosphere may produce climate changes that
have significant physical effects, such as increased frequency
and severity of storms, droughts, and floods and other climatic
events; if any such effects were to occur, they could have an
adverse effect on ECAs assets and operations.
Federal and state legislative and regulatory initiatives
relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays as well as
adversely affect ECAs services.
The U.S. Congress is considering legislation that would
amend the federal Safe Drinking Water Act to subject hydraulic
fracturing operations to regulation under the Act. Hydraulic
fracturing is an important and commonly used process for the
completion of natural gas wells, and to a lesser extent, oil
wells, in formations with low permeabilities, such as shale
formations, and involves the pressurized injection of water,
sand and chemicals into rock formations to stimulate natural gas
production. Sponsors of the legislation have asserted that
chemicals used in the fracturing process could adversely affect
drinking water supplies. If enacted, the legislation could
result in additional regulatory burdens involving permitting,
construction standards for wells, monitoring, recordkeeping and
closure of wells. The legislation also proposes requiring the
disclosure of chemical constituents used in the fracturing
process to state or federal regulatory authorities who would
then make such information publicly available. The availability
of this information could make it easier for third parties
opposing the hydraulic fracturing process to initiate legal
proceedings based on allegations that specific chemicals used in
the fracturing process could adversely affect groundwater. In
addition, various state and local governments are considering
increased regulatory oversight of hydraulic fracturing through
additional permit requirements, operational restrictions and
temporary or permanent bans on hydraulic fracturing in certain
environmentally sensitive areas such as watersheds. For
instance, the New York Department of Environmental
Conservation announced in April 2010 that the watersheds relied
upon by New York City and Syracuse as sources of drinking
water would be excluded from the pending generic environmental
review process, thereby requiring natural gas operators seeking
to
35
drill in either of the watersheds, which are located in the
Marcellus Shale region, to pursue a
case-by-case
environmental review to establish whether appropriate measures
to mitigate potential impacts can be developed. Moreover, the
Pennsylvania Department of Environmental Protection has adopted
a new permitting policy concerning surface water discharges from
wastewater treatment facilities handling flowback fluids and
produced waters from oil and gas well sites that could result in
increased requirements for treatment of these fluids and
limitations on their discharge to receiving waters. The adoption
of the pending congressional legislation or any other federal or
state laws or regulations imposing reporting obligations on, or
otherwise limiting, the hydraulic fracturing process could make
it more difficult for ECA to complete natural gas wells in the
Marcellus Shale as well as increase its costs of compliance and
doing business. Moreover, on March 18, 2010, the EPA
announced that it has allocated $1.9 million in 2010 and
has requested funding in fiscal year 2011 for conducting a
comprehensive research study on the potential adverse impacts
that hydraulic fracturing may have on water quality and public
health. The results of such a study, once completed, could
further spur action towards federal legislation and regulation
of hydraulic fracturing activities. If ECA is unable to remove
and dispose of water at a reasonable cost and within applicable
environmental rules, ECAs ability to produce gas
commercially and in commercial quantities from the Underlying
Properties could be impaired.
Tax Risks
Related to the Trusts Common Units
The trusts tax treatment depends on its status as a
partnership for federal income tax purposes. If the IRS were to
treat the trust as a corporation for federal income tax
purposes, then its cash available for distribution to you would
be substantially reduced.
The anticipated after-tax economic benefit of an investment in
the trust units depends largely on the trust being treated as a
partnership for federal income tax purposes. The trust has not
requested, and does not plan to request, a ruling from the
Internal Revenue Service, or IRS, on this or any other tax
matter affecting it.
It is possible in certain circumstances for a publicly traded
trust otherwise treated as a partnership, such as the trust, to
be treated as a corporation for federal income tax purposes.
Although the trust does not believe based upon its current
activities that it is so treated, a change in current law could
cause it to be treated as a corporation for federal income tax
purposes or otherwise subject it to taxation as an entity.
If the trust was treated as a corporation for federal income tax
purposes, it would pay federal income tax on its taxable income
at the corporate tax rate, which is currently a maximum of 35%,
and would likely be required to pay state income tax.
Distributions to you would generally be taxed again as corporate
distributions, and no income, gains, losses, deductions or
credits would flow through to you. Because a tax would be
imposed upon the trust as a corporation, its cash available for
distribution to you would be substantially reduced. Therefore,
treatment of the trust as a corporation would result in a
material reduction in the anticipated cash flow and after-tax
return to the trust unitholders, likely causing a substantial
reduction in the value of the trust units.
The trust agreement provides that if a law is enacted or
existing law is modified or interpreted in a manner that
subjects the trust to taxation as a corporation or otherwise
subjects it to entity-level taxation for federal income tax
purposes, the minimum quarterly distribution amount and the
target distribution amounts may be adjusted to reflect the
impact of that law on the trust.
36
If the trust were subjected to a material amount of
additional entity-level taxation by Pennsylvania or any other
states, the trusts cash available for distribution to you
would be reduced.
The trust will be required to pay Pennsylvania franchise tax on
its capital stock value, as determined pursuant to the statute
and apportioned to Pennsylvania. The current tax rate of 0.289%
is currently scheduled to be reduced to 0.189% in 2012 and
0.089% in 2013 and to be completely phased out in 2014. This
schedule may be altered and the taxes left in place subject to
the General Assembly in its annual budget process. Changes in
current state law may subject the trust to additional
entity-level taxation by Pennsylvania or other states. Because
of widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise and other forms of taxation. Imposition of any
additional taxes on the trust may substantially reduce the cash
available for distribution to you and, therefore, negatively
impact the value of an investment in the trust units. The trust
agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects the trust to
additional amounts of entity-level taxation for state or local
income tax purposes, the target distribution amounts may be
adjusted to reflect the impact of that law on the trust.
The tax treatment of an investment in trust units could be
affected by recent and potential legislative, judicial or
administrative changes and differing interpretations, possibly
on a retroactive basis.
The recently enacted Health Care and Education Reconciliation
Act of 2010 includes a provision that, in taxable years
beginning after December 31, 2012, subjects an individual
having adjusted gross income in excess of $200,000 (or $250,000
for married taxpayers filing joint returns) to an additional
medicare tax equal generally to 3.8% of the lesser
of such excess or the individuals net investment income,
which appears to include interest income and royalty income
derived from investments such as the trust units as well as any
net gain from the disposition of trust units. In addition,
absent new legislation extending the current rates, beginning
January 1, 2011, the highest marginal U.S. federal
income tax rate applicable to ordinary income and long-term
capital gains of individuals will increase to 39.6% and 20%,
respectively. Moreover, these rates are subject to change by new
legislation at any time.
Current law may change so as to cause the trust to be treated as
a corporation for federal income tax purposes or otherwise
subject the trust to entity-level taxation. Specifically, the
present federal income tax treatment of publicly traded
partnerships, including the trust, or an investment in the trust
units may be modified by administrative, legislative or judicial
interpretation at any time. For example, at the federal level,
legislation has been proposed that would eliminate partnership
tax treatment for certain publicly traded partnerships. Although
such legislation would not apply to the trust as currently
proposed, it could be amended prior to enactment in a manner
that does apply to the trust.
The trust will adopt positions that may not conform to all
aspects of existing Treasury Regulations. If the IRS contests
the federal income tax positions the trust takes, the value of
the trust units may be adversely affected, the cost of any IRS
contest will reduce the trusts cash available for
distribution to you and income, gain, loss and deduction may be
reallocated among trust unitholders.
The trust will treat each purchaser of common units as having
the same economic attributes without regard to the actual common
units purchased. Moreover, the trust will generally prorate its
items of income, gain, loss and deduction between transferors
and transferees of the trust units each month based upon the
ownership of the trust units on the first day of each month,
instead
37
of on the basis of the date a particular trust unit is
transferred. Although simplifying conventions are contemplated
by the Internal Revenue Code, and most publicly traded
partnerships use similar simplifying conventions, the use of
these methods may not be permitted under existing Treasury
Regulations. If the IRS contests the federal income tax
positions the trust takes, the market for the trust units may be
adversely impacted, the cost of any IRS contest will reduce the
trusts cash available for distribution to you and items of
income, gain, loss and deduction may be reallocated among trust
unitholders.
If the IRS contests the federal income tax positions the
trust takes, the market for the trust units may be adversely
impacted and the cost of any IRS contest will reduce the
trusts cash available for distribution to you.
The trust has not requested a ruling from the IRS with respect
to its treatment as a partnership for federal income tax
purposes or any other matter affecting the trust. The IRS may
adopt positions that differ from the conclusions of the
trusts counsel expressed in this prospectus or from the
positions the trust takes. It may be necessary to resort to
administrative or court proceedings to attempt to sustain some
or all of the conclusions of the trusts counsel or the
positions the trust takes. A court may not agree with some or
all of the conclusions of the trusts counsel or positions
the trust takes. Any contest with the IRS may materially and
adversely impact the market for the trust units and the price at
which they trade. In addition, the trusts costs of any
contest with the IRS will be borne indirectly by the trust
unitholders because the costs will reduce the trusts cash
available for distribution.
You will be required to pay taxes on your share of the
trusts income even if you do not receive any cash
distributions from the trust.
Because the trust unitholders will be treated as partners to
whom the trust will allocate taxable income which could be
different in amount than the cash the trust distributes, you
will be required to pay any federal income taxes and, in some
cases, state and local income taxes on your share of the
trusts taxable income even if you receive no cash
distributions from the trust. You may not receive cash
distributions from the trust equal to your share of the
trusts taxable income or even equal to the actual tax
liability that results from that income.
Tax gain or loss on the disposition of the trust units
could be more or less than expected.
If you sell your trust units, you will recognize a gain or loss
equal to the difference between the amount realized and your tax
basis in those trust units. Because distributions in excess of
your allocable share of the trusts net taxable income
decrease your tax basis in your trust units, the amount, if any,
of such prior excess distributions with respect to the trust
units you sell will, in effect, become taxable income to you if
you sell such trust units at a price greater than your tax basis
in those trust units, even if the price you receive is less than
your original cost. Furthermore, a substantial portion of the
amount realized, whether or not representing gain, may be taxed
as ordinary income due to potential recapture items, including
depletion recapture. Please read Federal Income Tax
Considerations Disposition of
Trust Units Recognition of Gain or Loss
for a further discussion of the foregoing.
Tax-exempt entities and
non-U.S.
persons face unique tax issues from owning the trust units that
may result in adverse tax consequences to them.
Investment in trust units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), and
non-U.S. persons
raises issues unique to them. For example, distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
may be required to file U.S. federal income tax returns and
pay tax on
38
their share of the trusts taxable income. If you are a tax
exempt entity or a
non-U.S. person,
you should consult a tax advisor before investing in the trust
units.
The trust will treat each purchaser of trust units as
having the same economic attributes without regard to the actual
trust units purchased. The IRS may challenge this treatment,
which could adversely affect the value of the trust
units.
Due to a number of factors, including the trusts inability
to match transferors and transferees of trust units, the trust
will adopt positions that may not conform to all aspects of
existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax
benefits available to you. It also could affect the timing of
these tax benefits or the amount of gain from your sale of trust
units and could have a negative impact on the value of the trust
units or result in audit adjustments to your tax returns. Please
read Federal income tax considerations Tax
consequences of trust unit ownership
Section 754 election.
The trust will prorate its items of income, gain, loss and
deduction between transferors and transferees of the trust units
each month based upon the ownership of the trust units on the
first day of each month, instead of on the basis of the date a
particular trust unit is transferred. The IRS may challenge this
treatment, which could change the allocation of items of income,
gain, loss and deduction among the trust unitholders.
The trust will generally prorate its items of income, gain, loss
and deduction between transferors and transferees of the trust
units each month based upon the ownership of the trust units on
the first day of each month, instead of on the basis of the date
a particular trust unit is transferred. The use of this
proration method may not be permitted under existing Treasury
Regulations, and, accordingly, the trusts counsel is
unable to opine as to the validity of this method. Recently,
however, the U.S. Treasury Department issued proposed
Treasury Regulations that provide a safe harbor pursuant to
which publicly traded partnerships may use a similar monthly
simplifying convention to allocate tax items among transferor
and transferee unitholders. Nonetheless, the proposed
regulations do not specifically authorize the use of the
proration method the trust will adopt. If the IRS were to
challenge the trusts proration method, the trust may be
required to change its allocation of items of income, gain, loss
and deduction among the trust unitholders. Please read
Federal Income Tax Considerations Disposition
of trust units Allocations between transferors
and transferees.
A trust unitholder whose trust units are loaned to a
short seller to cover a short sale of trust units
may be considered as having disposed of those trust units. If
so, he would no longer be treated for tax purposes as a partner
with respect to those trust units during the period of the loan
and may recognize gain or loss from the disposition.
Because a trust unitholder whose trust units are loaned to a
short seller to cover a short sale of trust units
may be considered as having disposed of the loaned trust units,
he may no longer be treated for tax purposes as a partner with
respect to those trust units during the period of the loan to
the short seller and the unitholder may recognize gain or loss
from such disposition. Moreover, during the period of the loan
to the short seller, any of the trusts income, gain, loss
or deduction with respect to those trust units may not be
reportable by the unitholder and any cash distributions received
by the unitholder as to those trust units could be fully taxable
as ordinary income. The trusts counsel has not rendered an
opinion regarding the treatment of a unitholder where trust
units are loaned to a short seller to cover a short sale of
trust units; therefore, trust unitholders desiring to assure
their status as partners and avoid the risk of gain recognition
from a loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
loaning their trust units.
39
The trust will adopt certain valuation methodologies that
may affect the income, gain, loss and deduction allocable to the
trust unitholders. The IRS may challenge this treatment, which
could adversely affect the value of the trust units.
The federal income tax consequences of the ownership and
disposition of trust units will depend in part on the
trusts estimates of the relative fair market values, and
the initial tax bases of the trusts assets. Although the
trust may from time to time consult with professional appraisers
regarding valuation matters, the trust will make many of the
relative fair market value estimates itself. These estimates and
determinations of basis are subject to challenge and will not be
binding on the IRS or the courts. If the estimates of fair
market value or basis are later found to be incorrect, the
character and amount of items of income, gain, loss or
deductions previously reported by trust unitholders might
change, and trust unitholders might be required to adjust their
tax liability for prior years and incur interest and penalties
with respect to those adjustments.
The sale or exchange of 50% or more of the trusts
capital and profits interests during any twelve-month period
will result in the termination of the trusts partnership
status for federal income tax purposes.
The trust will be considered to have technically terminated for
federal income tax purposes if there is a sale or exchange of
50% or more of the total interests in its capital and profits
within a twelve-month period. For purposes of determining
whether the 50% threshold has been met, multiple sales of the
same trust unit within any 12 month period will be counted
only once. The trusts termination would, among other
things, result in the closing of its taxable year for all trust
unitholders, which would result in the trust filing two tax
returns (and the trust unitholders could receive two Schedules
K-1) for one calendar year. The IRS has recently announced a
relief procedure whereby if a publicly traded partnership that
has technically terminated requests and the IRS grants special
relief, among other things, the partnership will be required to
provide only a single
Schedule K-1
to unitholders for the tax year in which the termination occurs.
In the case of a unitholder reporting on a taxable year other
than a calendar year ending December 31, the closing of the
trusts taxable year may also result in more than twelve
months of the trusts taxable income being includable in
his taxable income for the year of termination. A technical
termination would not affect the trusts classification as
a partnership for federal income tax purposes, but instead, the
trust would be treated as a new partnership for tax purposes. If
treated as a new partnership, the trust must make new tax
elections and could be subject to penalties if the trust is
unable to determine that a technical termination occurred.
Certain federal income tax preferences currently available
with respect to natural gas production may be eliminated as a
result of future legislation.
Among the changes contained in President Obamas Budget
Proposal for Fiscal Year 2011 (the 2011 Budget) is
the elimination of certain key U.S. federal income tax
preferences relating to natural gas exploration and production.
The 2011 Budget proposes to eliminate certain tax preferences
applicable to taxpayers engaged in the exploration or production
of natural resources effective in 2011. Specifically, the 2011
Budget proposes to repeal the deduction for percentage depletion
with respect to oil and natural gas wells, including interests
such as the Perpetual Royalty Interests, in which case only cost
depletion would be available.
40
FORWARD-LOOKING
STATEMENTS
This prospectus contains forward-looking statements
about ECA and the trust that are subject to risks and
uncertainties. All statements other than statements of
historical fact included in this document, including, without
limitation, statements under Summary and Risk
factors regarding the financial position, business
strategy, production and reserve growth, and other plans and
objectives for the future operations of ECA and the activities
of the trust are forward-looking statements.
Such statements may be influenced by factors that could cause
actual outcomes and results to differ materially from those
projected. Forward-looking statements are subject to risks and
uncertainties and include statements made in this prospectus
under Target distributions and subordination and incentive
thresholds, statements pertaining to future development
activities and costs, and other statements in this prospectus
that are prospective and constitute forward-looking statements.
When used in this document, the words believes,
expects, anticipates,
intends or similar expressions are intended to
identify such forward-looking statements. The following
important factors, in addition to those discussed elsewhere in
this document, could affect the future results of the energy
industry in general, and ECA and the trust in particular, and
could cause those results to differ materially from those
expressed in such forward-looking statements:
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risks incident to the drilling and operation of natural gas
wells;
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future production and development costs;
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the effect of existing and future laws and regulatory actions;
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|
the effect of changes in commodity prices, the ability of the
trusts hedge counterparties, including ECA, to meet their
contractual obligations and conditions in the capital markets;
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|
competition from others in the energy industry; and
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|
uncertainty of estimates of natural gas reserves and production.
|
This prospectus describes other important factors that could
cause actual results to differ materially from expectations of
ECA and the trust, including under the heading Risk
factors. All written and oral forward-looking statements
attributable to ECA or the trust or persons acting on behalf of
ECA or the trust are expressly qualified in their entirety by
such factors.
41
USE OF
PROCEEDS
The trust is offering the common units to be sold in this
offering. Assuming no exercise of the underwriters
over-allotment option and an initial public offering price of
$20.00 per common unit, the estimated net proceeds of this
offering will be approximately $161 million, after
deducting underwriting discounts and commissions and offering
expenses. The trust will use approximately $161 million of
the net proceeds to pay ECAs wholly-owned subsidiary for
the conveyance of the Term Royalties and any remaining net
proceeds will be distributed to ECA. In turn, ECAs
wholly-owned subsidiary will use all of the proceeds received
from the trust to repay all or a portion of an approximately
$161 million demand note payable to ECA issued as
consideration for the transfer of the Term Royalties thereto.
The note held by ECA is payable by ECAs subsidiary and is
nonrecourse to the trust. As a result, the trust has no
obligation to ECA on the note held by ECA.
ECA intends to use the proceeds received from the repayment of
the demand note by ECAs subsidiary and from any exercise
of the underwriters over-allotment option (a) to
purchase 209,312 common units from the Private Investors at
the initial public offering price, (b) to repay borrowings
under its revolving and term credit facility and (c) for
general corporate purposes, including the funding of the
drilling obligation. As of June 18, 2010, the outstanding
balance on the revolving credit facility, which matures on
July 10, 2012, was approximately $130.3 million, and
the weighted average interest rate of the revolving credit
facility was 2.47%. Borrowings in the prior year were incurred
to fund working capital and capital expenditures. Please read
Certain transactions.
The table below sets forth ECAs intended use of proceeds
with the corresponding dollar amounts planned for such use
assuming no exercise of the underwriters over-allotment
option and an initial public offering price of $20.00 per
common unit.
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Intended Amount
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|
Intended Use
|
|
Dedicated to Such Use
|
|
|
Purchase of common units from the Private Investors
|
|
$
|
4.2 million
|
|
Repay borrowings under revolving credit facility
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|
$
|
130.0 million
|
|
Repay borrowings under single advance term loan
|
|
$
|
24.0 million
|
|
General corporate purposes
|
|
$
|
2.8 million
|
|
An increase or decrease in the initial public offering price of
$1.00 per common unit would cause the net proceeds from the
offering, after deducting underwriting discounts and
commissions, to increase or decrease by $8 million. If the
proceeds increase or decrease due to a higher or lower initial
public offering price, the trust will allocate said increase or
decrease among the conveyances of ECA based on their relative
fair market value. An increase or decrease in proceeds will
result in a corresponding increase or decrease in amounts used
by ECA for general corporate purposes including the funding of
its drilling obligation.
The trust will use the net proceeds from any exercise of the
underwriters over-allotment option to repurchase an equal
number of common units from ECA at the initial public offering
price, after deducting underwriting discounts and commissions.
42
NATURAL
GAS FUNDAMENTALS IN THE MARCELLUS SHALE
DEMAND
FOR NATURAL GAS
Natural gas continues to be a critical component of energy
consumption in the United States, accounting for approximately
24.4% of all energy used in 2009, representing approximately
22.8 Tcf of natural gas, according to the U.S. Energy
Information Administration (EIA). According to the
EIA, during the period from 2001 through 2009, natural gas
consumption increased by 2.7% overall from an average of
approximately 60.9 Bcf per day in 2001 to an average of
approximately 62.6 Bcf per day in 2009.
The EIA estimates that real gross domestic product will grow by
2.4% per year from 2008 to 2035 (Annual Energy Outlook 2010).
Over the same period, the EIA estimates that total domestic
energy consumption will increase by over 19%. Consumption of
natural gas is projected to continue to increase through this
period due to:
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domestic economic and population growth;
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|
added capacity of natural gas-fired, as opposed to coal-fired,
electricity generation;
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|
|
growth in the application of natural gas as a fuel source as a
means of diversifying away from foreign oil, such as in natural
gas vehicles; and
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indirectly through additions of electric vehicles.
|
NATURAL
GAS RESERVES AND PRODUCTION
Historically, the majority of the domestic natural gas supply
has been produced from onshore and offshore conventional sources
and is supplemented by production from historically declining
pipeline imports from Canada, imports of liquefied natural gas
(LNG) from foreign sources as well as some
production in Alaska. In order to maintain current levels of
U.S. natural gas supply and to meet the projected increase
in demand, new sources of domestic natural gas must continue to
be developed to offset an established trend of depletion
associated with these conventional sources as well as the
uncertainty of future LNG imports and infrastructure challenges
associated with sourcing additional production from Alaska. Over
the past several years, a fundamental shift in natural gas
production has emerged with the increased contribution of
natural gas from unconventional resources, defined by the EIA as
natural gas produced from shale formations and coalbeds. The
emergence of these unconventional resources has been made
possible through advances in technology that have allowed
producers to extract significant volumes of natural gas from
these unconventional plays at cost-advantaged per unit economics
versus most conventional sources.
43
The U.S. Geological Service, Mineral Management Service and
EIA estimate that in 2010 the U.S. possesses over 2,000 Tcf
of technically recoverable natural gas resources, representing a
92 year reserve life based on current production levels, an
increase of approximately 30% from 2008 estimates of technically
recoverable natural gas resources, which is primarily driven by
shale gas and other unconventional sources. As total energy
consumption increases and the depletion of onshore and offshore
conventional resources continues, natural gas from
unconventional resources is forecast to continue to gain market
share from higher-cost conventional sources of natural gas.
Natural gas production from shale formations is forecast to
provide the majority of the growth in unconventional natural gas
supply, increasing to approximately 26% of total
U.S. natural gas supply in 2035 as compared with 11.5% in
2009. This represents a projected two-fold increase in natural
gas shales market share of U.S. natural gas supply.
The chart below illustrates the composition of the EIAs
forecasted natural gas production through 2035.
OVERVIEW
OF THE MARCELLUS SHALE
The Marcellus Shale formation is the most expansive shale gas
play in the U.S., spanning six states in the northeastern U.S.
In its April 2009 Modern Shale Gas: A Primer, the United
States Department of Energy quoted an estimated potential
recoverable resource in the Marcellus Shale formation of over
260 Tcf of gas. The Marcellus Shale is a black, organic rich
shale formation located at depths between 4,000 and
8,500 feet, covering approximately 95,000 square miles
at an average thickness of 50 ft to 200 ft. In the area of the
Underlying Properties in Greene County, Pennsylvania, the
Marcellus Shale ranges in thickness from 140 feet to
208 feet.
The first commercial well drilled and completed in the Marcellus
Shale was in 2005 in Pennsylvania. Since the beginning of 2007,
there have been over 3,800 wells permitted in Pennsylvania
in the Marcellus Shale and over 1,500 of the approved wells have
been drilled.
44
In 2009, more than 550 wells were drilled in the Marcellus
Shale, making it one of the most active and prominent shale gas
plays in the U.S., and it is expected to continue to be an area
of active, widespread drilling. During 2009, there were more
than 50 operators active in the play.
Advances in modern drilling and completion technologies, such as
horizontal drilling and hydraulic fracturing, have increased the
value potential for many properties in Appalachia by enabling
better exploitation of the Marcellus Shale formation and other
unconventional reservoirs that are challenging to produce
efficiently. In general, horizontal wells use directional
drilling to create one or more lateral legs designed to allow
the well bore to stay in contact with the reservoir longer and
to intersect more vertical fractures in the formation than
conventional methods. These lateral legs can be several thousand
feet long. While it is more expensive than vertical drilling on
a per well basis, horizontal drilling may improve overall
returns on investment by increasing recovery volumes and rates,
limiting the number of wells necessary to develop an area and
reducing the costs and surface disturbances caused by multiple
vertical wells. Horizontal drilling and completion techniques
have shown improvements in terms of costs and drilling times
throughout the Marcellus Shale. ECA has increased the
productivity of its operations in Appalachia which target
development of the Marcellus Shale formation through the use of
horizontal drilling.
45
ENERGY
CORPORATION OF AMERICA
ECA is a privately held energy company engaged in the
exploration, development, production, gathering, aggregation and
sale of natural gas and oil, primarily in the Appalachian Basin,
Gulf Coast and Rocky Mountain regions in the United States and
in New Zealand. ECA or its predecessors have owned and operated
natural gas properties in the Appalachian Basin for more than
45 years, and ECA is one of the largest natural gas
operators in the Appalachian Basin. As of December 31,
2009, ECA operated approximately 5,100 wells in the
Appalachian Basin and had an aggregate leasehold position of
approximately one million gross acres with 85% of this acreage
held by production. ECA sells gas from its own wells as well as
third-party wells to local gas distribution companies,
industrial end users located in the Northeast, other gas
marketing entities and into the spot market for gas delivered
into interstate pipelines. ECA owns and operates approximately
5,000 miles of gathering lines and intrastate pipelines
that are used in connection with its gas aggregation activities.
During the fiscal year ended June 30, 2009, ECA and its
affiliates aggregated and sold 22.5 Bcf of gas for an
average of 62 MMcf of gas per day, of which 20.7 Bcf,
or 57 MMcf per day, represented sales of gas produced from
wells operated by ECA.
Substantially all of the production subject to the PDP Royalty
Interest and PUD Royalty Interest will be gathered by ECAs
Greene County Gathering System. This system currently accesses
two separate interconnects with the Texas Eastern Transmission,
L.P. and Columbia Gas Transmission, L.L.C. interstate pipeline
systems and includes six (6) compressors (with 8,785 total
horsepower) together with associated processing equipment.
ECAs interconnect agreements with these interstate
pipelines currently allow it to deliver at the interconnections
between ECAs facilities and the interstate pipelines up to
a total of 105,000 MMBtu per day for transportation by the
interstate pipelines to ECAs customers (approximately
16,000 MMBtu per day is currently being utilized), which is
in excess of its current and expected volumes from the
Underlying Properties. To the extent necessary, ECA will add
additional compression and related facilities to this system at
no cost to the trust, other than potential increases to the
Post-Production Service fee to the extent necessary to recover
certain capital expenditures after drilling is complete.
ECA was formed in September 1992 as a Colorado corporation and
subsequently reincorporated in West Virginia through a merger in
June 1995. ECAs predecessor began operating in the
Appalachian Basin in 1963. ECAs principal offices are
located at 4643 South Ulster Street, Suite 1100, Denver,
Colorado 80237, and its telephone number is
(303) 694-2667.
For additional information concerning ECA, see Information
about Energy Corporation of America beginning on
page ECA-1
of this prospectus. ECA will not be a reporting company
following this offering and will not file periodic reports with
the SEC. Therefore, as a trust unitholder, you will not have
access to the financial information of ECA.
The trust units do not represent interests in or obligations
of ECA.
46
SUMMARY
CONSOLIDATED FINANCIAL DATA OF ECA
The summary consolidated financial data presented below should
be read in conjunction with the audited consolidated financial
statements and the unaudited condensed consolidated financial
statements of ECA and the related notes and
Managements Discussion and Analysis of Financial
Condition and Results of Operations of Energy Corporation of
America included elsewhere in this prospectus. The
following summary consolidated financial data of ECA as of, and
for the years ended, June 30, 2007, 2008 and 2009 have been
derived from ECAs audited consolidated financial
statements included elsewhere in this prospectus. The following
summary consolidated financial data of ECA as of March 31,
2010 and for the nine months ended March 31, 2009 and 2010
have been derived from ECAs unaudited interim condensed
consolidated financial statements. The unaudited financial
statements were prepared on a basis consistent with the audited
statements and, in the opinion of ECA, include all adjustments
(consisting only of normal recurring adjustments) necessary to
present fairly the results of ECA for the periods presented.
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Nine Months Ended
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|
Year Ended June 30,
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March 31,
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Historical Results
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2007
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|
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2008
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|
|
2009
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|
|
2009
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|
|
2010
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|
|
|
|
|
|
|
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|
(Unaudited)
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|
|
|
(Dollars in thousands, except per share and reserve data)
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|
Operating revenue
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|
$
|
211,954
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|
|
$
|
247,071
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|
|
$
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216,220
|
|
|
$
|
174,132
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|
|
$
|
135,351
|
|
Income from operations
|
|
|
40,658
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|
|
|
51,912
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|
|
|
30,350
|
|
|
|
27,187
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|
|
|
21,594
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|
Earnings per common share basic and diluted
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|
|
33.66
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|
|
|
19.93
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|
|
|
36.98
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38.06
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|
|
|
7.64
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|
Dividends declared
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|
|
11.23
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12.50
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|
|
|
12.50
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|
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9.38
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|
|
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9.75
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Total assets
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|
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413,321
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|
|
|
557,980
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|
|
|
543,719
|
|
|
|
544,984
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|
|
|
546,321
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|
Total long-term debt
|
|
|
135,166
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|
|
|
197,125
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|
|
|
218,134
|
|
|
|
217,111
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|
|
|
249,897
|
|
Production (MMcfe) (unaudited)
|
|
|
9,636
|
|
|
|
10,684
|
|
|
|
9,646
|
|
|
|
7,249
|
|
|
|
8,201
|
|
Net proved developed reserves (MMcfe) (unaudited)
|
|
|
173,474
|
|
|
|
176,672
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|
|
|
145,102
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|
|
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47
MANAGEMENT
OF ECA
The executive officers and directors of ECA are listed below,
together with a description of their experience and certain
other information. All of the directors were elected or
re-elected for a one-year term at ECAs December 2009
annual meeting of stockholders. Executive officers are appointed
by the Board of Directors.
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Name
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|
Age
|
|
Position with ECA or its Subsidiaries
|
|
John Mork
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|
|
62
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|
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President and Chief Executive Officer
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Michael S. Fletcher
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|
|
61
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|
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Chief Financial Officer
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Donald C. Supcoe
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|
|
54
|
|
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Senior Vice President, Secretary and General Counsel
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J. Michael Forbes
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|
|
50
|
|
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Vice President and Treasurer
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Kyle M. Mork
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|
|
30
|
|
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Vice President of Eastern Operations
|
George V. OMalley
|
|
|
58
|
|
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Vice President Accounting
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W. Gaston Caperton, III
|
|
|
70
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|
|
Director
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Peter H. Coors
|
|
|
63
|
|
|
Director
|
L.B. Curtis
|
|
|
85
|
|
|
Director (Chairman Emeritus)
|
John J. Dorgan
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|
|
86
|
|
|
Director
|
John S. Fischer
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|
|
59
|
|
|
Director
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Thomas R. Goodwin
|
|
|
66
|
|
|
Director (Chairman)
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F.H. McCullough, III
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|
|
62
|
|
|
Director
|
Julie M. Mork
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|
|
59
|
|
|
Director
|
Jerry W. Neely
|
|
|
73
|
|
|
Director
|
Arthur C. Nielsen, Jr.
|
|
|
90
|
|
|
Director
|
Jay S. Pifer
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|
|
72
|
|
|
Director
|
John Mork has been President and Chief Executive
Officer of ECA and a Director of ECA since its formation.
Mr. Mork served in various capacities at Union Oil Company
until 1972 when he joined Pacific States Gas and Oil, Inc. and
subsequently founded Eastern American Energy Corporation
(EAEC). Mr. Mork was President and a Director
of EAEC from 1973 until 1993 with the incorporation of ECA.
Mr. Mork is a past Director of the Independent Petroleum
Association of America, and the Independent Oil and Gas
Association of West Virginia. Mr. Mork was a member of and
held various positions with the Young Presidents
Organization from 1984 until 1998. He also founded the Mountain
State Chapter of the Young Presidents Organization located
in Charleston, West Virginia. He is currently a member of the
Chief Executives Organization, the World Presidents
Organization, the University of Southern California Engineering
School Board of Councilors and the University of Southern
California Board of Trustees. Mr. Mork holds a Bachelor of
Science Degree in Petroleum Engineering from the University of
Southern California and is a graduate of the Stanford Business
School Program for Chief Executive Officers. Mr. Mork
serves on the Board of Directors of the ECA Foundation, Inc. He
is the husband of Julie Mork and the father of Kyle Mork.
Michael S. Fletcher has been Chief Financial
Officer of ECA since December 1999. He also held the position of
Treasurer of ECA from December 1999 through December 2000. In
addition, Mr. Fletcher was President of Mountaineer Gas
Company from 1998 until ECA sold Mountaineer in August 2000.
Prior to becoming President in 1998, he held the positions of
Senior Vice President and Chief Financial Officer of
Mountaineer. Before joining Mountaineer in 1987,
Mr. Fletcher was a partner of Arthur Andersen and Company
and was employed by that firm for fifteen years.
Mr. Fletcher is a Certified Public Accountant and a
graduate of Utah State
48
University with a Bachelor Degree in Accounting.
Mr. Fletcher serves on the Board of Directors of the ECA
Foundation, Inc.
Donald C. Supcoe has been a Director of the ECA
since 2005. He has served as Senior Vice President, Corporate
Secretary and General Counsel since 2000 and is responsible for
ECAs operations east of the Mississippi River.
Mr. Supcoe was the Senior Vice President of Mountaineer Gas
Company from 1998 until its sale in August 2000. Prior to
joining Mountaineer in 1998, he was the Vice President, General
Counsel and Corporate Secretary of ECAs predecessor where
he held various positions since 1981. Mr. Supcoe is active
in the Independent Oil and Gas Association of West Virginia and
currently serves as President of that organization. He is also a
past Vice President of the Independent Petroleum Association of
America. Mr. Supcoe is currently a member of the Board of
Directors of Mid-Atlantic Holdings, Inc., and is a Trustee at
Large of the Energy and Mineral Law Foundation. Mr. Supcoe
graduated from West Virginia University with a Bachelor of
Science Degree in Business Administration. Mr. Supcoe
received a Doctor of Jurisprudence Degree from West Virginia
University College of Law. Mr. Supcoe serves on the Board
of Directors of the ECA Foundation, Inc.
J. Michael Forbes is Vice President and Treasurer
of ECA. Mr. Forbes has been an officer of ECA since 1995
and prior to that was an officer with its predecessor, which he
joined in 1982. Mr. Forbes graduated with a Bachelor of
Arts in Accounting and Finance and a minor in Economics from
Glenville State College and is a Certified Public Accountant. He
also holds a Master of Business Administration from Marshall
University and is a graduate of Stanford Universitys
Program for Chief Financial Officers. Mr. Forbes serves on
the board for numerous community organizations, including Thomas
Health Systems where he serves as First Vice Chairman, the ECA
Foundation, Inc. and is the Past Chairman of the YMCA of the
Kanawha Valley.
Kyle M. Mork has been the Vice President of
Eastern Operations for ECA since 2006. He began his career with
Halliburton Energy Services as a stimulation engineer before
moving to ECA in 2003 as a drilling engineer in Houston, Texas.
In 2004, he became the Drilling Manager for ECAs Eastern
Region based in Charleston, West Virginia. He graduated in 2002
with a Bachelor of Science Degree in Chemical Engineering from
Cornell University, and has taken Masters level courses in
Petroleum Engineering at the University of Southern California.
Currently, he is enrolled in the Executive MBA program at the
Kellogg Graduate School of Management at Northwestern University
and will graduate in June 2010. Kyle also serves on the Board of
Directors of the ECA Foundation, Inc., the YMCA of the Kanawha
Valley, Energize WV, and the Clay Center for the Arts. He is the
son of John and Julie Mork.
George V. OMalley has been Vice President of
Accounting for ECA since December 2002. Before being elected
Vice President, Mr. OMalley served as Director of
Accounting. Mr. OMalley joined its predecessor in
April 1991 and served in various capacities including Vice
President and Treasurer. Prior to joining ECA, he held various
positions in industry and public accounting.
Mr. OMalley currently serves on the Marshall
University School of Business and Department of Accountancy and
Legal Environment Advisory Boards. He is a former board member
and past President of the West Virginia Society of CPAs
and board member of the Independent Oil & Gas
Association of West Virginia. Mr. OMalley graduated
from Marshall University with a Bachelor Degree in Accounting
and is a Certified Public Accountant.
W. Gaston Caperton, III has been a Director
of ECA since 1997. Mr. Caperton has been a successful
leader in three diverse fields: business, government and
education. He was the principal owner of a large insurance
brokerage firm, is a former two-term governor of West Virginia,
and is the current President and Chief Executive Officer of The
College Board.
49
Peter H. Coors has been a Director of ECA since
1997. Mr. Coors is the Chairman of Molson Coors Brewing
Company and the Chairman of MillerCoors LLC. He received his
Bachelor Degree in Industrial Engineering from Cornell
University in 1969 and his Master of Business Administration
from the University of Denver in 1970. Mr. Coors also
serves on the Board of Directors of the University of Colorado
Hospital. He is President of the Adolph Coors Foundation, Castle
Rock Foundation, and University of Colorado Hospital Foundation.
He also serves on the Board of the Denver Area Council of the
Boy Scouts of America and is a member of Denver
Universitys Strategic Panel on Immigration.
L.B. Curtis has been a Director of ECA since 1993.
He was Chairman from 1998 through 2006 and is now Chairman
Emeritus. Mr. Curtis was a Director of its predecessor from
1988 until 1993. Mr. Curtis is retired from a career at
Conoco, Inc. where he held the position of Vice President of
Production Engineering with Conoco Worldwide. Mr. Curtis
was highly recognized across the petroleum industry in the
upstream segment of the industry. He is a member of the American
Petroleum Institute and Society of Petroleum Engineers (SPE) and
is a trustee of the SPE Foundation. He was instrumental in the
design and development of the North Sea tension-leg
production platform and a member of the Dupont Lavoisier
Academy. Mr. Curtis graduated from The Colorado School of
Mines with an Engineer of Petroleum Professional Degree.
John J. Dorgan has been a Director of ECA since
1993 and served as a Director of its predecessor in 1992. He is
a former Executive Vice President and consultant to Occidental
Petroleum Corporation where he had worked in various capacities
starting in 1972. He is also a former Director and Chairman of
the Finance Committee, Canadian Occidental.
John S. Fischer has been a Director of ECA since
2005. He founded Solid Systems Engineering Co. in 1979 to
service high tonnage conveyor systems in the mining, power and
primary metals industries; in 2008 the company was acquired by
Fenner Dunlop International. In 1994 Mr. Fischer started
Air Control Science, Inc. having recognized the need for a firm
with innovative technology to focus exclusively on effective
design and construction of dust, spillage and fume control
systems for the coal-fired power, coal mining and primary metals
industries; in 2007 Air Control Science was acquired by CCC
Group, Inc. Mr. Fischer has authored and co-authored
patents related to leading technology in coal-fired power and
primary metals particulate and dust control. Mr. Fischer
graduated from the Northwestern University Kellogg Graduate
School with a Master of Business Administration. Currently, he
is a member of the World Presidents Organization and Chief
Executives Organization. Mr. Fischer serves on the National
Coal Council for the Secretary of Energy, the Board of
University of Colorado Leeds Business School and the Board of
the Great Lakes Business School in Chennai India.
Thomas R. Goodwin has been a Director of ECA since
2005 and has served as Chairman of the Board of Directors since
2007. Mr. Goodwin is Managing Partner of the law firm of
Goodwin and Goodwin, LLP which provides legal advice to ECA. He
is a member of the West Virginia State Bar and has appeared
before the West Virginia Supreme Court of Appeals and the Fourth
Circuit Court of Appeals. He is listed in the Best Lawyers of
America and is counselor to corporations and board of directors.
He formerly served as the West Virginia State Tax Commissioner
and Executive Assistant to the Governor of West Virginia,
Chairman of West Virginia Economic Development Authority,
Chairman of the West Virginia Municipal Bond Committee, and past
member of Board of Advisors of West Virginia University.
Mr. Goodwins legal expertise is focused on corporate
purchases, corporate sales and financing, and complex
litigation. He received his law degree from West Virginia
University and his Master Degree in Law from Harvard Law School.
F.H. McCullough, III has been a Director of
ECA since 1993. He joined EAEC in 1977 and served in various
capacities until 1999, including Director from 1978 until 1993.
Mr. McCullough
50
is currently President and Chief Financial Officer of Spring
Creek Energy Company, LLC, a developer of metallurgical coal
reserves in West Virginia. He has served as a Director of the
Independent Oil and Gas Association of West Virginia and is the
Co-Founder, past President and current Director of the Angelman
Syndrome Foundation, Inc. Mr. McCullough is a graduate of
the University of Southern California with a Bachelor of Arts
Degree in International Economics and two Masters Degrees in
Business Administration and Financial Systems Management. He is
a graduate of the Northwestern University Kellogg Graduate
School of Management Executive Marketing Program.
Mr. McCullough serves on the Board of Directors of the ECA
Foundation, Inc.
Julie M. Mork has been a Director of ECA since
1993. She is the Managing Director of the ECA Foundation, Inc.,
a private corporate foundation based in Denver, Colorado having
a focus on youth and education. Mrs. Mork served as a
founder and Secretary/Treasurer of Pacific States
Gas & Oil, Inc. and EAEC. From 1989 until 1991, she
served as Community Relations and Human Resources Director of
EAEC. She has volunteered her time to several organizations
including the Anchor Center for Blind Children where she
currently serves as a member of the Advisory Board and is a past
President of its Board of Directors. She also served as a member
of the Cherry Creek Schools Foundation for six years. In October
2004, Mrs. Mork was elected to the National Board of
College Summit, an organization dedicated to increasing the
college enrollment rate of low-income students in America.
Mrs. Mork received a Bachelor of Arts Degree in History
from the University of California in Los Angeles and holds a
Certificate in Real Estate Paralegal Training. She is the wife
of John Mork and the mother of Kyle Mork.
Jerry W. Neely has been a Director of ECA since
2009. Mr. Neely is the former President, Chairman and CEO
of Smith International, a public multinational oil service
company. He is currently on the Board of Directors of Smith
International, Avery Dennison, Security Pacific Corporation,
Security Pacific National Bank, Peretec Computer, American
Petroleum Institute, Petroleum Suppliers Association and the
World Presidents Organization. He is on the University of
Southern California Board of Trustees and was awarded the USC
School of Business Outstanding Alumni Achievement Award. He has
a Bachelor of Science Degree in Industrial Management and
Business Administration from the University of Southern
California.
Arthur C. Nielsen, Jr. Chairman Emeritus of the
A.C. Nielsen Company, has been a Director of ECA since 1993. He
was a Director of its predecessor from 1985 until 1993. He has
served on the board of directors of 21 firms, some for more than
a quarter of a century, including the A.C. Nielsen Company,
Dun & Bradstreet, General Binding Corporation, Harris
Bank, Marsh & McLennan, Motorola, Walgreens Co.,
Hercules, and International Executive Service Corp., and was
Advisor to three U.S. Presidents. He is a Life Trustee for
the American Management Association, a Director for the Chicago
Foundation for Education, Life Member and President of the
Economic Club of Chicago, Life Trustee for the Advertising
Council, Life Trustee for the Illinois Childrens Home and
Aid Society, Life Trustee for the University of Chicago,
President Emeritus and Past President of the Wisconsin Alumni
Research Foundation, Life Trustee for Northwestern Memorial
Hospital, and Past President of the Management Executive
Society. Mr. Nielsen is a graduate of the University of
Wisconsin, from which he received an honorary doctorate of Human
Letters Degree.
Jay S. Pifer has been a Director of ECA since
2003. Mr. Pifer served as President of West Penn Power Co.,
Monongahela Power Co., and The Potomac Edison Co. before
becoming President of Allegheny Power where he also served as
Chief Operating Officer before retiring. Under his leadership
Allegheny Power became recognized as a world-class company and
was ranked number one in the nation in customer satisfaction
among the 30 largest electric and gas companies, ranked second
in the east and in the top ten nationally by JD Power and
Associates. Active in community affairs, Mr. Pifer has
served on the boards of numerous organizations including,
Waynesburg College, Penn State Fayette University Advisory
Board, University of
51
Pittsburgh-Greensburg, United Way, as well as Director and
Chairman of the Energy Association of Pennsylvania, Director of
Ohio Electric Utilities Institute, TEAM Pennsylvania, Western
Pennsylvania Conservancy, Educational Alliance of West Virginia,
The Westmoreland Trust and chair of their Strategic Planning
Committee, and Director of the Business Roundtable of
Pennsylvania and West Virginia. He is a graduate of Penn State
University and Clarion State University.
BENEFICIAL
OWNERSHIP OF ECA
The following table sets forth certain information regarding
(i) the share ownership of ECA by each person known to ECA
to be the beneficial owner of more than 5% of the outstanding
shares of common stock of ECA, (ii) the share ownership of
common stock of ECA by each director, (iii) the share
ownership of common stock of ECA by certain executive officers
and (iv) the share ownership of common stock of ECA by all
directors and executive officers as a group, in each case as of
March 31, 2010. The business address of each officer and
director listed below is:
c/o Energy
Corporation of America, 4643 S. Ulster,
Suite 1100, Denver, Colorado 80237.
|
|
|
|
|
|
|
|
|
|
|
Beneficial Ownership
|
|
|
|
Common Stock
|
|
|
|
Shares
|
|
|
Percent
|
|
|
W. Gaston Caperton, III
|
|
|
11,680
|
|
|
|
2.24
|
%
|
Peter H. Coors(1)
|
|
|
8,196
|
|
|
|
1.57
|
%
|
L.B. Curtis(2)
|
|
|
10,750
|
|
|
|
2.06
|
%
|
John J. Dorgan(3)
|
|
|
4,130
|
|
|
|
*
|
|
John S. Fischer
|
|
|
|
|
|
|
|
|
Michael S. Fletcher
|
|
|
1,000
|
|
|
|
*
|
|
J. Michael Forbes
|
|
|
1,850
|
|
|
|
*
|
|
Thomas R. Goodwin
|
|
|
|
|
|
|
|
|
F.H. McCullough, III (4)
|
|
|
58,080
|
|
|
|
11.15
|
%
|
John Mork (5)
|
|
|
367,543
|
|
|
|
70.58
|
%
|
Julie M. Mork (5)
|
|
|
367,543
|
|
|
|
70.58
|
%
|
Kyle M. Mork (6)
|
|
|
5,544
|
|
|
|
1.06
|
%
|
Arthur C. Nielsen, Jr.(7)
|
|
|
19,880
|
|
|
|
3.82
|
%
|
George OMalley
|
|
|
|
|
|
|
|
|
Jerry W. Neely
|
|
|
|
|
|
|
|
|
Jay S. Pifer
|
|
|
|
|
|
|
|
|
Donald C. Supcoe
|
|
|
4,583
|
|
|
|
*
|
|
All officers and directors as a group (17 persons)
|
|
|
493,236
|
|
|
|
94.72
|
%
|
|
|
|
*
|
|
Less than one percent
|
|
(1)
|
|
Includes shares held by the Peter
H. Coors 2010 Grantor Retained Annuity Trust II U/A dated
January 22, 2010.
|
|
(2)
|
|
Includes shares held by the Curtis
Family Revocable Trust dated December 2, 1992.
|
|
(3)
|
|
Includes shares held by the Dorgan
Living Trust dated April 22, 1993 as amended.
|
|
(4)
|
|
Includes 56,080 shares held by
F.H. McCullough, III and Kathy McCullough as joint tenants,
880 shares held by the Katherine F. McCullough Trust, and
400 shares held by each of the Lesley McCullough Trust, the
Meredith McCullough Trust and the Kristin McCullough Trust.
|
|
(5)
|
|
Includes 285,404 shares held
by Shenandoah LLC, an entity wholly owned and controlled by a
grantor trust created by John and Julie Mork, 74,032 shares
held by John and Julie Mork as joint tenants, 2,563 shares
held by Julie Mork individually, and 5,544 shares held by
the Alison Mork Trust.
|
|
(6)
|
|
Includes 5,544 shares held by
the Kyle Mork Trust.
|
|
(7)
|
|
Includes shares held by the Arthur
C. Nielsen, Jr. Trust dated July 14, 2003.
|
52
The following table sets forth certain information regarding
(1) the share ownership of ECA by each person known to ECA
to be the beneficial owner of more than 5% of the outstanding
shares of Class A Stock, (2) the share ownership of
ECAs Class A Stock by each Director, (3) the
share ownership of ECAs Class A Stock by certain
executive officers and (4) the share ownership of
ECAs Class A Stock by all directors and executive
officers as a group, in each case as of March 31, 2010. The
Class A Stock differs from the Common Stock in that the
Class A Stock does not have voting rights. The business
address of each officer and director listed below is:
c/o Energy
Corporation of America, 4643 South Ulster Street,
Suite 1100, Denver, Colorado 80237.
|
|
|
|
|
|
|
|
|
|
|
Beneficial Ownership
|
|
|
|
Class A Stock
|
|
|
|
Shares
|
|
|
Percent
|
|
|
W. Gaston Caperton, III
|
|
|
3,420
|
|
|
|
5.23
|
%
|
Peter H. Coors (1)
|
|
|
4,528
|
|
|
|
6.92
|
%
|
L.B. Curtis (2)
|
|
|
1,180
|
|
|
|
1.81
|
%
|
John J. Dorgan (3)
|
|
|
3,820
|
|
|
|
5.85
|
%
|
John S. Fischer
|
|
|
480
|
|
|
|
*
|
|
Michael S. Fletcher (4)
|
|
|
2,270
|
|
|
|
3.47
|
%
|
J. Michael Forbes (4)
|
|
|
1,550
|
|
|
|
2.37
|
%
|
Thomas R. Goodwin
|
|
|
3,820
|
|
|
|
5.85
|
%
|
F.H. McCullough, III
|
|
|
1,180
|
|
|
|
1.81
|
%
|
John Mork (4)(5)
|
|
|
4,750
|
|
|
|
7.26
|
%
|
Julie M. Mork (4)(5)
|
|
|
4,750
|
|
|
|
7.26
|
%
|
Kyle M. Mork (4)(6)
|
|
|
1,969
|
|
|
|
3.01
|
%
|
Jerry W. Neely
|
|
|
|
|
|
|
|
|
Arthur C. Nielsen, Jr. (7)
|
|
|
1,180
|
|
|
|
1.81
|
%
|
George V. OMalley (4)
|
|
|
1,170
|
|
|
|
1.79
|
%
|
Jay S. Pifer
|
|
|
1,340
|
|
|
|
2.05
|
%
|
Donald C. Supcoe (4)
|
|
|
2,630
|
|
|
|
4.02
|
%
|
All officers and directors as a group (17 persons)
|
|
|
35,287
|
|
|
|
54.00
|
%
|
|
|
|
*
|
|
Less than one percent
|
|
(1)
|
|
Includes shares held by the
Peter H. Coors 2010 Grantor Retained Annuity Trust II U/A
dated January 22, 2010.
|
|
(2)
|
|
Includes shares held by the Curtis
Family Revocable Trust dated December 2, 1992.
|
|
(3)
|
|
Includes shares held by the Dorgan
Living Trust dated April 22, 1993 as amended.
|
|
(4)
|
|
Includes shares included in
ECAs Incentive Stock Purchase Plan.
|
|
(5)
|
|
Includes 1,730 shares held by
John and Julie Mork as joint tenants, 1,800 shares held by
Julie Mork individually and 1,220 shares held by the Alison
Mork Trust.
|
|
(6)
|
|
Includes 1,219 shares held by
the Kyle Mork Trust.
|
|
(7)
|
|
Includes shares held by the Arthur
C. Nielsen, Jr. Trust dated July 14, 2003.
|
53
EASTERN
AMERICAN NATURAL GAS TRUST
In 1993, ECA sponsored the formation of the Eastern American
Natural Gas Trust (NYSE: NGT), a publicly traded Delaware trust
(NGT), to which it contributed net profits interests
in Appalachian Basin natural gas properties trust units.
Depositary units consisting of trust units and an interest in
United States Treasury obligations (Depositary
Units) were sold in a public offering at a price of $20.50
per Depositary Unit, resulting in gross proceeds of
$120.9 million. This royalty trust holds net profits
interests conveyed from the interests of ECA in 650 producing
gas wells, 65 proved development well locations and associated
acreage located in West Virginia and Pennsylvania. In connection
with the formation of this trust, ECA agreed to drill 65
development wells over a period of five years from which NGT
would be entitled to a specified percentage of the proceeds from
the natural gas production. ECA completed its obligation within
the stipulated period. From the formation of the trust through
June 15, 2010, NGT distributed $31.24 per Depositary
Unit in the aggregate. As of June 18, 2010, the closing
price of each Depositary Unit as reported by the New York Stock
Exchange was $22.38. The Eastern American Natural Gas Trust is
expected to terminate in 2013. The historical results of
operations and performance of NGT should not be relied on as an
indicator of how the trust will perform.
54
THE
TRUST
The trust is a statutory trust created under the Delaware
Statutory Trust Act in March 2010. The business and affairs
of the trust will be managed by The Bank of New York Mellon
Trust Company, N.A., as trustee. Although ECA will operate all
of the Producing Wells and substantially all of the PUD Wells,
ECA has no ability to manage or influence the management of the
trust. In addition, the Corporation Trust Company will act
as Delaware trustee of the trust. The Delaware trustee will have
only minimal rights and duties as are necessary to satisfy the
requirements of the Delaware Statutory Trust Act.
In connection with the formation of the trust, ECA will convey
to a wholly owned subsidiary a term royalty interest entitling
the holder of the interest to receive 45% of the proceeds from
the sale of production of natural gas attributable to ECAs
interest in the Producing Wells (after deducting post-production
costs and any applicable taxes) for a period of 20 years
commencing on April 1, 2010 (the Term PDP
Royalty) and a term royalty interest entitling such holder
of the interest to receive 25% of the proceeds from the sale of
the production of natural gas attributable to ECAs
interest in the PUD Wells (after deducting post-production costs
and any applicable taxes) for a period of 20 years
commencing on April 1, 2010 (the Term PUD
Royalty) in exchange for a demand note in the principal
amount of approximately $161 million. The Term PDP Royalty
and the Term PUD Royalty are collectively referred to as the
Term Royalties.
Prior to the closing of this offering, ECA and the Private
Investors will convey to the trust perpetual royalty interests
entitling the trust to receive, in the aggregate, 45% of the
proceeds from the sale of production of natural gas attributable
to the interests of ECA in the Producing Wells (after deducting
post-production costs and any applicable taxes) (the
Perpetual PDP Royalty) and ECA will convey to the
trust a perpetual royalty interest entitling the trust to
receive an additional 25% of the proceeds from the sale of
production of natural gas attributable to ECAs interest in
the PUD Wells (after deducting post-production costs and any
applicable taxes) (the Perpetual PUD Royalty) in
exchange for an aggregate 4,401,250 common units
constituting 25% of the trust units outstanding and 4,401,250
subordinated units constituting 25% of the trust units
outstanding. The Perpetual PDP Royalty and the Perpetual PUD
Royalty are collectively referred to as the Perpetual
Royalties.
In connection with the completion of this offering, ECAs
subsidiary will convey the Term Royalties to the trust in
exchange for the net proceeds of this offering, after deducting
underwriting commissions and discounts and expenses, and will
use the net proceeds to repay all or a portion of the demand
note to ECA.
The trustee can authorize the trust to borrow money to pay trust
administrative or incidental expenses that exceed cash held by
the trust. The trustee may authorize the trust to borrow from
the trustee as a lender provided the terms of the loan are fair
to the trust unitholders. The trustee may also deposit funds
awaiting distribution in an account with itself, if the interest
paid to the trust at least equals amounts paid by the trustee on
similar deposits, and make other short term investments with the
funds distributed to the trust. The Trustee may also hold funds
awaiting distribution in a non interest bearing account.
The trust will be responsible for paying all legal, accounting,
tax advisory, engineering, printing costs and other
administrative and
out-of-pocket
expenses incurred by or at the direction of the trustee or the
Delaware trustee. The trust will also be responsible for paying
other expenses incurred as a result of being a publicly traded
entity, including costs associated with annual and quarterly
reports to unitholders, tax return and Schedule K-1
preparation and distribution, independent auditor fees and
registrar and transfer agent fees. These trust administrative
expenses as well as the costs associated with being a publicly
traded entity are anticipated to
55
aggregate approximately $800,000 per year, although such costs
could be greater or less depending on future events that cannot
be predicted. Included in the $800,000 annual estimate is an
annual administrative fee of $150,000 for the trustee, which may
be adjusted beginning on the fifth anniversary of the trust as
provided in the trust agreement, and an annual administrative
fee of $2,400 for the Delaware trustee. These costs as well as
those to be paid to ECA pursuant to the Administrative Services
Agreement outlined below under Administrative
services agreement and development agreement, will be
deducted by the trust before distributions are made to trust
unitholders.
The trust will begin to liquidate on the Termination Date and
will soon thereafter wind up its affairs and terminate. The Term
Royalties will automatically revert to ECA at the Termination
Date, while the Perpetual Royalties will be sold and the
proceeds will be distributed to the unitholders at the
Termination Date or soon thereafter.
ECA will have a right of first refusal to purchase the Perpetual
Royalties at the Termination Date. This right of first refusal
provides that the trustee will use commercially reasonable
efforts to retain a third-party advisor to market the Perpetual
Royalties within 30 business days of the Termination Date. If
the trustee receives a bid from a proposed purchaser other than
ECA and wants to sell all or part of the Perpetual Royalties, it
will be required to give notice (the Offer Notice)
to ECA, identifying the proposed purchaser and setting forth the
proposed sale price, payment terms and other material terms
under which the trustee is proposing to sell. ECA would then
have 30 days from receipt of the Offer Notice to elect, by
notice to the trustee, to purchase the subject properties
offered for sale on the terms and conditions set forth in the
Offer Notice. If ECA makes such election, the proposed purchaser
would be entitled to receive reimbursement of its reasonable and
documented expenses incurred in connection with its review and
analysis of the subject properties and bid preparation. ECA and
the trust would share equally the cost of reimbursement to the
proposed purchaser.
If ECA does not give notice within the
30-day
period following the Offer Notice, the trustee may sell such
properties to the identified purchaser on terms and conditions
that are substantially the same as those previously set forth in
such Offer Notice.
If, after a reasonable marketing period, no bid is received on
any or all of the Perpetual Royalties from any party other than
ECA, then ECA shall obtain, at the trusts expense, and
deliver to the trustee, a fairness opinion from a
nationally-recognized valuation firm with expertise in fairness
opinions stating that the proposed sale price to be paid by ECA
to the trust for the properties is fair to the trust.
ADMINISTRATIVE
SERVICES AGREEMENT AND DEVELOPMENT AGREEMENT
In connection with the closing of this offering, the trust will
enter into an Administrative Services Agreement with ECA that
obligates the trust to pay ECA each quarter an administrative
services fee for accounting, bookkeeping and informational
services to be performed by ECA on behalf of the trust relating
to the royalty interests. The annual fee, payable in equal
quarterly installments, will total $60,000. After the completion
of ECAs drilling obligation, ECA and the trustee each may
terminate the provisions of the Administrative Services
Agreement relating to the provision by ECA of administrative
services at any time following delivery of notice no less than
90 days prior to the date of termination.
The Development Agreement will obligate ECA to drill all of the
PUD Wells by March 31, 2013. In the event of delays, ECA
will have until March 31, 2014 under the Development
Agreement to fulfill its drilling obligation. ECA will grant to
the trust a lien on ECAs interest in the Marcellus Shale
formation in the AMI (except the Producing Wells and any other
wells which are
56
already producing and not subject to the Royalty Interests) in
order to secure the estimated amount of the drilling costs for
the trusts interests in the PUD Wells (the Drilling
Support Lien). The amount obtained by the trust pursuant
to the Drilling Support Lien may not exceed $91 million. As
ECA fulfills its drilling obligation over time, the total dollar
amount that may be recovered will be proportionately reduced and
the completed PUD Wells will be released from the lien.
For purposes of ECAs drilling obligation, and subject to
the following paragraph, ECA will be credited with a full
development well drilled if its working interest in the
development well drilled is 100%. In the event that ECAs
working interest in a development well drilled is less than
100%, ECA will be credited with a portion of a development well
in the proportion that its working interest in the development
well bears to 100%. For example, if ECAs working interest
in a development well drilled by ECA in connection with
fulfilling its drilling obligation to the trust is 50%, ECA will
be credited with one-half of a development well for purposes of
satisfying its drilling obligation in the period the development
well was drilled. As a result, ECA will be required to drill
more than the 52 Marcellus Shale natural gas development wells,
in the aggregate, if ECAs interest in any development well
is less than 100%.
Wells drilled horizontally in the Marcellus Shale formation with
a horizontal lateral distance (measured from the midpoint of the
curve to the end of the lateral) of less than 2,500 feet
will count as a fractional well in proportion to total lateral
length divided by 2,500 feet. In the event ECA commences
drilling of a PUD Well, but fails to drill beyond the mid-point
of the curve, such well will not count as a fractional well.
Wells with a horizontal lateral distance of greater than
2,500 feet (subject to a maximum of 3,500 feet) will
count as one well plus a fractional well equal to the length
drilled in excess of 2,500 (up to 3,500 feet) feet divided
by 2,500 feet. Among the Producing Wells, the average
lateral length completed has been approximately 2,500 feet,
with the most recent wells extending beyond the average with a
maximum lateral length drilled of 3,271 feet. The reserve
report was prepared based on an average lateral length of 2,000
feet for the PUD Wells.
ECA is obligated to bear all of the costs of drilling and
completing the PUD Wells. ECA is required to complete and equip
each development well that reasonably appears to ECA to be
capable of producing gas in quantities sufficient to pay
completion, equipping and operating costs. In making such
decisions, ECA is required to act as a reasonably prudent
operator in the AMI under the same or similar circumstances as
it would act if it were acting with respect to its own
properties, disregarding the existence of the royalty interests
as burdens affecting such property. See The underlying
properties Sale and abandonment of underlying
properties.
ECA will covenant and agree not to drill and complete, and will
not permit any other person within its control to drill and
complete, any well in the Marcellus Shale formation on lease
acreage included within the AMI for its own account until such
time as ECA has met its commitment to drill the PUD Wells. Once
ECA has completed its drilling obligation, the trustee will be
required to release the Drilling Support Lien in full. Upon the
trustees release of the Drilling Support Lien, ECA will
further agree not to drill and complete, and will not permit any
other person within its control to drill and complete, any well
on the lease acreage that will have a perforated segment that
will be within 500 feet of any perforated interval of PUD
Well or Producing Well in the Marcellus Shale formation.
57
TARGET
DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE
THRESHOLDS
ECA will create the royalty interests through conveyances to the
trust of royalty interests carved from their working interests
in specified gas properties in Pennsylvania. The PDP Royalty
Interest will entitle the trust to receive 90% of the proceeds
(exclusive of any production or development costs but after
deducting post-production costs and any applicable taxes) from
the sale of production of natural gas attributable to ECAs
interest in the Producing Wells for a period of 20 years
commencing on April 1, 2010 and 45% thereafter. The PUD
Royalty Interest will entitle the trust to receive 50% of the
proceeds (exclusive of any production or development costs but
after deducting post-production costs and any applicable taxes)
from the sale of future production of natural gas attributable
to ECAs interest in the PUD Wells for a period of
20 years commencing on April 1, 2010 and 25%
thereafter.
The amount of trust revenues and cash distributions to trust
unitholders will depend on:
|
|
|
|
|
the timing of initial production from the PUD Wells;
|
|
|
|
natural gas prices received;
|
|
|
|
the volume and Btu rating of natural gas produced and sold;
|
|
|
|
post-production costs and any applicable taxes;
|
|
|
|
the reimbursement by the trust, if any, of ECAs costs
associated with establishing the floor price contracts to be
transferred to the trust; and
|
|
|
|
administrative expenses of the trust and expenses incurred as a
result of being a publicly traded entity.
|
ECA has calculated quarterly target levels of cash distributions
for the life of the trust. Such target distribution levels are
set forth on Annex B to this prospectus. The target
distributions were prepared by ECA on an accrual basis based on
volumes, pricing and other assumptions that are described below
in Significant assumptions used to prepare the
target distributions. As used herein, accrual basis means
ECA will pay to the trust each quarter an amount equal to the
estimated proceeds of production from the trust properties
during the calendar quarter most recently ended before the
distribution (exclusive of any production or development costs
but after deducting post-production costs and any applicable
taxes), regardless of whether such amounts have actually been
received by ECA from the purchaser of the natural gas produced.
The amount of the quarterly distributions may fluctuate from
quarter to quarter, depending on the proceeds received by the
trust, among other factors. Annex B reflects that while
target distributions increase as ECA completes its drilling
obligations and production attributable to the trust increases,
over time these target distributions decline as a result of the
depletion of the reserves in the Underlying Properties. These
target distributions do not represent the actual
distributions you should expect to receive with respect to your
common units. Rather, the trust has established the target
distributions in part to calculate the subordination and
incentive thresholds described in more detail below.
In order to provide support for cash distributions on the common
units, ECA has agreed to subordinate 4,401,250 of the trust
units it will retain following this offering, which will
constitute 25% of the outstanding trust units. While the
subordinated units will be entitled to receive pro rata
distributions from the trust if and to the extent there is
sufficient cash to provide a cash distribution on the common
units which is no less than the applicable quarterly
subordination threshold, if there is not sufficient cash to fund
such a distribution on all trust units, the distribution to be
made with respect to the subordinated units will be reduced or
eliminated in
58
order to make a distribution, to the extent possible, of up to
the subordination threshold amount on the common units. Each
applicable quarterly subordination threshold is equal to 80% of
the target distribution level for the corresponding quarter as
reflected on Annex B. In exchange for agreeing to
subordinate these trust units, and in order to provide
additional financial incentive to ECA to perform its drilling
obligation and operations on the Underlying Properties in an
efficient and cost-effective manner, ECA will be entitled to
receive incentive distributions equal to 50% of the amount by
which the cash available for distribution on all of the trust
units in any quarter exceeds 150% of the subordination threshold
for such quarter (which is 120% of the target distribution for
such quarter). ECAs right to receive the incentive
distributions will terminate upon the expiration of the
subordination period.
ECA has incurred costs of approximately $5.0 million in
establishing the floor price contracts to be transferred to the
trust. ECA will be entitled to reimbursement for these
expenditures plus interest accrued at 10% per annum only if and
to the extent distributions to trust unitholders would otherwise
exceed the incentive threshold. This reimbursement will be
deducted, over time, from the 50% of cash available for
distribution in excess of the incentive thresholds otherwise
payable to the trust unitholders.
The subordinated units will automatically convert into common
units on a
one-for-one
basis and ECAs right to receive incentive distributions
and to recoup the reimbursement amount will terminate, at the
end of the fourth full calendar quarter following ECAs
satisfaction of its drilling obligation to the trust.
Accordingly, ECA bears the risk that it will not be partially or
fully reimbursed for the hedging contracts it has established
for the benefit of the trust. The trust currently expects that
ECA will complete its drilling obligation on or before
March 31, 2013 and that, accordingly, the subordinated
units would convert into common units on or before
March 31, 2014. In the event of delays, ECA will have until
March 31, 2014 under the Development Agreement to drill all
the PUD Wells, in which event the subordinated units would
convert into common units on or before March 31, 2015.
59
The table below sets forth the target distributions and
subordination and incentive thresholds for each calendar quarter
through the first quarter of 2015. The effective date of the
trust is April 1, 2010, meaning it will receive the
proceeds of production attributable to the PDP Royalty Interest
from that date even though the PDP Royalty Interest will not be
conveyed to the trust until the closing of this offering.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordination
|
|
Target
|
|
Incentive
|
Period
|
|
Threshold
|
|
Distribution
|
|
Threshold
|
|
|
|
|
(per unit)
|
|
|
|
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter
|
|
$
|
0.181
|
|
|
$
|
0.227
|
|
|
$
|
0.272
|
|
Third Quarter
|
|
|
0.334
|
|
|
|
0.417
|
|
|
|
0.501
|
|
Fourth Quarter
|
|
|
0.478
|
|
|
|
0.597
|
|
|
|
0.716
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.446
|
|
|
|
0.558
|
|
|
|
0.669
|
|
Second Quarter
|
|
|
0.451
|
|
|
|
0.564
|
|
|
|
0.676
|
|
Third Quarter
|
|
|
0.550
|
|
|
|
0.688
|
|
|
|
0.825
|
|
Fourth Quarter
|
|
|
0.565
|
|
|
|
0.706
|
|
|
|
0.847
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.574
|
|
|
|
0.717
|
|
|
|
0.861
|
|
Second Quarter
|
|
|
0.602
|
|
|
|
0.752
|
|
|
|
0.903
|
|
Third Quarter
|
|
|
0.624
|
|
|
|
0.780
|
|
|
|
0.937
|
|
Fourth Quarter
|
|
|
0.701
|
|
|
|
0.876
|
|
|
|
1.051
|
|
2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
0.756
|
|
|
$
|
0.945
|
|
|
$
|
1.135
|
|
Second Quarter
|
|
|
0.754
|
|
|
|
0.942
|
|
|
|
1.131
|
|
Third Quarter
|
|
|
0.701
|
|
|
|
0.876
|
|
|
|
1.052
|
|
Fourth Quarter
|
|
|
0.659
|
|
|
|
0.824
|
|
|
|
0.989
|
|
2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.610
|
|
|
|
0.763
|
|
|
|
0.915
|
|
Second Quarter
|
|
|
0.589
|
|
|
|
0.736
|
|
|
|
0.883
|
|
Third Quarter
|
|
|
0.571
|
|
|
|
0.713
|
|
|
|
0.856
|
|
Fourth Quarter
|
|
|
0.549
|
|
|
|
0.687
|
|
|
|
0.824
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.519
|
|
|
|
0.649
|
|
|
|
0.779
|
|
ECA does not as a matter of course make public projections as to
future sales, earnings, or other results. However, the
management of ECA has prepared the projected operational and
financial information set forth below in order to present the
target distributions attributable to the natural gas sales
volumes reflected in Ryder Scotts reserve report attached
hereto as Annex A. The target distributions, in the view of
ECAs management, were prepared on a reasonable basis based
on the assumptions outlined in Significant
assumptions used to prepare the target distributions.
The projections outlined below are not fact and should not be
relied upon as being necessarily indicative of future results.
Neither ECA nor the trust undertakes any obligation to update
the financial forecast to reflect events or circumstances after
the date of this prospectus and readers of this prospectus are
cautioned not to place undue reliance on the projected financial
information.
Neither ECAs independent auditors, nor any other
independent accountants, have compiled, examined, or performed
any procedures with respect to the projected financial
information contained herein, nor have they expressed any
opinion or any other form of assurance on such information or
its achievability, and assume no responsibility for, and
disclaim any association with, the projected financial
information.
The projections and assumptions on which they are based are
subject to significant uncertainties, many of which are beyond
the control of ECA and the trust. Actual cash distributions
to trust unitholders, therefore, could vary significantly based
upon events or conditions occurring that are different from the
events or conditions assumed to occur for purposes of these
projections. Cash distributions to trust unitholders will be
particularly sensitive to fluctuations in natural gas prices
production volumes. See Sensitivity of target
distributions to natural gas prices and volumes which
shows estimated effects to cash
60
distributions through March 31, 2011 from hypothetical
changes in natural gas prices as well as hypothetical changes in
production volumes. As a result of typical production declines
for natural gas properties, production estimates generally
decrease from year to year. However, the production estimates
included in the table below reflect that these declines are
expected to be offset by additional production from PUD Wells as
they are turned in line. The timing of the completion of, and
the amount of production attributable to the PUD Wells, are
substantially dependent on ECA executing its drilling plans with
respect to the drilling and completion of the PUD Wells in a
manner substantially similar to those underlying the assumptions
used in establishing these target distributions. Please see
Risk factors for risks relating to the timing of
drilling and amount of production attributable to the PUD Wells.
As a result of these factors, the target distributions shown
in the tables below are not necessarily indicative of
distributions for future years. Because payments to the
trust will be generated by depleting assets and the trust has a
finite life with the production from the Underlying Properties
diminishing over time, a portion of each distribution will
represent a return of trust unitholders original
investment. See Risk factors The natural gas
reserves attributable to the Underlying Properties of the trust
are depleting assets and production from those reserves will
diminish over time. Furthermore, the trust is generally
precluded from acquiring other oil and gas properties or royalty
interests to replace the depleting assets and production.
The table below presents the calculation of the target
distributions for each quarter through and including the quarter
ending June 30, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ending
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(In thousands, except well number, volumetric and per unit
data)
|
|
|
Number of Wells Expected to be Producing at Quarter End
|
|
|
8
|
|
|
|
17
|
|
|
|
22
|
|
|
|
25
|
|
|
|
31
|
|
Estimated Production from Trust Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas PDP Sales Volumes (MMcf)
|
|
|
675
|
|
|
|
1,318
|
|
|
|
1,464
|
|
|
|
1,204
|
|
|
|
1,073
|
|
Natural Gas PUD Sales Volumes (MMcf)
|
|
|
|
|
|
|
81
|
|
|
|
514
|
|
|
|
553
|
|
|
|
770
|
|
Total Sales Volumes (MMcf)
|
|
|
675
|
|
|
|
1,399
|
|
|
|
1,979
|
|
|
|
1,757
|
|
|
|
1,843
|
|
Daily Sales Volumes (MMcf/d)
|
|
|
7.4
|
|
|
|
15.2
|
|
|
|
21.5
|
|
|
|
19.5
|
|
|
|
20.2
|
|
Commodity Prices and Hedging Positions (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumed NYMEX Price ($/MMBtu) (2)
|
|
$
|
4.15
|
|
|
$
|
4.84
|
|
|
$
|
5.21
|
|
|
$
|
5.59
|
|
|
$
|
5.29
|
|
Assumed Price ($/Mcf)
|
|
|
4.27
|
|
|
|
4.99
|
|
|
|
5.36
|
|
|
|
5.76
|
|
|
|
5.45
|
|
Realized Unhedged Price after Basis Differential ($/Mcf) (3)
|
|
|
4.43
|
|
|
|
5.14
|
|
|
|
5.52
|
|
|
|
5.91
|
|
|
|
5.61
|
|
Daily Hedged Volumes
(MMcf/d)
|
|
|
7.3
|
|
|
|
7.3
|
|
|
|
9.7
|
|
|
|
9.0
|
|
|
|
9.5
|
|
Percent of Total Volumes Swapped
|
|
|
98
|
%
|
|
|
48
|
%
|
|
|
34
|
%
|
|
|
37
|
%
|
|
|
36
|
%
|
Swap Price ($/MMBtu)
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
Percent of Total Volumes Floored
|
|
|
|
|
|
|
|
|
|
|
11
|
%
|
|
|
9
|
%
|
|
|
11
|
%
|
Floor Price ($/MMBtu)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5.00
|
|
|
$
|
5.00
|
|
|
$
|
5.00
|
|
Realized Hedged Weighted Average Price ($/Mcf) (3)
|
|
$
|
7.06
|
|
|
$
|
6.08
|
|
|
$
|
6.06
|
|
|
$
|
6.36
|
|
|
$
|
6.15
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ending
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(In thousands, except well number, volumetric and per unit
data)
|
|
|
Estimated Cash Available for Distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Revenues
|
|
$
|
2,988
|
|
|
$
|
7,193
|
|
|
$
|
10,920
|
|
|
$
|
10,386
|
|
|
$
|
10,332
|
|
Swap and Floor Hedge Revenues
|
|
|
1,772
|
|
|
|
1,313
|
|
|
|
1,061
|
|
|
|
781
|
|
|
|
991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
4,760
|
|
|
$
|
8,506
|
|
|
$
|
11,981
|
|
|
$
|
11,167
|
|
|
$
|
11,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Production Services Fee (4)
|
|
$
|
361
|
|
|
$
|
749
|
|
|
$
|
1,060
|
|
|
$
|
941
|
|
|
$
|
987
|
|
Trust Expenses
|
|
|
200
|
|
|
|
200
|
|
|
|
200
|
|
|
|
200
|
|
|
|
201
|
|
Franchise Taxes
|
|
|
207
|
|
|
|
207
|
|
|
|
211
|
|
|
|
211
|
|
|
|
211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Available for Distribution
|
|
$
|
3,991
|
|
|
$
|
7,350
|
|
|
$
|
10,510
|
|
|
$
|
9,815
|
|
|
$
|
9,924
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust Units Outstanding
|
|
|
17,605
|
|
|
|
17,605
|
|
|
|
17,605
|
|
|
|
17,605
|
|
|
|
17,605
|
|
Target Distribution Per Trust Unit
|
|
$
|
0.227
|
|
|
$
|
0.417
|
|
|
$
|
0.597
|
|
|
$
|
0.558
|
|
|
$
|
0.564
|
|
Subordination Threshold Per Trust Unit
|
|
$
|
0.181
|
|
|
$
|
0.334
|
|
|
$
|
0.478
|
|
|
$
|
0.446
|
|
|
$
|
0.451
|
|
Incentive Threshold Per Trust Unit
|
|
$
|
0.272
|
|
|
$
|
0.501
|
|
|
$
|
0.716
|
|
|
$
|
0.669
|
|
|
$
|
0.676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
If actual cash available exceeds targeted by 20%
|
|
$
|
4,789
|
|
|
$
|
8,820
|
|
|
$
|
12,612
|
|
|
$
|
11,778
|
|
|
$
|
11,909
|
|
Cash necessary to meet incentive threshold
|
|
|
4,789
|
|
|
|
8,820
|
|
|
|
12,612
|
|
|
|
11,778
|
|
|
|
11,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess cash available above incentive threshold
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning hedge balance
|
|
|
4,958
|
|
|
|
5,082
|
|
|
|
5,209
|
|
|
|
5,339
|
|
|
|
5,473
|
|
Hedge recoupment to ECA (50% of excess cash available above
incentive threshold)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending hedge balance
|
|
|
4,958
|
|
|
|
5,082
|
|
|
|
5,209
|
|
|
|
5,339
|
|
|
|
5,473
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess cash available for incentive distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive distributions to ECA (50% of excess cash available
above incentive threshold)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess distributions to unitholders above the incentive
distributions
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ending
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(In thousands, except well number, volumetric and per unit
data)
|
|
|
If actual cash available exceeds targeted by 40%
|
|
$
|
5,588
|
|
|
$
|
10,290
|
|
|
$
|
14,714
|
|
|
$
|
13,741
|
|
|
$
|
13,894
|
|
Cash necessary to meet incentive threshold
|
|
|
4,789
|
|
|
|
8,820
|
|
|
|
12,612
|
|
|
|
11,778
|
|
|
|
11,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess cash available above incentive threshold
|
|
|
798
|
|
|
|
1,470
|
|
|
|
2,102
|
|
|
|
1,963
|
|
|
|
1,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning hedge balance
|
|
|
4,958
|
|
|
|
4,673
|
|
|
|
4,036
|
|
|
|
3,060
|
|
|
|
2,130
|
|
Hedge recoupment to ECA (50% of excess cash available above
incentive threshold)
|
|
|
399
|
|
|
|
735
|
|
|
|
1,051
|
|
|
|
982
|
|
|
|
992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending hedge balance
|
|
|
4,559
|
|
|
|
3,938
|
|
|
|
2,985
|
|
|
|
2,078
|
|
|
|
1,138
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess cash available for incentive distributions
|
|
|
399
|
|
|
|
735
|
|
|
|
1,051
|
|
|
|
982
|
|
|
|
992
|
|
Incentive distributions to ECA (50% of excess cash available
above incentive threshold)
|
|
|
399
|
|
|
|
735
|
|
|
|
1,051
|
|
|
|
982
|
|
|
|
992
|
|
Excess distributions to unitholders above the incentive
distributions
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
If actual cash available falls short of targeted by 20%
|
|
$
|
3,193
|
|
|
$
|
5,880
|
|
|
$
|
8,408
|
|
|
$
|
7,852
|
|
|
$
|
7,939
|
|
Cash available for distribution to common units before effect of
subordination
|
|
|
2,395
|
|
|
|
4,410
|
|
|
|
6,306
|
|
|
|
5,889
|
|
|
|
5,954
|
|
Cash necessary to meet common unit subordination threshold
|
|
|
2,395
|
|
|
|
4,410
|
|
|
|
6,306
|
|
|
|
5,889
|
|
|
|
5,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash short of subordination threshold
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash from subordinated units to support subordination threshold
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions to common unitholders
|
|
$
|
2,395
|
|
|
$
|
4,410
|
|
|
$
|
6,306
|
|
|
$
|
5,889
|
|
|
$
|
5,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions to subordinated units
|
|
$
|
798
|
|
|
$
|
1,470
|
|
|
$
|
2,102
|
|
|
$
|
1,963
|
|
|
$
|
1,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ending
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(In thousands, except well number, volumetric and per unit
data)
|
|
|
If actual cash available falls short of targeted by 40%
|
|
$
|
2,395
|
|
|
$
|
4,410
|
|
|
$
|
6,306
|
|
|
$
|
5,889
|
|
|
$
|
5,954
|
|
Cash available for distribution to common units before effect of
subordination
|
|
|
1,796
|
|
|
|
3,307
|
|
|
|
4,730
|
|
|
|
4,417
|
|
|
|
4,466
|
|
Cash necessary to meet common unit subordination threshold
|
|
|
2,395
|
|
|
|
4,410
|
|
|
|
6,306
|
|
|
|
5,889
|
|
|
|
5,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash short of subordination threshold
|
|
|
(599
|
)
|
|
|
(1,120
|
)
|
|
|
(1,577
|
)
|
|
|
(1,472
|
)
|
|
|
(1,489
|
)
|
Cash from subordinated units to support subordination threshold
|
|
|
599
|
|
|
|
1,102
|
|
|
|
1,577
|
|
|
|
1,472
|
|
|
|
1,489
|
|
Cash distributions to common unitholders
|
|
$
|
2,395
|
|
|
$
|
4,410
|
|
|
$
|
6,306
|
|
|
$
|
5,889
|
|
|
$
|
5,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions to subordinated units
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
For a more detailed description of
the natural gas hedging contracts established for the benefit of
the trust, please see Description of the royalty
interests.
|
|
|
|
(2)
|
|
Based on settled NYMEX pricing for
April, May and June 2010 of $3.842, $4.271 and $4.155 per MMBtu,
respectively, and NYMEX forward pricing as of June 4, 2010
for the thirty three month period ending March 31, 2013.
Assumed price per Mcf calculated based on an assumed conversion
rate of 1.03 MMBtu per Mcf.
|
|
(3)
|
|
Adjusted for an assumed basis
differential of $0.15 per MMBtu.
|
|
(4)
|
|
Consists of a fee of $0.52 per
MMBtu.
|
SIGNIFICANT
ASSUMPTIONS USED TO PREPARE THE TARGET DISTRIBUTIONS
In preparing the target distributions and subordination and
incentive threshold tables above and sensitivity tables below,
the revenues and expenses of the trust were calculated based on
the terms of the conveyances creating the trusts royalty
interests using the following assumptions and those set forth
above under Target distributions and subordination and
incentive thresholds. These calculations are described
under Description of the royalty interests.
Production estimates. Production estimates for each
of the quarters during the life of the trust are based on the
reserve report. The estimates of reserves and production
relating to the Underlying Properties and the royalty interests
included in the reserve report have been made in accordance with
the SECs new rules for reserve reporting. Production
attributable to the royalty interests from the Underlying
Properties for the twelve months ending June 30, 2011 is
estimated to be 6,977 MMcfe of natural gas. The estimated
production in the forecast period gives effect to the drilling
and completion by ECA of three PUD Wells in the third quarter of
2010; five PUD Wells in the fourth quarter of 2010; three PUD
Wells in the first quarter of 2011; six PUD Wells in the second
quarter of 2011; and the completion by ECA of its drilling
obligation to the trust by March 31, 2013. See
Natural gas prices below for a
description of changes in production due to price variations.
Differing levels of production will result in different levels
of distributions and cash returns.
64
Natural gas prices. The hypothetical natural gas
prices utilized for purposes of preparing the target
distributions are based on estimated market prices for natural
gas based on settled NYMEX pricing for April, May and June 2010
of $3.842, $4.271 and $4.155 per MMBtu, respectively, and NYMEX
forward pricing as of June 4, 2010 for the thirty three
month period ending March 31, 2013 and increased thereafter
by a 2.5% annual escalator (as adjusted for a basis differential
of $0.15 per MMBtu), capped at $9.00 per MMBtu starting in 2027.
The table below sets forth settled NYMEX pricing for April, May
and June of 2010 and NYMEX forward pricing as of June 4,
2010 for the 33 month period ending March 31, 2013.
Estimated
Market Prices for Natural Gas
Based on Settled NYMEX Pricing
as of June 4, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
|
2011
|
|
|
|
2012
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
|
January
|
|
$
|
5.664
|
|
|
January
|
|
$
|
6.205
|
|
|
January
|
|
$
|
6.437
|
|
|
|
|
|
|
|
February
|
|
$
|
5.618
|
|
|
February
|
|
$
|
6.140
|
|
|
February
|
|
$
|
6.377
|
|
|
|
|
|
|
|
March
|
|
$
|
5.491
|
|
|
March
|
|
$
|
5.965
|
|
|
March
|
|
$
|
6.182
|
|
April
|
|
$
|
3.842
|
|
|
April
|
|
$
|
5.264
|
|
|
April
|
|
$
|
5.507
|
|
|
|
|
|
|
|
May
|
|
$
|
4.271
|
|
|
May
|
|
$
|
5.282
|
|
|
May
|
|
$
|
5.511
|
|
|
|
|
|
|
|
June
|
|
$
|
4.155
|
|
|
June
|
|
$
|
5.329
|
|
|
June
|
|
$
|
5.544
|
|
|
|
|
|
|
|
July
|
|
$
|
4.797
|
|
|
July
|
|
$
|
5.384
|
|
|
July
|
|
$
|
5.604
|
|
|
|
|
|
|
|
August
|
|
$
|
4.842
|
|
|
August
|
|
$
|
5.430
|
|
|
August
|
|
$
|
5.654
|
|
|
|
|
|
|
|
September
|
|
$
|
4.863
|
|
|
September
|
|
$
|
5.457
|
|
|
September
|
|
$
|
5.684
|
|
|
|
|
|
|
|
October
|
|
$
|
4.940
|
|
|
October
|
|
$
|
5.544
|
|
|
October
|
|
$
|
5.777
|
|
|
|
|
|
|
|
November
|
|
$
|
5.202
|
|
|
November
|
|
$
|
5.767
|
|
|
November
|
|
$
|
6.002
|
|
|
|
|
|
|
|
December
|
|
$
|
5.490
|
|
|
December
|
|
$
|
6.025
|
|
|
December
|
|
$
|
6.247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The assumed price per Mcf is calculated based on an assumed
conversion rate of 1.03 MMBtu per Mcf. Actual MMBtu per Mcf may
differ as it will be based on the actual heat content of the gas
produced. These prices estimate market prices of $4.15 per MMBtu
for the quarter ending June 30, 2010, $4.84 per MMBtu for
the quarter ending September 30, 2010, $5.21 per MMBtu for
the quarter ending December 31, 2010, $5.59 per MMBtu for
the quarter ending March 31, 2011 and $5.29 per MMBtu
for the quarter ending June 30, 2011. We have assumed that
50% of the estimated natural gas production attributable to the
trusts royalty interests will be hedged from April 1,
2010 to March 31, 2014. These floor price contracts will be
transferred to the trust by ECA, while ECA will enter into a
back-to-back swap agreement with the trust, and ECA will be
entitled to recoup the costs of establishing the floor price
contracts if cash available for distribution by the trust
reaches certain levels. The average realized sales price for gas
gathered and sold on ECAs Greene County Gathering System
(prior to any post-production costs) for the twelve months ended
June 30, 2009 was $6.85 per MMBtu. This was
approximately $0.46 above the average closing NYMEX natural gas
futures contract prices for the same period. However, if
previously occurring location, quality and other differentials
change in the future, there may be more significant differences
between the natural gas price received and the NYMEX price than
the assumed $0.15 per MMBtu differential used in these
estimations. In addition, the market price of natural gas is
generally higher in the winter months than during the other
months of the year due to increased demand for natural gas for
heating purposes during the winter season. The price of natural
gas fluctuates based on levels of supply and demand at any given
time. The adjustments to realized natural gas prices applied in
the tables above are based upon an analysis by ECA of the
historic price differentials for production from the Underlying
65
Properties with consideration given to quality and
transportation and marketing costs that may affect these
differentials for the forecast period. There is no assurance
that these assumed differentials will be the same during the
periods presented in the tables above.
If natural gas prices decline, the operators of producing oil
and gas properties may elect to reduce or completely suspend
production. ECA is required under the applicable conveyance to
act as a reasonably prudent operator with respect to the
Underlying Properties under the same or similar circumstances as
it would act if it were acting with respect to its own
properties, disregarding the existence of the royalty interests
as burdens affecting such property. No adjustments have been
made to estimated production in the tables above to reflect
potential reductions or suspensions of production.
Administrative expense. Trust administrative expense
per year is expected to be approximately $800,000 per year,
although such costs could be greater or less depending on future
events that cannot be predicted. Included in the $800,000 annual
estimate, among other miscellaneous items, is an annual
administrative fee of $150,000 for the trustee and an annual
administrative fee of $2,400 for the Delaware trustee. In
addition, the trust will pay an annual administrative fee to ECA
pursuant to the Administrative Services Agreement, which fee
will total $60,000 per year which will remain flat for the life
of the trust. The balance ($740,000) is escalated at 2.5%
annually starting in the second quarter of 2011. The trust will
also pay, out of the first cash payment received by the trust,
the trustees and Delaware trustees legal expenses
incurred in forming the trust as well as the Delaware
trustees acceptance fee in the amount of $125,000. These
costs will be deducted by the trust before distributions are
made to trust unitholders.
Tax treatment of royalty interests. For federal
income tax purposes, the Term PDP Royalty will be and the Term
PUD Royalty should be treated as debt instruments. Accordingly,
the Term Royalties will be subject to the original issue
discount, or OID, rules of the Internal Revenue Code which
require that payments made to the trust with respect to the Term
Royalties will be treated first as consisting of a payment of
interest to the extent of interest deemed accrued under the OID
rules at the applicable federal rate and the excess, if any,
will be treated as a payment of principal (which is
non-taxable). For federal income tax purposes, the Perpetual PDP
Royalties will be, and the Perpetual PUD Royalties should be,
treated as mineral royalty interests, which give rise to
ordinary income subject to depletion.
Timing of actual cash distributions. The payments by
ECA in respect of the royalty interests will be made by ECA on
an accrual basis. As used herein, accrual basis means ECA will
pay to the trust each calendar quarter an amount equal to the
proceeds of estimated production from the trust properties
during the calendar quarter most recently ended before the
distribution.
Post-production costs. The Post-Production Services
Fee of $0.52 per MMBtu is held flat for the life of the trust in
the reserve report. The actual Post-Production Services Fee of
$0.52 per MMBtu may differ once ECAs drilling obligation
is fulfilled. ECA may increase this fee to the extent necessary
to recover certain capital expenditures on the Greene County
Gathering System after the completion of the drilling period,
provided the resulting charge does not exceed the prevailing
charges in the area for similar services.
Estimated total reserves and quarterly production volumes are
net of an assumed 5% natural gas fuel compression charge and
line loss, which percentage is based off of ECAs
historical experience in Greene County, Pennsylvania. In the
event that ECA chooses to use electrical compression in the
future, costs would differ. Actual compressor fuel charges and
line loss will be allocated to the trusts interests and
may differ from the 5% assumed in the reserve report. No
66
other post-production costs were contemplated in the target
distributions but the trust would be responsible for any new
post-production costs.
Applicable taxes. There are currently no taxes in
Pennsylvania related to the production or severance of oil and
natural gas in Pennsylvania. Pennsylvania has not historically
imposed any such taxes, but legislation is pending in the
Pennsylvania Senate Finance and the House Energy and
Environmental Resources Committees that provides for a severance
tax of 5% on the value of the natural gas at the wellhead plus
$0.047 per thousand cubic feet of natural gas severed. See
Risk factors Recently proposed severance taxes
in Pennsylvania could materially increase the post-production
costs that are borne by the trust. In addition, the trust
will be required to pay Pennsylvania franchise tax on its
capital stock value, as determined pursuant to the statute and
apportioned to Pennsylvania. The current tax rate of 0.289% is
currently scheduled to be reduced to 0.189% in 2012 and 0.089%
in 2013 and to be completely phased out in 2014. This schedule
may be altered and the taxes left in place subsequent to the
General Assembly in its annual budget process.
Hedge cost reimbursement. To the extent that the
trust has cash available for distribution in excess of the
incentive thresholds during the subordination period, ECA will
be entitled to receive 50% of such cash as incentive
distributions and 50% of such cash as recoupment of its costs
for establishing the hedge contracts until it has recouped
approximately $5 million, plus interest. The incentive
distributions and the hedging reimbursement terminate upon
completion of the subordination period.
SENSITIVITY
OF TARGET DISTRIBUTIONS TO CHANGES IN NATURAL GAS PRICES AND
VOLUMES
The amount of revenues of the trust and cash distributions to
the trust unitholders will be directly dependent on the sales
price for natural gas sold, the volumes of gas produced and, to
some degree, variations in property and production taxes, if
any, and post-production costs. The following tables demonstrate
the projected effect that hypothetical changes in the estimated
gas production for the forecast period ending June 30, 2011
as reflected in the reserve report and the impact that
hypothetical fluctuations in assumed realized gas prices could
have on cash distributions to the trust unitholders.
These tables set forth the sensitivity of annual cash
distributions per trust unit for the forecast period ending
June 30, 2011 based upon (1) the assumption that a
total of 17,605,000 trust units are issued and outstanding after
the closing of the offering made hereby; (2) an assumed
initial public offering price of $20.00 per common unit;
(3) various realizations of production levels estimated in
the reserve report; (4) various hypothetical realized gas
prices; (5) the impact of the natural gas hedging contracts
owned by the trust that entitle the trust to receive payments
from the counterparties to such contracts, including ECA, in the
event that natural gas prices are lower than the floor prices
specified in the contracts; (6) assumptions regarding
applicable taxes and post-production costs; (7) assumptions
regarding administrative expenses; and (8) other
assumptions described below under Significant
assumptions used to prepare the target distributions. The
hypothetical realized prices of gas production shown have been
chosen solely for illustrative purposes.
The tables give effect to the subordination and incentive
distribution features that are contained in the terms of the
trust. For a description of the way in which those features
would impact trust unitholders distributions, please see
Target distributions and subordination and incentive
thresholds.
67
The below tables are not a projection or forecast of the
actual or estimated results from an investment in the common
units. The purpose of these tables is to illustrate the
sensitivity of cash distributions to changes in production
levels and the price of natural gas. There is no assurance that
the hypothetical assumptions described below will actually occur
or that production levels and the price of natural gas will not
change by amounts different from those shown in the tables.
The trusts natural gas hedging contracts will be in
effect only through March 31, 2014, and thus there is
likely to be greater fluctuation in cash distributions resulting
from fluctuations in realized natural gas prices in periods
subsequent to the expiration of those contracts. See Risk
factors for a discussion of various items that could
impact production levels and the price of natural gas.
These distributions are sensitized to both assumed NYMEX natural
gas prices as well as the assumed production from the trust
properties. The quarterly distributions in the tables below are
based on assumptions outlined in Significant
assumptions used to prepare the target distributions. In
the tables set forth below, we have provided examples of
possible distributions for the quarters ending June 30,
2010, September 30, 2010, December 31, 2010 and
March 31, 2011 based on various NYMEX pricing and
production assumptions.
For scenarios in these tables which involve lower NYMEX gas
prices and production volumes, the quarterly distribution per
unit does not fall below the subordination threshold because
either the per unit cash available for distribution to trust
unitholders was at or above the subordination threshold or the
cash flows to the subordinated units support the distributions
to the common units. For scenarios in these tables with higher
gas prices and production volumes, the quarterly distribution
per unit does not exceed the incentive threshold either because
the per unit cash available for distribution to trust
unitholders was at or below the incentive threshold or because
the per unit cash available for distribution in excess of the
incentive threshold is used to reimburse ECA for its costs of
approximately $5 million plus interest accrued at 10% per
annum for establishing the natural gas hedging contracts
transferred to the trust.
68
For each table, the assumed NYMEX gas price per MMBtu used to
estimate quarterly distributions is also the assumed NYMEX gas
price for all previous quarters. In order for a trust unitholder
to receive a distribution in excess of the incentive threshold,
the hedge cost must be repaid to ECA in full.
69
THE
UNDERLYING PROPERTIES
The Underlying Properties consist of the working interests owned
by ECA and the Private Investors in the Marcellus Shale
formation in Greene County, Pennsylvania arising under leases
and farmout agreements related to properties from which the PDP
Royalty Interest and the PUD Royalty Interest will be conveyed.
There are in excess of 100 potential drilling locations for the
PUD Wells within the AMI. As of March 31, 2010 and after
giving effect to the conveyance of the PDP Royalty Interest and
the PUD Royalty Interest, the total gas reserves attributable to
the trust interests were 108.6 Bcf. This amount includes
73.5 Bcf attributable to the PUD Royalty Interest and
35.1 Bcf attributable to the PDP Royalty Interest. ECA is
currently the operator of all of the wells subject to the PDP
Royalty Interest. ECA has an average working interest of
approximately 93% in the wells subject to the PDP Royalty
Interest. Two third parties hold an approximate 50% and 35%
working interest in two Producing Wells. ECA holds the remaining
approximate 50% and 65% working interest in such wells. The
reserves attributable to the trusts royalty interests
include the reserves that are expected to be produced from the
Marcellus Shale formation during the
20-year
period in which the trust owns the royalty interests as well as
the residual interest in the reserves that the trust will sell
on or shortly following the Termination Date.
As of March 31, 2010, the Underlying Properties include
eight gross (7.65 net) productive gas wells which encompass
approximately 493 gross (474 net) productive acres.
Immediately following the completion and initial production of
the final six Producing Wells (currently classified as proved
behind pipe), the Underlying Properties will include
14 gross (13.15 net) productive gas wells encompassing
819 gross (769 net) productive acres. Currently, the
Underlying Properties include approximately 9,300 acres of
which ECA owns substantially all of the working interests.
70
HISTORICAL
RESULTS FROM THE PRODUCING WELLS
The following table provides revenues and direct operating
expenses relating to the Producing Wells for the year ended
December 31, 2009 and for the three months ended
March 31, 2010, derived from the Underlying
Properties statements of revenues and direct operating
expenses included elsewhere in this prospectus. During the year
ended December 31, 2009, only four of the 14 Producing
Wells were completed while eight of the 14 producing wells
were completed as of March 31, 2010. As a result, the
information in the table set forth below will not be comparable
to the trusts results going forward as ECA completes
additional Producing Wells. The information in the table below
does not reflect the formation of the trust or the conveyance of
the PDP Royalty Interest to the trust. The selected financial
data presented below should be read in conjunction with the
audited statement of revenues and direct operating expenses of
the Underlying Properties, the related notes and
Discussion and Analysis of Historical Results from the
Producing Wells included elsewhere in this prospectus and
the discussion of ECAs business and related
Managements Discussion and Analysis of Financial Condition
and Results of Operations of Energy Corporation of America set
forth in Information about Energy Corporation of
America.
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
Three Months Ended
|
Historical Results
|
|
December 31, 2009
|
|
March 31, 2010
|
|
|
|
|
(unaudited)
|
|
|
(Dollars in thousands,
|
|
|
except volumetric data)
|
|
Natural gas sales volumes (Mcf) (unaudited) (1)
|
|
|
841,261
|
|
|
|
724,343
|
|
Gross sales price per Mcf (unaudited)
|
|
$
|
4.31
|
|
|
$
|
5.66
|
|
|
|
|
|
|
|
|
|
|
Revenues from gas sales
|
|
$
|
3,623
|
|
|
$
|
4,100
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
Production and property taxes
|
|
|
|
|
|
|
|
|
Production expenses
|
|
|
24
|
|
|
|
16
|
|
Marketing fee (2)
|
|
|
132
|
|
|
|
111
|
|
Gathering and transportation charges
|
|
|
458
|
|
|
|
385
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
614
|
|
|
|
512
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
3,009
|
|
|
$
|
3,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Natural gas sales volumes represent
volumes attributable to ECAs interest only and are net of
all burdens and any third-party interest in the wells. Gross
production volumes from the four completed wells were 1,061,934
Mcf for the year ended December 31, 2009 and from the eight
completed wells were 912,890 Mcf for the three months ended
March 31, 2010.
|
|
(2)
|
|
A wholly-owned subsidiary of ECA
markets the production from the Underlying Properties.
Historically, such subsidiary has charged a marketing fee for
its services; however, the trust will not be charged a marketing
fee by ECA for marketing production.
|
71
NATURAL
GAS SALES PRICES AND PRODUCTION COSTS
The following table sets forth the production, the average sales
price per Mcf and the production costs for the year ended
December 31, 2009 and three months ended March 31,
2010 for the Producing Wells on a historical basis and for the
year ended on December 31, 2009 and three months ended on
March 31, 2010 for the royalty interests on a pro forma
basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical for
|
|
Pro forma for
|
|
Historical for
|
|
Pro forma for
|
|
|
Producing Wells
|
|
Royalty Interest (1)
|
|
Producing Wells
|
|
Royalty Interest (1)
|
|
|
Year Ended
|
|
Year Ended
|
|
Three Months Ended
|
|
Three Months Ended
|
|
|
December 31,
|
|
December 31,
|
|
March 31,
|
|
March 31,
|
|
|
2009
|
|
2009
|
|
2010
|
|
2010
|
|
Production (MMcf)
|
|
|
841
|
|
|
|
757
|
|
|
|
724
|
|
|
|
652
|
|
Average net sales price per Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average gross sales price per Mcf
|
|
$
|
4.31
|
|
|
$
|
4.31
|
|
|
$
|
5.66
|
|
|
$
|
5.66
|
|
Gathering and transportation charges (Mcf)
|
|
|
0.54
|
|
|
|
0.54
|
|
|
|
0.53
|
|
|
|
0.53
|
|
Average sales price (2)
|
|
|
3.60
|
|
|
|
3.76
|
|
|
|
4.98
|
|
|
|
5.13
|
|
Average production cost per Mcf (3)
|
|
|
0.03
|
|
|
|
|
|
|
|
0.02
|
|
|
|
|
|
|
|
|
(1)
|
|
Pro forma figures are calculated as
if the conveyances were in effect for the period indicated.
|
|
(2)
|
|
Average sales price generally
represents the realized price of gas which is net of
post-production costs and applicable taxes, if any.
|
|
(3)
|
|
Production costs include lease
operating costs.
|
DISCUSSION
AND ANALYSIS OF HISTORICAL RESULTS FROM THE PRODUCING
WELLS
During the year ended December 31, 2009, ECA drilled and
completed four horizontal wells in the Marcellus Shale formation
in Greene County, Pennsylvania. The first of these wells began
producing and selling natural gas on July 17, 2009. One of
the remaining three wells was put into production during
each of the months of August, September and October 2009. These
wells were drilled with an average lateral length of
2,000 feet and completed with an average of 7.5 fracture
stimulations per well. Aggregate monthly production ranged from
a low of 35,690 Mcf during the month of July 2009 to a high
of 192,445 Mcf during the month of November 2009 and ended
the period with all four wells in line and producing an average
of more than 5,600 Mcf per day in aggregate. Total volumes
produced and sold during the period, from the four wells were
841,261 Mcf.
The average gross sales price received for gas produced during
the year ended December 31, 2009 was $4.31 per Mcf, before
deduction of any post-production costs or operating expenses.
Gross sales prices received ranged from a low of $3.06 per Mcf
during the month of September 2009 to a high of $5.34 per Mcf
during the month of December 2009. Post-production costs, which
consisted of a gathering fee of $0.54 per Mcf and a marketing
fee of $0.16 per Mcf, totaled $590,439 for the period. Operating
expenses averaged approximately $1,333 per well month during the
period. Revenues less direct operating expenses were
approximately $3.01 million for the year ended
December 31, 2009.
72
During the three months ended March 31, 2010, ECA drilled
and completed four horizontal wells in the Marcellus Shale
formation in Greene County, Pennsylvania. Two of these wells
were put into production during January 2010, while one
additional well was put into production in February 2010.
These wells were drilled with an average lateral length of 2,767
feet and completed with an average of 10.5 fracture stimulations
per well. Aggregate monthly production ranged from a low of
190,453 Mcf during the month of January 2010 to a high of
311,196 Mcf during the month of March 2010. With seven
wells in line and producing during the month of March 2010, the
average daily production was more than 10,000 Mcf per day in the
aggregate. Total volumes produced and sold during the three
month period were 724,343 Mcf.
The average gross sales price received for gas produced during
the three months ended March 31, 2010 was $5.66 per Mcf,
before deduction of any post-production costs or operating
expenses. Post-production costs, which consisted of a gathering
fee of $0.53 per Mcf and a marketing fee of $0.15 per Mcf,
totaled $496,009 for the period. Operating expenses averaged
approximately $783 per well month during the period. Revenues
less direct operating expenses were approximately $3.59 million
for the three months ended March 31, 2010.
THE
UNDERLYING PUD PROPERTIES
At the completion of this offering, the underlying PUD
properties will consist of all of the working interests in
proved undeveloped gas properties in the AMI held by ECA. The
interests of ECA in the gas properties to which the underlying
PUD properties relate consist of working interests of
approximately 100%. The conveyance related to the PUD Royalty
Interest, however, provides that the proceeds from the PUD Wells
will be calculated on the basis that the underlying PUD Wells
are only burdened by interests that in total would not exceed
12.5% of the revenues from such properties, regardless of
whether the other interest owners are actually entitled to a
greater percentage of revenues from such properties. The AMI is
located in Greene County, Pennsylvania, which is in southwestern
Pennsylvania and consists of approximately 121 square miles.
The PUD Royalty Interest will entitle the trust to receive an
undivided 50% interest in the proceeds from the sale of future
production of natural gas resulting from the drilling of the PUD
Wells. Once ECA has drilled all of the PUD Wells, the trustee
will be required to release the Drilling Support Lien.
ECA will covenant and agree not to drill and complete, and will
not permit any other person within its control to drill and
complete, any well in the Marcellus Shale formation on the lease
acreage included within the AMI described above for its own
account until such time as ECA has met its commitment to drill
the PUD Wells. Upon the trustees release of the Drilling
Support Lien, ECA will further agree not to drill and complete,
and will not permit any other person within its control to drill
and complete, any well in the Marcellus Shale formation on the
lease acreage that will have a perforated segment that will be
within 500 feet of any perforated interval of any PUD or
Producing Well.
ECA, in the conveyance documents for the PUD Royalty Interest,
will expressly except and reserve all right, title and interest
in and to any well and appurtenant production facilities not
expressly conveyed to the trust. The PDP Royalty Interest is
included within the AMI and those properties will remain subject
to the terms and conditions of the PDP Royalty Interest
conveyance documents.
The PUD Royalty Interest conveyances shall further provide that
the PUD Royalty Interest of the trust will be applicable to any
additional acreage leased or acquired by any other means by ECA
within the AMI until the drilling obligation of ECA to the trust
is met. Subject to the terms
73
of the PUD Royalty Interest, ECA, in its sole discretion, may
add such additional acreage to the trust, and may exchange
acreage for other acreage in the AMI, provided the aggregate
acreage attributable to additional leases and the exchange
leases shall not exceed five percent of the acreage currently
subject to the PUD Royalty Interest. No assurance can be given,
however, that any development well will produce in commercial
quantities or that the characteristics of any development well
will match the characteristics of ECAs existing wells or
ECAs historical drilling success rate. ECA operates all of
the Producing Wells and will agree to operate not less than 90%
of the PUD Wells during the subordination period.
NATURAL
GAS RESERVES
Ryder Scott estimated natural gas reserves attributable to the
Underlying Properties as of March 31, 2010. Numerous
uncertainties are inherent in estimating reserve volumes and
values, and the estimates are subject to change as additional
information becomes available. The reserves actually recovered
and the timing of production of the reserves may vary
significantly from the original estimates.
Proved reserves of Underlying Properties and royalty
interests. The following table, effective as of
March 31, 2010, contains certain estimated proved reserves,
estimated future net revenues and the discounted present value
thereof attributable to both the Underlying Properties and the
royalty interests, in each case derived from the reserve report.
The reserve report was prepared by Ryder Scott in accordance
with criteria established by the SEC. In accordance with the
SECs new rules, the reserves presented below were
determined using the twelve month unweighted arithmetic average
of the
first-day-of-the-month
price for the period from April 1, 2009 through
March 1, 2010, without giving effect to any derivative
transactions, and were held constant for the life of the
properties. This yielded a price for natural gas of $3.984 per
MMBtu. Proved reserve quantities attributable to the royalty
interests are calculated by multiplying the gross reserves for
each property by the royalty interest assigned to the trust in
each property. The net revenues attributable to the trusts
reserves are net of the trusts obligation to reimburse ECA
for the post-production costs. The reserves related to the
Underlying Properties include all of the proved reserves
expected to be economically produced from the Marcellus Shale
formation during the life of the properties. The reserves and
revenues attributable to the trusts interests include only
the reserves attributable to the Underlying Properties that are
expected to be produced within the
20-year
period in which the trust owns the royalty interest as well as
the 50% residual interest in the reserves that the trust will
own on the Termination Date. A summary of the reserve report is
included as Annex A to this prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Gas
|
|
|
|
Discounted
|
|
|
Reserves
|
|
Estimated Future
|
|
Estimated Future
|
Proved reserves
|
|
(Bcf)
|
|
Net Revenues
|
|
Net Revenues (1)
|
|
|
(Dollars in thousands)
|
|
Underlying Properties
|
|
|
202.0
|
|
|
$
|
535,435
|
|
|
$
|
175,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty Interests:
|
|
|
|
|
|
|
|
|
|
|
|
|
PDP Royalty Interest (90%) (2)
|
|
|
35.1
|
|
|
$
|
130,690
|
|
|
$
|
72,560
|
|
PUD Royalty Interest (50%)
|
|
|
73.5
|
|
|
$
|
273,267
|
|
|
$
|
133,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
108.6
|
|
|
$
|
403,957
|
|
|
$
|
205,875
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The present values of future net
revenues for the Underlying Properties and the royalty interests
were determined using a discount rate of 10% per annum.
|
|
(2)
|
|
Includes reserves currently behind
pipe in existing wells which are in the process of being
completed.
|
74
Information concerning historical changes in net proved reserves
attributable to the Underlying Properties, and the calculation
of the standardized measure of discounted future net revenues
related thereto, is contained in the unaudited supplemental
information contained elsewhere in this prospectus. ECA has not
filed reserve estimates covering the Underlying Properties with
any other federal authority or agency.
THE
RESERVE REPORT
Technologies. The reserve report was prepared using
decline curve analysis to determine the reserves of individual
Producing Wells. After estimating the reserves of each proved
developed well, it was determined that a reasonable level of
certainty exists with respect to the reserves which can be
expected from any individual undeveloped well in the field. The
consistency of reserves attributable to the Producing Wells,
which cover a wide area of the AMI, further supports proved
undeveloped classification.
Also, a 3-D
seismic survey was shot and interpreted across substantially all
of the AMI and has been used to confirm the consistency of
important reservoir properties throughout the AMI. Seismic
interpretation has been used to support our belief of a
consistency of Marcellus Shale formation thickness across the
AMI, which is further substantiated by electric log and mudlog
data from wells drilled on the Underlying Properties and
adjacent wells drilled by third-party operators. Also, ECA has
recently begun using seismic analysis of structural features on
the Underlying Properties to optimally place PUD Wells within
the acreage. By observing faults and other structural features
within the acreage, ECA is able to place PUD Wells so that they
will have the longest lateral length possible while staying in
the Marcellus Shale formation by avoiding significant faults.
The location of these faults also confirms the number of
potential proved undeveloped locations on the acreage and
indicates that the PUD locations will be able to be drilled
without crossing significant faults or encountering structural
features, such as steeply dipping beds near faults, which could
limit lateral length. Electric logs and other geologic and
engineering data gathered from proved developed wells and
vertical Marcellus Shale wells ECA has previously drilled across
the AMI further support the consistency of the Marcellus Shale
reservoir throughout the AMI. Finally, ECA regularly trades
geologic, engineering, and operations data with other operators
in the area surrounding the AMI. This technical and production
data further supports the consistency of the Marcellus Shale in
and around the AMI.
While a number of PUD Wells within the Underlying Properties are
not direct offsets of other producing wells, both ECA and Ryder
Scott, as independent petroleum engineers, were reasonably
certain that all of the undrilled wells could be classified as
PUD Wells because of the consistency of the Marcellus Shale
formation across the AMI. As noted above,
3-D seismic
data has been used to target PUD Well placement so as to avoid
encountering significant faults or structural features. Data
from both ECA and offset operators with which ECA has exchanged
technical data demonstrate a consistency in this resource play
over an area much larger than the AMI. In addition, direct
measurement from other producing wells has also been used to
confirm consistency in reservoir properties such as total
organic content, vitrinite reflectance, porosity, thickness, and
stratigraphic conformity. Most importantly, production from
other producing wells confirms that horizontal Marcellus Shale
wells across the AMI have similar performance with respect to
initial production, decline curve shape, and estimated ultimate
recovery, consistent with the characteristics of a resource play.
Internal Controls. Ryder Scott, the independent
petroleum engineering consultant, estimated, in accordance with
appropriate engineering, geologic, and evaluation principles and
techniques that are in accordance with practices generally
accepted in the petroleum industry, and definitions and
guidelines established by the SEC, all of the proved reserve
information in this registration statement. These reserves
estimation methods and techniques are widely taught in
75
university petroleum curricula and throughout the
industrys ongoing training programs. Although these
appropriate engineering, geologic, and evaluation principles and
techniques that are in accordance with practices generally
accepted in the petroleum industry are based upon established
scientific concepts, the application of such principles involves
extensive judgment and is subject to changes in existing
knowledge and technology, economic conditions and applicable
statutory and regulatory provisions. These same industry wide
applied techniques are used in determining our estimated reserve
quantities. The technical persons responsible for preparing the
reserves estimates presented herein meet the requirements
regarding qualifications, independence, objectivity and
confidentiality set forth in the Society of Petroleum
Engineers Standards Pertaining to the Estimating and
Auditing of Oil and Gas Reserves Information. ECAs
internal control over its reserve reporting process is designed
to result in accurate and reliable estimates in compliance with
applicable regulations and guidance. Internal reserve
preparation is performed by staff reservoir engineers and
geoscientists before review by the Reservoir Engineering Manager
and finally the Vice President of Eastern Operations. These
individuals consult regularly with Ryder Scott during the
reserve estimation process to review properties, assumptions,
and any new data available. Additionally, ECAs senior
management reviewed and approved all Ryder Scott reserve reports
contained herein.
ECAs reserves are first estimated by a Staff Reservoir
Engineer before being reviewed by the Reservoir Engineering
Manager. The Reservoir Engineering Manager has a Bachelor of
Science in Petroleum and Natural Gas Engineering and a Master of
Business Administration. He has over 28 years of oil and
gas industry experience in drilling and completions, reservoir
engineering, and acquisitions and divestitures. During the past
18 years, he has focused on reserves estimates and asset
development.
ECAs Vice President of Eastern Operations is the primary
technical person responsible for overseeing the reserve
reporting process. This individual has a Bachelor of Science
degree in Chemical Engineering with Masters of Petroleum
Engineering coursework along with a Master of Business
Administration degree. He has worked in drilling, completions,
production, and reservoir engineering along with acquisitions
during his career and is a member of the Society of Petroleum
Engineers. He has over six years of experience in reserve
evaluation.
Material Changes. The reserve report for Underlying
Properties was prepared for the first time as of
December 31, 2009. At this time, four of the wells were
classified as proved developed wells, three wells were
classified as proved behind pipe, with the remaining
59 wells to be drilled classified as PUD wells. During the
three months prior to the March 31, 2010 report, ECA
completed the three proved behind pipe wells along with one
proved undeveloped well, all of which were converted to proved
developed wells. Additionally, ECA was preparing for completion
six wells, which were converted from proved undeveloped to
proved behind pipe wells. As a part of the Development
Agreement, ECA has an obligation to drill all 52 PUD Wells by
March 31, 2013, and no later than March 31, 2014 if
delays occur. Therefore, upon its completion of its drilling
obligation, ECA anticipates that all proved undeveloped reserves
should be converted to proved developed reserves.
During the three month period from December 31, 2009 to
March 31, 2010, ECA spent $6,750,000 converting four wells
from proved behind pipe or proved undeveloped to proved
developed reserves, and ECA spent $4,295,000 converting six
proved undeveloped wells to proved behind pipe wells.
During the three month period from December 31, 2009 to
March 31 2010, ECA drilled four productive development wells and
zero dry wells. Also during this time, ECA began preparation for
the completion process for the wells currently classified as
proved behind pipe reserves.
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As of March 31, 2010, ECA was preparing for the completion
of the final six proved developed wells on the Underlying
Properties, which are currently classified as proved behind pipe
wells within the reserve report. These wells are all located on
the same pad drilling location and will be completed at the same
time.
Well
Locations
ECA has over 100 locations within the AMI and may drill some of
the PUD Wells on units that encompass land controlled by
third-party operators in order to maximize recovery in the field
and also maximize the lateral length of each PUD Well drilled.
If ECA drills one or more PUD Wells in which it controls less
than 100% working interest, it will be obligated to drill
additional PUD Wells above the 52 planned for the trust in order
to make the total number of net (equivalent) PUD Wells equal 52.
For instance, if ECA drilled one well in which it controlled 50%
working interest, and it was drilled to a horizontal lateral
length of 2,500 feet, this well would only count as
one-half of a PUD Well. In order to compensate for this, ECA
would be obligated to drill an additional PUD Well with a
horizontal lateral length of 2,500 feet and a 50% working
interest so that the trust still received in total 52 equivalent
wells.
SALE AND
ABANDONMENT OF UNDERLYING PROPERTIES
ECA and any transferee will have the right to abandon its
interest in any well or property comprising a portion of the
Underlying Properties if, in its opinion, such well or property
ceases to produce or is not capable of producing in commercially
paying quantities. To reduce or eliminate the potential conflict
of interest between ECA and the trust in determining whether a
well is capable of producing in commercially paying quantities,
ECA is required under the applicable conveyance to act as a
reasonably prudent operator in the AMI under the same or similar
circumstances would act if it were acting with respect to its
own properties, disregarding the existence of the royalty
interests as a burden affecting such property.
After completion of its drilling obligation, ECA generally may
sell all or a portion of its interests in the Underlying
Properties, subject to and burdened by the royalty interests,
without the consent of the trust unitholders. In addition, ECA
may, without the consent of the trust unitholders, require the
trust to release royalty interests with an aggregate value to
the trust not to exceed $5.0 million during any
12-month
period. These releases will be made only in connection with a
sale by ECA of the Underlying Properties and are conditioned
upon the trust receiving an amount equal to the fair value to
the trust of such royalty interests. ECA operates all of the
Producing Wells and will operate not less than 90% of the PUD
Wells during the subordination period. Any net sales proceeds
paid to the trust are distributable to trust unitholders for the
quarter in which they are received. ECA has not identified for
sale any of the Underlying Properties.
MARKETING
AND POST-PRODUCTION SERVICES
Pursuant to the terms of the conveyances creating the royalty
interests, ECA will have the responsibility to market, or cause
to be marketed, the natural gas production related to the
Underlying Properties. The terms of the conveyances creating the
royalty interests do not permit ECA to charge any marketing fee
when determining the proceeds upon which the royalty payments
will be calculated. As a result, the proceeds to the trust from
the sales of natural gas production from the Underlying
Properties will be determined based on the same price (net of
post-production costs) that ECA receives for natural gas
production attributable to ECAs remaining interest in the
Underlying Properties.
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A wholly owned subsidiary of ECA markets the majority of
ECAs operated production and markets substantially all of
the gas produced from the Underlying Properties. Such subsidiary
enters into gas sales arrangements with large aggregators of
supply and these arrangements may be on a
month-to-month
basis or may be for a term of up to one year or longer. The
natural gas is sold at a market price and subsequently any
applicable post-production costs will be deducted. The trust
will not be charged any fee for marketing by ECA. The primary
aggregators of supply with whom ECA currently does business in
the AMI are BP Energy Company, Equitable Energy LLC, South
Jersey Resource Group and Hess Corporation. In addition to
providing marketing services, ECAs subsidiary purchases
all of the production from the Underlying Properties and those
sales account for 100% of the revenue from the Underlying
Properties.
Substantially all of the production from the Producing Wells and
the PUD Wells will be gathered by ECAs Greene County
Gathering System. Following this offering, the trust will pay
the initial Post-Production Services Fee of $0.52 per MMBtu for
use of this system, including ECAs costs to gather,
compress, transport, process, treat, dehydrate and market the
gas. This fee is fixed until ECAs drilling obligation is
satisfied; thereafter, ECA may increase this fee to the extent
necessary to recover certain capital expenditures on the Greene
County Gathering System made after the completion of the
drilling period, provided the resulting charge does not exceed
the prevailing charges in the area for similar services. This
fee does not include the cost of fuel used in the compression
process or equivalent electricity charges when electric
compressors are used. The reserve report assumes a 5% retainage
for compression fuel and line loss on the Greene County
Gathering System. This percentage represents current operating
conditions, though such level may fluctuate going forward. The
trusts cash available for distribution will be reduced by
ECAs deductions for these post-production services.
There are currently no third-party post-production costs, but
ECA or one of its affiliates may enter into arrangements with
third parties to provide gathering, transportation, processing
and other reasonable post-production services, including
transportation on downstream interstate pipelines. Such
additional post-production costs will be expressed as either
(1) a cost per MMBtu or Mcf or (2) a percentage of the
gross production from a well. To the extent that post-production
costs are expressed as a cost per MMBtu or Mcf, such costs may
be deducted by the ultimate purchaser of the natural gas prior
to payment being made to ECA or its marketing affiliate for such
production. At other times, ECA or its marketing affiliate will
make payments directly to the third parties providing such
post-production services. In either instance, the trusts
cash available for distribution will be reduced by the costs
paid by ECA for such post-production services provided by third
parties. If the post-production costs are expressed as a
percentage of the gross production from a well, then the volume
of production from that well actually available for sale is less
the applicable percentage charged, and as a result the reserves
associated with that well that are attributable to the royalty
interest are reduced accordingly.
The post-production costs for natural gas production from the
Producing Wells were $0.52 per MMBtu as of December 31,
2009. After giving effect to the drilling and completion of the
PUD Wells, ECA anticipates that the Post-Production Services Fee
will be the only such cost, yielding the weighted average
post-production costs for production attributable to the
trusts royalty interest of approximately $0.52 per MMBtu.
Regardless of whether the post-production costs are based upon
(1) a cost per MMBtu or Mcf or (2) a percentage of
gross production from a well, such costs may increase or
decrease in the future. The post-production costs attributable
to third party arrangements may be costs established by
arms-length negotiations or pursuant to a state or federal
regulatory proceeding. ECA will be permitted to deduct from the
proceeds available to the trust other post-production costs
necessary to make the natural gas from the Underlying Properties
marketable, so long as such costs do not materially exceed the
charges prevailing in the area for similar services.
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ECA expects to enter into similar gas supply arrangements and
post-production service arrangements for the gas to be produced
from the underlying PUD properties. Any new gas supply
arrangements or those entered into for providing post-production
services, will be utilized in determining the proceeds for the
Underlying Properties.
TITLE TO
PROPERTIES
The Underlying Properties are subject to certain burdens that
are described in more detail below. To the extent that these
burdens and obligations affect ECAs rights to production
and the value of production from the Underlying Properties, they
have been taken into account in calculating the trusts
interests and in estimating the size and the value of the
reserves attributable to the royalty interests.
ECA acquired its interests in the Underlying Properties through
a variety of means, including through the acquisition of oil and
gas leases by ECA directly from the mineral owner, through
assignments of oil and gas leases to ECA by the lessee who
originally obtained the leases from the mineral owner, through
farmout agreements that grant ECA the right to earn interests in
the properties covered by such agreements by drilling wells, and
through acquisitions of other oil and gas interests by ECA.
ECAs interests in the gas properties comprising the
Underlying Properties are typically subject, in one degree or
another, to one or more of the following:
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royalties and other burdens, express and implied, under gas
leases;
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production payments and similar interests and other burdens
created by ECA or its predecessors in title;
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a variety of contractual obligations arising under operating
agreements, farmout agreements, production sales contracts and
other agreements that may affect the properties or their titles;
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liens that arise in the normal course of operations, such as
those for unpaid taxes, statutory liens securing unpaid
suppliers and contractors and contractual liens under operating
agreements that are not yet delinquent or, if delinquent, are
being contested in good faith by appropriate proceedings;
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pooling, unitization and communitization agreements,
declarations and orders;
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easements, restrictions,
rights-of-way
and other matters that commonly affect property;
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conventional rights of reassignment that obligate ECA to
reassign all or part of a property to a third party if ECA
intends to release or abandon such property; and
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rights reserved to or vested in the appropriate governmental
agency or authority to control or regulate the Underlying
Properties and the royalty interests therein.
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ECA believes that the burdens and obligations affecting the
Underlying Properties and the royalty interests are conventional
in the industry for similar properties. ECA also believes that
the burdens and obligations do not, in the aggregate, materially
interfere with the use of the Underlying Properties and will not
materially adversely affect the value of the royalty interest.
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ECA believes that its title to the Underlying Properties is, and
the trusts title to the royalty interests will be, good
and defensible in accordance with standards generally accepted
in the oil and gas industry, subject to such exceptions as are
not so material as to detract substantially from the use or
value of such properties or royalty interests. Consistent with
industry practice, ECA has not obtained a preliminary title
review of the PUD Wells. Prior to drilling a PUD Well, ECA
intends to obtain a preliminary title review to ensure there are
no obvious defects in title to the well. Frequently, as a result
of such examination, certain curative work must be done to
correct defects in the marketability of title. ECA does not
intend to perform any further title examination prior to the
closing of the offering being made hereby. The conveyance
related to the PUD Royalty Interest obligates ECA to conduct a
more thorough title examination of the drill site tract prior to
drilling any of the PUD Wells. ECA will not be relieved of its
obligation to drill a well if such title examination prior to
drilling reveals a title defect preventing ECA from drilling in
such drill site.
It is unclear under Pennsylvania law whether the royalty
interests would be treated as real property interests.
Nevertheless, ECA intends to record the conveyances of the
royalty interests in the real property records of Pennsylvania
in accordance with local recording acts. ECA will grant to the
trust the Royalty Interest Lien to provide protection to the
trust, in the event of a bankruptcy of ECA, against the risk
that the royalty interests were not considered real property
interests.
COMPETITION
AND MARKETS
The natural gas industry is highly competitive. ECA competes
with major oil and gas companies and independent oil and gas
companies for oil and gas leases, equipment, personnel and
markets for the sale of natural gas. Many of these competitors
are financially stronger than ECA, but even financially troubled
competitors can affect the market because of their need to sell
natural gas at any price to attempt to maintain cash flow. The
trust will be subject to the same competitive conditions as ECA
and other companies in the natural gas industry.
Natural gas competes with other forms of energy available to
customers, primarily based on price. These alternate forms of
energy include electricity, coal and fuel oils. Changes in the
availability or price of natural gas or other forms of energy,
as well as business conditions, conservation, legislation,
regulations and the ability to convert to alternate fuels and
other forms of energy may affect the demand for natural gas.
Future price fluctuations for natural gas will directly impact
trust distributions, estimates of reserves attributable to the
trusts interests, and estimated and actual future net
revenues to the trust. In view of the many uncertainties that
affect the supply and demand for natural gas, neither the trust
nor ECA can make reliable predictions of future gas supply and
demand, future gas prices or the effect of future gas prices on
the trust.
REGULATION
Natural gas regulation. The availability, terms and
cost of transportation significantly affect sales of natural
gas. The interstate transportation and sale for resale of
natural gas is subject to federal regulation, including
regulation of the terms, conditions and rates for interstate
transportation, storage and various other matters, primarily by
the Federal Energy Regulatory Commission. Federal and state
regulations govern the price and terms for access to natural gas
pipeline transportation. The Federal Energy Regulatory
Commissions regulations for interstate natural gas
transmission in some circumstances may also affect the
intrastate transportation of natural gas.
Although natural gas prices are currently unregulated, Congress
historically has been active in the area of natural gas
regulation. Neither ECA nor the trust can predict whether new
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legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the
various state legislatures, and what effect, if any, the
proposals might have on the operations of the Underlying
Properties. Sales of condensate and natural gas liquids are not
currently regulated and are made at market prices.
Environmental regulation. The exploration,
development and production operations of ECA are subject to
stringent and comprehensive federal, state and local laws and
regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection.
These laws and regulations may, among other things, require the
acquisition of permits to conduct drilling, water withdrawal and
waste disposal operations; govern the amounts and types of
substances that may be disposed or released into the
environment; limit or prohibit construction or drilling
activities in sensitive areas such as wetlands, wilderness areas
or areas inhabited by endangered or threatened species; require
investigatory and remedial actions to mitigate pollution
conditions arising from ECAs operations or attributable to
former operations; and impose obligations to reclaim and abandon
well sites and pits. Failure to comply with these laws and
regulations may result in the assessment of administrative,
civil and criminal penalties, the imposition of remedial
obligations and the issuance of orders enjoining some or all of
ECAs operations in affected areas.
The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus, any changes in environmental laws and
regulations or re-interpretation of enforcement policies that
result in more stringent and costly waste handling, storage,
transport, disposal, or remediation requirements could have a
material adverse effect on ECAs operations and financial
position. ECA may be unable to pass on such increased compliance
costs to its customers. Moreover, accidental releases or spills
may occur in the course of ECAs operations, and there can
be no assurance that ECA will not incur significant costs and
liabilities as a result of such releases or spills, including
any third party claims for damage to property and natural
resources or personal injury. While ECA believes that it is in
substantial compliance with existing environmental laws and
regulations and that continued compliance with current
requirements would not have a material adverse effect on it,
there is no assurance that this trend will continue in the
future.
The following is a summary of the more significant existing
environmental, health and safety laws and regulations to which
ECAs business operations are subject and for which
compliance may have a material adverse impact on ECAs
capital expenditures, results of operations or financial
position.
Hazardous Substances and Wastes. The Comprehensive
Environmental Response, Compensation, and Liability Act, as
amended, (CERCLA), also known as the Superfund law
and comparable state laws impose liability without regard to
fault or the legality of the original conduct on certain classes
of persons who are considered to be responsible for the release
of a hazardous substance into the environment. These
persons include current and prior owners or operators of the
site where the release occurred and entities that disposed or
arranged for the disposal of the hazardous substances found at
the site. Under CERCLA, these responsible persons
may be subject to joint and several, strict liability for the
costs of cleaning up the hazardous substances that have been
released into the environment, for damages to natural resources,
and for the costs of certain health studies. CERCLA also
authorizes the EPA and, in some instances, third parties to act
in response to threats to the public health or the environment
and to seek to recover from the responsible classes of persons
the costs they incur. It is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of
hazardous substances or other pollutants into the environment.
ECA generates materials in the course of ECAs operations
that may be regulated as hazardous substances.
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ECA also generates solid and hazardous wastes that are subject
to the requirements of the Resource Conservation and Recovery
Act, as amended (RCRA), and comparable state
statutes. RCRA imposes strict requirements on the generation,
storage, treatment, transportation and disposal of hazardous
wastes. In the course of its operations, ECA generates petroleum
hydrocarbon wastes and ordinary industrial wastes that may be
regulated as hazardous wastes.
ECA currently owns or leases, and in the past may have owned or
leased, properties that have been used for numerous years to
explore and produce oil and natural gas. Although ECA may have
utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons and wastes may have been
disposed of or released on or under the properties owned or
leased by ECA or on or under the other locations where these
hydrocarbons and wastes have been taken for treatment or
disposal. In addition, certain of these properties have been
operated by third parties whose treatment and disposal or
release of hydrocarbons and wastes was not under ECAs
control. These properties and wastes disposed thereon may be
subject to CERCLA, RCRA and analogous state laws. Under these
laws, ECA could be required to remove or remediate previously
disposed wastes, to clean up contaminated property and to
perform remedial operations to prevent future contamination.
Air Emissions. The Clean Air Act, as amended, and
comparable state laws and regulations restrict the emission of
air pollutants from many sources and also impose various
monitoring and reporting requirements. These laws and
regulations may require ECA to obtain pre-approval for the
construction or modification of certain projects or facilities
expected to produce or significantly increase air emissions,
obtain and strictly comply with stringent air permit
requirements or utilize specific equipment or technologies to
control emissions. Obtaining permits has the potential to delay
the development of natural gas projects. While ECA may be
required to incur certain capital expenditures in the next few
years for air pollution control equipment or other air
emissions-related issues, ECA does not believe that such
requirements will have a material adverse effect on its
operations.
Climate Change. In response to certain scientific
studies suggesting that emissions of certain gases, commonly
referred to as greenhouse gases (GHGs) and including
carbon dioxide and methane, are contributing to the warming of
the Earths atmosphere and other climatic changes, the
U.S. House of Representatives passed the American
Clean Energy and Security Act of 2009 (ACESA)
on June 26, 2009, which would establish an economy-wide
cap-and-trade
program to reduce U.S. emissions of GHGs that may
contribute to warming of the Earths atmosphere and other
climatic changes. ACESA would require a 17 percent
reduction in GHG emissions from 2005 levels by 2020 and just
over an 80% reduction of such emissions by 2050. Under this
legislation, the EPA would issue a capped and steadily declining
number of tradable emissions allowances to major sources of GHG
emissions so that such sources could continue to emit GHGs into
the atmosphere. These allowances would be expected to escalate
significantly in cost over time. The U.S. Senate has begun
work on its own legislation for restricting domestic GHG
emissions and President Obama has indicated his support of
legislation to reduce GHG emissions through an emission
allowance system. Although it is not possible at this time to
predict when the Senate may act on climate change legislation or
how any bill passed by the Senate would be reconciled with
ACESA, any future federal laws or implementing regulations that
may be adopted to address GHG emissions could require ECA to
incur increased operating costs and could adversely affect
demand for the natural gas that it produces.
In addition, on December 15, 2009, the EPA published its
findings that emissions of carbon dioxide, methane and other
GHGs present an endangerment to public health and the
environment because emissions of such gases are, according to
the EPA, contributing to warming of the earths atmosphere
and other climatic changes. These findings allow the EPA to
adopt and implement regulations that would restrict emissions of
GHGs under existing provisions of the federal Clean
82
Air Act. These findings allow the EPA to adopt and implement
regulations that would restrict emissions of GHGs under existing
provisions of the federal Clean Air Act. Accordingly, the EPA
has proposed regulations that would require a reduction in
emissions of GHGs from motor vehicles and adopted regulations
that could trigger permit review for GHG emissions from certain
stationary sources. In addition, on October 30, 2009, the
EPA published a final rule requiring the reporting of GHG
emissions from specified large GHG emission sources in the
United States, including sources emitting more than 25,000 tons
of GHGs on an annual basis, beginning in 2011 for emissions
occurring in 2010. On March 23, 2010, the EPA announced a
proposed rulemaking that would expand its final rule on
reporting of GHG emissions to include owners and operators of
onshore oil and natural gas production. If the proposed rule is
finalized in its current form, reporting of GHG emissions from
such onshore production would be required on an annual basis
beginning in 2012 for emissions occurring in 2011. The adoption
and implementation of any regulations imposing reporting
obligations on, or limiting emissions of GHG gases from,
ECAs equipment and operations could require ECA to incur
costs to reduce emissions of GHGs associated with its operations
or could adversely affect demand for the natural gas it
produces. Finally, it should be noted that some scientists have
concluded that increasing concentrations of GHGs in the
Earths atmosphere may produce climate changes that have
significant physical effects, such as increased frequency and
severity of storms, droughts, and floods and other climatic
events; if any such effects were to occur, they could have an
adverse effect on ECAs assets and operations.
Even if such legislation is not adopted at the national level,
more than one-third of the states have begun taking actions to
control
and/or
reduce emissions of GHGs, primarily through the planned
development of GHG emission inventories
and/or
regional GHG cap and trade programs. Although most of the
state-level initiatives have to date focused on large sources of
GHG emissions, such as coal-fired electric plants, it is
possible that smaller sources of emissions could become subject
to GHG emission limitations or allowance purchase requirements
in the future. Any one of these climate change regulatory and
legislative initiatives could have a material adverse effect on
ECAs business, financial condition and results of
operations.
Water Discharges. The Federal Water Pollution
Control Act, as amended (Clean Water Act), and
analogous state laws impose restrictions and strict controls
regarding the discharge of pollutants into navigable waters.
Pursuant to the Clean Water Act and analogous state laws,
permits must be obtained to discharge pollutants into state
waters or waters of the United States. Any such discharge of
pollutants into regulated waters must be performed in accordance
with the terms of the permit issued by EPA or the analogous
state agency. Spill prevention, control and countermeasure
requirements under federal law require appropriate containment
berms and similar structures to help prevent the contamination
of navigable waters in the event of a petroleum hydrocarbon tank
spill, rupture or leak. In addition, the Clean Water Act and
analogous state laws, including Pennsylvania, require individual
permits or coverage under general permits for discharges of
storm water runoff from certain types of facilities.
It is customary to recover natural gas from deep shale
formations, including the Marcellus Shale formation, through the
use of hydraulic fracturing, combined with sophisticated
horizontal drilling. Hydraulic fracturing involves the injection
of water, sand and chemical additives under pressure into rock
formations to stimulate gas production. Due to public concerns
raised regarding potential impacts of hydraulic fracturing on
groundwater quality, legislative and regulatory efforts at the
federal level and in some states have been initiated to require
or make more stringent the permitting and compliance
requirements for hydraulic fracturing operations. In particular,
two companion bills have been introduced in the
U.S. Congress entitled the Fracturing Responsibility
and Awareness of Chemicals Act to amend the federal Safe
Drinking Water Act to subject hydraulic fracturing operations to
regulation under that Act and to require the disclosure of
chemicals used by the oil and gas industry in the hydraulic
fracturing process.
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Sponsors of these bills currently pending before the
U.S. Senate and House of Representatives have asserted that
chemicals used in the fracturing process could adversely affect
drinking water supplies. Proposed legislation would require,
among other things, the reporting and public disclosure of
chemicals used in the fracturing process, which could make it
easier for third parties opposing the hydraulic fracturing
process to initiate legal proceedings against producers. These
bills, if adopted, could establish an additional level of
regulation and permitting of hydraulic fracturing operations at
the federal level, which could lead to operational delays,
increased operating costs and additional regulatory burdens that
could make it more difficult for ECA to perform hydraulic
fracturing. Any increased federal, state or local regulation
could reduce the volumes of natural gas that ECA produces, which
would materially adversely affect its revenues and results of
operations. Moreover, in March 2010, the EPA announced that it
has allocated $1.9 million in 2010 and has requested
funding in fiscal year 2011 for conducting a comprehensive
research study on the potential adverse impacts that hydraulic
fracturing may have on water quality and public health. The
results of such a study, once completed, could further spur
action towards federal legislation and regulation of hydraulic
fracturing activities.
Endangered Species Act. The federal Endangered
Species Act, as amended (ESA), restricts activities
that may affect endangered and threatened species or their
habitats. While some of ECAs facilities or leased acreage
may be located in areas that are designated as habitat for
endangered or threatened species, ECA believes that it is in
substantial compliance with the ESA. However, the designation of
previously unidentified endangered or threatened species could
cause ECA to incur additional costs or become subject to
operating restrictions or bans in the affected areas.
Employee Health and Safety. The operations of ECA
are subject to a number of federal and state laws and
regulations, including the federal Occupational Safety and
Health Act, as amended (OSHA), and comparable state
statutes, whose purpose is to protect the health and safety of
workers. In addition, the OSHA hazard communication standard,
the EPA community
right-to-know
regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes
require that information be maintained concerning hazardous
materials used or produced in ECAs operations and that
this information be provided to employees, state and local
government authorities and citizens. ECA believes that it is in
substantial compliance with all applicable laws and regulations
relating to worker health and safety.
State regulation. Pennsylvania regulates the
drilling for, and the production, gathering and sale of, natural
gas, including imposing requirements for obtaining drilling
permits, the method of developing new fields, the spacing and
operation of wells, production rates and the prevention of waste
of natural gas resources. Realized prices are not currently
subject to state regulation or subject to other similar direct
economic regulation, but there can be no assurance that they
will not do so in the future. The effect of these regulations
may be to limit the amounts of natural gas that may be produced
from ECAs wells and to limit the number of wells or
locations ECA can drill.
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DESCRIPTION
OF THE ROYALTY INTERESTS
The royalty interests will be conveyed to the trust by ECA by
means of conveyance instruments that will be recorded in the
appropriate real property records in Greene County, Pennsylvania
where the gas properties to which the Underlying Properties
relate are located. The PDP Royalty Interest will burden the
existing working interests owned by ECA in the Producing Wells.
ECA has an average working interest of approximately 93% in
these wells.
The PUD Royalty Interest will initially burden 50% of all of the
interests of ECA in the Marcellus Shale formation in the AMI.
ECAs interests in the gas properties to which the PUD
Wells relate consist of an average working interest of 100%. The
conveyance related to the PUD Royalty Interest, however,
provides that the proceeds from the PUD Wells will be calculated
on the basis that the PUD Wells are only burdened by interests
that in total would not exceed 12.5%. In the event that
ECAs interest in any of the wells subject to the PUD
Royalty Interest that are drilled is subject to burdens in
excess of a 12.5%, such burdens will be fully allocated against
ECAs retained interest in such well, the net effect of
which is that the trust will receive payments with respect to
the PUD Royalty Interest as if the burdens effecting the PUD
Wells were in total 12.5% (proportionately reduced). Please see
The trust Administrative services agreement
and development agreement for a description of the
drilling obligations of ECA to the trust.
Generally, the percentage of production proceeds to be received
by the trust with respect to a well will equal the product of
(i) the percentage of proceeds to which the trust is
entitled under the terms of the conveyances (90% for the
Producing Wells and 50% for the PUD Wells) multiplied by
(ii) ECAs net revenue interest in the well. ECA on
average owns an 81.53% net revenue interest in the Producing
Wells. Therefore, the trust will be entitled to receive on
average 73.37% of the proceeds of production from the Producing
Wells. With respect to a PUD Well, the conveyance related to the
PUD Royalty Interest provides that the proceeds from the PUD
Wells will be calculated on the basis that the underlying PUD
Wells are burdened only by interests that in total would not
exceed 12.5% of the revenues from such properties, regardless of
whether the royalty interest owners are actually entitled to a
greater percentage of revenues from such properties. As the
applicable net revenue interest of a well is calculated by
multiplying ECAs percentage working interest in such well
by the unburdened interest percentage (87.5%), assuming ECA owns
a 100% working interest in a PUD Well, such well would have a
minimum 87.5% net revenue interest. Accordingly, the trust would
be entitled to 43.75% of the production proceeds from such well.
Pursuant to the Development Agreement, ECA will satisfy its
drilling obligation only when it has drilled 52 equivalent
wells. The proved undeveloped reserves included in the reserve
report represent the reserves assigned to undeveloped locations
that ECA anticipates drilling. However, under the conveyances,
ECA is obligated to act as a reasonably prudent operator in the
AMI under the same or similar circumstances as it would if it
were acting with respect to its own properties, disregarding the
existence of the royalty interests as burdens affecting such
properties. Accordingly, there may be situations where ECA will
be obligated to drill on one or more of the over 100 potential
drilling locations within the AMI, including the 52 drilling
locations identified in the reserve report, that are not those
identified locations underlying the reserve report.
Based on extensive geologic and engineering data from the
Producing Wells and vertical Marcellus Shale wells in the AMI,
as well as
3-D seismic
testing within the region, ECA believes that the Marcellus Shale
formation has demonstrated consistency in formation thickness
and other important characteristics across the AMI. When
combined with the fact that ECA is obligated to operate as a
reasonably prudent operator with respect to the PUD Wells, ECA
believes that a deviation from the 52 identified drilling
locations underlying the reserve report would not occur absent a
reasonable belief that (i) such deviation would not result
in production
85
at least equal to that of the location deviated from, and
(ii) not materially reduce the anticipated reserves
attributable to the 52 equivalent wells forming the PUD Wells.
To the extent ECAs working interest in a PUD Well is less
than 100%, the trusts share of proceeds would be
proportionately reduced. Pursuant to the Development Agreement,
however, ECA will only satisfy its drilling obligation when it
has drilled 52 equivalent wells. Therefore, any reduction
in production proceeds attributable to a PUD Well caused by ECA
having less than a 100% working interest in the well will be
offset by the requirement to drill additional wells. An
equivalent PUD Well is calculated by multiplying the working
interest held by ECA by the horizontal lateral length of the
well relative to 2,500 feet. PUD Wells drilled horizontally
in the Marcellus Shale formation with a horizontal lateral
distance (measured from the midpoint of the curve to the end of
the lateral) of less than 2,500 feet will count as a
fractional well in proportion to total lateral length divided by
2,500 feet. In the event ECA commences drilling of a PUD
Well but fails to drill beyond the mid-point of the curve, such
well will not count as a fractional well. PUD Wells with a
horizontal lateral distance of greater than 2,500 feet
(subject to a maximum of 3,500 feet) will count as one well
plus a fractional well equal to the length drilled in excess of
2,500 (up to 3,500 feet) feet divided by 2,500 feet.
Accordingly, for example, if ECA drilled one well in which it
has a 50% working interest, and such well was drilled to a
horizontal lateral length of 2,500 feet, such well would
count for purposes of the Development Agreement as only 0.50 PUD
Wells. In order to compensate for this, ECA would be obligated
to drill an additional 0.50 PUD Wells. Such additional 0.50 PUD
Wells could be achieved, for example, by drilling an additional
PUD Well with a horizontal lateral length of 3,000 feet (or
500 feet longer than the 2,500 foot base lateral length) in
which ECA holds a 41.7% working interest, or by drilling an
additional PUD Well with a horizontal lateral length of
2,000 feet (or 500 feet shorter than the 2,500 foot
base lateral length) in which ECA holds a 62.5% working
interest. ECA believes that longer laterals will produce more
reserves both in the near term and ultimately. Consequently,
longer lateral distances achieved should provide incremental
benefit to the trust.
PDP Royalty Interest. The conveyances creating the
PDP Royalty Interest entitle the trust to receive an amount of
cash for each calendar quarter equal to 90% of the proceeds
(exclusive of any production or development costs but after
deducting postproduction costs and any applicable taxes)
from the sale of estimated natural gas production attributable
to the Producing Wells regardless of whether such amounts have
actually been received by ECA from the purchases of the natural
gas produced. Proceeds from the sale of natural gas production
attributable to the Producing Wells in any calendar quarter
means:
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amount calculated based on estimated production volumes
attributable to the Producing Wells;
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in each case, after deducting the trusts proportionate
share of:
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any taxes levied on the severance or production of the natural
gas produced from the Producing Wells and any property taxes
attributable to the natural gas production attributable to the
Producing Wells; and
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post-production costs, which will generally consist of costs
incurred to gather, compress, transport, process, treat,
dehydrate and market the natural gas produced. Any charge
payable to ECA for such post-production costs on its Greene
County Gathering System will be limited to $0.52 per MMBtu of
gas gathered until ECA has fulfilled its drilling obligation.
Thereafter, ECA may increase this Post-Production Service Fee to
the extent it is necessary to recover certain capital
expenditures in ECAs Greene County Gathering System.
Additionally, the trust will be charged for the cost of fuel
used in the compression process, including equivalent
electricity charges in instances when electric compressors are
used.
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86
Proceeds payable to the trust from the sale of natural gas
production attributable to the Producing Wells in any calendar
quarter will not be subject to any deductions for any expenses
attributable to exploration, drilling, development, operating,
maintenance or any other costs incident to the production of
natural gas production attributable to the Producing Wells,
including any costs to plug and abandon a Producing Well.
PUD Royalty Interest. The conveyances creating the
PUD Royalty Interest entitles the trust to receive an amount of
cash for each calendar quarter equal to 50% of the proceeds
(after deducting postproduction costs and any applicable
taxes) from the sale of estimated natural gas production
attributable to the PUD Wells regardless of whether such amounts
have actually been received by ECA from the purchase of the
natural gas produced. Proceeds from the sale of natural gas
production, if any, attributable to the PUD Wells in any
calendar quarter means:
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for any calendar quarter commencing on or after April 1,
2010, the amount calculated based on estimated production
volumes attributable to the PUD Wells:
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in each case after deducting the trusts proportionate
share of:
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any taxes levied on the severance or production of the natural
gas produced from the PUD Wells and any property taxes
attributable to the gas produced from the PUD Wells; and
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post-production costs will generally consist of costs incurred
to gather, compress, transport, process, treat, dehydrate and
market the natural gas produced. Any charge payable to ECA for
such post-production charges on its with ECAs Greene
County Gathering System will be limited to $0.52 per MMBtu of
gas gathered until ECA has fulfilled its drilling obligation.
Thereafter, ECA may increase this Post-Production Services Fee
to the extent is necessary to recover certain capital
expenditures in ECAs Greene County Gathering System.
Additionally, the trust will be charged for the cost of fuel
used in the compression process, including equivalent
electricity charges in instances when electric compressors are
used.
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Proceeds, if any, payable to the trust from the sale of natural
gas production attributable to the PUD Wells in any calendar
quarter:
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will be determined on the basis that ECAs working interest
with respect to the PUD Wells is not subject to burdens
(landowners royalties and other similar interests) in
excess of 12.5% of the proceeds from gas production attributable
to ECAs interest; and
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will not be subject to any deductions for any expenses
attributable to exploration, drilling, development, operating,
maintenance or any other costs incident to the production of
natural gas production attributable to the underlying PUD
properties, including any costs to plug and abandon a well
included in the underlying PUD properties.
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Royalty
Interest Lien
Under the laws of Pennsylvania, it is not clear that the royalty
interests conveyed by ECA to the trust would be treated as real
property interests. Therefore, ECA will grant to the trust the
Royalty Interest Lien to provide protection to the trust,
exercisable in the event of a bankruptcy of ECA, against the
risk that the royalty interests were not considered real
property interests. More specifically, the Royalty Interest Lien
will be a lien in the Subject Interest and the Subject Gas, to
the extent and only to the extent that such Subject Interest and
Subject Gas pertains to Gas in, under and that may be produced,
saved or sold from the Marcellus Shale formation from the
87
wellbore of the Producing Wells and the PUD Wells, sufficient to
cause the trust to receive a volume of Trust Gas calculated
in accordance with the provisions of the conveyances of the
royalty interests. Capitalized terms used in the preceding
sentence and not otherwise defined in this prospectus shall have
the following meanings:
Gas means natural gas and all other gaseous
hydrocarbons, excluding condensate, butane, and other liquid and
liquefiable components that are actually removed from the Gas
stream by separation, processing, or other means.
Subject Gas means Gas from the Marcellus Shale
formation from any Producing Well or PUD Well.
Subject Interest means ECAs undivided
interests in the AMI, as lessee under Gas leases, as an owner of
the Subject Gas (or the right to extract such Gas), or
otherwise, by virtue of which undivided interests ECA has the
right to conduct exploration and Gas production operations on
the AMI.
Trust Gas means that percentage of Gas to which
the Trust is entitled, calculated in accordance with the
provisions of the conveyances of the royalty interests.
It is expressly understood and agreed that the Royalty Interest
Lien shall not include ECAs retained interest in the PUD
and Producing Wells and the AMI or other interest of ECA in the
AMI, and ECA shall have the right to lien, mortgage, sell or
otherwise encumber the ECA retained interest subject to the
Royalty Interest Lien.
ECA will record the conveyances of the royalty interests and a
Mortgage/Fixture Filing in the real estate records of Greene
County, Pennsylvania and will file a corresponding UCC-1
Financing Statement in the Office of the Secretary of State of
West Virginia and the Commonwealth of Pennsylvania.
Hedging
Contracts Transferred to the Trust
At the closing of this offering, ECA will also transfer to the
trust natural gas derivative floor price contracts and enter
into a back-to-back swap agreement with the trust to provide the
trust with the benefit of certain contracts entered into between
ECA and third parties that equate to approximately 50% of the
estimated natural gas to be produced by the trust properties
from April 1, 2010 through March 31, 2014. The swap
contracts will relate to approximately 7,500 MMBtu per day
at a weighted average price of $6.78 per MMBtu for the period
commencing as of April 1, 2010 through June 30, 2012.
The price of any floor price hedging contract is $5.00 per
MMBtu.
88
The following table sets forth the volumes of natural gas
covered by the natural gas hedging contracts and the floor price
for each quarter during the term of the contracts.
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Swap Volume
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Swap Price
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Floor Volume
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Floor Price
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(MMBtu)
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(MMBtu)
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(MMBtu)
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(MMBtu)
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Second Quarter 2010
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682,500
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$
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6.75
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Third Quarter 2010
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690,000
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$
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6.75
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Fourth Quarter 2010
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690,000
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$
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6.75
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225,000
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$
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5.00
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First Quarter 2011
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675,000
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$
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6.75
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159,000
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$
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5.00
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Second Quarter 2011
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682,500
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$
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6.75
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210,000
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$
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5.00
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Third Quarter 2011
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690,000
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$
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6.82
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405,000
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$
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5.00
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Fourth Quarter 2011
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690,000
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$
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6.82
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384,000
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$
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5.00
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First Quarter 2012
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682,500
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$
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6.82
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369,000
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$
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5.00
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Second Quarter 2012
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682,500
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$
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6.82
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516,000
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$
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5.00
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Third Quarter 2012
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1,305,000
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$
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5.00
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Fourth Quarter 2012
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1,362,000
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$
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5.00
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First Quarter 2013
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1,395,000
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$
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5.00
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Second Quarter 2013
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1,380,000
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$
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5.00
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Third Quarter 2013
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1,278,000
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$
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5.00
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Fourth Quarter 2013
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1,188,000
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$
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5.00
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First Quarter 2014
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1,092,000
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$
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5.00
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The conveyances also provide that if ECAs interest with
respect to the PDP properties is greater than what was warranted
to the trust in the conveyances, ECA will have the right to
offset against amounts owed to the trust, the difference between
what the trust actually receives from PDP Royalty Interest and
what the trust should have received from the PDP Royalty
Interest had ECAs interest been the amount warranted.
The trust will begin to liquidate on the Termination Date and
will soon thereafter wind up its affairs and terminate. The Term
Royalties will automatically revert to ECA at the Termination
Date, while the Perpetual Royalties will be sold and the
proceeds thereof will be distributed to the unitholders at the
Termination Date or soon thereafter. ECA will have a first right
of refusal to purchase the Perpetual Royalties at the
Termination Date.
ADDITIONAL
PROVISIONS
If a controversy arises as to the sales price of any production,
then for purposes of determining gross proceeds:
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amounts withheld or placed in escrow by a purchaser are not
considered to be received by the owner of the underlying
property until actually collected;
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amounts received by the owner of the underlying property and
promptly deposited with a nonaffiliated escrow agent will not be
considered to have been received until disbursed to it by the
escrow agent; and
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amounts received by the owner of the underlying property and not
deposited with an escrow agent will be considered to have been
received.
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89
The trustee is not obligated to return any cash received from
the royalty interests. Any overpayments made to the trust by ECA
due to adjustments to prior calculations of proceeds or
otherwise will reduce future amounts payable to the trust until
ECA recovers the overpayments.
The conveyances generally permit ECA to sell, without the
consent or approval of the trust unitholders, all or any part of
its interest in the Underlying Properties, if the Underlying
Properties are sold, subject to and burdened by the royalty
interests. Notwithstanding the foregoing, the conveyances
provide that ECA may not sell any of the Underlying Properties
subject to the PUD Royalty Interest until it has satisfied its
obligation to drill PUD Wells pursuant to the terms of the
Development Agreement. The trust unitholders are not entitled to
any proceeds of any sale of ECAs interest in the
Underlying Properties that remains subject to and burdened by
the royalty interests. Following such sale, the proceeds
attributable to the transferred property will be calculated as
described in this prospectus, and paid by the purchaser or
transferee to the trust. As a result, any additional costs
resulting from the sold property will not reduce the proceeds
paid to the trust from the Underlying Properties retained by ECA.
Subject to the terms of the conveyances, ECA may at its option
at any time prior to the completion of its drilling obligation,
cause the trust to exchange leased acreage subject to the
royalty interests, free and clear of such royalty interests, for
other leased acreage within the AMI (as defined in the
Conveyances). Such leased acreage exchanged to the trust shall
then be subject to the Royalty Interests as set forth in the
conveyances.
Additionally, the conveyances provide that, in the event ECA
acquires any additional leases in the AMI prior to the
completion of its drilling obligation , ECA may at its option
make such additional lease subject to the royalty interests. In
no event may any additional lease be come subject to the royalty
interests, or any exchange of acreage be effected, unless ECA
certifies to the trust that, among other things, all of the
aggregate acreage attributable to the additional leases and
exchange leases shall not exceed five percent of the acreage
subject to the royalty interest.
ECA or any transferee of an Underlying Property will have the
right to abandon any well or property if it reasonably believes
the well or property ceases to produce or is not capable of
producing in commercially paying quantities. In making such
decisions, ECA or any transferee of an Underlying Property is
required under the applicable conveyance to act as a reasonably
prudent operator in the AMI under the same or similar
circumstances would act if it were acting with respect to its
own properties, disregarding the existence of the royalty
interests as burdens affecting such property. Upon termination
of the lease, that portion of the royalty interests relating to
the abandoned property will be extinguished.
ECA may, without the consent of the trust unitholders, require
the trust to release royalty interests with an aggregate value
to the trust up to $5.0 million during any
12-month
period. These releases will be made only in connection with a
sale by ECA of the Underlying Properties and are conditioned
upon the trust receiving an amount equal to the fair value to
the trust of such royalty interests.
ECA must maintain books and records sufficient to determine the
amounts payable for the royalty interests to the trust.
Quarterly and annually, ECA must deliver to the trustee a
statement of the computation of the proceeds for each
computation period as well as quarterly drilling and production
results. Following the completion of this offering, ECA will not
be obligated to publicly file any reports with the SEC.
90
DESCRIPTION
OF THE TRUST AGREEMENT
CREATION
AND ORGANIZATION OF THE TRUST; AMENDMENTS
In connection with the formation of the trust, ECA will convey
to a wholly owned subsidiary a term royalty interest entitling
the holder of the interest to receive 45% of the proceeds from
the sale of production of natural gas attributable to ECAs
interest in the Producing Wells (after deducting post-production
costs and any applicable taxes) for a period of 20 years
commencing on April 1, 2010 the Term PDP Royalty and a term
royalty interest entitling such holder of the interest to
receive 25% of the proceeds from the sale of the production of
natural gas attributable to ECAs interest in the PUD Wells
(after deducting post-production costs and any applicable taxes)
for a period of 20 years commencing on April 1, 2010
(the Term PUD Royalty) in exchange for a demand note
in the principal amount of approximately $161 million. The
Term PDP Royalty and the Term PUD Royalty are collectively
referred to as the Term Royalties.
Prior to the closing of this offering, ECA and the Private
Investors will convey to the trust perpetual royalty interests
entitling the trust to receive, in the aggregate, an additional
45% of the proceeds from the sale of production of natural gas
attributable to the interests of ECA in the Producing Wells
(after deducting post-production costs and any applicable taxes)
(the Perpetual PDP Royalty) and ECA will convey to
the trust a perpetual royalty interest entitling the trust to
receive an additional 25% of the proceeds from the sale of
production of natural gas attributable to ECAs interest in
the PUD Wells (after deducting post-production costs and any
applicable taxes) (the Perpetual PUD Royalty) in
exchange for an aggregate 4,401,250 common units constituting
25% of the trust units outstanding and 4,401,250 subordinated
units constituting 25% of the trust units outstanding. The
Perpetual PDP Royalty and the Perpetual PUD Royalty are
collectively referred to as the Perpetual Royalties.
In connection with the completion of this offering, ECAs
subsidiary will convey the Term Royalties to the trust in
exchange for the proceeds of this offering, after deducting
underwriting commissions and discounts and expenses, and will
use such proceeds to repay the demand note to ECA.
The trust was created under Delaware law to acquire and hold the
royalty interests for the benefit of the trust unitholders
pursuant to an agreement between ECA, the trustee and the
Delaware trustee. The royalty interests are passive in nature
and neither the trust nor the trustee has any control over or
responsibility for costs relating to the operation of the
Underlying Properties. Neither ECA nor other operators of the
Underlying Properties have any contractual commitments to the
trust to provide additional funding or to conduct further
drilling on or to maintain their ownership interest in any of
these properties other than the obligations of ECA to designate
and drill PUD Wells. After the conveyance of the royalty
interests, however, ECA will retain an interest in each of the
Underlying Properties. For a description of the Underlying
Properties and other information relating to them, see The
underlying properties.
The trust agreement will provide that the trusts business
activities will be limited to owning the royalty interests and
any activity reasonably related to such ownership, including
activities required or permitted by the terms of the conveyances
related to the royalty interests and the natural gas hedging
contracts relating to an estimated 50% of the trusts
royalty production for a term ending March 31, 2014. As a
result, the trust will not be permitted to acquire other oil and
gas properties or royalty interests. Additionally, following the
completion of this offering the trust is not able to issue any
additional trust units.
91
The beneficial interest in the trust is divided into 17,605,000
trust units. Each of the trust units represents an equal
undivided beneficial interest in the assets of the trust. Please
read Description of the trust units for additional
information concerning the Trust Units.
Amendment of the trust agreement generally requires a vote of
holders of a majority of the outstanding trust units, except
that amendments that would result in a materially
disproportionate benefit to ECA or its affiliates compared to
other owners of common units require a vote of the holders of a
majority of the outstanding common units and a majority of the
outstanding trust units. However, no amendment may:
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increase the power of the trustee to engage in business or
investment activities;
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alter the rights of the trust unitholders as among
themselves; or
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permit the trustee to distribute the royalty interests in kind.
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Certain amendments to the trust agreement do not require the
vote of the trust unitholders. The trustee may, without approval
of the trust unitholders, from time to time supplement or amend
the trust agreement in order to cure any ambiguity or to correct
or supplement any defective or inconsistent provisions provided
such supplement or amendment is not adverse to the interest of
the trust unitholders. The business and affairs of the trust
will be managed by the trustee. Although ECA will operate all of
the Producing Wells and substantially all of the PUD Wells
during the subordination period, ECA has no ability to manage or
influence the management of the trust.
ASSETS OF
THE TRUST
Upon completion of this offering, the assets of the trust will
consist of royalty interests, natural gas hedging contracts, the
Administrative Services Agreement, the Development Agreement
that obligates ECA to drill the PUD Wells, and any cash and
temporary investments being held for the payment of expenses and
liabilities and for distribution to the trust unitholders.
DUTIES
AND POWERS OF THE TRUSTEE
The duties of the trustee are specified in the trust agreement
and by the laws of the State of Delaware, except as modified by
the trust agreement. The trustees principal duties
consist of:
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collecting cash attributable to the royalty interests;
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paying expenses, charges and obligations of the trust from the
trusts assets;
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determining whether cash distributions exceed subordination or
incentive thresholds, and making such cash distributions to the
common and subordinated unitholders and ECA with respect to its
right to receive incentive distributions and reimbursement of
its approximately $5.0 million hedging costs;
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causing to be prepared and distributed a
Schedule K-1
for each trust unitholder and to prepare and file tax returns on
behalf of the trust;
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causing to be prepared and filed reports required to be filed
under the Securities Exchange Act of 1934, as amended, and by
the rules of any securities exchange or quotation system on
which the trust units are listed or admitted to trading; and
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taking any action it deems necessary and advisable to best
achieve the purposes of the trust.
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92
If a trust liability is contingent or uncertain in amount or not
yet currently due and payable, the trustee may create a cash
reserve to pay for the liability. If the trustee determines that
the cash on hand and the cash to be received are insufficient to
cover the trusts liability, the trustee may borrow funds
required to pay the liabilities. The trustee may borrow the
funds from any person, including itself or its affiliates. The
terms of such indebtedness, if funds were loaned by the entity
serving as trustee or Delaware trustee, would be similar to the
terms which such entity would grant to a similarly situated
commercial customer with whom it did not have a fiduciary
relationship, and such entity shall be entitled to enforce its
rights with respect to any such indebtedness as if it were not
then serving as trustee or Delaware trustee. If the trustee
borrows funds, the trust unitholders will not receive
distributions until the borrowed funds are repaid.
Each quarter, the trustee will pay trust obligations and
expenses and distribute to the trust unitholders the remaining
proceeds received from the royalty interests. The cash held by
the trustee as a reserve against future liabilities must be
invested in:
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interest bearing obligations of the United States government;
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money market funds that invest only in United States government
securities;
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repurchase agreements secured by interest-bearing obligations of
the United States government;
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bank certificates of deposit; or
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cash held for distribution at the next distribution date may be
held in a non interest bearing account.
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The trust may not acquire any asset except the royalty
interests, the natural gas hedging contracts, cash and temporary
cash investments, and it may not engage in any investment
activity except investing cash on hand.
The trust may merge or consolidate with or into one or more
limited partnerships, general partnerships, corporations,
business trusts, limited liability companies, or associations or
unincorporated businesses if such transaction is agreed to by
the trustee and by the affirmative vote of the holders of a
majority of the outstanding trust units (or by the holders of a
majority of the common units and a majority of the outstanding
trust units if such transaction would result in a materially
disproportionate benefit to ECA or its affiliates compared to
other owners of common units) and such transaction is permitted
under the Delaware Statutory Trust Act and any other
applicable law.
The trustee may sell the royalty interests under any of the
following circumstances:
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the sale is requested by ECA, following the satisfaction of its
drilling obligation, in accordance with the provisions of the
Trust Agreement; or
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the holders representing a majority of the outstanding trust
units approving the sale (or by the holders of a majority of the
common units and a majority of the outstanding trust units if
such transaction would result in a materially disproportionate
benefit to ECA or its affiliates compared to other owners of
common units).
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Upon dissolution of the trust the trustee must sell the royalty
interests. No trust unitholder approval is required in this
event.
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The trustee will distribute the net proceeds from any sale of
the royalty interests and other assets to the trust unitholders.
The trustee may amend or supplement the Trust Agreement, the
conveyances, the Development Agreement, the Administrative
Services Agreement, the Hedge Agreements, the registration
rights agreement, the Drilling Support Lien and the Royalty
Interest Lien, without the approval of the trust unitholders, to
cure ambiguities, to correct or supplement defective or
inconsistent provisions, to grant any benefit to all Trust
unitholders, to add collateral to the Drilling Support Lien and
the Royalty Interest Lien or to change the name of the Trust,
provided, however, that any such supplement or amendment does
not adversely affect the interest of the trust unitholders.
Furthermore, the trustee, acting alone, may amend the
Administrative Services Agreement without the approval of trust
unitholders if such amendment would not increase the cost or
expense of the trust or create an adverse economic impact on the
trust unitholders. All other permitted amendments may only be
made by the affirmative vote of a majority of the trust units
(or by the holders of a majority of the common units and a
majority of the outstanding trust units if such transaction
would result in a materially disproportionate benefit to ECA or
its affiliates compared to other owners of common units).
LIABILITIES
OF THE TRUST
Because the trust does not conduct an active business and the
trustee has little power to incur obligations, it is expected
that the trust will only incur liabilities for routine
administrative expenses, such as the trustees fees and
accounting, engineering, legal, tax advisory and other
professional fees.
FEES AND
EXPENSES
Ongoing administrative expenses. The trust will be
responsible for paying all legal, accounting, tax advisory,
engineering, printing and other administrative and
out-of-pocket
expenses incurred by or at the direction of the trustee or the
Delaware trustee. The trust will also be responsible for paying
other expenses incurred as a result of its being a publicly
traded entity, including costs associated with annual and
quarterly reports to unitholders, tax return and
Schedule K-1 preparation and distribution, independent
auditor fees and registrar and transfer agent fees. These trust
administrative expenses as well as the costs associated with
being a publicly traded entity are initially anticipated to
aggregate approximately $800,000 per year, although such costs
could be greater or less depending on future events that cannot
be predicted. Included in the $800,000 annual estimate is an
annual administrative fee of $150,000 for the trustee and an
annual administrative fee of $2,400 for the Delaware trustee.
These costs as well as those to be paid to ECA pursuant to the
Administrative Services Agreement outlined under The trust
Administrative services agreement and development
agreement, will be deducted by the trust before
distributions are made to trust unitholders.
Fees to ECA. The Administrative Services Agreement
provides that the trust is obligated, throughout the term of the
trust, to pay to ECA each quarter an administrative services fee
for accounting, bookkeeping and informational services relating
to the royalty interests. The annual fee, payable in equal
quarterly installments, will total $60,000 per year.
RESPONSIBILITY
AND LIABILITY OF THE TRUSTEE
The duties and liabilities of the Trustee are set forth in the
Trust Agreement. The Trust Agreement provides that (a) the
Trustee shall not have any duties or liabilities, including
fiduciary duties, except as expressly set forth in the Trust
Agreement, and (b) the duties and liabilities of the
Trustee as set forth in the Trust Agreement replace any other
duties and liabilities, including fiduciary duties, to which the
Trustee might otherwise be subject.
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The trustee will not make business decisions affecting the
assets of the trust. Therefore, substantially all of the
trustees functions under the trust agreement are expected
to be ministerial in nature. See Duties and
powers of the trustee, above. The trust agreement,
however, provides that the trustee may:
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charge for its services as trustee;
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retain funds to pay for future expenses and deposit them with
one or more banks or financial institutions (which may include
the trustee to the extent permitted by law);
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lend funds at commercial rates to the trust to pay the
trusts expenses; and
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seek reimbursement from the trust for its
out-of-pocket
expenses.
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In discharging its duty to trust unitholders, the trustee may
act in its discretion and will be liable to the trust
unitholders only for fraud, gross negligence or acts or
omissions constituting bad faith. The trustee will not be liable
for any act or omission of its agents or employees unless the
trustee acted with fraud, in bad faith or with gross negligence
in their selection and retention. The trustee will be
indemnified individually or as the trustee for any liability or
cost that it incurs in the administration of the trust, except
in cases of fraud, gross negligence or bad faith. The trustee
will have a lien on the assets of the trust as security for this
indemnification and its compensation earned as trustee. Trust
unitholders will not be liable to the trustee for any
indemnification. See Description of the trust
units Liability of trust unitholders. The
trustee will ensure that all contractual liabilities of the
trust are limited to the assets of the trust.
DURATION
OF THE TRUST; SALE OF ROYALTY INTERESTS
The trust will remain in existence until the Termination Date,
which is March 31, 2030. The trust will dissolve prior to
the Termination Date if:
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the trust sells all of the royalty interests;
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gross proceeds attributable to the royalty interests are less
than $1.5 million for any four consecutive quarters;
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the holders of a majority of the outstanding trust units vote in
favor of dissolution; or
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the trust is judicially dissolved.
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The trustee would then sell all of the trusts assets,
either by private sale or public auction, and distribute the net
proceeds of the sale to the trust unitholders.
DISPUTE
RESOLUTION
Any dispute, controversy or claim that may arise between ECA and
the trustee relating to the trust will be submitted to binding
arbitration before a panel of three arbitrators.
COMPENSATION
OF THE TRUSTEE AND THE DELAWARE TRUSTEE
The trustees and the Delaware trustees compensation
will be paid out of the trusts assets. See
Fees and expenses.
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TAX
MATTERS
Trust unitholders will be treated as partners of the trust for
federal income tax purposes. The trust agreement contains tax
provisions that generally allocate the trusts income,
gain, loss, deduction and credit among the trust unitholders in
accordance with their percentage interests in the trust. The
trust agreement also sets forth the tax accounting principles to
be applied by the trust.
MISCELLANEOUS
The trustee may consult with counsel, accountants, tax advisors,
geologists and engineers and other parties the trustee believes
to be qualified as experts on the matters for which advice is
sought. The trustee will be protected for any action it takes in
good faith reliance upon the opinion of the expert.
The principal offices of the trustee are located at
919 Congress Avenue, Suite 500, Austin, TX 78701, and
its telephone number is
1-800-852-1422.
The Delaware trustee and the trustee may resign at any time or
be removed with or without cause at any time by a vote of not
less than a majority of the outstanding trust units. Any
successor must be a bank or trust company meeting certain
requirements including having combined capital, surplus and
undivided profits of at least $20 million, in the case of
the Delaware trustee, and $100 million, in the case of the
trustee.
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DESCRIPTION
OF THE TRUST UNITS
Each trust unit is a unit of the beneficial interest in the
trust and is entitled to receive cash distributions from the
trust on a pro rata basis. Each trust unitholder has the same
rights regarding each of his trust units as every other trust
unitholder has regarding his units. The trust will have
17,605,000 trust units outstanding upon completion of the
offering, consisting of 13,203,750 common units and
4,401,250 subordinated units.
DISTRIBUTIONS
AND INCOME COMPUTATIONS
Cash distributions to trust unitholders will be made from
available funds at the trust for each calendar quarter.
Production payments due to the trust with respect to any
calendar quarter will be accrued based on estimated production
volumes attributable to the trust properties during such quarter
(as measured at ECA metering systems) and market prices for such
volumes. ECA will make a payment to the trust equal to such
accrued amounts within 30 days of the end of such calendar
quarter. After receipt of such payment, the trustee will
determine for such calendar quarter the amount of funds
available for distribution to the trust unitholders. Available
funds are the excess cash, if any, received by the trust over
the trusts expenses for that quarter. Available funds will
be reduced by any cash the trustee decides to hold as a reserve
against future liabilities. Any difference between the payment
made by ECA to the trust with respect to a calendar quarter and
the actual cash production payments relative to the trust
properties received by ECA will be netted against future
payments by ECA to the trust. As a result, during the
subordination period, the netting of such difference could
result in (i) an inability by the trust to make cash
distributions in excess of applicable subordination thresholds
with respect to a subsequent calendar quarter or
(ii) distributions in excess of the incentive thresholds
for a prior calendar quarter notwithstanding the fact that such
shortfall or excess, respectively, would not have existed had
production payments owed to the trust been calculated on an
actual cash basis.
The amount of available funds for distribution each quarter will
be payable to the trust unitholders of record on or about the
45th day following the end of such calendar quarter or such
later date as the trustee determines is required to comply with
legal or stock exchange requirements. The trustee will
distribute cash on or about the 60th day (or the next
succeeding business day following such day if such day is not a
business day) following such calendar quarter to each person who
was a trust unitholder of record on the quarterly record date,
together with interest expected to be earned on the amount of
such quarterly distribution from the date of receipt thereof by
the trustee to the payment date.
Unless otherwise advised by counsel or the IRS, the trustee will
treat the income and expenses of the trust for each month as
belonging to the trust unitholders of record on the first
business day of the month. Trust unitholders will recognize
income and expenses for tax purposes in the month the trust
receives or pays those amounts, rather than in the month the
trust distributes them. Minor variances may occur. For example,
the trustee could establish a reserve in one month that would
not result in a tax deduction until a later month. The trustee
could also make a payment in one month that would be amortized
for tax purposes over several months. See Federal income
tax considerations.
TRANSFER
OF TRUST UNITS
Trust unitholders may transfer their trust units in accordance
with the trust agreement. The trustee will not require either
the transferor or transferee to pay a service charge for any
transfer of a trust unit. The trustee may require payment of any
tax or other governmental charge imposed for a transfer. The
trustee may treat the owner of any trust unit as shown by its
records as the owner of the trust unit. The trustee will not be
considered to know about any claim or demand
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on a trust unit by any party except the record owner. A person
who acquires a trust unit after any quarterly record date will
not be entitled to the distribution relating to that quarterly
record date. Delaware law will govern all matters affecting the
title, ownership or transfer of trust units.
PERIODIC
REPORTS
The trustee will file all required trust federal and state
income tax and information returns. The trustee will prepare and
mail to trust unitholders a
Schedule K-1
that trust unitholders need to correctly report their share of
the income and deductions of the trust. The trustee will also
cause to be prepared and filed reports required to be filed
under the Securities Exchange Act of 1934, as amended, and by
the rules of any securities exchange or quotation system on
which the trust units are listed or admitted to trading.
Each trust unitholder and his representatives may examine, for
any proper purpose, during reasonable business hours the records
of the trust and the trustee.
LIABILITY
OF TRUST UNITHOLDERS
Under the Delaware Statutory Trust Act, trust unitholders
will be entitled to the same limitation of personal liability
extended to stockholders of private corporations for profit
under the General Corporation Law of the State of Delaware. No
assurance can be given, however, that the courts in
jurisdictions outside of Delaware will give effect to such
limitation.
VOTING
RIGHTS OF TRUST UNITHOLDERS
The trustee or trust unitholders owning at least 10% of the
outstanding trust units may call meetings of trust unitholders.
The trust will be responsible for all costs associated with
calling a meeting of trust unitholders unless such meeting is
called by the trust unitholders, in which case the trust
unitholders will be responsible for all costs associated with
calling such meeting of trust unitholders. Meetings must be held
in such location as is designated by the trustee in the notice
of such meeting. The trustee must send written notice of the
time and place of the meeting and the matters to be acted upon
to all of the trust unitholders at least 20 days and not
more than 60 days before the meeting. Trust unitholders
representing a majority of trust units outstanding must be
present or represented to have a quorum. Each trust unitholder
is entitled to one vote for each trust unit owned.
Unless otherwise required by the trust agreement, a matter may
be approved or disapproved by the vote of a majority of the
trust units held by the trust unitholders at a meeting where
there is a quorum. This is true, even if a majority of the total
outstanding trust units did not approve it. The affirmative vote
of the holders of a majority of the outstanding trust units is
required to:
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dissolve the trust (except in accordance with its terms);
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remove the trustee or the Delaware trustee;
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amend the trust agreement, the royalty conveyances, the
Administrative Services Agreement, the Development Agreement,
the Drilling Support Lien, the Royalty Interest Lien and the
hedge agreements (except with respect to certain matters that do
not adversely affect the right of trust unitholders in any
material respect);
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merge or consolidate the trust with or into another
entity; or
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approve the sale of all or any material part of the assets of
the trust.
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except that if any of the matters listed above (except removal
of the trustee or the Delaware trustee) would result in a
materially disproportionate benefit to ECA or its affiliates
compared to other owners of common units, the affirmative vote
of the holders of a majority of common units and a majority of
trust units is required.
In addition, certain amendments to the trust agreement may be
made by the trustee without approval of the trust unitholders.
The trustee must consent before all or any part of the trust
assets can be sold except in connection with the dissolution of
the trust or limited sales directed by ECA in conjunction with
its sale of Underlying Properties.
COMPARISON
OF TRUST UNITS AND COMMON STOCK
Trust unitholders have more limited voting rights than those of
stockholders of most public corporations. For example, there is
no requirement for annual meetings of trust unitholders or for
annual or other periodic re-election of the trustee.
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Unitholders should also be aware of the following ways in which
an investment in trust units is different from an investment in
common stock of a corporation.
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Trust units
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Common stock
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Voting
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The trust agreement provides voting rights to trust unitholders
to remove and replace (but not elect) the trustee and to approve
or disapprove major trust transactions.
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Corporate statutes provide voting rights to stockholders of the
corporation to elect directors and to approve or disapprove
major corporate transactions.
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Income Tax
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The trust is not subject to federal income tax; trust
unitholders are subject to income tax on their allocable share
of trust income, gain, loss and deduction.
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Corporations are taxed on their income, and their stockholders
are taxed on dividends.
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Distributions
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Substantially all trust revenue is distributed to trust
unitholders.
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Stockholders receive dividends at the discretion of the board of
directors.
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Business and Assets
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The business of the trust is limited to specific assets with a
finite economic life.
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A corporation conducts an active business for an unlimited term
and can reinvest its earnings and raise additional capital to
expand.
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Fiduciary Duties
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To the extent provided in the trust agreement, the trustee has
limited its fiduciary duties in the trust agreement as permitted
by the Delaware Statutory Trust Act so that it will be
liable to unitholders only for fraud, gross negligence or acts
or omissions constituting bad faith.
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Officers and directors have a fiduciary duty of loyalty to
stockholders and a duty to use due care in management and
administration of a corporation.
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TRUST UNITS
ELIGIBLE FOR FUTURE SALE
General
Prior to this offering, there has been no public market for the
common units. Sales of substantial amounts of the common units
in the open market, or the perception that those sales could
occur, could adversely affect prevailing market prices.
Upon completion of this offering, there will be
17,605,000 trust units outstanding. All of the
8,802,500 common units sold in this offering, or the
10,122,875 common units if the underwriters exercise their
over-allotment option in full, will be freely tradable without
restriction under the Securities Act. The 1,104,567 common
units to be held by the Private Investors and the
7,697,933 trust units to be held by ECA (6,377,558 trust
units if the underwriters exercise their over-allotment in full)
following completion of the offering will be restricted
securities within the meaning of Rule 144 under the
Securities Act and may not be sold other than through
registration under the Securities Act or pursuant to an
exemption from registration, subject to the restrictions on
transfer contained in the
lock-up
agreements described below and in Underwriting.
Lock-up
Agreements
In connection with this offering, ECA and the Private Investors
have agreed, for a period of 180 days after the date of
this prospectus, not to offer, sell, contract to sell or
otherwise dispose of or transfer any trust units or any
securities convertible into or exchangeable for trust units,
other than the sale of 209,312 common units to ECA by the
Private Investors, without the prior written consent of Raymond
James & Associates, Inc. and Citigroup Global Markets
Inc., subject to specified exceptions. See
Underwriting for a description of these
lock-up
arrangements. Upon the expiration of these
lock-up
agreements, all of the common units held by ECA and the Private
Investors will be eligible for sale in the public market under
Rule 144 of the Securities Act, subject to volume
limitations and other restrictions contained in Rule 144,
or through registration under the Securities Act.
Rule 144
The common units sold in the offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any common units owned by an
affiliate of ECA or the trust may not be resold
publicly except in compliance with the registration requirements
of the Securities Act or under an exemption under Rule 144
or otherwise. Rule 144 permits securities acquired by an
affiliate to be sold into the market in an amount that does not
exceed, during any three-month period, the greater of:
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1.0% of the total number of the securities outstanding, or
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the average weekly reported trading volume of the common units
for the four calendar weeks prior to the sale.
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Sales under Rule 144 are also subject to specific manner of
sale provisions, holding period requirements, notice
requirements and the availability of current public information
about the trust. A person who is not deemed to have been an
affiliate of ECA or the trust at any time during the three
months preceding a sale, and who has beneficially owned his
common units for at least six months (provided we are in
compliance with the current public information requirement) or
one year (regardless of whether we are in compliance with the
current public information requirement), would be entitled to
sell common units under Rule 144 without regard to the
rules
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public information requirements, volume limitations, manner of
sale provisions and notice requirements.
Registration
Rights
The trust intends to enter into a registration rights agreement
for the benefit of ECA, John Mork and certain of his affiliates
in connection with ECAs conveyance to the trust of the PDP
Royalty Interest and the PUD Royalty Interest. In the
registration rights agreement, the trust will agree, for the
benefit of ECA, John Mork and certain of his affiliates and any
of their transferees (each, a holder), to register
the trust units it holds. Specifically, the trust will agree:
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subject to the restrictions described above under
Lock-up
agreements and under Underwriting
Lock-up
agreements, to use its reasonable best efforts to file a
registration statement, including, if so requested, a shelf
registration statement, with the SEC as promptly as practicable
following receipt of a notice requesting the filing of a
registration statement from holders representing a majority of
the then outstanding registrable trust units;
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to use its reasonable best efforts to cause the registration
statement or shelf registration statement to be declared
effective under the Securities Act as promptly as practicable
after the filing thereof; and
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to continuously maintain the effectiveness of the registration
statement under the Securities Act for 90 days (or
continuously if a shelf registration statement is requested)
after the effectiveness thereof or until the trust units covered
by the registration statement have been sold pursuant to such
registration statement or until all registrable trust units:
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have been sold pursuant to Rule 144 under the Securities
Act if the transferee thereof does not receive restricted
securities;
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have been sold in a private transaction in which the
transferors rights under the registration rights agreement
are not assigned to the transferee of the trust units; or
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become eligible for resale pursuant to Rule 144 (or any
similar rule then in effect under the Securities Act).
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ECA, John Mork and certain of his affiliates will have the right
to require the trust to file no more than three registration
statements in aggregate.
In connection with the preparation and filing of any
registration statement, ECA will bear all costs and expenses
incidental to any registration statement, excluding certain
internal expenses of the trust, which will be borne by the
trustee, and any underwriting discounts and commissions, which
will be borne by the seller of the trust units.
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FEDERAL
INCOME TAX CONSIDERATIONS
This section is a discussion of the material tax considerations
that may be relevant to prospective trust unitholders who are
individual citizens or residents of the United States and,
unless otherwise noted in the following discussion, is the
opinion of Vinson & Elkins L.L.P., counsel to ECA and
the trust, insofar as it relates to legal conclusions with
respect to matters of U.S. federal income tax law. This
section is based upon current provisions of the Internal Revenue
Code of 1986, as amended (the Internal Revenue
Code), existing and proposed Treasury regulations
promulgated under the Internal Revenue Code (the Treasury
Regulations) and current administrative rulings and court
decisions, all of which are subject to change. Future changes in
these authorities may cause the tax consequences to vary
substantially from the consequences described below.
The following discussion does not address all federal income tax
matters affecting the trust or the trust unitholders. Moreover,
the discussion focuses on trust unitholders who are individual
citizens or residents of the United States and has only limited
application to corporations, estates, trusts, nonresident aliens
or other unitholders subject to specialized tax treatment, such
as tax-exempt institutions,
non-U.S. persons,
taxpayers subject to the alternative minimum tax, individual
retirement accounts (IRAs), employee benefit plans, real estate
investment trusts (REITs) or mutual funds. Accordingly, the
trust encourages each prospective trust unitholder to consult,
and depend on, his own tax advisor in analyzing the federal,
state, local and foreign tax consequences particular to him of
the ownership or disposition of trust units.
No ruling has been or will be requested from the Internal
Revenue Service (the IRS) regarding any matter
affecting the trust or prospective trust unitholders. Instead,
the trust will rely on opinions of Vinson & Elkins
L.L.P. Unlike a ruling, an opinion of counsel represents only
that counsels best legal judgment and does not bind the
IRS or the courts. Accordingly, the opinions and statements made
herein may not be sustained by a court if contested by the IRS.
Any contest of this sort with the IRS may materially and
adversely impact the market for the trust units and the prices
at which trust units trade. In addition, the costs of any
contest with the IRS, principally legal, accounting and related
fees, will result in a reduction in cash available for
distribution to the trust unitholders, and thus will be borne
indirectly by the trust unitholders. Furthermore, the tax
treatment of the trust, or of an investment in the trust, may be
significantly modified by future legislative or administrative
changes or court decisions. Any modifications may or may not be
retroactively applied.
All statements as to matters of law and legal conclusions, but
not as to factual matters, contained in this section, unless
otherwise noted, are the opinion of Vinson & Elkins
L.L.P. and are based on the accuracy of the representations made
by ECA and the trust.
For the reasons described below, Vinson & Elkins
L.L.P. has not rendered an opinion with respect to the following
specific federal income tax issues: (1) the treatment of a
trust unitholder whose trust units are loaned to a short seller
to cover a short sale of trust units (please read
Tax consequences of trust unit
ownership Treatment of short sales);
(2) whether the trusts monthly convention for
allocating taxable income and losses is permitted by existing
Treasury Regulations (please read Disposition
of trust units Allocations between transferors
and transferees); and (3) whether percentage
depletion will be available to a trust unitholder or the extent
of the percentage depletion deduction available to any trust
unitholder (please read Tax consequences of
trust unit ownership Tax treatment of the
perpetual royalties).
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As used herein, the term trust unitholder means a
beneficial owner of trust units that for U.S. federal
income tax purposes is:
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an individual who is a citizen of the United States or who is
resident in the United States for U.S. federal income tax
purposes,
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a corporation, or an entity treated as a corporation for
U.S. federal income tax purposes, created or organized in
or under the laws of the United States, a state thereof or the
District of Columbia,
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an estate the income of which is subject to U.S. federal
income taxation regardless of its source, or
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a trust if it is subject to the primary supervision of a
U.S. court and the control of one or more United States
persons (as defined for U.S. federal income tax purposes)
or that has a valid election in effect under applicable
U.S. Treasury regulations to be treated as a United States
person.
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The term
non-U.S. trust
unitholder means any beneficial owner of a trust unit
(other than an entity that is classified for U.S. federal
income tax purposes as a partnership or as a disregarded
entity) that is not a trust unitholder.
If an entity that is classified for U.S. federal income tax
purposes as a partnership is a beneficial owner of trust units,
the tax treatment of a member of the entity will depend upon the
status of the member and the activities of the entity. The trust
encourages any entity that is classified for U.S. federal
income tax purposes as a partnership and that is a beneficial
owner of trust units, and the members of such an entity, to
consult their own tax advisors about the U.S. federal
income tax considerations of purchasing, owning, and disposing
of trust units.
CLASSIFICATION
OF THE TRUST AS A PARTNERSHIP
Although the trust is formed as a statutory trust under Delaware
law, the trusts classification for federal income tax
purposes is based on its characteristics rather than its form.
Based on such characteristics, it is expected that, as described
below, the trust will be treated for federal and applicable
state income tax purposes as a partnership and trust unitholders
will be treated as partners in that partnership.
A partnership is not a taxable entity and incurs no federal
income tax liability. Instead, each partner of a partnership is
required to take into account his share of items of income,
gain, loss, deduction and credit of the partnership in computing
his federal income tax liability, regardless of whether cash
distributions are made to him by the partnership. Distributions
by a partnership to a partner are generally not taxable to the
partner unless the amount of cash distributed to him is in
excess of the partners adjusted basis in his partnership
interest as of the end of the taxable year in which the
distribution is made.
Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, an exception, referred to in this
discussion as the Qualifying Income Exception,
exists with respect to publicly traded partnerships of which 90%
or more of the gross income for every taxable year consists of
qualifying income. Qualifying income includes income
and gains derived from the exploration, development, production
and marketing of crude oil and natural gas and interest income
(other than from a financial business). Other types of
qualifying income include gains from the sale of real property
and income from certain hedging transactions. The trust
anticipates that substantially all of its
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gross income will be qualifying income. Based upon the factual
representations made by the trust and ECA and a review of the
applicable legal authorities, Vinson & Elkins L.L.P.
is of the opinion that at least 90% of the trusts gross
income will constitute qualifying income.
No ruling has been or will be sought from the IRS and the IRS
has made no determination as to the trusts status for
federal income tax purposes or whether the trusts
operations generate qualifying income under
Section 7704 of the Internal Revenue Code. Instead, the
trust will rely on the opinion of Vinson & Elkins
L.L.P. on such matters. It is the opinion of Vinson &
Elkins L.L.P. that, based upon the Internal Revenue Code,
Treasury Regulations, published revenue rulings and court
decisions and the representations described below, the trust
will be classified as a partnership for federal income tax
purposes.
In rendering its opinion, Vinson & Elkins L.L.P. has
relied on factual representations made by the trust and ECA. The
representations made by the trust and ECA upon which
Vinson & Elkins L.L.P. has relied are:
(a) The trust has not, and will not, elect to be treated as
a corporation;
(b) The trust is, and will be organized and operated in
accordance with (i) all applicable trust statutes,
including the Delaware Statutory Trust Act, (ii) the
trust agreement, and (iii) the description thereof in this
prospectus;
(c) For each taxable year, more than 90% of the
trusts gross income will be income that Vinson &
Elkins L.L.P. has opined or will opine is qualifying income
within the meaning of Section 7704(d) of the Internal
Revenue Code; and
(d) Each hedging transaction that the trust treats as
resulting in qualifying income will be appropriately identified
as a hedging transaction pursuant to applicable Treasury
Regulations, and will be associated with oil, gas or products
thereof that are held or will be held by the trust in activities
that Vinson & Elkins L.L.P. has opined or will opine
result in qualifying income.
The trust believes that these representations are true and
expects that these representations will continue to be true in
the future.
If the trust fails to meet the Qualifying Income Exception,
other than a failure that is determined by the IRS to be
inadvertent and that is cured within a reasonable time after
discovery (in which case the IRS may also require the trust to
make adjustments with respect to the trusts unitholders
allocable share of trust income, gain, loss or deduction or pay
other amounts), the trust will be treated as if it had
transferred all of its assets, subject to liabilities, to a
newly formed corporation, on the first day of the year in which
the trust fails to meet the Qualifying Income Exception, in
return for stock in that corporation, and then distributed that
stock to the unitholders in liquidation of their interests in
the trust. This deemed contribution and liquidation should be
tax-free to the trust unitholders and the trust. Thereafter, the
trust would be treated as an association taxable as a
corporation for federal income tax purposes.
If the trust were treated as an association taxable as a
corporation in any taxable year, either as a result of a failure
to meet the Qualifying Income Exception or otherwise, the
trusts items of income, gain, loss and deduction would be
reflected only on the trusts tax return rather than being
passed through to the trust unitholders, and the trusts
net income would be taxed to the trust at corporate rates. In
addition, any distribution made to a trust unitholder would be
treated as either taxable dividend income, to the extent of the
trusts current or accumulated earnings and profits, or, in
the absence of earnings and profits, a nontaxable return of
capital, to the extent
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of the trust unitholders tax basis in his trust units, or
taxable capital gain, after the trust unitholders tax
basis in his trust units is reduced to zero. Accordingly,
taxation as a corporation would result in a material reduction
in a trust unitholders cash flow and after-tax return and
thus would likely result in a substantial reduction of the value
of the trust units.
The discussion below is based on Vinson & Elkins
L.L.P.s opinion that the trust will be classified as a
partnership for federal income tax purposes.
PARTNER
STATUS
Trust unitholders will be treated as partners of ECA Marcellus
Trust I for federal income tax purposes. Also, trust
unitholders whose trust units are held in street name or by a
nominee and who have the right to direct the nominee in the
exercise of all substantive rights attendant to the ownership of
their trust units will be treated as partners of ECA Marcellus
Trust I for federal income tax purposes.
A beneficial owner of trust units whose trust units have been
transferred to a short seller to complete a short sale would
appear, as a result, to lose his status as a partner with
respect to those trust units for federal income tax purposes.
Please read Tax consequences of
trust unit ownership Treatment of short
sales. Income, gain, deductions or losses would not appear
to be reportable by a trust unitholder who is not a partner for
federal income tax purposes, and any cash distributions received
by a trust unitholder who is not a partner for federal income
tax purposes would therefore appear to be fully taxable as
ordinary income. These unitholders are urged to consult their
own tax advisors with respect to their tax considerations
related to holding trust units. The references to
unitholders in the discussion that follows are to
persons who are treated as partners in ECA Marcellus
Trust I for federal income tax purposes.
TAX
CLASSIFICATION OF THE PDP ROYALTY INTEREST AND THE PUD ROYALTY
INTEREST
For federal income tax purposes, the PDP Royalty Interest and
the PUD Royalty Interest will have the tax characteristics of
mineral royalty interests to the extent they are, at the time of
their creation, reasonably expected to have an economic life
that corresponds substantially to the economic life of the
mineral property or properties burdened thereby. Payments out of
production that are received in respect of a mineral interest
that constitutes a royalty interest for federal income tax
purposes are taxable under current law as ordinary income
subject to an allowance for cost or percentage depletion in
respect of such income.
In contrast, the PDP Royalty Interest and the PUD Royalty
Interest will have the tax characteristics of production
payments governed by Section 636 of the Internal Revenue
Code to the extent they may not, at the time of their creation,
be reasonably expected to extend in substantial amounts over the
entire productive lives of the mineral property or properties
they burden. Payments out of production that are received in
respect of a mineral interest that constitutes a production
payment for federal income tax purposes are treated under
current law as consisting of a receipt of principal and interest
on a nonrecourse debt obligation, with the interest component
being taxable as ordinary income.
In the event that a portion of a single royalty interest
terminates by its terms prior to the point in time that the
economically productive life of the burdened mineral property is
substantially exhausted and the remaining portion continues to
burden the property until its economically productive life is
substantially exhausted, the federal income tax characteristics
of the royalty interest are determined as if it comprised two
separate interests, with the terminating
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portion being treated as a production payment and the continuing
portion being treated as a royalty interest.
Based on the reserve report and representations made by ECA
regarding the expected economic life of the Underlying
Properties and the expected duration of the Term Royalties and
the Perpetual Royalties, the Term PDP Royalty will and the Term
PUD Royalty should be treated as production payments
under Section 636 of the Internal Revenue Code, and thus as
nonrecourse debt instruments of ECA for U.S. federal income
tax purposes. The Perpetual PDP Royalty will and the Perpetual
PUD Royalty should be treated as continuing, nonoperating
economic interest in the nature of royalties payable out of
production from the mineral interests they burden.
Consistent with this characterization, ECA and the trust intend
to treat the Perpetual Royalties as mineral royalty interests
for federal income tax purposes. In addition, ECA and the trust
intend to treat the Term Royalties as debt instruments for
U.S. federal income tax purposes subject to the Treasury
Regulations applicable to contingent payment debt instruments
(the CPDI regulations), and the trust will agree to
be bound by ECAs application of the CPDI regulations,
including ECAs determination of the rate at which interest
will be deemed to accrue on the such interests. The remainder of
this discussion assumes that the Term Royalties will be treated
in accordance with that agreement and ECAs determinations
and that the Perpetual Royalties will be treated as mineral
royalty interests. No assurance can be given that the IRS will
not assert that such interests should be treated differently.
Such different treatment could affect the amount, timing and
character of income, gain or loss in respect of an investment in
trust units and could require a trust unitholder to accrue
interest income at a rate different than the comparable
yield described below. Please read Tax
consequences of trust unit ownership Tax
treatment of the term royalties, and Tax
consequences of trust unit ownership Tax
treatment of the perpetual royalties.
TAX
CONSEQUENCES OF TRUST UNIT OWNERSHIP
Flow-Through
of Taxable Income
As a partnership for federal income tax purposes, the trust will
not be a taxable entity required to pay any federal income tax.
Instead, each trust unitholder will be required to report on his
income tax return his allocable share of the trusts
income, gains, losses, deductions and credits without regard to
whether the trust makes cash distributions to him. Consequently,
the trust may allocate taxable income to a trust unitholder even
if he has not received a cash distribution.
Accounting
Method and Taxable Year
The trust will use the year ending December 31 as its taxable
year and the accrual method of accounting for federal income tax
purposes. Each trust unitholder will be required to include in
income his share of the trusts income, gain, loss,
deduction and credit for the trusts taxable year ending
within or with his taxable year. In addition, a trust unitholder
who has a taxable year ending on a date other than December 31
and who disposes of all of his trust units following the close
of the trusts taxable year but before the close of his
taxable year must include his share of the trusts income,
gain, loss, deduction and credit in his taxable income for his
taxable year, with the result that he will be required to
include in income for his taxable year his share of more than
twelve months of the trusts income, gain, loss, deduction
and credit. Please read Disposition of
trust units Allocations between transferors and
transferees.
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Basis
of Trust Units
A trust unitholders initial tax basis for his trust units
will be the amount he paid for the trust units. That basis will
be increased by his share of the trusts income and gain
and decreased, but not below zero, by distributions from the
trust, by the trust unitholders share of the trusts
losses, if any, by depletion deductions taken by him to the
extent such deductions do not exceed his proportionate allocated
share of the adjusted tax basis of the Perpetual Royalties, and
by his share of the trusts expenditures that are not
deductible in computing taxable income and are not required to
be capitalized. Please read Disposition of
trust units Recognition of gain or loss.
Allocation
of Income, Gain, Loss, Deduction and Credit
In general, if the trust has a net profit, the trusts
items of income, gain, loss, deduction and credit will be
allocated among the trust unitholders in accordance with their
percentage interests in the trust. At any time that
distributions are made to the common units in excess of
distributions to the subordinated trust units, or incentive
distributions are made in respect of the subordinated trust
units, gross income will be allocated to the recipients to the
extent of these distributions. If the trust has a net loss, that
loss will be allocated first to the subordinated trust units to
the extent of their positive capital accounts and thereafter to
the trust unitholders in accordance with their percentage
interests in the trust.
Specified items of the trusts income, gain, loss,
deduction and credit will be allocated under Section 704(c)
of the Internal Revenue Code to account for any difference
between the tax basis and fair market value of any property
treated as having been contributed to the trust by ECA or
certain of its affiliates that exists at the time of such
contribution, together, referred to in this discussion as the
Contributed Property. These
Section 704(c) Allocations are required to
eliminate the difference between a partners
book capital account, credited with the fair market
value of Contributed Property, and the tax capital
account, credited with the tax basis of Contributed Property,
referred to in this discussion as the Book-Tax
Disparity. The effect of these 704(c) Allocations to a
unitholder purchasing trust units from the trust in this
offering will be essentially the same as if the tax bases of the
trusts assets were equal to their fair market value at the
time of this offering. Finally, although the trust does not
expect that its operations will result in the creation of
negative capital accounts, if negative capital accounts
nevertheless result, items of the trusts income and gain
will be allocated in an amount and manner sufficient to
eliminate the negative balance as quickly as possible.
An allocation of items of the trusts income, gain, loss,
deduction or credit, other than an allocation required by
Section 704(c) of the Internal Revenue Code to eliminate
the Book-Tax Disparity, will generally be given effect for
federal income tax purposes in determining a unitholders
share of an item of income, gain, loss, deduction or credit only
if the allocation has substantial economic effect. In any other
case, a unitholders share of an item will be determined on
the basis of his interest in the trust, which will be determined
by taking into account all the facts and circumstances,
including:
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his relative contributions to the trust;
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the interests of all the partners in profits and losses;
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the interest of all the partners in cash flow; and
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the rights of all the partners to distributions of capital upon
liquidation.
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Vinson & Elkins L.L.P. is of the opinion that, with
the exception of the issues described in Disposition of
trust units Allocations between transferors and
transferees, allocations under the trust agreement will be
given effect for federal income tax purposes in determining a
partners share of an item of income, gain, loss, deduction
or credit.
Treatment
of Trust Distributions
Distributions by the trust to a trust unitholder generally will
not be taxable to the trust unitholder for federal income tax
purposes, except to the extent the amount of any such cash
distribution exceeds his tax basis in his trust units
immediately before the distribution. The trusts cash
distributions in excess of a unitholders tax basis (if
any) generally will be considered to be gain from the sale or
exchange of the trust units, taxable in accordance with the
rules described under Disposition of
trust units below.
Ratio
of Taxable Income to Distributions
The trust estimates that a purchaser of trust units in this
offering who owns those trust units from the date of closing of
this offering through the record date for distributions for the
period ending December 31, 2012, will be allocated, on a
cumulative basis, an amount of federal taxable income for that
period that will be approximately 65% or less of the cash
distributed with respect to that period. These estimates and
assumptions are subject to, among other things, numerous
business, economic, regulatory, legislative, competitive and
political uncertainties beyond the trusts control.
Further, the estimates are based on current tax law and tax
reporting positions that the trust will adopt and with which the
IRS could disagree. Accordingly, the trust cannot assure
unitholders that these estimates will prove to be correct. The
actual percentage of distributions that will correspond to
taxable income could be higher or lower than expected, and any
differences could be material and could materially affect the
value of the trust units.
Tax
Treatment of the Term Royalties
Under the CPDI regulations, the trust generally will be required
to accrue income on the Term Royalties which are treated as
production payments, and therefore as nonrecourse debt
obligations of ECA for federal income tax purposes, in the
amounts described below.
The CPDI regulations provide that the trust must accrue an
amount of ordinary interest income for U.S. federal income
tax purposes, for each accrual period prior to and including the
maturity date of the debt instrument that equals:
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the product of (i) the adjusted issue price (as defined
below) of the debt instrument as of the beginning of the accrual
period; and (ii) the comparable yield to maturity (as
defined below) of such debt instrument, adjusted for the length
of the accrual period;
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divided by the number of days in the accrual period; and
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multiplied by the number of days during the accrual period that
the trust held the debt instrument.
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The issue price of the debt instrument represented
by each production payment held by the trust is the portion of
the first price at which a substantial amount of the trust units
is sold to the public, excluding sales to bond houses, brokers
or similar persons or organizations acting in the capacity of
underwriters, placement agents or wholesalers, that is allocable
to the production payment based on the relative fair market
value of the production payment to the other assets of the
trust. The adjusted issue price of such a debt
instrument is its issue price increased by any
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interest income previously accrued, determined without regard to
any adjustments to interest accruals described below, and
decreased by the projected amount of any payments scheduled to
be made with respect to the debt instrument at an earlier time
(without regard to the actual amount paid). The term
comparable yield means the annual yield ECA would be
expected to pay, as of the initial issue date, on a fixed rate
debt security with no contingent payments but with terms and
conditions otherwise comparable to those of the debt instrument
represented by the production payment.
ECA and the trust intend to take the position that the
comparable yield for each debt instrument held by the trust is
an annual rate of 10%, compounded semi-annually. The CPDI
regulations require that ECA provide to the trust, solely for
determining the amount of interest accruals for
U.S. federal income tax purposes, a schedule of the
projected amounts of payments, which are referred to as
projected payments, on the Term Royalties treated as debt
instruments held by the trust. These payments set forth on the
schedule must produce a total return on such debt instruments
equal to their comparable yield. Amounts treated as interest
under the CPDI regulations are treated as original issue
discount for all purposes of the Internal Revenue Code.
As required by the CPDI regulations, for U.S. federal
income tax purposes, the trust must use the comparable yield and
the schedule of projected payments as described above in
determining the trusts interest accruals, and the
adjustments thereto described below, in respect of the debt
instruments held by the trust.
ECAs determinations of the comparable yield and the
projected payment schedule are not binding on the IRS and it
could challenge such determinations. If it did so, and if any
such challenge were successful, then the amount and timing of
interest income accruals of the trust would be different from
those reported by the trust or included on previously filed tax
returns by the trust unitholders.
The comparable yield and the schedule of projected payments are
not determined for any purpose other than for the determination
for U.S. federal income tax purposes of the trusts
interest accruals and adjustments thereof in respect of the debt
instruments held by the trust and do not constitute a projection
or representation regarding the actual amounts payable to the
trust.
For U.S. federal income tax purposes, the trust is required
under the CPDI regulations to use the comparable yield and the
projected payment schedule established by ECA in determining
interest accruals and adjustments in respect of the production
payments, unless the trust timely discloses and justifies the
use of a different comparable yield and projected payment
schedule to the IRS. Pursuant to the terms of the conveyance,
ECA and the trust have agreed (in the absence of an
administrative determination or judicial ruling to the contrary)
to be bound by ECAs determination of the comparable yield
and projected payment schedule.
If, during any taxable year, the trust receives actual payments
with respect to a debt instrument held by the trust that in the
aggregate exceed the total amount of projected payments for that
taxable year, the trust will incur a net positive
adjustment under the CPDI regulations equal to the amount
of such excess. The trust will treat a net positive
adjustment as additional interest income for such taxable
year.
If the trust receives in a taxable year actual payments with
respect to a debt instrument held by the trust that in the
aggregate are less than the amount of projected payments for
that taxable year, the trust will incur a net negative
adjustment under the CPDI regulations equal to the amount
of such deficit. This adjustment will (a) reduce the
trusts interest income on the debt instrument held by the
trust for that taxable year, and (b) to the extent of any
excess after the application of (a) give rise to an
ordinary loss to the extent of the trusts interest income
on such
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debt instrument during prior taxable years, reduced to the
extent such interest was offset by prior net negative
adjustments. Any negative adjustment in excess of the amount
described in (a) and (b) will be carried forward, as a
negative adjustment to offset future interest income in respect
of that debt instrument held by the trust. If either of the Term
Royalties is not treated as a production payment (and hence not
as a debt instrument) for federal income tax purposes, the trust
intends to take the position that its basis in the Term Royalty
is recouped in proportion to the production from the Term
Royalty.
Neither the trust nor the trust unitholders are entitled to
claim depletion deductions with respect to the Term Royalties.
Tax
Treatment of the Perpetual Royalties
The payments received by the trust in respect of the Perpetual
Royalties treated as mineral royalty interests for federal
income tax purposes should be treated as ordinary income. Trust
unitholders should be entitled to deductions for the greater of
either cost depletion or (if otherwise allowable) percentage
depletion with respect to such income. Although the Internal
Revenue Code requires each trust unitholder to compute his own
depletion allowance and maintain records of his share of the
adjusted tax basis of the underlying royalty interest for
depletion and other purposes, the trust intends to furnish each
of the trust unitholders with information relating to this
computation for federal income tax purposes. Each trust
unitholder, however, remains responsible for calculating his own
depletion allowance and maintaining records of his share of the
adjusted tax basis of the Perpetual Royalties for depletion and
other purposes.
Percentage depletion is generally available with respect to
trust unitholders who qualify under the independent producer
exemption contained in Section 613A(c) of the Internal
Revenue Code. For this purpose, an independent producer is a
person not directly or indirectly involved in the retail sale of
oil, natural gas, or derivative products or the operation of a
major refinery. Percentage depletion is calculated as an amount
generally equal to 15% (and, in the case of marginal production,
potentially a higher percentage) of the trust unitholders
gross income from the depletable property for the taxable year.
The percentage depletion deduction with respect to any property
is limited to 100% of the taxable income of the trust unitholder
from the property for each taxable year, computed without the
depletion allowance. A trust unitholder that qualifies as an
independent producer may deduct percentage depletion only to the
extent the trust unitholders average daily production of
domestic crude oil, or the natural gas equivalent, does not
exceed 1,000 barrels. This depletable amount may be
allocated between oil and natural gas production, with 6,000
cubic feet of domestic natural gas production regarded as
equivalent to one barrel of crude oil. The 1,000-barrel
limitation must be allocated among the independent producer and
controlled or related persons and family members in proportion
to the respective production by such persons during the period
in question.
In addition to the foregoing limitations, the percentage
depletion deduction otherwise available is limited to 65% of a
trust unitholders total taxable income from all sources
for the year, computed without the depletion allowance, net
operating loss carrybacks, or capital loss carrybacks. Any
percentage depletion deduction disallowed because of the 65%
limitation may be deducted in the following taxable year if the
percentage depletion deduction for such year plus the deduction
carryover does not exceed 65% of the trust unitholders
total taxable income for that year. The carryover period
resulting from the 65% net income limitation is unlimited.
In addition to the limitations on percentage depletion discussed
above, on February 1, 2010, the White House released
President Obamas budget proposal for the fiscal year 2011
(the 2011 Budget). The 2011 Budget proposes to
eliminate certain tax preferences applicable to taxpayers
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engaged in the exploration or production of natural resources
effective in 2011. Specifically, the 2011 Budget proposes to
repeal the deduction for percentage depletion with respect to
oil and natural gas wells, in which case only cost depletion
would be available. It is uncertain whether this or any other
legislative proposals will ever be enacted and, if so, when it
would become effective.
Trust unitholders that do not qualify under the independent
producer exemption are generally restricted to depletion
deductions based on cost depletion. Cost depletion deductions
are calculated by (i) dividing the trust unitholders
allocated share of the adjusted tax basis in the underlying
mineral property by the number of mineral units (barrels of oil
and thousand cubic feet, or Mcf, of natural gas) remaining as of
the beginning of the taxable year and (ii) multiplying the
result by the number of mineral units sold within the taxable
year. The total amount of deductions based on cost depletion
cannot exceed the trust unitholders share of the total
adjusted tax basis in the property.
The foregoing discussion of depletion deductions does not
purport to be a complete analysis of the complex legislation and
Treasury Regulations relating to the availability and
calculation of depletion deductions by the trust unitholders.
Further, because depletion is required to be computed separately
by each trust unitholder and not by the trust, no assurance can
be given, and counsel is unable to express any opinion, with
respect to the availability or extent of percentage depletion
deductions to the trust unitholders for any taxable year. The
trust encourages each prospective trust unitholder to consult
his tax advisor to determine whether percentage depletion would
be available to him.
Tax
Treatment Upon Sale of the Perpetual Royalties at Termination
Date
The sale of the Perpetual Royalties by the trust at or shortly
after the Termination Date will generally give rise to long-term
capital gain or loss to the trust unitholders for federal income
tax purposes, except that any gain will be taxed at ordinary
income rates to the extent of depletion deductions that reduced
the trust unitholders adjusted basis in the Perpetual
Royalties. Each trust unitholder will be responsible for
calculating his gain or loss based on the difference between his
pro-rata share of the amount realized on the sale by the trust
and his adjusted basis in the Perpetual Royalties, and if a gain
is realized, the portion thereof taxable as ordinary income by
reason of depletion deductions previously claimed by such trust
unitholder. However, the trust intends to furnish each of the
trust unitholders with information relating to this calculation
for federal income tax purposes in connection with the final
partnership tax return for the trust.
Limitations
on Deductibility of Losses
It is not anticipated that the trust will generate losses.
Nevertheless, should losses result, trust unitholders must
consult their own tax advisors as to the applicability to them
of loss limitation rules that could operate to limit the
deductibility to a trust unitholder of his share of the
trusts losses such as the basis limitation, the at
risk rules and the passive loss rules. Special passive
loss limitation rules apply with respect to publicly-traded
partnerships.
Limitations
on Interest Deductions
The deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
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interest on indebtedness properly allocable to property held for
investment;
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the trusts interest expense attributed to portfolio
income; and
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the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
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The computation of a trust unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a trust
unit. Net investment income includes gross income from property
held for investment and amounts treated as portfolio income
under the passive loss rules, less deductible expenses, other
than interest, directly connected with the production of
investment income, but generally does not include gains
attributable to the disposition of property held for investment
or qualified dividend income. The IRS has indicated that the net
passive income earned by a publicly traded partnership will be
treated as investment income to its unitholders for purposes of
the investment interest deduction limitation. In addition, the
trust unitholders share of the trusts portfolio
income will be treated as investment income.
Entity-Level Withholdings
If the trust is required or elects under applicable law to pay
any federal, state, local or foreign income tax on behalf of any
trust unitholder or any former trust unitholder, the trust is
authorized to pay those taxes from its funds. That payment, if
made, will be treated as a distribution of cash to the trust
unitholder on whose behalf the payment was made. If the payment
is made on behalf of a person whose identity cannot be
determined, the trust is authorized to treat the payment as a
distribution to all current trust unitholders. The trust is
authorized to amend its trust agreement in the manner necessary
to maintain uniformity of intrinsic tax characteristics of trust
units. Payments by the trust as described above could give rise
to an overpayment of tax on behalf of an individual trust
unitholder in which event the trust unitholder would be required
to file a claim in order to obtain a credit or refund.
Treatment
of Short Sales
A trust unitholder whose trust units are loaned to a short
seller to cover a short sale of trust units may be
considered as having disposed of those units. If so, he would no
longer be treated for tax purposes as a partner with respect to
those trust units during the period of the loan and may
recognize gain or loss from the disposition. As a result, during
this period:
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any of the trusts income, gain, loss, deduction or credit
with respect to those trust units would not be reportable by the
trust unitholder;
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any cash distributions received by the trust unitholder as to
those trust units would be fully taxable; and
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all of these distributions would appear to be ordinary income.
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Vinson & Elkins L.L.P. has not rendered an opinion
regarding the tax treatment of a trust unitholder whose trust
units are loaned to a short seller to cover a short sale of
trust units; therefore, trust unitholders desiring to assure
their status as partners and avoid the risk of gain recognition
from a loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
borrowing and loaning their trust units. The IRS has previously
announced that it is studying issues relating to the tax
treatment of short sales of partnership interests. Please also
read Disposition of
trust units Recognition of gain or loss.
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Alternative
Minimum Tax
Each trust unitholder will be required to take into account his
distributive share of any items of the trusts income,
gain, loss, deduction or credit for purposes of the alternative
minimum tax. The current minimum tax rate for noncorporate
taxpayers is 26% on the first $175,000 of alternative minimum
taxable income in excess of the exemption amount and 28% on any
additional alternative minimum taxable income. Prospective trust
unitholders are urged to consult with their tax advisors as to
the impact of an investment in trust units on their liability
for the alternative minimum tax.
Tax
Rates
Under current law, the highest marginal U.S. federal income
tax rate applicable to ordinary income of individuals is 35% and
the highest marginal U.S. federal income tax rate
applicable to long-term capital gains (generally, capital gains
on certain assets held for more than 12 months) of
individuals is 15%. However, absent new legislation extending
the current rates, beginning January 1, 2011, the highest
marginal U.S. federal income tax rate applicable to
ordinary income and long-term capital gains of individuals will
increase to 39.6% and 20%, respectively. Moreover, these rates
are subject to change by new legislation at any time.
The recently enacted Health Care and Education Reconciliation
Act of 2010 will impose a 3.8% Medicare tax on certain
investment income earned by individuals for taxable years
beginning after December 31, 2012. For these purposes,
investment income generally includes a trust unitholders
allocable share of the trusts income and gain realized by
a trust unitholder from a sale of trust units. The tax will be
imposed on the lesser of (i) the trust unitholders
net income from all investments, and (ii) the amount by
which the trust unitholders adjusted gross income exceeds
$250,000 (if the trust unitholder is married and filing jointly)
or $200,000 (if the trust unitholder is not married).
Section 754
Election
The trust will make the election permitted by Section 754
of the Internal Revenue Code. That election is irrevocable
without the consent of the IRS. The election will generally
permit the trust to adjust a subsequent trust unit
purchasers tax basis in the trusts assets
(inside basis) under Section 743(b) of the
Internal Revenue Code to reflect his purchase price of trust
units acquired from another trust unitholder. The
Section 743(b) adjustment belongs to the purchaser and not
to other trust unitholders. For purposes of this discussion, a
trust unitholders inside basis in the trusts assets
will be considered to have two components: (1) his share of
tax basis in the trusts assets (common basis)
and (2) his Section 743(b) adjustment to that basis.
A Section 754 election is advantageous if the
transferees tax basis in his units is higher than the
units share of the aggregate tax basis of the trusts
assets immediately prior to the transfer. In such a case, as a
result of the election, the transferee would have a higher tax
basis in his share of the trusts assets for purposes of
calculating, among other items, cost depletion deductions on the
Perpetual Royalties, and his share of any gain on a sale of the
trusts assets would be less. Conversely, a
Section 754 election is disadvantageous if the
transferees tax basis in his units is lower than those
trust units share of the aggregate tax basis of the
trusts assets immediately prior to the transfer. Thus, the
fair market value of the trust units may be affected either
favorably or unfavorably by the election. A basis adjustment is
required regardless of whether a Section 754 election is
made in the case of a transfer of an interest in the trust if it
has a substantial built-in loss immediately after the transfer.
Generally a built in loss or a basis reduction is
substantial if it exceeds $250,000.
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The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
value of the trusts assets and other matters. For example,
the allocation of the Section 743(b) adjustment among the
trusts assets must be made in accordance with the Internal
Revenue Code. The trust cannot assure unitholders that the
determinations it makes will not be successfully challenged by
the IRS and that the deductions resulting from them will not be
reduced or disallowed altogether. Should the IRS require a
different basis adjustment to be made, and should, in the
trusts opinion, the expense of compliance exceed the
benefit of the election, the trust may seek permission from the
IRS to revoke its Section 754 election. If permission is
granted, a subsequent purchaser of trust units may be allocated
more income than he would have been allocated had the election
not been revoked.
Initial
Tax Basis and Amortization
The initial tax basis of the portion of the PDP Royalty Interest
treated as a royalty interest in minerals and the portion
treated as a production payment, and the initial basis of the
portion of the PUD Royalty Interest treated as a royalty
interest in minerals and the portion treated as a production
payment will be effectively equal on a
per-unit
basis to the portion of the unit price allocated to each based
on each such portions relative fair market value.
The costs incurred in selling the trust units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon the trusts
termination. There are uncertainties regarding the
classification of costs as organization expenses, which may be
amortized by the trust, and as syndication expenses, which may
not be amortized by the trust. The underwriting discounts and
commissions the trust incurs will be treated as syndication
expenses.
Valuation
and Tax Basis of the Trusts Properties
The federal income tax consequences of the ownership and
disposition of trust units will depend in part on the
trusts estimates of the relative fair market values, and
the initial tax bases, of the trusts assets. Although the
trust may from time to time consult with professional appraisers
regarding valuation matters, the trust will make many of the
relative fair market value estimates itself. These estimates and
determinations of basis are subject to challenge and will not be
binding on the IRS or the courts. If the estimates of fair
market value or basis are later found to be incorrect, the
character and amount of items of income, gain, loss or
deductions previously reported by trust unitholders might
change, and trust unitholders might be required to adjust their
tax liability for prior years and incur interest and penalties
with respect to those adjustments.
DISPOSITION
OF TRUST UNITS
Recognition
of Gain or Loss
Gain or loss will be recognized on a sale of trust units equal
to the difference between the amount realized and the trust
unitholders tax basis for the trust units sold. A trust
unitholders amount realized will be measured by the sum of
the cash or the fair market value of other property received.
The amount realized should be reduced by the unused net negative
adjustments attributable to the trust units disposed of as
described above under Tax Consequences of
trust unit ownership Tax treatment of the term
royalties. A trust unitholders adjusted tax basis in
his trust units will be equal to the trust unitholders
original purchase price for the trust units, increased by income
and decreased by losses or deductions previously allocated to
the trust unitholder and by distributions to the trust
unitholder and depletion deductions claimed by the trust
unitholder.
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Prior distributions from the trust in excess of cumulative net
taxable income for a trust unit that decreased a
unitholders tax basis in that trust unit will, in effect,
become taxable income if the trust unit is sold at a price
greater than the trust unitholders tax basis in that trust
unit, even if the price received is less than his original cost.
Except as noted below, gain or loss recognized by a trust
unitholder, other than a dealer in trust units, on
the sale or exchange of a trust unit will generally be taxable
as capital gain or loss. Capital gain recognized by an
individual on the sale of trust units held for more than twelve
months will generally be taxed at a maximum U.S. federal
income tax rate of 15% through December 31, 2010 and 20%
thereafter (absent new legislation extending or adjusting the
current rate). However, a portion, which will likely be
substantial, of this gain or loss will be separately computed
and taxed as ordinary income or loss under Section 751 of
the Internal Revenue Code to the extent attributable to assets
giving rise to unrealized receivables the trust
owns. The term unrealized receivables includes
potential recapture items, including depletion recapture.
Ordinary income attributable to unrealized receivables such as
depletion recapture may exceed net taxable gain realized upon
the sale of a trust unit and may be recognized even if there is
a net taxable loss realized on the sale of a trust unit. Thus, a
trust unitholder may recognize both ordinary income and a
capital loss upon a sale of trust units. Net capital losses may
offset capital gains and no more than $3,000 of ordinary income,
in the case of individuals, and may only be used to offset
capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in his entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling trust unitholder who can
identify trust units transferred with an ascertainable holding
period to elect to use the actual holding period of the trust
units transferred. Thus, according to the ruling discussed
above, a trust unitholder will be unable to select high or low
basis trust units to sell as would be the case with corporate
stock, but, according to the Treasury Regulations, he may
designate specific trust units sold for purposes of determining
the holding period of trust units transferred. A trust
unitholder electing to use the actual holding period of trust
units transferred must consistently use that identification
method for all subsequent sales or exchanges of trust units. A
trust unitholder considering the purchase of additional trust
units or a sale of trust units purchased in separate
transactions is urged to consult his tax advisor as to the
possible consequences of this ruling and application of the
Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
appreciated partnership interest, one in which gain
would be recognized if it were sold, assigned or terminated at
its fair market value, if the taxpayer or related persons
enter(s) into:
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a short sale;
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an offsetting notional principal contract; or
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a futures or forward contract with respect to the partnership
interest or substantially identical property.
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Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
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taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations
Between Transferors and Transferees
In general, the trusts taxable income and losses will be
determined annually, will be allocated on a monthly basis and
will be subsequently apportioned among the trust unitholders in
proportion to the number of trust units owned by each of them as
of the opening of the applicable exchange on which the trust
units are then traded on the first business day of the month,
which is referred to in this prospectus as the Allocation
Date. However, gain or loss realized on a sale or other
disposition of the trusts assets other than in the
ordinary course of business will be allocated among the trust
unitholders on the Allocation Date in the month in which that
gain or loss is recognized. As a result, a trust unitholder
transferring trust units may be allocated income, gain, loss and
deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the
Internal Revenue Code, and most publicly traded partnerships use
similar simplifying conventions, the use of this method may not
be permitted under existing Treasury Regulations. Recently,
however, the Department of the Treasury and the IRS issued
proposed Treasury Regulations that provide a safe harbor
pursuant to which a publicly traded partnership may use a
similar monthly simplifying convention to allocate tax items
among transferor and transferee unitholders, although such tax
items must be prorated on a daily basis. Existing publicly
traded partnerships are entitled to rely on these proposed
Treasury Regulations; however, they are not binding on the IRS
and are subject to change until final Treasury Regulations are
issued. Accordingly, Vinson & Elkins L.L.P. is unable
to opine on the validity of this method of allocating income and
deductions between transferor and transferee trust unitholders.
If this method is not allowed under the Treasury Regulations, or
only applies to transfers of less than all of the trust
unitholders interest, the trusts taxable income or
losses might be reallocated among the trust unitholders. The
trust is authorized to revise its method of allocation between
transferor and transferee trust unitholders, as well as trust
unitholders whose interests vary during a taxable year, to
conform to a method permitted under future Treasury Regulations.
A trust unitholder who owns trust units at any time during a
quarter and who disposes of them prior to the record date set
for a cash distribution for that quarter will be allocated items
of the trusts income, gain, loss and deductions
attributable to that quarter but will not be entitled to receive
that cash distribution.
Notification
Requirements
A trust unitholder who sells any of his trust units is generally
required to notify the trust in writing of that sale within
30 days after the sale (or, if earlier, January 15 of the
year following the sale). A purchaser of trust units who
purchases trust units from another trust unitholder is also
generally required to notify the trust in writing of that
purchase within 30 days after the purchase. Upon receiving
such notifications, the trust is required to notify the IRS of
that transaction and to furnish specified information to the
transferor and transferee. Failure to notify the trust of a
purchase may, in some cases, lead to the imposition of
penalties. However, these reporting requirements do not apply to
a sale by an individual who is a citizen of the United States
and who affects the sale or exchange through a broker who will
satisfy such requirements.
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Constructive
Termination
The trust will be considered to have been terminated for tax
purposes if there are sales or exchanges which, in the
aggregate, constitute 50% or more of the total interests in the
trusts capital and profits within a twelve-month period.
For purposes of measuring whether the 50% threshold is reached,
multiple sales of the same interest are counted only once. A
constructive termination results in the closing of the
trusts taxable year for all trust unitholders. In the case
of a trust unitholder reporting on a taxable year other than a
calendar year, the closing of the trusts taxable year may
result in more than twelve months of the trusts taxable
income or loss being includable in his taxable income for the
year of termination. A constructive termination occurring on a
date other than December 31 will result in the trust filing two
tax returns (and trust unitholders may receive two
Schedule K-1s)
for one fiscal year and the cost of the preparation of these
returns will be borne by all trust unitholders. The trust would
be required to make new tax elections after a termination,
including a new election under Section 754 of the Internal
Revenue Code. A termination could also result in penalties if
the trust was unable to determine that the termination had
occurred. Moreover, a termination might either accelerate the
application of, or subject the trust to, any tax legislation
enacted before the termination.
TAX
EXEMPT ORGANIZATIONS AND OTHER INVESTORS
Ownership of trust units by employee benefit plans, other
tax-exempt organizations, non-resident aliens,
non-U.S. corporations
and other
non-U.S. persons
raises issues unique to those investors and, as described below,
may have substantially adverse tax consequences to them. If a
potential investor is a tax-exempt entity or a
non-U.S. person,
then it should consult a tax advisor before investing in the
trust units.
Tax
Exempt Organizations
Employee benefit plans and most other organizations exempt from
federal income tax including IRAs and other retirement plans are
subject to federal income tax on unrelated business taxable
income. Because all of the income of the trust is expected to be
royalty income, interest income, hedging income and gain from
the sale of real property, none of which is unrelated business
taxable income, any such organization exempt from federal income
tax is not expected to be taxable on income generated by
ownership of trust units so long as neither the property held by
the trust nor the trust units are debt-financed property within
the meaning of Section 514(b) of the Internal Revenue Code.
In general, trust property would be debt-financed if the trust
incurs debt to acquire the property or otherwise incurs or
maintains a debt that would not have been incurred or maintained
if the property had not been acquired and a trust unit would be
debt-financed if the trust unitholder incurs debt to acquire the
trust unit or otherwise incurs or maintains a debt that would
not have been incurred or maintained if the trust unit had not
been acquired.
Non-U.S.
Persons
The trust will be required to withhold (at a 30% rate or lower
applicable treaty rate) on interest and royalty income allocable
to
non-U.S. trust
unitholders.
Moreover, each of the PDP and PUD Royalty Interests will be
treated as a United States real property interest
for U.S. federal income tax purposes. However, as long as
the trust units are regularly traded on an established
securities market, gain realized by a
non-U.S. trust
unitholder on a sale of trust units will be subject to federal
income tax only if:
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the gain is, or is treated as, effectively connected with
business conducted by the
non-U.S. trust
unitholder in the United States, and in the case of an
applicable tax treaty,
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is attributable to a U.S. permanent establishment
maintained by the
non-U.S. trust
unitholder;
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the
non-U.S. trust
unitholder is an individual who is present in the United States
for at least 183 days in the year of the sale and certain
other conditions are met; or
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the
non-U.S. trust
unitholder owns currently, or owned at certain earlier times,
directly or by applying certain attribution rules, more than 5%
of the trust units.
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ADMINISTRATIVE
MATTERS
Trust Information
Returns and Audit Procedures
The trust intends to furnish to each trust unitholder, within
90 days after the close of each calendar year, specific tax
information, including a
Schedule K-1,
which describes his share of the trusts income, gain, loss
and deduction for the trusts preceding taxable year. In
preparing this information, which will not be reviewed by
counsel, the trust will take various accounting and reporting
positions, some of which have been mentioned earlier, to
determine each trust unitholders share of income, gain,
loss and deduction. The trust cannot assure unitholders that
those positions will yield a result that conforms to the
requirements of the Internal Revenue Code, Treasury Regulations
or administrative interpretations of the IRS. Neither the trust
nor Vinson & Elkins L.L.P. can assure prospective
trust unitholders that the IRS will not successfully contend in
court that those positions are impermissible. Any challenge by
the IRS could negatively affect the value of the units.
The IRS may audit the trusts federal income tax
information returns. Adjustments resulting from an IRS audit may
require each trust unitholder to adjust a prior years tax
liability, and possibly may result in an audit of his return.
Any audit of a trust unitholders return could result in
adjustments not related to the trusts returns as well as
those related to the trusts returns.
Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of
administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax Matters Partner for these
purposes. The trust agreement names ECA as the trusts Tax
Matters Partner.
The Tax Matters Partner has made and will make some elections on
behalf of the trust and the trust unitholders. In addition, the
Tax Matters Partner can extend the statute of limitations for
assessment of tax deficiencies against trust unitholders for
items in the trusts returns. The Tax Matters Partner may
bind a trust unitholder with less than a 1% profits interest in
the trust to a settlement with the IRS unless that trust
unitholder elects, by filing a statement with the IRS, not to
give that authority to the Tax Matters Partner. The Tax Matters
Partner may seek judicial review, by which all the trust
unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any trust
unitholder having at least a 1% interest in profits or by any
group of trust unitholders having in the aggregate at least a 5%
interest in profits. However, only one action for judicial
review will go forward, and each trust unitholder with an
interest in the outcome may participate.
A trust unitholder must file a statement with the IRS
identifying the treatment of any item on his federal income tax
return that is not consistent with the treatment of the item on
the trusts
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return. Intentional or negligent disregard of this consistency
requirement may subject a trust unitholder to substantial
penalties.
Nominee
Reporting
Persons who hold an interest in the trust as a nominee for
another person are required to furnish to the trust:
(a) the name, address and taxpayer identification number of
the beneficial owner and the nominee;
(b) whether the beneficial owner is:
1. a person that is not a United States person;
2. a
non-U.S. government,
an international organization or any wholly owned agency or
instrumentality of either of the foregoing; or
3. a tax-exempt entity;
(c) the amount and description of units held, acquired or
transferred for the beneficial owner; and
(d) specific information including the dates of
acquisitions and transfers, means of acquisitions and transfers
and acquisition cost for purchases, as well as the amount of net
proceeds from sales.
Brokers and financial institutions are required to furnish
additional information, including whether they are United States
persons and specific information on units they acquire, hold or
transfer for their own account. A penalty of $50 per failure, up
to a maximum of $100,000 per calendar year, is imposed by the
Internal Revenue Code for failure to report that information to
the trust. The nominee is required to supply the beneficial
owner of the trust units with the information furnished to the
trust.
Accuracy-Related
Penalties
An additional tax equal to 20% of the amount of any portion of
an underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or
regulations, substantial understatements of income tax and
substantial valuation misstatements, is imposed by the Internal
Revenue Code. No penalty will be imposed, however, for any
portion of an underpayment if it is shown that there was a
reasonable cause for that portion and that the taxpayer acted in
good faith regarding that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000. The amount of any
understatement subject to penalty generally is reduced if any
portion is attributable to a position adopted on the return:
(1) for which there is, or was, substantial
authority; or
(2) as to which there is a reasonable basis and the
pertinent facts of that position are disclosed on the return.
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If any item of income, gain, loss or deduction included in the
distributive shares of trust unitholders might result in that
kind of an understatement of income for which no
substantial authority exists, the trust must
disclose the pertinent facts on its return. In addition, the
trust will make a reasonable effort to furnish sufficient
information for trust unitholders to make adequate disclosure on
their returns and to take other actions as may be appropriate to
permit trust unitholders to avoid liability for this penalty.
More stringent rules apply to tax shelters, which
the trust does not believe includes it, or any of the
trusts investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the
value of any property, or the tax basis of any property, claimed
on a tax return is 150% or more of the amount determined to be
the correct amount of the valuation or tax basis, (b) the
price for any property or services (or for the use of property)
claimed on any such return with respect to any transaction
between persons described in Internal Revenue Code
Section 482 is 200% or more (or 50% or less) of the amount
determined under Section 482 to be the correct amount of
such price, or (c) the net Internal Revenue Code
Section 482 transfer price adjustment for the taxable year
exceeds the lesser of $5 million or 10% of the
taxpayers gross receipts.
No penalty is imposed unless the portion of the underpayment
attributable to a substantial valuation misstatement exceeds
$5,000 ($10,000 for most corporations). The penalty is increased
to 40% in the event of a gross valuation misstatement. The trust
does not anticipate making any valuation misstatements.
Reportable
Transactions
If the trust were to engage in a reportable
transaction, the trust (and possibly the unitholders)
would be required to make a detailed disclosure of the
transaction to the IRS. A transaction may be a reportable
transaction based upon any of several factors, including the
fact that it is a type of tax avoidance transaction publicly
identified by the IRS as a listed transaction or
that it produces certain kinds of losses for partnerships,
individuals, S corporations, and trusts in excess of
$2 million in any single year, or $4 million in any
combination of 6 successive tax years. The trusts
participation in a reportable transaction could increase the
likelihood that the trusts federal income tax information
return (and possibly the unitholders tax return) would be
audited by the IRS. Please read
Trust information returns and audit
procedures.
Moreover, if the trust were to participate in a reportable
transaction with a significant purpose to avoid or evade tax, or
in any listed transaction, unitholders may be subject to the
following provisions of the American Jobs Creation Act of 2004:
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accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described above at Accuracy-related
penalties;
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for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability; and
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in the case of a listed transaction, an extended statute of
limitations.
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The trust does not expect to engage in any reportable
transactions.
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STATE TAX
CONSIDERATIONS
The following is intended as a brief summary of certain
information regarding state income taxes and other state tax
matters affecting individuals who are trust unitholders. Trust
unitholders are urged to consult their own legal and tax
advisors with respect to these matters.
Prospective investors should consider state and local tax
consequences of an investment in the common units. The trust
will own the royalty interests burdening specified gas
properties located in Greene County, Pennsylvania. The state of
Pennsylvania has income taxes applicable to individuals, but
currently does not require the trust to withhold taxes from
distributions made to nonresident unitholders. If withholding
were required under current Pennsylvanian law, the rate would be
3.07% of taxable income attributable to Pennsylvania. A trust
unitholder may be required to file state income tax returns
and/or pay
taxes in Pennsylvania and may be subject to penalties for
failure to comply with such requirements. Taxes withheld by the
trust would be treated as deductions against state income taxes
otherwise payable.
The trust units may constitute real property or an interest in
real property under the inheritance, estate and probate laws of
Pennsylvania.
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ERISA
CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended,
regulates pension, profit-sharing and other employee benefit
plans to which it applies. ERISA also contains standards for
persons who are fiduciaries of those plans. In addition, the
Internal Revenue Code provides similar requirements and
standards which are applicable to qualified plans, which include
these types of plans, and to individual retirement accounts,
whether or not subject to ERISA.
A fiduciary of a qualified plan should carefully consider
fiduciary standards under ERISA regarding the qualified
plans particular circumstances before authorizing an
investment in trust units. A fiduciary should consider:
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|
|
|
|
whether the investment satisfies the prudence requirements of
Section 404(a)(1)(B) of ERISA;
|
|
|
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whether the investment satisfies the diversification
requirements of Section 404(a)(1)(C) of ERISA; and
|
|
|
|
whether the investment is in accordance with the documents and
instruments governing the qualified plan as required by
Section 404(a)(1)(D) of ERISA.
|
A fiduciary should also consider whether an investment in common
units might result in direct or indirect nonexempt prohibited
transactions under Section 406 of ERISA and Internal
Revenue Code Section 4975. In deciding whether an
investment involves a prohibited transaction, a fiduciary must
determine whether there are plan assets in the transaction. The
Department of Labor has published final regulations concerning
whether or not a qualified plans assets would be deemed to
include an interest in the underlying assets of an entity for
purposes of the reporting, disclosure and fiduciary
responsibility provisions of ERISA and analogous provisions of
the Internal Revenue Code. These regulations provide that the
underlying assets of an entity will not be considered plan
assets if the equity interests in the entity are a
publicly offered security. ECA expects that at the time of the
sale of the trust units in this offering, they will be publicly
offered securities. Fiduciaries, however, will need to determine
whether the acquisition of trust units is a nonexempt prohibited
transaction under the general requirements of ERISA
Section 406 and Internal Revenue Code Section 4975.
The prohibited transaction rules are complex, and persons
involved in prohibited transactions are subject to penalties.
For that reason, potential qualified plan investors should
consult with their counsel to determine the consequences under
ERISA and the Internal Revenue Code of their acquisition and
ownership of trust units.
123
SELLING
TRUST UNITHOLDER
Prior to the closing of the offering made hereby, ECA will
convey the royalty interests to the trust in exchange for cash,
3,087,371 common units and 4,401,250 subordinated units.
Additionally, at the closing of this offering, ECA will purchase
from the Private Investors a total of 209,312 common units at
the initial offering price. If the underwriters exercise the
option to purchase an additional 1,320,375 common units at the
initial public offering price, then the trust will use the net
proceeds to repurchase 1,320,375 common units from ECA at the
initial public offering price after deducting underwriting
discounts and commissions. ECA and the Private Investors have
agreed, however, not to sell any trust units for period of 180
days after the date of this prospectus without the prior written
consent of Raymond James & Associates, Inc. and
Citigroup Global Markets Inc. acting as representatives of the
several underwriters, subject to specified exceptions and other
than the sale of common units to ECA by the Private Investors.
See Underwriting.
The following table provides information regarding the selling
trust unitholders ownership of the trust units. This table
assumes the underwriters over-allotment option is
exercised.
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Ownership of
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Ownership of Trust Units
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Trust Units
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|
After Offering (Assuming
|
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Before Exercise
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|
Full Exercise
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|
of Underwriters
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|
Number of
|
|
of Underwriters
|
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|
Over-Allotment Option
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|
Common Units
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|
Over-Allotment)
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Selling Trust Unitholder
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Number
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Percentage
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|
Being Offered
|
|
Number
|
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Percentage
|
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Energy Corporation of America
|
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7,697,933
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43.7%
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1,320,375
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6,377,558
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36.2%
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Prior to this offering there has been no public market for the
common units. Therefore, if ECA disposes of its remaining trust
units, it cannot predict the effect of such disposal on future
market prices, if any, of market sales of such remaining trust
units or the availability of trust units for sale. Nevertheless,
sales of substantial amounts of trust units in the public market
could adversely affect future market prices.
124
UNDERWRITING
Subject to the terms and conditions in an underwriting agreement
dated June , 2010, the underwriters named
below, for whom Raymond James & Associates, Inc. and
Citigroup Global Markets Inc. are acting as representatives,
have severally agreed to purchase from ECA the common of trust
units set forth opposite their names:
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Number of
|
|
Name of Underwriter
|
|
Common Units
|
|
|
Raymond James & Associates, Inc.
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|
Citigroup Global Markets Inc.
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|
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Oppenheimer & Co. Inc.
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|
|
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RBC Capital Markets Corporation
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|
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Robert W. Baird & Co. Incorporated
|
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|
|
|
|
|
|
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Total
|
|
|
8,802,500
|
|
|
|
|
|
|
The underwriting agreement provides that the obligations of the
underwriters to purchase and accept delivery of the common units
offered by this prospectus are subject to the satisfaction of
the conditions contained in the underwriting agreement,
including:
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|
|
the representations and warranties made by ECA to the
underwriters are true;
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|
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there is no material adverse change in the financial
market; and
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|
ECA delivers customary closing documents and legal opinions to
the underwriters.
|
The underwriters are obligated to purchase and accept delivery
of all of the trust units offered by this prospectus, if any of
the units are purchased, other than those covered by the option
to purchase additional common units described below.
The underwriters propose to offer the common units directly to
the public at the public offering price indicated on the cover
page of this prospectus and to various dealers at that price
less a concession not in excess of
$ per unit. If all of the common
units are not sold at the public offering price, the
underwriters may change the public offering price and other
selling terms. The common units are offered by the underwriters
as stated in this prospectus, subject to receipt and acceptance
by them. The underwriters reserve the right to reject an order
for the purchase of the common units in whole or in part.
OPTION TO
PURCHASE ADDITIONAL COMMON UNITS
The trust has granted the underwriters an option, exercisable
for 30 days after the date of this prospectus, to purchase
from time to time up to an aggregate of
1,320,375 additional common units to cover over-allotments,
if any, at the public offering price less the underwriting
discounts and commissions set forth on the cover page of this
prospectus. The net proceeds of any exercise of the
underwriters over-allotment option will be used to redeem
an equal number of common units held by ECA. If the underwriters
exercise this option, each underwriter, subject to certain
conditions, will become obligated to purchase its pro rata
portion of these additional units based on the
underwriters percentage purchase commitment in this
offering as indicated in the table above. The underwriters may
exercise the option to purchase additional common units only to
cover over-allotments made in connection with the sale of the
common units offered in this offering.
125
DISCOUNTS
AND EXPENSES
The following table shows the amount per unit and total
underwriting discounts ECA will pay to the underwriters (dollars
in thousands, except per unit). The amounts are shown assuming
both no exercise and full exercise of the underwriters
option to purchase additional common units.
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|
|
Total without
|
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Total with
|
|
|
|
|
|
|
Over-Allotment
|
|
|
Over-Allotment
|
|
|
|
Per Unit
|
|
|
Exercise
|
|
|
Exercise
|
|
|
Price to the public
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Underwriting discount and commissions
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Proceeds, to the trust (before expenses)
|
|
$
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|
|
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|
In addition, the trust will pay a structuring fee equal to 0.50%
of the gross proceeds from this offering, or approximately
$ million
($ million
in the event the underwriters exercise the over-allotment option
in full), to Raymond James & Associates, Inc. for
evaluation, analysis and structuring of the trust. The other
expenses of this offering that are payable by the trust are
estimated to be $2.8 million (exclusive of underwriting
discounts and commissions).
INDEMNIFICATION
ECA has agreed to indemnify the underwriters and persons who
control the underwriters against certain liabilities that may
arise in connection with this offering, including liabilities
under the Securities Act of 1933 and liabilities arising from
breaches of representations and warranties contained in the
underwriting agreement.
LOCK-UP
AGREEMENTS
Subject to specified exceptions, including the sale of 209,312
common units to ECA by the Private Investors at the closing of
this offering, ECA and the Private Investors have agreed with
the underwriters, for a period of 180 days after the date
of this prospectus, without the prior written consent of Raymond
James & Associates, Inc. and Citigroup Global Markets
Inc.:
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not to offer, sell, contract to sell, announce the intention to
sell or pledge any of the trust units;
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|
not to grant or sell any option or contract to purchase any of
the trust units;
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|
not to enter into any swap or other agreement that transfers any
of the economic consequences of ownership of or otherwise
transfer or dispose of, directly or indirectly, any of the trust
units; and
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|
not to enter into any hedging, collar or other transaction or
arrangement that is designed or reasonably expected to lead to
or result in a transfer, in whole or in part, of any of the
economic consequences of ownership of the trust units, whether
or not such transfer would be for any consideration.
|
These agreements also prohibit ECA and the Private Investors
from entering into any of the foregoing transactions with
respect to any securities that are convertible into or
exchangeable for the trust units.
126
Raymond James & Associates, Inc. and Citigroup Global
Markets Inc. may, in their discretion and at any time without
notice, release all or any portion of the securities subject to
these agreements. Raymond James & Associates, Inc. and
Citigroup Global Markets Inc. do not have any present intent or
any understanding to release all or any portion of the
securities subject to these agreements.
The 180-day
period described in the preceding paragraphs will be
extended if:
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|
|
during the last 17 days of the
180-day
period, the trust issues an earnings release or announces
material news or a material event relating to the trust
occurs; or
|
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|
|
prior to the expiration of the
180-day
period, the trust announces that it will release earnings
results during the
16-day
period beginning on the last day of the
180-day
period, in which case the restrictions described in the
preceding paragraphs will continue to apply until the expiration
of the
18-day
period beginning on the issuance of the earnings release, the
announcement of the material news or the occurrence of the
material event.
|
STABILIZATION
Until this offering is completed, rules of the SEC may limit the
ability of the underwriters and various selling group members to
bid for and purchase the common units. As an exception to these
rules, the underwriters may engage in activities that stabilize,
maintain or otherwise affect the price of the common units,
including:
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|
|
short sales,
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|
|
syndicate covering transactions,
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|
imposition of penalty bids, and
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|
|
purchases to cover positions created by short sales.
|
Stabilizing transactions consist of bids or purchases made for
the purpose of preventing or retarding a decline in the market
price of the common units while this offering is in progress.
Stabilizing transactions may include making short sales of
common units, which involve the sale by the underwriters of a
greater number of common units than it is required to purchase
in this offering and purchasing common units from ECA or in the
open market to cover positions created by short sales. Short
sales may be covered shorts, which are short
positions in an amount not greater than the underwriters
option to purchase additional common units referred to above, or
may be naked shorts, which are short positions in
excess of that amount.
Each underwriter may close out any covered short position either
by exercising its option to purchase additional common units, in
whole or in part, or by purchasing common units in the open
market. In making this determination, each underwriter will
consider, among other things, the price of common units
available for purchase in the open market compared to the price
at which the underwriter may purchase common units pursuant to
the option to purchase additional common units.
A naked short position is more likely to be created if the
underwriters are concerned that there may be downward pressure
on the price of the common units in the open market that could
adversely affect investors who purchased in this offering. To
the extent that the underwriters create a naked short position,
they will purchase common units in the open market to cover the
position.
127
The underwriters also may impose a penalty bid on selling group
members. This means that if the underwriters purchase common
units in the open market in stabilizing transactions or to cover
short sales, the underwriters can require the selling group
members that sold those common units as part of this offering to
repay the selling concession received by them.
As a result of these activities, the price of the common units
may be higher than the price that otherwise might exist in the
open market. If the underwriters commence these activities, they
may discontinue them without notice at any time. The
underwriters may carry out these transactions on the New York
Stock Exchange or otherwise.
CONFLICTS/AFFILIATES
Certain of the underwriters and their affiliates may provide in
the future investment banking, financial advisory or other
financial services for ECA and its affiliates, for which they
may receive advisory or transaction fees, as applicable, plus
out-of-pocket expenses, of the nature and in amounts customary
in the industry for these financial services.
DIRECTED
UNIT PROGRAM
At ECAs request, the underwriters have reserved up to 6%
of the common units being offered by this prospectus for sale to
ECAs directors, officers and employees and certain other
persons associated with ECA at the initial public offering
price. The sales will be made by Raymond James through a
directed unit program. We do not know if these persons will
choose to purchase all or any portion of these reserved units,
but any purchases they do make will reduce the number of common
units available to the general public. To the extent the
allotted reserved units are not purchased in the directed unit
program, we will offer these common units to the general public
on the same basis as all other common units offered by this
prospectus. These persons must commit to purchase no later than
before the open of business on the day following the date of
this prospectus, but in any event, these persons are not
obligated to purchase common units. Any directors, officers and
employees or other persons associated with ECA purchasing
reserved units, other than the Private Investors, if any, will
not be subject to a
lock-up
agreement. ECA has agreed to indemnify Raymond James against
certain liabilities and expenses, including liabilities under
the Securities Act of 1933, in connection with the sales of the
reserved units.
DISCRETIONARY
ACCOUNTS
The underwriters may confirm sales of the common units offered
by this prospectus to accounts over which they exercise
discretionary authority but do not expect those sales to exceed
5% of the total common units offered by this prospectus.
LISTING
The common units have been approved for listing on the New York
Stock Exchange under the symbol ECT, subject to
official notice of issuance. In connection with the listing of
the common units on the New York Stock Exchange, the
underwriters will undertake to sell round lots of 100 units
or more to a minimum of 400 beneficial owners.
DETERMINATION
OF INITIAL OFFERING PRICE
Prior to this offering, there has been no public market for the
common units. Consequently, the initial public offering price
for the common units will be determined by negotiations among
128
ECA and the underwriters. The primary factors to be considered
in determining the initial public offering price will be:
|
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|
|
|
estimates of distributions to trust unitholders,
|
|
|
|
overall quality of the natural gas properties attributable to
the Underlying Properties,
|
|
|
|
industry and market conditions prevalent in the energy industry,
|
|
|
|
the information set forth in this prospectus and otherwise
available to the representatives, and
|
|
|
|
the general conditions of the securities markets at the time of
this offering.
|
The initial offering price may not correspond to the price at
which the common units will trade in the public market
subsequent to this offering, and an active trading market may
develop and continue after this offering.
ELECTRONIC
PROSPECTUS
A prospectus in electronic format may be available on the
Internet sites or through other online services maintained by
one or more of the underwriters and selling group members
participating in this offering, or by their affiliates. In those
cases, prospective investors may view offering terms online and,
depending upon the underwriter or the selling group member,
prospective investors may be allowed to place orders online. The
underwriters may agree with ECA to allocate a specific number of
common units for sale to online brokerage account holders. Any
such allocation for online distributions will be made by the
underwriters on the same basis as other allocations.
Other than the prospectus in electronic format, the information
on any underwriters or any selling group members
website and any information contained in any other website
maintained by the underwriters or any selling group member is
not part of this prospectus or the registration statement of
which this prospectus forms a part, has not been approved or
endorsed by ECA or any underwriters or any selling group member
in its capacity as underwriter or selling group member and
should not be relied upon by investors.
FINRA
RULES
Because the Financial Industry Regulatory Authority, or the
FINRA is expected to view the common units offered
hereby as interests in a direct participation program, this
offering is being made in compliance with Rule 2310 of the
FINRA Rules. Investor suitability with respect to the common
units should be judged similarly to the suitability with respect
to other securities that are listed for trading on a national
securities exchange.
129
CERTAIN
TRANSACTIONS
Certain officers, directors and employees of ECA and members of
their families (the Private Investors) regularly
participate in ECAs annual drilling programs. Under such
drilling programs, ECA has the right to select the wells to be
drilled, and the Private Investors cannot selectively choose the
wells in which they participate. For so long as (i) a
Private Investor remains a director or employee of ECA (or, in
the case of a family member, for so long as the family member
remains a director or employee of ECA) and (ii) such
Private Investor has participated in the prior years
drilling program, such Private Investor has the right to
participate in ECAs future drilling programs. The Private
Investors listed below participated in ECAs 2009 drilling
program (the Drilling Program), and based on the
success of this program, are entitled to participate in future
drilling programs.
The following table sets forth with respect to those Private
Investors that are beneficial holders of more than 5% of either
class of ECAs securities, directors of ECA or executive
officers of ECA, and their immediate family members; all other
Private Investors as a group; and all the Private Investors as a
group: (i) the purchase price paid by such Private Investor
for his or her interest in the Drilling Program and
(ii) such Private Investors percentage interest in
the Drilling Program.
|
|
|
|
|
|
|
|
|
|
|
Purchase Price for
|
|
|
Percentage
|
|
|
|
Participation
|
|
|
Interest in the
|
|
|
|
in Drilling
|
|
|
Drilling
|
|
Private Investors
|
|
Program
|
|
|
Program
|
|
|
W. Gaston Caperton, III
|
|
$
|
116,259
|
|
|
|
1.89%
|
|
Peter H. Coors
|
|
|
290,646
|
|
|
|
4.72%
|
|
L.B. Curtis
|
|
|
67,430
|
|
|
|
1.10%
|
|
John J. Dorgan
|
|
|
58,129
|
|
|
|
0.94%
|
|
John S. Fischer
|
|
|
290,646
|
|
|
|
4.72%
|
|
Michael S. Fletcher
|
|
|
29,065
|
|
|
|
0.47%
|
|
J. Michael Forbes
|
|
|
40,458
|
|
|
|
0.66%
|
|
Thomas R. Goodwin
|
|
|
174,388
|
|
|
|
2.83%
|
|
F.H. McCullough III (1)
|
|
|
453,408
|
|
|
|
7.36%
|
|
John Mork (2)
|
|
|
3,573,790
|
|
|
|
58.05%
|
|
Julie M. Mork (2)
|
|
|
3,573,790
|
|
|
|
58.05%
|
|
Kyle M. Mork (3)
|
|
|
337,150
|
|
|
|
5.48%
|
|
Arthur C. Nielsen, Jr.
|
|
|
29,065
|
|
|
|
0.47%
|
|
George OMalley
|
|
|
29,669
|
|
|
|
0.48%
|
|
Jay S. Pifer
|
|
|
29,065
|
|
|
|
0.47%
|
|
Donald C. Supcoe
|
|
|
58,129
|
|
|
|
0.94%
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,577,297
|
|
|
|
90.59%
|
|
Other Private Investors
|
|
|
549,043
|
|
|
|
8.92%
|
|
|
|
|
|
|
|
|
|
|
Private Investor Total
|
|
$
|
6,126,340
|
|
|
|
99.51%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Includes investments by the
Katherine F. McCullough Trust, the Lesley McCullough Trust, the
Kristin McCullough Trust and the Meredith McCullough Trust.
|
|
(2)
|
|
Includes investments by John and
Julie Mork as joint tenants, and investments by the Alison Mork
Trust.
|
|
(3)
|
|
Includes investments by the Kyle
Mork Trust.
|
130
Immediately prior to the closing of this offering, the Private
Investors will convey to ECA the working interest each such
Private Investor holds in the Producing Wells, retaining a
perpetual royalty interest identical in nature to the Perpetual
PDP Royalty to be contributed by ECA to the trust (individually,
a Private Investor Royalty and collectively, the
Private Investors Royalties). At the closing of this
offering, the Private Investors will convey the Private
Investors Royalties to the trust and agree to forgo his or her
ability to participate in future drilling programs with respect
to the portion of PUD Wells being conveyed to the trust in
exchange for the common units described below. Certain Private
Investors have elected for ECA to purchase at the closing of the
offering a portion of their common units to be received as
described above at the initial public offering price. Pursuant
to such election, ECA will purchase a total of 209,312 common
units from the Private Investors at the closing of this
offering. Upon completion of the transactions described above,
ECA will hold 3,296,683 common units (1,976,308 if the
underwriters exercise their over-allotment option in full) and
4,401,250 subordinated units, representing 43.7% of the trust
units (36.2% if the underwriters exercise their over-allotment
option in full), and the Private Investors will hold 1,104,567
common units, representing 6.3% of the trust units.
The table below sets forth with respect to those Private
Investors that are beneficial holders of more than 5% of either
class of ECAs securities, directors of ECA or executive
officers of ECA, and their immediate family members; all other
Private Investors and all Private Investors as a group:
(i) the value of the Private Investors interest in
the Drilling Program, including relinquishment of the right to
participate in the portion of the PUD Wells being conveyed to
the trust; (ii) the Private Investors percentage
interest in the Drilling Program; (iii) the number of
common units to be owned by the Private Investor after the
purchase by ECA of a portion of the common units as described
above; and (iv) the cash proceeds to be received by such
Private Investor upon the purchase by ECA of such common units.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Cash Proceeds
|
|
|
|
Value of
|
|
|
Percentage
|
|
|
Common Units
|
|
|
Upon Sale to
|
|
|
|
Interest in the
|
|
|
Interest in the
|
|
|
After Purchase
|
|
|
ECA of
|
|
Private Investors
|
|
Drilling Program
|
|
|
Drilling Program (1)
|
|
|
by ECA
|
|
|
Common Units (2)
|
|
|
W. Gaston Caperton, III
|
|
$
|
496,209
|
|
|
|
1.89%
|
|
|
|
24,933
|
|
|
$
|
|
|
Peter H. Coors
|
|
|
1,240,522
|
|
|
|
4.72%
|
|
|
|
62,333
|
|
|
|
|
|
L.B. Curtis
|
|
|
287,801
|
|
|
|
1.10%
|
|
|
|
13,000
|
|
|
|
29,220
|
|
John J. Dorgan
|
|
|
248,104
|
|
|
|
0.94%
|
|
|
|
12,467
|
|
|
|
|
|
John S. Fischer
|
|
|
1,240,522
|
|
|
|
4.72%
|
|
|
|
56,100
|
|
|
|
124,660
|
|
Michael S. Fletcher
|
|
|
124,052
|
|
|
|
0.47%
|
|
|
|
3,233
|
|
|
|
60,000
|
|
J. Michael Forbes
|
|
|
172,681
|
|
|
|
0.66%
|
|
|
|
8,677
|
|
|
|
|
|
Thomas R. Goodwin
|
|
|
744,314
|
|
|
|
2.83%
|
|
|
|
37,400
|
|
|
|
|
|
F.H. McCullough III (3)
|
|
|
1,935,215
|
|
|
|
7.36%
|
|
|
|
78,000
|
|
|
|
384,800
|
|
John Mork (4)
|
|
|
15,253,477
|
|
|
|
58.05%
|
|
|
|
616,451
|
|
|
|
3,000,000
|
|
Julie M. Mork (4)
|
|
|
15,253,477
|
|
|
|
58.05%
|
|
|
|
616,451
|
|
|
|
3,000,000
|
|
Kyle M. Mork (5)
|
|
|
1,439,007
|
|
|
|
5.48%
|
|
|
|
72,307
|
|
|
|
|
|
Arthur C. Nielsen, Jr.
|
|
|
124,052
|
|
|
|
0.47%
|
|
|
|
6,233
|
|
|
|
|
|
George OMalley
|
|
|
126,633
|
|
|
|
0.48%
|
|
|
|
2,000
|
|
|
|
87,260
|
|
Jay S. Pifer
|
|
|
124,052
|
|
|
|
0.47%
|
|
|
|
6,233
|
|
|
|
|
|
Donald C. Supcoe
|
|
|
248,104
|
|
|
|
0.94%
|
|
|
|
6,234
|
|
|
|
124,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
23,804,748
|
|
|
|
90.59%
|
|
|
|
1,005,601
|
|
|
$
|
3,810,600
|
|
Other Private Investors
|
|
|
2,343,397
|
|
|
|
8.92%
|
|
|
|
98,966
|
|
|
|
375,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Private Investor Total
|
|
$
|
26,148,145
|
|
|
|
99.51%
|
|
|
|
1,104,567
|
|
|
$
|
4,186,240
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
131
|
|
|
(1)
|
|
At the closing of this offering,
each Private Investor will retain an identical percentage
ownership in the Drilling Program. However, the size of the
Drilling Program will have been reduced following the
conveyances of the Private Investors Royalties due to the
Private Investors foregoing their ability to participate in
future drilling programs with respect to the royalty interest in
the PUD Wells being conveyed to the trust. Accordingly, the
total value of each Private Investors interest in the
Drilling Program will have been reduced, despite such Private
Investor retaining the same percentage interest in the Drilling
Program.
|
|
(2)
|
|
Based on an assumed public offering
price of $20 per common unit.
|
|
(3)
|
|
Includes investments by the
Katherine F. McCullough Trust, the Lesley McCullough Trust, the
Kristin McCullough Trust and the Meredith McCullough Trust.
|
|
(4)
|
|
Includes investments by John and
Julie Mork as joint tenants, and investments by the Alison Mork
Trust.
|
|
(5)
|
|
Includes investments by the Kyle
Mork Trust.
|
132
LEGAL
MATTERS
Richards, Layton & Finger, P.A., as special Delaware
counsel to the Trust, will give a legal opinion as to the
validity of the trust units. Vinson & Elkins L.L.P.,
Houston, Texas, counsel to ECA, will give opinions as to certain
other matters relating to the offering, including the tax
opinion described in the section of this prospectus captioned
Federal income tax considerations. Certain legal
matters in connection with the common units offered hereby will
be passed upon for the underwriters by Baker Botts L.L.P.,
Houston, Texas.
EXPERTS
Certain information appearing in this prospectus regarding the
March 31, 2010 estimated quantities of reserves of the
Underlying Properties and royalty interests owned by the trust,
the future net revenues from those reserves and their present
value is based on estimates of the reserves and present values
prepared by or derived from estimates prepared by Ryder Scott
Company, L.P., independent petroleum engineers.
The consolidated financial statements of Energy Corporation of
America as of June 30, 2009 and 2008 and for each of three
years in the period ended June 30, 2009 and the statement
of historical revenues and direct operating expenses of the
Underlying PDP Properties, for the year ended December 31,
2009 appearing in this prospectus have been audited by
Ernst & Young LLP, independent registered public
accounting firm, as set forth in their reports thereon appearing
elsewhere herein, and are included in reliance upon such reports
given on the authority of such firm as experts in accounting and
auditing.
The statement of assets and trust corpus of ECA Marcellus Trust
I as of March 19, 2010, included in this Registration
Statement has been audited by Ernst & Young LLP, an
independent registered public accounting firm, as stated in
their report appearing elsewhere herein, and is included in
reliance upon such report given on the authority of such firm as
experts in accounting and auditing.
WHERE YOU
CAN FIND MORE INFORMATION
The trust and ECA have filed with the SEC a registration
statement on
Form S-1
regarding the common units. This prospectus does not contain all
of the information found in the registration statement. For
further information regarding the trust, ECA and the common
units offered by this prospectus, you may desire to review the
full registration statement, including its exhibits and
schedules, filed under the Securities Act. The registration
statement of which this prospectus forms a part, including its
exhibits and schedules, may be inspected and copied at the
public reference room maintained by the SEC at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. Copies of the materials may also be
obtained from the SEC at prescribed rates by writing to the
public reference room maintained by the SEC at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. You may obtain information on the
operation of the public reference room by calling the SEC at
1-800-SEC-0330.
The SEC maintains a web site on the Internet at
http://www.sec.gov.
The trusts and ECAs registration statement, of which
this prospectus constitutes a part, can be downloaded from the
SECs web site.
We intend to furnish the trusts unitholders annual reports
containing our audited consolidated financial statements and to
furnish or make available to the trusts unitholders
quarterly reports containing the trusts unaudited interim
financial information for the first three fiscal quarters of
each of our fiscal years.
133
GLOSSARY
OF CERTAIN OIL AND NATURAL GAS TERMS AND
TERMS RELATED TO THE TRUST
In this prospectus the following terms have the meanings
specified below.
AMI The area of mutual interest, or AMI, will
consist of the Marcellus Shale formation in approximately
121 square miles and is depicted by the area identified on
the inside front cover of this prospectus. ECA is obligated to
drill the 52 development wells from drill sites on approximately
9,300 leased acres which ECA presently holds in the AMI. Until
ECA has satisfied its drilling obligation, it will not be
permitted to drill and complete any well in the Marcellus Shale
formation on lease acreage included within the AMI for its own
account. Also, ECA will grant to the trust a lien on ECAs
interest in the Marcellus Shale formation in the AMI (except
currently producing wells) in order to secure its drilling
obligation to the Trust.
Bbl One stock tank barrel, of 42
U.S. gallons liquid volume, used herein in reference to
crude oil, condensate or natural gas liquids.
Bcf One billion cubic feet of natural gas.
Bcfe One billion cubic feet of natural gas
equivalent, with one barrel of crude oil being equivalent to six
Mcf.
Btu A British Thermal Unit, a common unit of
energy measurement.
ECAs retained interest ECAs
retained interest in 10% of the proceeds from the sale of
production from the 14 producing Marcellus Shale natural gas
wells located in Greene County, Pennsylvania as well as
ECAs retained interest in 50% of the proceeds from the
sale of production from the PUD Wells to be drilled in the AMI.
Estimated future net revenues Also referred
to as estimated future net cash flows. The result of
applying current prices of natural gas to estimated future
production from natural gas proved reserves, reduced by
estimated future expenditures, based on current costs to be
incurred, in developing and producing the proved reserves,
excluding overhead.
Farmout agreement A farmout agreement is
typically an agreement under which a lessee under an oil and gas
lease agrees to grant to another party the right to drill wells
on the tract covered by such lease and to earn certain acreage
for drilling such wells.
Fractional well The fraction (either greater
than one or less than one) of a well obtained by dividing the
horizontal lateral (measured from the midpoint of the curve) of
such well by 2,500 feet (subject to a maximum of
3,500 feet).
MBbl One thousand barrels of crude oil,
condensate or natural gas liquids.
Mcf One thousand cubic feet of natural gas.
Mcfe One thousand cubic feet of natural gas
equivalent, with one barrel of crude oil being equivalent to six
Mcf.
MMBtu One million British Thermal Units.
MMcf One million cubic feet of natural gas.
134
MMcfe One million cubic feet of natural gas
equivalent, with one barrel of crude oil being equivalent to six
Mcf.
Net Profits Interest A nonoperating interest
that creates a share in gross production from an operating or
working interest in oil and natural gas properties. The share is
measured by net profits from the sale of production after
deducting costs associated with that production.
PDP Royalty Interest Royalty interests
entitling the trust to receive an aggregate of 90% of the
proceeds (exclusive of any production or development costs but
after deducting post-production costs and any applicable taxes)
from the sale of production of natural gas attributable to
ECAs working interest in the eight horizontal wells
producing from the Marcellus Shale formation together with six
additional wells that are undergoing completion operations and
are expected to be online by August 15, 2010 all of which
are located in Greene County, Pennsylvania for 20 years,
and 45% of such proceeds thereafter (pending a sale thereof by
the trust).
Proved developed reserves Reserves that can
be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved reserves Under SEC rules for fiscal
years ending on or after December 31, 2009, proved reserves
are defined as:
Those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible
from a given date forward, from known reservoirs, and under
existing economic conditions, operating methods, and government
regulations prior to the time at which contracts
providing the right to operate expire, unless evidence indicates
that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the
estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it
will commence the project within a reasonable time. The area of
the reservoir considered as proved includes (i) the area
identified by drilling and limited by fluid contacts, if any,
and (ii) adjacent undrilled portions of the reservoir that
can, with reasonable certainty, be judged to be continuous with
it and to contain economically producible oil or gas on the
basis of available geoscience and engineering data. In the
absence of data on fluid contacts, proved quantities in a
reservoir are limited by the lowest known hydrocarbons, LKH, as
seen in a well penetration unless geoscience, engineering, or
performance data and reliable technology establishes a lower
contact with reasonable certainty. Where direct observation from
well penetrations has defined a highest known oil, HKO,
elevation and the potential exists for an associated gas cap,
proved oil reserves may be assigned in the structurally higher
portions of the reservoir only if geoscience, engineering, or
performance data and reliable technology establish the higher
contact with reasonable certainty. Reserves which can be
produced economically through application of improved recovery
techniques (including, but not limited to, fluid injection) are
included in the proved classification when (i) successful
testing by a pilot project in an area of the reservoir with
properties no more favorable than in the reservoir as a whole,
the operation of an installed program in the reservoir or an
analogous reservoir, or other evidence using reliable technology
establishes the reasonable certainty of the engineering analysis
on which the project or program was based; and (ii) the
project has been approved for development by all necessary
parties and entities, including governmental entities. Existing
economic conditions include prices and costs at which economic
producibility from a reservoir is to be determined. The price
shall be the average price during the
12-month
period prior to the ending date of the period covered by the
report, determined as an unweighted arithmetic average of the
first-day-of-the-month
price for each month within such period, unless prices are
defined by contractual arrangements, excluding escalations based
upon future conditions.
135
Under SEC rules for fiscal years ending prior to
December 31, 2009, proved reserves are defined as:
The estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate
is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on
escalations based upon future conditions. Reservoirs are
considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area
of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil
and/or
oil-water contacts, if any, and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the proved classification when successful testing by
a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on
which the project or program was based. Estimates of proved
reserves do not include the following: (A) Oil that may
become available from known reservoirs but is classified
separately as indicated additional reserves; (B) crude oil,
natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and (D) crude oil,
natural gas, and natural gas liquids, that may be recovered from
oil shales, coal, gilsonite and other such sources.
Proved undeveloped reserves Proved reserves
that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major
expenditure is required for recompletion.
PUD Royalty Interest Royalty interests
entitling the trust to receive an aggregate of 50% of the
proceeds (net of post-production costs and any applicable taxes)
from the sale of production of natural gas attributable to
ECAs interest in 52 horizontal Marcellus Shale natural gas
wells to be drilled in the AMI and 25% of such proceeds
thereafter (pending a sale thereof by the trust).
Tcf One trillion standard cubic feet of
natural gas.
Working interest The right granted to the
lessee of a property to explore for and to produce and own oil,
gas, or other minerals. The working interest owners bear the
exploration, development, and operating costs on either a cash,
penalty, or carried basis.
136
Report of
Independent Registered Public Accounting Firm
To the Board
of Directors and Stockholders
Energy Corporation of America:
We have audited the accompanying statement of historical
revenues and direct operating expenses of the Underlying
Properties (the Properties) of Energy Corporation of
America (the Company) for the year ended
December 31, 2009. This financial statement is the
responsibility of the Companys management. Our
responsibility is to express an opinion on this financial
statement based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statement of historical
revenues and direct operating expenses of the Properties is free
of material misstatement. We were not engaged to perform an
audit of the Companys internal control over financial
reporting. Our audit included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the statement of historical revenues and direct
operating expenses, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall statement of historical revenues and direct
operating expenses presentation. We believe that our audit
provides a reasonable basis for our opinion.
The accompanying statement was prepared for the purpose of
complying with the rules and regulations of the Securities and
Exchange Commission as described in the notes to the financial
statement and is not intended to be a complete presentation of
the Companys interests in the Properties.
In our opinion, the statement referred to above presents fairly,
in all material respects, the historical revenues and direct
operating expenses of the Properties for the year ended
December 31, 2009, in conformity with U.S. generally
accepted accounting principles.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
March 12, 2010
F-2
|
|
|
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
Gas Sales
|
|
$
|
3,623
|
|
|
|
|
|
|
Total Revenues
|
|
|
3,623
|
|
Operating Expenses:
|
|
|
|
|
Taxes on Production and Property
|
|
|
|
|
Lease Operation Expenses
|
|
|
22
|
|
Field Operation Expenses
|
|
|
2
|
|
Marketing Fee
|
|
|
132
|
|
Gathering and Transportation
|
|
|
458
|
|
|
|
|
|
|
Total Operating Expenses
|
|
|
614
|
|
|
|
|
|
|
Excess of revenues over operating expenses
|
|
$
|
3,009
|
|
|
|
|
|
|
See accompanying notes to the
Statement of Historical Revenues and Direct Operating Expenses.
F-3
UNDERLYING
PROPERTIES
Direct
Operating Expenses
FOR THE
YEAR ENDED DECEMBER 31, 2009
The Underlying Properties (Properties) consist of
the working interests owned by Energy Corporation of America and
the Private Investors in the Marcellus Shale formation in Greene
County, Pennsylvania arising under leases and farmout agreements
from which the PDP Royalty Interest and the PUD Royalty Interest
will be conveyed. As of December 31, 2009 the Properties
consisted of four producing wells, the first of which began
production on July 17, 2009, three proved behind pipe
wells, and 59 horizontal natural gas development wells to
be drilled to the Marcellus Shale formation within the Area of
Mutual Interest, which consists of the Marcellus Shale formation
in approximately 121 square miles. Approximately 9,300 acres in
the Area of Mutual Interest are held by ECA, of which it owns
substantially all of the working interests, in Greene County,
Pennsylvania.
Eastern Marketing Corporation, a wholly owned subsidiary of ECA,
has purchased the natural gas production from these wells at
prices substantially equivalent to prices paid by unaffiliated
purchasers in the marketing area.
The accompanying statement of historical revenues and direct
operating expenses was derived from the historical accounting
records of ECA and reflects the historical revenues and
operating expenses directly attributable to the Underlying
Properties for the period described herein. Such amounts may not
be representative of future operations. The statement does not
include depreciation, depletion and amortization, general and
administrative expenses, interest expense, federal and state
income taxes or other expenses of an indirect nature. The
amounts represent 100% of ECAs and the Private
Investors interest.
Historical financial statements reflecting financial position,
results of operations and cash flows required by generally
accepted accounting principles are not presented as such
information is not readily available on an individual property
basis and not meaningful to the Underlying Properties.
Accordingly, the statement of historical revenue and direct
operating expenses is presented in accordance with Staff
Accounting Bulletin Topic
2-D,
Financial Statements of Oil and Gas Exchange Offers.
The accompanying statement of historical revenues and direct
operating expenses included herein was prepared on an accrual
basis. Revenue from gas sales is recognized when the gas is
produced and sold.
The process of preparing the financial statements in conformity
with generally accepted accounting principles requires the use
of estimates and assumptions regarding certain types of revenues
and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial
statements. Accordingly, upon settlement, actual results may
differ from estimated amounts.
F-4
UNDERLYING
PROPERTIES
Notes to the Statement of Historical Revenues and
Direct Operating Expenses (Continued)
|
|
3.
|
SUPPLEMENTAL
INFORMATION ON GAS PRODUCING ACTIVITIES (UNAUDITED)
|
Information with respect to gas producing activities of the
Underlying Properties is presented in the following tables. The
information was derived from reserve reports which were prepared
by independent reserve engineers as of December 31, 2009,
in accordance with ASU
2010-03
Extractive Activities Oil and Gas (Topic 932):
Oil and Gas Reserve Estimation and Disclosures.
Gas
Reserves
Estimates of proved reserves are inherently imprecise and are
continually subject to revision based on production history,
results of additional exploration and development, price changes
and other factors.
The following table summarizes the estimated quantities of the
proved natural gas reserves (MMcfs) of the Underlying Properties:
|
|
|
|
|
|
|
Natural Gas
|
|
|
(Mmcf)
|
|
Proved reserves:
|
|
|
|
|
June 30, 2009
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
|
|
Extensions and discoveries
|
|
|
195,214
|
(1)
|
Sales of reserves in place
|
|
|
|
|
Purchases of reserves in place
|
|
|
|
|
Production
|
|
|
(841
|
)
|
|
|
|
|
|
December 31, 2009
|
|
|
194,373
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
December 31, 2009
|
|
|
9,664
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Extensions and discoveries during
the period ending December 31, 2009 are a result of the
discovery and extensive production from a new Marcellus Shale
field. This field had previously been tested with vertical
Marcellus Shale wells, and during 2009 ECA drilled four
producing Marcellus Shale horizontal wells and participated in
the drilling of one well with another operator, all of which
demonstrated consistent levels of production and provided
reasonable certainty that wells to be drilled within the field
qualified for Proved Undeveloped classification.
|
Proved reserves are estimated quantities of natural gas which
geological and engineering data indicated with reasonable
certainty to be recoverable in future years from known reserves
under existing economic and operating conditions. Proved
developed reserves are proven reserves, which are expected to be
recovered through existing wells with existing equipment and
operation methods.
Estimated
Present Value of Future Net Cash Flows
Standardized Measure of Discounted Future Net Cash
Flows Estimated discounted future net cash
flows and changes therein were determined in accordance with ASC
932, Disclosures
F-5
UNDERLYING
PROPERTIES
Notes to the Statement of Historical Revenues and
Direct Operating Expenses (Continued)
About Oil and Gas Producing Activities. Certain
information concerning the assumptions used in computing the
valuation of proved developed reserves and their inherent
limitations are discussed below. ECA believes such information
is essential for a proper understanding and assessment of the
data presented.
Future cash inflows are computed by applying the average prices
of gas during the
12-month
period ending December 31, 2009, determined using the
unweighted arithmetic average of the prices in effect on the
first-day-of-the-month
for each month within the period relating to the Underlying
Properties proved reserves to the period-end quantities of those
reserves. Future price changes are considered only to the extent
provided by contractual arrangements in existence at period-end.
The assumptions used to compute estimated future net revenues do
not necessarily reflect ECAs expectations of actual
revenues or costs or their present worth. In addition,
variations from the expected production rates also could result
directly or indirectly from factors outside of ECAs
control, such as unintentional delays in development, changes in
prices or regulatory controls. The reserve valuation further
assumes that all reserves will be disposed of by production.
However, if reserves are sold in place, this could affect the
amount of cash eventually realized.
Future development and production costs are computed by
estimating the expenditures to be incurred in developing and
producing the proved oil and gas reserves at December 31,
2009, based on period-end costs and assuming continuation of
existing economic conditions.
Future income tax expenses are computed by applying the
appropriate period-end statutory tax rates and existing tax
credits, with consideration of future tax rates already
legislated, to the future pretax net cash flows relating to the
Underlying Properties proved gas reserves.
An annual discount rate of 10% was used to reflect the timing of
the future net cash flows relating to proved developed gas
reserves in accordance with the rules and regulations of the SEC.
Information with respect to the Underlying Properties estimated
discounted future net cash flows related to its proved gas
reserves as of December 31, 2009 is as follows (in
thousands):
|
|
|
|
|
|
|
2009
|
|
|
Future cash in flows
|
|
$
|
774,788
|
|
Future production and development costs
|
|
|
(332,616
|
)
|
Future income tax expense
|
|
|
(172,000
|
)
|
|
|
|
|
|
Future net cash flows before discount
|
|
|
270,172
|
|
10% discount to present value
|
|
|
(192,146
|
)
|
|
|
|
|
|
Standardized measure of discounted future net cash flows related
to proved oil and gas reserves
|
|
$
|
78,026
|
|
|
|
|
|
|
F-6
UNDERLYING
PROPERTIES
Notes to the Statement of Historical Revenues and
Direct Operating Expenses (Continued)
The changes in the standardized measure of discounted future net
cash flows relating to proved gas reserves as of
December 31, 2009 is as follows (in thousands):
|
|
|
|
|
|
|
2009
|
|
|
Standardized measure of discounted future net cash flow at
beginning of period
|
|
$
|
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(3,009
|
)
|
Net changes in prices and production costs
|
|
|
|
|
Changes in production rates and other
|
|
|
|
|
Extensions, discoveries and other additions, net of future
production and development costs
|
|
|
75,460
|
|
Changes in estimated future development costs
|
|
|
|
|
Development costs incurred
|
|
|
5,575
|
|
Revisions of previous quantity estimates
|
|
|
|
|
Purchase of reserves in place
|
|
|
|
|
Accretion of discount
|
|
|
|
|
Net change in income taxes
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows at end
of period
|
|
$
|
78,026
|
|
|
|
|
|
|
F-7
|
|
|
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
Gas Sales
|
|
$
|
4,100
|
|
|
|
|
|
|
Total Revenues
|
|
|
4,100
|
|
Operating Expenses:
|
|
|
|
|
Taxes on Production and Property
|
|
|
|
|
Lease Operation Expenses
|
|
|
13
|
|
Field Operation Expenses
|
|
|
3
|
|
Marketing Fee
|
|
|
111
|
|
Gathering and Transportation
|
|
|
385
|
|
|
|
|
|
|
Total Operating Expenses
|
|
|
512
|
|
|
|
|
|
|
Excess of revenues over operating expenses
|
|
$
|
3,588
|
|
|
|
|
|
|
See accompanying notes to the
Statement of Revenues and Direct Operating Expenses.
F-8
UNDERLYING
PROPERTIES
Direct
Operating Expenses
FOR THE
THREE MONTHS ENDED MARCH 31, 2010
The Underlying Properties (Properties) consist of
working interests owned by Energy Corporation of America and the
Private Investors in the Marcellus Shale Formation in Greene
County, Pennsylvania arising under leases and farmout agreements
from which the PDP Royalty Interest and the PUD Royalty Interest
will be conveyed. As of March 31, 2010, the Properties
consisted of eight producing wells, six wells in the process of
being drilled, and 52 horizontal natural gas development wells
to be drilled to the Marcellus Shale formation within the Area
of Mutual Interest, which is comprised of approximately 9,300
acres held by ECA, of which it owns substantially all of the
working interests, in Greene County, Pennsylvania.
Eastern Marketing Corporation, a wholly owned subsidiary of ECA,
has purchased the natural gas production from these wells at
prices substantially equivalent to prices paid by unaffiliated
purchasers in the marketing area.
The accompanying statement of revenues and direct operating
expenses was derived from the accounting records of ECA and
reflects the revenues and operating expenses directly
attributable to the Underlying Properties for the period
described herein. Such amounts may not be representative of
future operations. The statement does not include depreciation,
depletion and amortization, general and administrative expenses,
interest expense, federal and state income taxes or other
expenses of an indirect nature. The amounts represent 100% of
ECAs interest and the Private Investors interest.
Financial statements reflecting financial position, results of
operations and cash flows required by generally accepted
accounting principles are not presented as such information is
not readily available on an individual property basis and not
meaningful to the Underlying Properties. Accordingly, the
statement of revenue and direct operating expenses is presented
in accordance with Staff Accounting Bulletin Topic
2-D,
Financial Statements of Oil and Gas Exchange Offers.
The accompanying statement of revenues and direct operating
expenses included herein was prepared on an accrual basis.
Revenue from gas sales is recognized when the gas is produced
and sold.
The process of preparing the financial statements in conformity
with generally accepted accounting principles requires the use
of estimates and assumptions regarding certain types of revenues
and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial
statements. Accordingly, upon settlement, actual results may
differ from estimated amounts.
F-9
ECA
MARCELLUS TRUST I
|
|
|
|
|
|
|
As of
|
|
|
|
March 19, 2010
|
|
|
Assets:
|
|
|
|
|
Cash
|
|
$
|
10
|
|
|
|
|
|
|
Total
|
|
$
|
10
|
|
|
|
|
|
|
Trust Corpus:
|
|
|
|
|
Trust corpus
|
|
$
|
10
|
|
|
|
|
|
|
Total
|
|
$
|
10
|
|
|
|
|
|
|
See notes to the statement of
assets and trust corpus.
F-11
ECA
MARCELLUS TRUST I
|
|
1.
|
ORGANIZATION
OF THE TRUST
|
The ECA Marcellus Trust I (the Trust) is a
statutory trust formed in March 2010 under the Delaware
Statutory Trust Act pursuant to a Trust Agreement (the
Trust Agreement) among Energy Corporation of
America (ECA), as trustor, The Bank of New York
Mellon Trust Company, N.A., as Trustee (the
Trustee), and Corporation Trust Company, as Delaware
Trustee (the Delaware Trustee).
The Trust was created to acquire and hold royalty interests for
the benefit of Trust unitholders pursuant to an agreement
between ECA, the Trustee and the Delaware Trustee. These royalty
interests are interests in underlying producing properties
consisting of ECAs interests in specified gas properties
located in the Marcellus Shale Formation in Greene County,
Pennsylvania. These properties consist of four producing wells,
the first of which began production on July 17, 2009, three
proved behind pipe wells, and 59 horizontal natural gas
development wells to be drilled to the Marcellus Shale formation
within the area of mutual interest, which is comprised of
approximately 9,300 acres held by ECA, of which it owns
substantially all of the working interests, in Greene County,
Pennsylvania.
The royalty interests are passive in nature and neither the
Trust nor the Trustee has any control over, or responsibility
for, costs relating to the operation of the Underlying
Properties. After the conveyance of royalty interests, ECA will
retain interest in each of the Underlying PDP Properties and
Underlying PUD Properties. The trust agreement will provide that
the Trusts business activities will be limited to owning
the royalty interests and any activity reasonably related to
such ownership including activities of a portion of certain
natural gas floor price contracts which relate to a portion of
the natural gas production attributable to the trusts
royalty interest. The Trust will not be permitted to acquire
other oil and gas properties or royalty interests.
The Trust will begin to liquidate on March 31, 2030 (the
Termination Date) and will soon thereafter wind up
its affairs and terminate. Fifty percent of the royalty
interests will automatically revert to ECA at the Termination
Date, while the Perpetual Royalties will be sold and the
proceeds will be distributed to the unitholders at the
Termination Date or soon thereafter. ECA will have a right of
first refusal to purchase the remaining fifty percent of the
royalty interests at the Termination Date.
|
|
2.
|
SIGNIFICANT
ACCOUNTING POLICIES
|
The following is a summary of the significant accounting
policies followed by the Trust.
Basis of Accounting The financial statements
of the Trust are prepared on the following basis:
|
|
|
|
|
Royalty income recorded is the amount computed to be paid by ECA
to the Trustee on behalf of the Trust for the corresponding
quarter.
|
|
|
|
Trust expenses are recorded when paid.
|
F-12
ECA
MARCELLUS TRUST I
Notes to
Statement of Assets and
Trust Corpus (Continued)
|
|
|
|
|
Distributable income is reduced by cash reserves established for
liabilities and contingencies.
|
|
|
|
Distributions to unitholders are recorded in the quarter to
which they apply.
|
The financial statements of the trust differ from financial
statements prepared in accordance with accounting principles
generally accepted in the United States of America
(GAAP) because certain cash reserves may be
established for contingencies, which would not be accrued in
financial statements prepared in accordance with GAAP.
Amortization of the investment in overriding royalty interests
calculated on a
unit-of-production
basis is charged directly to trust corpus. This comprehensive
basis of accounting other than GAAP corresponds to the
accounting permitted for royalty trusts by the
U.S. Securities and Exchange Commission as specified by
Staff Accounting Bulletin Topic 12:E, Financial Statements
of Royalty Trusts.
Cash Cash consists of highly liquid
instruments with maturities at the time of acquisition of three
months or less.
Use of Estimates in the Preparation of Financial
Statements The preparation of financial
statements requires the trust to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those
estimates.
The Trust is a Delaware statutory trust and is not required to
pay federal or state income taxes.
|
|
4.
|
DISTRIBUTIONS
TO UNITHOLDERS
|
The trust will make quarterly cash distributions of the cash
received from Energy Corporation of America, after deducting
trust administrative expenses paid on or about 60 days
after the completion of each quarter through (and including) the
quarter ending March 31, 2030 (the Termination
Date). The first quarterly distribution is expected to be
made on or about August 31, 2010 to record unitholders as
of August 15, 2010. The trust will begin to liquidate on
the Termination Date and will soon thereafter wind up its
affairs and terminate. Upon termination of the trust, 50% of
each of the PDP Royalty Interest and the PUD Royalty Interest
will revert automatically to ECA. The remaining 50% of each of
the PDP Royalty Interest and the PUD Royalty Interest will be
sold, and the net proceeds therefrom will be distributed pro
rata to the unitholders soon after the Termination Date. Because
payments to the trust will be generated by depleting assets and
the trust has a finite life with the production from the
Underlying Properties diminishing over time, a portion of each
distribution will represent a return of your original investment.
F-13
ECA
MARCELLUS TRUST I
Unaudited
Pro Forma Financial Information
The following unaudited pro forma statement of asset and trust
corpus and unaudited pro forma statements of distributable
income for the Trust have been prepared to illustrate the
conveyance of royalty interests in certain Underlying Properties
to the trust by ECA. The unaudited pro forma statement of asset
and trust corpus presents the beginning statement of assets,
liabilities and trust corpus of the Trust as of March 19,
2010, giving effect to the royalty interests conveyance as if it
occurred on that date. The unaudited pro forma statement of
distributable income presents the statements of historical
revenue and direct operating expenses of the Underlying
Properties for the year ended December 31, 2009 and for the
three months ended March 31, 2010, giving effect to the royalty
interests conveyance as if it occurred as of the beginning of
the period presented, reflecting only pro forma adjustments
expected to have a continuing impact on the combined results.
These unaudited pro forma financial statements are for
informational purposes only. They do not purport to present the
results that would have actually occurred had the royalty
interests conveyance been completed on the assumed dates or for
the periods presented, or which may be realized in the future.
To produce the pro forma financial information, management made
certain estimates. The accompanying unaudited pro forma
statement of assets, liabilities and trust corpus assumes a
March 19, 2010 issuance of 17,605,000 trust units at
$20.00 per unit. The accompanying unaudited pro forma
statements of distributable income for the year ended
December 31, 2009 and the three months ended March 31,
2010, have been prepared assuming Trust formation and royalty
interests conveyance at the beginning of the period presented.
These estimates are based on the most recently available
information. To the extent there are significant changes in
these amounts, the assumptions and estimates herein could change
significantly. The statements of distributable income should be
read in conjunction with the Managements Discussion
and Analysis of Financial Condition and Results of Operations of
Energy Corporation of America included in the ECA Annex to
this prospectus and the historical statements of the trust, ECA
and the Underlying Properties, including the related notes,
included in this prospectus.
F-14
ECA
MARCELLUS TRUST I
Unaudited
Pro Forma Statements of Assets, Liabilities, and
Trust Corpus
As of
March 19, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Pro Forma
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
10
|
|
|
$
|
|
|
|
$
|
10
|
|
Investment in Royalty Interest
|
|
|
|
|
|
|
352,100,000
|
(a)
|
|
|
352,100,000
|
|
Floor price contracts
|
|
|
|
|
|
|
4,957,920
|
(a)
|
|
|
4,957,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
10
|
|
|
$
|
357,057,920
|
|
|
$
|
357,057,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor premiums payable
|
|
$
|
|
|
|
$
|
4,957,920
|
(b)
|
|
$
|
4,957,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
$
|
|
|
|
$
|
4,957,920
|
|
|
$
|
4,957,920
|
|
Trust Corpus:
|
|
|
|
|
|
|
|
|
|
|
|
|
17,605,000 Trust Units Issued and Outstanding at Formation
|
|
$
|
10
|
|
|
$
|
352,100,000
|
|
|
$
|
352,100,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Trust Corpus
|
|
$
|
10
|
|
|
$
|
357,057,920
|
|
|
$
|
357,057,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are integral
part of the unaudited pro forma financial information
F-15
ECA
MARCELLUS TRUST I
Unaudited
Pro Forma Statement of Distributable Income
For the
Periods Ended December 31, 2009 and March 31, 2010
(In
thousands, except per unit)
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Three Months Ended
|
|
|
|
December 31,
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
Historical results:
|
|
|
|
|
|
|
|
|
Revenue from gas sales
|
|
$
|
3,623
|
|
|
$
|
4,100
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
Production and property taxes
|
|
|
|
|
|
|
|
|
Production expenses
|
|
|
24
|
|
|
|
16
|
|
Marketing fee
|
|
|
132
|
|
|
|
111
|
|
Gathering and transportation
|
|
|
458
|
|
|
|
385
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
614
|
|
|
|
512
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses before pro
forma adjustments
|
|
$
|
3,009
|
|
|
$
|
3,588
|
|
Pro Forma adjustments:
|
|
|
|
|
|
|
|
|
Historical production expenses (c)
|
|
|
24
|
|
|
|
16
|
|
Marketing fee (c)
|
|
|
132
|
|
|
|
111
|
|
|
|
|
|
|
|
|
|
|
Total pro forma adjustments
|
|
|
156
|
|
|
|
127
|
|
|
|
|
|
|
|
|
|
|
Pro forma gross net proceeds
|
|
$
|
3,165
|
|
|
$
|
3,715
|
|
Overriding royalty interest percentage
|
|
|
90
|
%
|
|
|
90
|
%
|
|
|
|
|
|
|
|
|
|
Net proceeds to trust
|
|
$
|
2,849
|
|
|
$
|
3,344
|
|
Less trust general and administrative expenses and state
franchise taxes (d)
|
|
|
550
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
|
Distributable income (e)
|
|
$
|
2,299
|
|
|
$
|
3,044
|
|
|
|
|
|
|
|
|
|
|
Distributable income per unit
|
|
$
|
0.13
|
|
|
$
|
0.17
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are integral
part of the unaudited pro forma financial information
F-16
ECA
MARCELLUS TRUST I
Notes to
Unaudited Pro Forma Financial Information
|
|
NOTE 1.
|
BASIS OF
PRESENTATION
|
ECA Marcellus Trust I is a Delaware statutory trust formed
in March 2010 by Energy Corporation of America to own royalty
interests in eight producing horizontal natural gas wells
producing from the Marcellus Shale formation, together with six
additional wells that are undergoing completion operations and
are expected to be online by August 15, 2010, all of which
are located in Greene County, Pennsylvania (the Producing
Wells), and royalty interests in 52 horizontal natural gas
development wells to be drilled to the Marcellus Shale formation
(the PUD Wells) within the Area of Mutual
Interest, or AMI, in which ECA presently holds
approximately 9,300 acres, of which it owns substantially all of
the working interests, in Greene County, Pennsylvania. The Area
of Mutual Interest consists of the Marcellus shale formation in
approximately 121 square miles and is depicted by the area
identified on the inside front cover of this prospectus. ECA is
obligated to drill the 52 development wells from drill sites on
approximately 9,300 leased acres in the AMI. Until ECA has
satisfied its drilling obligation, it will not be permitted to
drill and complete any well in the Marcellus Shale formation on
lease acreage included within the AMI for its own account. Also,
ECA will grant to the trust a lien on ECAs interest in the
Marcellus Shale formation in the AMI (except currently producing
wells) in order to secure its drilling obligation to the Trust.
The royalty interests will be conveyed from ECAs working
interest in the Producing Wells and the PUD Wells limited to the
Marcellus Shale formation (the Underlying
Properties). The royalty interest in the Producing Wells
(the PDP Royalty Interest) entitles the trust to
receive 90% of the proceeds (after deducting post-production
costs and any applicable taxes) from the sale of production of
natural gas attributable to ECAs interest in the Producing
Wells. The royalty interest in the PUD Wells (the PUD
Royalty Interest) entitles the trust to receive 50% of the
proceeds (after deducting post-production costs and applicable
taxes) from the sale of production of natural gas attributable
to ECAs interest in the PUD Wells. Approximately 50% of
the estimated natural gas production attributable to the
trusts royalty interests will be hedged with a combination
of floors and swaps from April 1, 2010 to March 31,
2014. The floor price contracts will be transferred to the trust
by ECA, while ECA will enter into a back-to-back swap agreement
with the trust to provide the trust with the benefit of swap
contracts entered into between ECA and third parties. ECA will
be entitled to recoup the costs of establishing the floor price
contracts only if and to the extent cash available for
distribution by the trust exceeds certain levels.
The unaudited pro forma financial information assumes the
issuance of 17,605,000 trust units at $20.00 per unit.
In order to provide support for cash distributions on the common
units, ECA has agreed to subordinate 4,401,250 of the trust
units it will retain following this offering, which will
comprise 25% of the outstanding trust units. While the
subordinated units will be entitled to receive pro rata
distributions from the trust if and to the extent there is
sufficient cash to provide a cash distribution on the common
units which is no less than the applicable quarterly
subordination threshold, if there is not sufficient cash to fund
such a distribution on all trust units, the distribution to be
made with respect to the subordinated units will be reduced or
eliminated in order to make a distribution, to the extent
possible, of up to the subordination threshold amount on the
common units. Each applicable quarterly subordination threshold
is equal to 80% of the target cash distribution level for the
corresponding quarter as reflected on Annex B (each, a
subordination threshold). In exchange for agreeing
to subordinate these trust units, and in order to provide
additional financial incentive to ECA to perform its drilling
obligation and operations in the Underlying Properties in an
efficient and cost-effective manner, ECA will be entitled to
F-17
ECA
MARCELLUS TRUST I
Notes to
Unaudited Pro Forma Financial
Information (Continued)
receive incentive distributions (the incentive
distributions) equal to 50% of the amount by which the
cash available for distribution on all of the trust units in any
quarter exceeds 150% of the subordination threshold for such
quarter (which is 120% of the target cash distribution) (each,
an incentive threshold). ECAs right to receive
this incentive distribution will terminate upon the expiration
of the subordination period. Additionally and notwithstanding
the foregoing, in exchange for the transfer by ECA to the trust
of the natural gas hedging contracts, until the earlier of the
expiration of the subordination period (as defined below) or
such time as the costs associated with establishing the natural
gas hedging contracts (the reimbursement amount)
have been paid in full, the trust will pay ECA an amount equal
to 50% of the amount by which the cash receipts in respect of
the royalties in any quarter exceeds the applicable incentive
threshold. Such obligation includes interest on the
reimbursement amount accruing at 10% per year. ECA bears the
risk that the subordination period will end before it is
reimbursed in full for establishing the hedging contracts.
ECA has incurred costs of approximately $5.0 million in
securing the hedging contracts to be transferred to the trust.
ECA will be entitled to reimbursement for these expenditures
only if and to the extent distributions to trust unitholders
would otherwise exceed the incentive threshold. This
reimbursement will be deducted, over time, from the 50% of cash
available for distribution in excess of the incentive thresholds
otherwise payable to the trust unitholders. ECAs right to
receive the remaining 50% of such cash in the form of incentive
distributions would not be affected.
The subordinated units will automatically convert into common
units on a
one-for-one
basis and ECAs right to receive incentive distributions
and to recoup the reimbursement amount will terminate, at the
end of the fourth full calendar quarter following ECAs
satisfaction of its drilling obligation to the trust.
Accordingly, ECA bears the risk that it will not be partially or
fully reimbursed for the hedging contracts it is transferring to
the trust. The trust currently expects that ECA will complete
this drilling obligation on or before March 31, 2013 and
that, accordingly, the subordinated units will convert into
common units on or before March 31, 2014. In the event of
delays, ECA will have until March 31, 2014 to drill all the
PUD Wells, in which event the subordinated units will convert
into common units on or before March 31, 2015. The period
during which the subordinated units are outstanding is referred
to as the subordination period.
|
|
NOTE 2.
|
TRUST ACCOUNTING
POLICIES
|
The Unaudited Pro Forma Statement of Distributable Income was
derived from the historical accounting records of the Underlying
Properties.
Income determined on the basis of generally accepted accounting
principles would include all expenses incurred for the period
presented. However, the Trust serves as a pass-through entity,
with expenses for depreciation, depletion, and amortization,
interest and income taxes being based on the status and
elections of the trust unitholders. In addition, the royalty
interest will not be burdened by field and lease operating
expenses. Thus, the statement purports to show distributable
income, defined as income of the Trust available for
distribution to the trust unitholders before application of
those additional unitholders additional expenses, if any,
for depreciation, depletion, and amortization, interest and
income taxes. The revenues are reflected net of existing
royalties and overriding royalties and have been reduced by
gathering/post-production expenses. Actual cash receipts may
vary due to timing delays of actual cash receipts
F-18
ECA
MARCELLUS TRUST I
Notes to
Unaudited Pro Forma Financial
Information (Continued)
from the property purchasers and due to wellhead and pipeline
volume balancing agreements or practices.
Investment in royalty interest is periodically assessed to
determine whether its aggregate value has been impaired below
its total capitalized cost based on the Underlying Properties.
The Trust will provide a write-down to its investment in the
royalty interests to the extent the total capitalized costs,
less accumulated depreciation, depletion and amortization,
exceed undiscounted future net revenues attributable to the
proved natural gas reserves of the Underlying Properties.
ECA believes that the assumptions used provide a reasonable
basis for presenting the significant effects directly
attributable to this transaction.
The unaudited pro forma financial information should be read in
conjunction with the Statement of Assets and Trust Corpus and
the Statement of Historical Revenues and Direct Operating Costs
for Underlying Properties and related notes for the period
presented.
The Trust is a Delaware statutory trust and is not required to
pay federal or state income taxes. Accordingly, no provision for
federal or state income taxes has been made.
|
|
NOTE 4.
|
PRO FORMA
ADJUSTMENTS
|
(a) Reflects ECAs transfer of certain natural gas
floor price contracts and
back-to-back
swap arrangements and the conveyance of the royalty interests to
the Trust in exchange for all of the net proceeds of this
offering as well common and subordinated units representing a
50% beneficial interest in the trust, with all trust units
valued at the initial public offering price of the common units.
(b) Until the earlier of the expiration of the
subordination period (as defined in Note 1) or such time as
the reimbursement amount has been paid in full, the trust will
pay ECA an amount equal to 50% of the amount by which the cash
receipts in respect of the royalties in any quarter exceeds the
applicable incentive threshold. Such obligation includes
interest on the reimbursement amount accruing at 10% per annum.
ECA bears the risk that the subordination period will end before
it is reimbursed in full.
(c) Historical well production and lease production
expenses and marketing fee are not deducted in determining net
revenue attributable to the royalty interests and in determining
distributable income. Royalty interests, as defined in the
conveyance, will bear a pro rata share of taxes on production
and property, if any, and applicable gathering/post-production
expenses relating to make the gas saleable.
(d) The Trusts general and administrative expenses
are estimated at $800,000 annually. Such expenses include
trustee fees, administrative service fees and costs associated
with being a public entity. Pennsylvania state franchise taxes
are estimated at $150,000 for the year ended December 31,
2009 and $100,000 for the three months ended March 31, 2010.
(e) Assumes that no incentive threshold was reached during
the period.
F-19
ECA
MARCELLUS TRUST I
Notes to
Unaudited Pro Forma Financial
Information (Continued)
|
|
5.
|
SUPPLEMENTAL
INFORMATION ON GAS PRODUCING ACTIVITIES
|
Information with respect to gas producing activities of the
trusts royalty interests in the Underlying Properties is
presented in the following tables. The information was derived
from reserve reports which were prepared by independent reserve
engineers as of December 31, 2009, in accordance with ASU
2010-03
Extractive Activities Oil and Gas (Topic 932):
Oil and Gas Reserve Estimation and Disclosures.
Gas
Reserves
Estimates of proved reserves are inherently imprecise and are
continually subject to revision based on production history,
results of additional exploration and development, price changes
and other factors.
The following table summarizes the estimated quantities of the
proved natural gas reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA Marcellus
|
|
|
|
|
|
Underlying
|
|
|
|
Trust I
|
|
|
Adjustments
|
|
|
Properties
|
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
Natural Gas
|
|
|
|
(Mmcf)
|
|
|
(Mmcf)
|
|
|
(Mmcf)
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries (1)
|
|
|
105,907
|
|
|
|
89,307
|
(a)
|
|
|
195,214
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(757
|
)
|
|
|
(84
|
) (a)
|
|
|
(841
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
105,150
|
|
|
|
89,223
|
|
|
|
194,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
8,125
|
|
|
|
1,539
|
(a)
|
|
|
9,664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed behind pipe reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
8,228
|
|
|
|
1,527
|
(a)
|
|
|
9,755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
88,797
|
|
|
|
86,157
|
(a)
|
|
|
174,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Extensions and discoveries during
the period ending December 31, 2009 are a result of the
discovery and extensive production from a new Marcellus Shale
field. This field had previously been tested with vertical
Marcellus Shale wells, and during 2009 ECA drilled four
producing Marcellus Shale horizontal wells and participated in
the drilling of one well with another operator, all of which
demonstrated consistent levels of production and provided
reasonable certainty that wells to be drilled within the field
qualified for Proved Undeveloped classification.
|
Proved reserves are estimated quantities of natural gas which
geological and engineering data indicated with reasonable
certainty to be recoverable in future years from known reserves
under existing economic and operating conditions. Proved
developed reserves are proven reserves,
F-20
ECA
MARCELLUS TRUST I
Notes to
Unaudited Pro Forma Financial
Information (Continued)
which are expected to be recovered through existing wells with
existing equipment and operation methods.
Estimated
Present Value of Future Net Cash Flows
Standardized Measure of Discounted Future Net Cash
Flows Estimated discounted future net cash flows
and changes therein were determined in accordance with ASC 932,
Disclosures About Oil and Gas Producing Activities.
Certain information concerning the assumptions used in computing
the valuation of proved reserves and their inherent limitations
are discussed below. ECA believes such information is important
to a proper understanding and assessment of the data presented.
Future cash inflows are computed by applying the average prices
of gas during the
12-month
period ending December 31, 2009, determined using the
unweighted arithmetic average of the prices in effect on the
first-day-of-the-month
for each month within the period relating to the trusts
royalty interest proved reserves to the period-end quantities of
those reserves. Future price changes are considered only to the
extent provided by contractual arrangements in existence at
period-end.
The assumptions used to compute estimated future net revenues do
not necessarily reflect ECAs expectations of actual
revenues or costs or their present worth. In addition,
variations from the expected production rates also could result
directly or indirectly from factors outside of ECAs
control, such as unintentional delays in development, changes in
prices or regulatory controls. The reserve valuation further
assumes that all reserves will be disposed of by production.
However, if reserves are sold in place, this could affect the
amount of cash eventually realized.
Future production costs are computed by estimating the
expenditures to be incurred in producing the proved gas reserves
at December 31, 2009, based on period-end costs and
assuming continuation of existing economic conditions.
Future income tax expenses are not computed as the Trust is not
required to pay federal or state income taxes.
An annual discount rate of 10% was used to reflect the timing of
the future net cash flows relating to proved gas reserves in
accordance with the rules and regulations of the SEC.
F-21
ECA
MARCELLUS TRUST I
Notes to
Unaudited Pro Forma Financial
Information (Continued)
Information with respect to estimated discounted future net cash
flows related to proved gas reserves as of December 31,
2009 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA Marcellus
|
|
|
|
|
|
Underlying
|
|
|
|
Trust I
|
|
|
Adjustments
|
|
|
Properties
|
|
|
Future cash in flows
|
|
$
|
419,139
|
|
|
$
|
355,649
|
(a)
|
|
$
|
774,788
|
|
Future production cost
|
|
|
(56,318
|
)
|
|
|
(276,298
|
) (b)
|
|
|
(332,616
|
)
|
Future income tax expense
|
|
|
|
|
|
|
(172,000
|
) (c)
|
|
|
(172,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows before discount
|
|
|
362,821
|
|
|
|
(92,649
|
)
|
|
|
270,172
|
|
10% discount to present value
|
|
|
(179,197
|
)
|
|
|
(12,949
|
)
|
|
|
(192,146
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows related
to proved oil and gas reserves
|
|
$
|
183,624
|
|
|
$
|
(105,598
|
)
|
|
$
|
78,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The changes in the standardized measure of discounted future net
cash flows relating to proved gas reserves as of
December 31, 2009 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Underlying
|
|
|
|
ECA Marcellus Trust I
|
|
|
Adjustments
|
|
|
Properties
|
|
|
Standardized measure of discounted future net cash flows at
beginning of period
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(2,849
|
)
|
|
|
(160
|
) (a)
|
|
|
(3,009
|
)
|
Net changes in prices and production costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in production rates and other
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions, discoveries and other additions, net of future
production and development costs
|
|
|
186,473
|
|
|
|
(111,013
|
) (d)
|
|
|
75,460
|
|
Changes in estimated future development costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Development costs incurred
|
|
|
|
|
|
|
5,575
|
(e)
|
|
|
5,575
|
|
Revisions of previous quantity estimates
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows at end
of period
|
|
$
|
183,624
|
|
|
$
|
(105,598
|
)
|
|
$
|
78,026
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
(a)
|
|
Reflects amounts attributable to
the retained interest of the Company in the Underlying
Properties.
|
|
(b)
|
|
Production costs and marketing fees
to which the trusts interest is not subject and amounts
attributable to the retained interest of the Company in the
Underlying Properties.
|
|
(c)
|
|
Future income tax expense related
to the Underlying Properties.
|
|
(d)
|
|
Extensions, discoveries and other
additions attributable to the retained interest of the Company
net of 100% of the future development costs, production costs
and marketing fees attributable to the Underlying Properties.
|
|
(e)
|
|
Development costs incurred for the
Underlying Properties for the year ended December 31, 2009.
|
F-22
Business
of Energy Corporation of America
General
Energy Corporation of America (ECA or the
Company) is a privately held energy company engaged
in the exploration, development, production, gathering,
aggregation and sale of natural gas and oil, primarily in the
Appalachian Basin, Gulf Coast and Rocky Mountain regions in the
United States and in New Zealand. ECA or its predecessors have
owned and operated natural gas properties in the Appalachian
Basin for more than 45 years, and ECA is one of the largest
natural gas operators in the Appalachian Basin. As of
December 31, 2009, ECA operated approximately
5,100 wells in the Appalachian Basin and had an aggregate
net leasehold position of approximately one million acres, with
85% of this acreage held by production. ECA sells gas from its
own wells as well as third-party wells to local gas distribution
companies, industrial end users located in the Northeast, other
gas marketing entities and into the spot market for gas
delivered into interstate pipelines. ECA owns and operates
approximately 5,000 miles of gathering lines and intrastate
pipelines that are used in connection with its gas aggregation
activities. During the fiscal year ended June 30, 2009, ECA
aggregated and sold 22.5 Bcf of gas for an average of
62 MMcf of gas per day, of which 20.7 Bcf, or
57 MMcf per day, represented sales of gas produced from
wells operated by ECA.
ECA was formed in September 1992 as a Colorado corporation and
subsequently reincorporated in West Virginia through a merger in
June 1995. ECAs predecessor began operating in the
Appalachian Basin in 1963. ECAs principal offices are
located at 4643 South Ulster Street, Suite 1100, Denver,
Colorado 80237, and its telephone number is
(303) 694-2667.
Gas
And Oil Development And Production
Operations
and Significant Developments
The Companys proved developed net natural gas and oil
reserves are estimated as of July 1, 2009 at
143,167 MMcf and 322 MBbls, respectively. For the
fiscal year ended June 30, 2009, the Companys net
natural gas production was 9,364 MMcf and net oil
production was 47 MBbls, for a total of 9,646 net
MMcfe.
Development
Activity
During the fiscal year ended June 30, 2009, the Company
drilled 26 productive gross wells (20.9 net) and recompleted
four wells. The average first month gross production rate
for the four horizontal Marcellus Shale wells that the Company
drilled in Greene County, Pennsylvania in fiscal year 2009 was
2,531 Mcf per day per well. The average first month gross
production rate for the seven vertical Marcellus Shale wells
that the Company drilled in Greene County, Pennsylvania in
fiscal year 2009 was 192 Mcf per day per well. The average
first month gross production rate for the other 15 wells
that the Company drilled in fiscal year 2009 was 162 Mcf
per day per well. The average initial increase in gross
production rate for the four wells that the Company recompleted
in fiscal year 2009 in Fort Bend County, Texas was 926.5
Mcf per day per well.
Competition
Given the increased activity in the Marcellus Shale formation,
the Company will encounter substantial competition in acquiring
properties, aggregating oil and natural gas, securing drilling
equipment and personnel and operating its properties. The
competitors in acquisitions,
ECA-2
development, exploration and production include major oil
companies, numerous independent oil and natural gas companies,
natural gas marketers, individual proprietors and others.
Natural gas competes with other forms of energy available to
customers, primarily based on price. These alternate forms of
energy include electricity, coal and fuel oils. Changes in the
availability or price of natural gas or other forms of energy,
as well as business conditions, conservation, legislation,
regulations and the ability to convert to alternate fuels and
other forms of energy may affect the demand for natural gas.
Regulations
Affecting Operations
The Companys operations are affected by extensive
regulation pursuant to various federal, state and local laws and
regulations relating to the exploration for and development,
production, gathering, aggregation, transportation and storage
of oil and natural gas. These regulations, among other things,
can affect the rate of oil and natural gas production. The
Companys operations are subject to numerous laws and
regulations governing plugging and abandonment, the discharge of
materials into the environment or otherwise relating to
environmental protection. These laws and regulations require the
acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that
can be released into the environment in connection with drilling
activities on certain lands lying within wilderness, wetlands
and other protected areas, and impose substantial liabilities
for pollution which might result from the Companys
operations. The Company believes it is in substantial compliance
with applicable regulations.
Gas
Aggregation and Pipelines
The Company, primarily through its wholly owned subsidiary
Eastern Marketing Corporation (Eastern Marketing),
aggregates natural gas through the purchase of production from
properties in the Appalachian Basin, including the Marcellus
Shale, in which the Company has an interest, the purchase of
natural gas delivered through the Companys gathering
pipelines located in the Appalachian Basin, and the purchase of
natural gas in the spot market. The Company sells natural gas to
local natural gas distribution companies, industrial end users
located in the Northeast, other natural gas marketing entities
and into the spot market for natural gas delivered into
interstate pipelines.
The Company owns and operates approximately 5,000 miles of
gathering lines and intrastate pipelines that are used in
connection with its gas aggregation activities. During the
fiscal year ended June 30, 2009, ECA and its affiliates
aggregated and sold 22.5 Bcf of natural gas for an average
of 62 MMcf of natural gas per day, of which 20.7 Bcf,
or 57 MMcf per day, represented sales of natural gas
produced from wells operated by ECA. Substantially all of the
production subject to the PDP Royalty Interest and PUD Royalty
Interest will be gathered by ECAs Greene County Gathering
System. This system currently accesses two separate
interconnects with the Texas Eastern Transmission, L.P. and
Columbia Gas Transmission, L.L.C. interstate pipeline systems
and includes six compressors (with 8,785 total horsepower)
together with associated processing equipment. ECA will add
additional compression and related facilities as the field is
developed. ECAs interconnect agreements with these
interstate pipelines currently allow it to deliver at the
interconnections between ECAs facilities and the
interstate pipelines, up to 105,000 MMBtu per day for
transportation by the interstate pipelines to ECAs
customers (approximately 16,000 MMBtu per day is currently being
utilized), on these two interstate pipeline systems, which is in
excess of its current and expected volumes from the Underlying
Properties. To the extent necessary, ECA will add additional
compression and related facilities to this System at no cost to
the trust, other than potential increases in gathering rates as
a result of capital expenditures.
ECA-3
Regulations
Affecting Marketing and Transportation
As a purchaser of natural gas, the Company depends on the
transportation, gathering and storage services offered by
various interstate and intrastate pipeline companies for the
delivery and sale of its own natural gas supplies as well as
those it processes
and/or
markets for others. Both the performance of transportation and
storage services by interstate pipelines and the rates charged
for such services are subject to the jurisdiction of the Federal
Energy Regulatory Commission. In addition, the performance of
transportation, gathering and storage services by intrastate
pipelines and the rates charged for such services are subject to
the jurisdiction of state regulatory agencies.
Oil
and Gas Reserves
The following information relating to estimated reserve
quantities, reserve values and discounted future net revenues is
derived from, and qualified in its entirety by reference to, the
more complete reserve and revenue information and assumptions
included in the Companys Supplemental Oil and Gas
Disclosures in the Companys financial statements. Ryder
Scott, the independent petroleum engineering consultant,
estimated, in accordance with appropriate engineering, geologic,
and evaluation principles and techniques that are in accordance
with practices generally accepted in the petroleum industry and
definitions and guidelines established by the SEC, all the
proved reserve information in this Registration Statement. These
reserves-estimation methods and techniques are widely taught in
university petroleum curricula and throughout the
industrys ongoing training programs. Although these
appropriate engineering, geologic, and evaluation principles and
techniques that are in accordance with practices generally
accepted in the petroleum industry are based upon established
scientific concepts, the application of such principles involves
extensive judgment and is subject to changes in existing
knowledge and technology, economic conditions and applicable
statutory and regulatory provisions. These same industry-wide
applied techniques are used in determining our estimated reserve
quantities. In December 2008, the Securities and Exchange
Commission (the SEC) announced that it had approved
revisions to modernize its oil and gas reserves reporting
requirements. The following reserve information was calculated
based on the SEC reserve reporting requirements in effect for
the periods presented, which do not give effect to the new SEC
requirements. Accordingly, the reserve information presented
below is calculated based on year-end pricing information. There
are numerous uncertainties inherent in estimating quantities of
proved reserves and projecting future rates of production and
timing of development expenditures. The following reserve
information represents estimates only and should not be
construed as being exact. Future reserve values are based on
fiscal year-end prices except in those instances where the sale
of natural gas and oil is covered by contract terms. Operating
costs, production and ad valorem taxes and future development
costs are based on current costs with no escalations. The table
below does not give effect to derivative transactions.
ECA-4
The following table sets forth the Companys estimated
proved and proved developed reserves and the related estimated
future value, as of June 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Net proved developed:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (MMcf)
|
|
|
170,625
|
|
|
|
174,396
|
|
|
|
143,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
475
|
|
|
|
379
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
173,474
|
|
|
|
176,672
|
|
|
|
145,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price ($/Mcf)
|
|
|
7.43
|
|
|
|
14.41
|
|
|
|
3.88
|
|
Future net cash flows before discount (in thousands)
|
|
$
|
737,309
|
|
|
$
|
1,362,849
|
|
|
$
|
358,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted future net cash flows related to proved developed oil
and gas reserves (in thousands) (1)
|
|
$
|
261,229
|
|
|
$
|
492,670
|
|
|
$
|
148,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Discounted using an annual discount
rate of 10%.
|
The following table sets forth the Companys estimated
proved reserves and the related estimated present value by
region, as of June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Percent of Proved
|
|
|
Present Value
|
|
Region
|
|
(MMcf)
|
|
|
(Mbbls)
|
|
|
Equivalent (MMcfe)
|
|
|
Developed Reserves
|
|
|
(Thousands)
|
|
|
Appalachian Basin
|
|
|
140,080
|
|
|
|
249
|
|
|
|
141,574
|
|
|
|
97.6
|
%
|
|
$
|
142,275
|
|
Western
|
|
|
3,087
|
|
|
|
73
|
|
|
|
3,525
|
|
|
|
2.4
|
%
|
|
|
6,398
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
143,167
|
|
|
|
322
|
|
|
|
145,099
|
|
|
|
100.0
|
%
|
|
$
|
148,673
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Estimated future net revenue
represents the estimated future gross revenue to be generated
from the production of proved developed reserves, net of
estimated production and future development costs, using prices
and costs under existing economic conditions at June 30,
2009. Prices were determined by applying period-end prices of
oil and natural gas relating to the Company in accordance with
the SECs ruling in effect as of June 30, 2009, and do
not give effect to any derivative transactions. This price
should not be interpreted as a prediction of future prices, nor
does it reflect the value of commodity hedges in place at
June 30, 2009. The amounts shown do not give effect to
non-property related expenses, such as corporate general and
administrative expenses and debt service, or to depreciation,
depletion and amortization.
|
Producing
Wells
The following table sets forth certain information relating to
productive wells at June 30, 2009. Wells are classified as
oil or natural gas according to their predominant production
stream.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Wells
|
|
|
Net Wells
|
|
Region
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Appalachian Basin
|
|
|
50
|
|
|
|
5,094
|
|
|
|
5,144
|
|
|
|
35.4
|
|
|
|
3,527.9
|
|
|
|
3,563.3
|
|
Western
|
|
|
|
|
|
|
24
|
|
|
|
24
|
|
|
|
0
|
|
|
|
11.3
|
|
|
|
11.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
50
|
|
|
|
5,118
|
|
|
|
5,168
|
|
|
|
35.4
|
|
|
|
3,539.2
|
|
|
|
3,574.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-5
Acreage
The following table sets forth the developed and undeveloped
gross and net acreage held at June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
Undeveloped Acreage
|
|
Region
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Appalachian Basin
|
|
|
836,277
|
|
|
|
766,676
|
|
|
|
189,405
|
|
|
|
163,993
|
|
Western
|
|
|
21,709
|
|
|
|
9,356
|
|
|
|
22,892
|
|
|
|
15,248
|
|
New Zealand
|
|
|
|
|
|
|
|
|
|
|
1,732,209
|
|
|
|
1,555,776
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
857,986
|
|
|
|
776,032
|
|
|
|
1,944,506
|
|
|
|
1,735,017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
The following table sets forth certain net production data and
average wellhead sales prices attributable to the Companys
properties for the years ended June 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
2008
|
|
2009
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
83
|
|
|
|
65
|
|
|
|
47
|
|
Natural gas (MMcf)
|
|
|
9,138
|
|
|
|
10,294
|
|
|
|
9,364
|
|
Average sales price (before the effect of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl
|
|
$
|
60.10
|
|
|
$
|
92.37
|
|
|
$
|
64.98
|
|
Natural gas per Mcf
|
|
$
|
7.01
|
|
|
$
|
8.53
|
|
|
$
|
6.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production Costs (per Mcfe)
|
|
$
|
1.13
|
|
|
$
|
1.01
|
|
|
$
|
1.09
|
|
ECA-6
Drilling
Activities
The Companys natural gas and oil exploratory and
developmental drilling activities are as follows for the years
ended June 30. The number of wells drilled refers to the
number of wells commenced at any time during the respective
fiscal year. A well is considered productive if it justifies the
installation of permanent equipment for the production of
natural gas or oil.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
93
|
|
|
|
80.3
|
|
|
|
93
|
|
|
|
82.1
|
|
|
|
24
|
|
|
|
19.5
|
|
Western/New Zealand
|
|
|
2
|
|
|
|
1.8
|
|
|
|
2
|
|
|
|
1.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
95
|
|
|
|
82.1
|
|
|
|
95
|
|
|
|
83.9
|
|
|
|
24
|
|
|
|
19.5
|
|
Nonproductive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western/New Zealand
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
5
|
|
|
|
4.5
|
|
|
|
2
|
|
|
|
1.8
|
|
|
|
2
|
|
|
|
1.4
|
|
Western/New Zealand
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
5
|
|
|
|
4.5
|
|
|
|
2
|
|
|
|
1.8
|
|
|
|
2
|
|
|
|
1.4
|
|
Nonproductive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western/New Zealand
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
0.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
101
|
|
|
|
87.6
|
|
|
|
98
|
|
|
|
86.4
|
|
|
|
26
|
|
|
|
20.9
|
|
ECA-7
Selected
Consolidated Financial Data of Energy Corporation Of
America
The following selected consolidated statements of operations
data of Energy Corporation of America and its subsidiaries for
each of the three years in the period ended June 30, 2009
and the selected consolidated balance sheet data for Energy
Corporation of America and its subsidiaries as of June 30,
2008 and 2009 are derived from the audited consolidated
financial statements of Energy Corporation of America and its
subsidiaries included elsewhere in this prospectus. The
following selected consolidated statement of operations data for
the nine months ended March 31, 2009 and 2010 and the
selected consolidated balance sheet data as of March 31,
2009 and 2010 are derived from the unaudited consolidated
financial statements of Energy Corporation of America and its
subsidiaries included elsewhere in this prospectus. The selected
consolidated balance sheet data presented as of June 30,
2007 has been derived from the audited consolidated financial
statements of Energy Corporation of America and its
subsidiaries, which are not included in this prospectus. The
information in the table should be read in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations of Energy Corporation of
America beginning on
page ECA-10
of this prospectus and the consolidated financial statements of
Energy Corporation of America and its subsidiaries, related
notes and other financial information included elsewhere in this
prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended June 30,
|
|
|
March 31,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except per share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
84,429
|
|
|
$
|
96,514
|
|
|
$
|
92,262
|
|
|
$
|
68,775
|
|
|
$
|
67,184
|
|
Gas aggregation and pipeline sales
|
|
|
120,549
|
|
|
|
142,825
|
|
|
|
116,730
|
|
|
|
99,926
|
|
|
|
62,682
|
|
Well operations and service revenues
|
|
|
6,976
|
|
|
|
7,732
|
|
|
|
7,228
|
|
|
|
5,431
|
|
|
|
5,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
211,954
|
|
|
|
247,071
|
|
|
|
216,220
|
|
|
|
174,132
|
|
|
|
135,351
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating expenses
|
|
|
17,700
|
|
|
|
18,234
|
|
|
|
18,772
|
|
|
|
14,050
|
|
|
|
13,390
|
|
Gas aggregation and pipeline cost of sales
|
|
|
110,226
|
|
|
|
131,051
|
|
|
|
104,685
|
|
|
|
89,745
|
|
|
|
54,108
|
|
General and administrative
|
|
|
17,742
|
|
|
|
17,933
|
|
|
|
18,858
|
|
|
|
14,069
|
|
|
|
13,212
|
|
Taxes, other than income
|
|
|
4,519
|
|
|
|
5,406
|
|
|
|
4,629
|
|
|
|
4,021
|
|
|
|
1,261
|
|
Depletion and depreciation of oil and gas properties
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
|
|
17,716
|
|
|
|
25,805
|
|
Depreciation of pipelines, other property and equipment
|
|
|
4,961
|
|
|
|
5,852
|
|
|
|
6,119
|
|
|
|
4,572
|
|
|
|
4,748
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
|
|
10,132
|
|
|
|
10,730
|
|
(Gain) on sale of assets
|
|
|
(10,454
|
)
|
|
|
(7,287
|
)
|
|
|
(9,114
|
)
|
|
|
(7,360
|
)
|
|
|
(9,497
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171,296
|
|
|
|
195,159
|
|
|
|
185,870
|
|
|
|
146,945
|
|
|
|
113,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
40,658
|
|
|
|
51,912
|
|
|
|
30,350
|
|
|
|
27,187
|
|
|
|
21,594
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended June 30,
|
|
|
March 31,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except per share data)
|
|
|
Other (income) and expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
8,245
|
|
|
|
10,688
|
|
|
|
9,986
|
|
|
|
7,661
|
|
|
|
7,268
|
|
Interest income (expense) and other
|
|
|
8,547
|
|
|
|
21,884
|
|
|
|
(18,722
|
)
|
|
|
(20,520
|
)
|
|
|
5,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,792
|
|
|
|
32,572
|
|
|
|
(8,736
|
)
|
|
|
(12,859
|
)
|
|
|
13,249
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations before income taxes
|
|
|
23,866
|
|
|
|
19,340
|
|
|
|
39,086
|
|
|
|
40,046
|
|
|
|
8,345
|
|
Income tax expense
|
|
|
4,815
|
|
|
|
7,855
|
|
|
|
17,355
|
|
|
|
17,684
|
|
|
|
3,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
|
$
|
22,362
|
|
|
$
|
4,482
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share, basic and diluted:
|
|
$
|
33.66
|
|
|
$
|
19.93
|
|
|
$
|
36.98
|
|
|
$
|
38.06
|
|
|
$
|
7.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet data (at end of period):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
$
|
347,617
|
|
|
$
|
451,742
|
|
|
$
|
479,722
|
|
|
$
|
463,582
|
|
|
$
|
486,039
|
|
Total assets
|
|
|
413,321
|
|
|
|
557,980
|
|
|
|
543,719
|
|
|
|
544,984
|
|
|
|
546,321
|
|
Working capital (deficiency)
|
|
|
(41,155
|
)
|
|
|
(78,179
|
)
|
|
|
(23,997
|
)
|
|
|
494
|
|
|
|
(16,495
|
)
|
Long term debt excluding current maturities
|
|
|
135,166
|
|
|
|
197,125
|
|
|
|
218,134
|
|
|
|
217,111
|
|
|
|
249,897
|
|
Stockholders equity
|
|
|
69,891
|
|
|
|
24,666
|
|
|
|
100,935
|
|
|
|
110,153
|
|
|
|
91,271
|
|
ECA-9
Managements
Discussion and Analysis of Financial Condition
and Results of Operations of Energy Corporation of
America
The following discussion should be read in conjunction with the
consolidated financial statements and the related notes thereto
of Energy Corporation of America and its subsidiaries appearing
elsewhere in this prospectus.
Safe
Harbor Statement Under the Private Securities Litigation Reform
Act of 1995
This discussion and analysis of financial condition and results
of operations, and other sections of this prospectus, contain
forward-looking statements that are based on managements
beliefs, assumptions, current expectations, estimates,
intentions and projections about the oil and natural gas
industry, the economy and about the Company itself. Words such
as anticipates, believes,
estimates, expects,
forecasts, intends, is
likely, plans, predicts,
projects, variations of such words and similar
expressions are intended to identify such forward-looking
statements under the Private Securities Litigation Reform Act of
1995. The Company cautions that these statements are not
guarantees of future performance and involve certain risks,
uncertainties and assumptions that are difficult to predict with
regard to timing, extent, likelihood and degree of occurrence.
Therefore, actual results and outcomes may materially differ
from what may be expressed or forecasted in such forward-looking
statements. Furthermore, the Company undertakes no obligation to
update, amend or clarify forward-looking statements, whether as
a result of new information, future events or otherwise.
Important factors that could cause actual results to differ
materially from the forward-looking statements include, but are
not limited to, weather conditions, changes in production
volumes, worldwide demand and commodity prices for petroleum
natural resources, the timing and extent of the Companys
success in discovering, acquiring, developing and producing oil
and natural gas reserves, risks incident to the drilling and
operation of oil and natural gas wells, future production and
development costs, foreign currency exchange rates, the effect
of existing and future laws, governmental regulations and the
political and economic climate of the United States and New
Zealand, the effect of hedging activities, and conditions in the
capital markets.
The following should be read in conjunction with the
Companys selected consolidated financial statements and
the related notes (including the segment information) beginning
on
page ECA-26
of this prospectus.
Critical
Accounting Policies And Estimates
The discussion of financial condition and results of operation
are based upon the information reported in the consolidated
financial statements. The preparation of these financial
statements requires the Company to make assumptions and
estimates that affect the reported amounts of assets,
liabilities, revenues and expenses as well as the disclosure of
contingent assets and liabilities at the date of the financial
statements. Decisions are based on historical experience and
various other sources that are believed to be reasonable under
the circumstances. Actual results may differ from the estimates
due to changing business conditions or unexpected circumstances.
The Company believes the following policies are critical to
understanding our business and results of operations. For
additional information on significant accounting policies, see
Notes to Consolidated Financial Statements, particularly
Note 2.
Revenue Recognition The Company is engaged in
the exploration, development, acquisition, production and
aggregation of natural gas and crude oil. The revenue
recognition policy is significant because it is a key component
of the results of operations and forward looking statements
contained in Liquidity and Capital Resources below.
Revenue is derived
ECA-10
primarily from the sale of produced natural gas and crude oil.
Revenue is recorded in the month production is delivered to the
purchaser, but payment is generally received between 30 and
90 days after the date of production. Monthly, the Company
makes estimates of the amount of production delivered to the
purchaser and the price to be received. The Company uses its
knowledge of properties, historical performance, NYMEX and local
spot market prices, and other factors as the basis for these
estimates. Variances between the estimates and the actual
amounts received, which historically have not been significant,
are recorded in the month revenue is distributed.
Derivative Instruments The estimated fair
values of all derivative instruments are recorded on the
consolidated balance sheet. All of the derivative instruments
are entered into to mitigate risks related to the prices to be
received for future natural gas and oil production. Derivative
instruments are not used for trading purposes. Although
derivatives are reported on the balance sheet at fair value, to
the extent that instruments qualify for hedge accounting
treatment, changes in fair value are recorded, net of taxes,
directly to stockholders equity as a component of other
comprehensive income until the hedged oil or natural gas
quantities are produced. To the extent changes in the fair
values of derivatives relate to instruments not qualifying for
hedge accounting treatment, such changes are recorded in
operations in the period they occur. In determining the amounts
to be recorded, the Company is required to estimate the fair
values of derivatives. The estimates are based upon various
factors that include contract volumes and prices, contract
settlement dates, quoted closing prices on the NYMEX or
over-the-counter,
volatility and the time value of options. The estimated future
prices are compared to the prices fixed by the derivatives
agreements and the resulting estimated future cash inflows or
outflows over the lives of the hedges are discounted to
calculate the fair value of the derivative contracts. These
pricing and discounting variables are sensitive to market
volatility as well as changes in future price forecasts and
regional price differences. Periodically the valuations are
validated using independent third party quotations.
Reserve Estimates The Companys estimate
of natural gas and oil reserves are projections based on
geologic and engineering data. There are uncertainties inherent
in the interpretation of such data as well as the projection of
future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of
estimating underground accumulations of natural gas and oil that
are difficult to measure. The accuracy of any reserve estimate
is a function of the quality of available data, engineering and
geological interpretation and judgment. Estimates of
economically recoverable natural gas and oil reserves and future
net cash flows depend upon a number of variable factors and
assumptions, such as expected future production rates, natural
gas and oil prices, operating costs, severance taxes, and
development costs, all of which may vary considerably from
actual results. Expected cash flows are reduced to present value
using a discount rate of 10%, as required by accounting
standards. Reserve estimates are inherently imprecise and
estimates of new discoveries are more imprecise than those of
proved producing oil and natural gas properties. Reserve
estimates are calculated based on the SEC reserve reporting
requirements in effect for the periods presented, which do not
give effect to the new SEC reserve reporting requirements.
Accordingly, reserve estimates are based on year-end pricing
information. The future drilling costs associated with reserves
assigned to proved undeveloped locations may ultimately increase
to an extent that these reserves may be determined to be
uneconomic. Any significant variance in the assumptions could
materially affect the estimated quantity and value of the
reserves, which could affect the carrying value of the
Companys natural gas and oil properties and their rates of
depletion. Changes in these calculations, caused by changes in
reserve quantities or net cash flows are recorded on a
prospective basis. Actual production, revenues and expenditures
with respect to the Companys reserves will likely vary
from estimates and such variances may be material.
ECA-11
Valuation Of Long-Lived and Intangible Assets
Property and equipment are recorded at cost. The carrying value
of property and equipment is reviewed for possible impairment
whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. Assets are determined to
be impaired if a forecast of undiscounted estimated future net
operating cash flows directly related to the asset, including
disposal value if any, is less than the carrying amount of the
asset. If any asset is determined to be impaired, the loss is
measured as the amount by which the carrying amount of the asset
exceeds its fair value. An estimate of fair value is based on
the best information available, including prices for similar
assets. Different pricing assumptions or discount rates would
result in a different calculated impairment.
Income Taxes The Company provides for
deferred income taxes on the difference between the tax basis of
an asset or liability and its carrying amount in the financial
statements. This difference will result in taxable income or
deductions in future years when the reported amount of the asset
or liability is recovered or settled, respectively. Federal and
state income tax returns are generally not filed before the
consolidated financial statements are prepared, therefore an
estimate of the tax basis of assets and liabilities is
determined at the end of each period as well as the effects of
tax rate changes, tax credits and net operating loss
carryforwards. Adjustments related to differences between the
estimates and actual amounts are recorded in the period the
income tax returns are filed.
Comparison
of Results of Operations for the Years Ended June 30, 2009
and 2008
The Company realized net income of $21.7 million for the
year ended June 30, 2009 compared to net income of
$11.5 million for the year ended June 30, 2008. The
increase of $10.2 million was primarily attributable to the
net effect of a $30.9 million decrease in revenue, a
$9.3 million decrease in costs and expenses, a
$0.7 million decrease in interest expense, a
$40.6 million increase in interest and other income and a
$9.5 million increase in income tax expense.
Production, aggregation and pipeline volumes, revenue and
average sales prices for the years ended June 30 and their
related variances are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
|
|
|
June 30,
|
|
|
Variance
|
|
|
|
2008
|
|
|
2009
|
|
|
Amount
|
|
|
Percent
|
|
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MMcf)
|
|
|
10,294
|
|
|
|
9,364
|
|
|
|
(930
|
)
|
|
|
(9.0
|
)%
|
Average sales price received ($/Mcf)
|
|
$
|
8.53
|
|
|
$
|
6.76
|
|
|
$
|
(1.77
|
)
|
|
|
(20.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
87,816
|
|
|
$
|
63,339
|
|
|
$
|
(24,477
|
)
|
|
|
(27.9
|
)%
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MBbl)
|
|
|
65
|
|
|
|
47
|
|
|
|
(18
|
)
|
|
|
(27.7
|
)%
|
Average sales price received ($/Bbl)
|
|
$
|
92.37
|
|
|
$
|
64.98
|
|
|
$
|
(27.39
|
)
|
|
|
(29.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
6,004
|
|
|
$
|
3,054
|
|
|
$
|
(2,950
|
)
|
|
|
(49.1
|
)%
|
Hedging
|
|
|
2,417
|
|
|
|
25,602
|
|
|
|
23,185
|
|
|
|
959.2
|
%
|
Other
|
|
|
277
|
|
|
|
267
|
|
|
|
(10
|
)
|
|
|
(3.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales (in thousands)
|
|
$
|
96,514
|
|
|
$
|
92,262
|
|
|
$
|
(4,252
|
)
|
|
|
(4.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
|
|
|
June 30,
|
|
|
Variance
|
|
|
|
2008
|
|
|
2009
|
|
|
Amount
|
|
|
Percent
|
|
|
Aggregation revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,607
|
|
|
|
13,165
|
|
|
|
558
|
|
|
|
4.4
|
%
|
Average sales price received ($/MMBtu)
|
|
$
|
8.73
|
|
|
$
|
6.99
|
|
|
$
|
(1.74
|
)
|
|
|
(19.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
110,029
|
|
|
$
|
92,003
|
|
|
$
|
(18,026
|
)
|
|
|
(16.4
|
)%
|
Pipeline revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,863
|
|
|
|
11,906
|
|
|
|
(957
|
)
|
|
|
(7.4
|
)%
|
Average sales price received ($/MMBtu)
|
|
$
|
2.55
|
|
|
$
|
2.08
|
|
|
$
|
(0.47
|
)
|
|
|
(18.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
32,796
|
|
|
$
|
24,727
|
|
|
$
|
(8,069
|
)
|
|
|
(24.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
142,825
|
|
|
$
|
116,730
|
|
|
$
|
(26,095
|
)
|
|
|
(18.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregation gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,607
|
|
|
|
13,165
|
|
|
|
558
|
|
|
|
4.4
|
%
|
Average price paid ($/MMBtu)
|
|
$
|
8.49
|
|
|
$
|
6.74
|
|
|
$
|
(1.75
|
)
|
|
|
(20.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
107,058
|
|
|
$
|
88,767
|
|
|
$
|
(18,291
|
)
|
|
|
(17.1
|
)%
|
Pipeline gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
3,407
|
|
|
|
2,828
|
|
|
|
(579
|
)
|
|
|
(17.0
|
)%
|
Average price paid ($/MMBtu)
|
|
$
|
7.04
|
|
|
$
|
5.63
|
|
|
$
|
(1.41
|
)
|
|
|
(20.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
23,993
|
|
|
$
|
15,918
|
|
|
$
|
(8,075
|
)
|
|
|
(33.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
131,051
|
|
|
$
|
104,685
|
|
|
$
|
(26,366
|
)
|
|
|
(20.1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES. Total revenues decreased
$30.9 million or 12.5% between the years. The decrease was
due to a 4.4% decrease in oil and natural gas sales, an 18.3%
decrease in natural gas aggregation and pipeline sales, and a
6.5% decrease in well operations and service revenues.
Revenues from oil and natural gas sales decreased
$4.2 million from $96.5 million for the year ended
June 30, 2008 to $92.3 million for the year ended
June 30, 2009. Natural gas sales decreased
$24.5 million and oil sales decreased $3.0 million
between such periods. The decreases are a result of a decrease
in both the average sales price received and production. The
price decline corresponds with the change in related indexes.
The decrease in production is primarily the result of the shut
in of certain properties due to low pricing conditions in
Montana and equipment failure on certain producing properties in
Texas. The decrease in production revenue was largely offset by
an increase in recognized gains on related derivative instrument
hedging transactions on natural gas and oil production which
totaled $25.6 million for the year ended June 30, 2009
as compared to a gain of $2.4 million for the year ended
June 30, 2008. The average price per Mcfe, after hedging,
was $9.56 and $9.03 for the years ended June 30, 2009 and
2008, respectively.
Revenues from natural gas aggregation and pipeline sales
decreased $26.1 million from $142.8 million during the
period ended June 30, 2008 to $116.7 million for the
period ended June 30, 2009. Gas aggregation revenue
decreased $18.0 million while pipeline revenue, which has a
sales and a transportation component, decreased
$8.1 million. The decrease in natural gas aggregation and
pipeline sales is attributable to the decline in average sales
price received and a decrease in pipeline volumes. The price
decrease corresponds with the decline in the related index price
of natural gas.
ECA-13
COSTS AND EXPENSES. The Companys costs
and expenses decreased $9.3 million or 4.8% between the
years. The net decrease was due to a 3.0% increase in field and
lease operating expenses, a 20.1% decrease in natural gas
aggregation and pipeline costs, a 5.2% increase in general and
administrative expenses, a 14.4% decrease in taxes other than
income, a 12.0% increase in oil and natural gas related
depletion, a 4.6% increase in depreciation and amortization
expenses of pipelines, property and equipment, a 509.1% increase
in exploration and impairment costs, and an increase in the gain
on sale of property of 25.1%.
Field and lease operating expenses increased $0.5 million.
The increase is primarily related to an increase in utilities
and compressor rentals related to upgraded and new facilities
and natural gas transmission costs for recently drilled
properties.
Gas aggregation and pipeline costs decreased $26.4 million.
Gas aggregation cost decreased $18.3 million while pipeline
cost decreased by $8.1 million. The decrease in natural gas
aggregation cost is attributable to the decline in average
purchase price partially offset by an increase in volumes
aggregated during the period. The decrease in pipeline costs is
a result of a decrease in price and volumes. The decline in
price corresponds with the decrease in related indexes.
General and administrative expenses increased $0.9 million
primarily as a result of an increase in payroll and associated
tax costs.
Taxes other than income decreased $0.8 million primarily as
a result of decreased wellhead oil and natural gas sales.
Depletion, depreciation and amortization of oil and natural gas
properties expense increased $2.5 million due to an
increase in depletion rates recognized by the Company.
Exploration and impairment costs increased $15.4 million.
The increase is a result of higher expenses primarily related to
dry hole costs in New Zealand and various other geological and
geophysical costs.
Gain on sale of property increased $1.8 million primarily
as a result of an increase in incentive distributions related to
a certain term royalty conveyance.
INTEREST EXPENSE. Interest expense decreased
$0.7 million due to lower interest rates, offset partially
by an increase in outstanding borrowings.
INTEREST INCOME AND OTHER. Other
non-operating income increased by $40.6 million primarily
as a result of an increase in derivative
mark-to-market
adjustments and settlement gains.
INCOME TAX. Income tax expense increased
$9.5 million primarily as a result of the increase in
income before tax and due to the expiration of certain deferred
tax carryovers that could no longer be utilized.
Comparison
of Results of Operations for the Years Ended June 30, 2008
and 2007
The Company realized net income of $11.5 million for the
year ended June 30, 2008 compared to net income of
$19.1 million for the year ended June 30, 2007. The
decrease of $7.6 million was primarily attributable to the
net effect of a $35.1 million increase in revenue, a
ECA-14
$23.9 million increase in costs and expenses, a
$2.4 million increase in interest expense, a
$13.3 million increase in other expenses and a
$3.0 million increase in income tax expense.
Production, aggregation and pipeline volumes, revenue and
average sales prices for the years ended June 30 and their
related variances are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
|
|
|
June 30,
|
|
|
Variance
|
|
|
|
2007
|
|
|
2008
|
|
|
Amount
|
|
|
Percent
|
|
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MMcf)
|
|
|
9,138
|
|
|
|
10,294
|
|
|
|
1,156
|
|
|
|
12.7
|
%
|
Average sales price received ($/Mcf)
|
|
$
|
7.01
|
|
|
$
|
8.53
|
|
|
$
|
1.52
|
|
|
|
21.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
64,024
|
|
|
$
|
87,816
|
|
|
$
|
23,792
|
|
|
|
37.2
|
%
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MBbl)
|
|
|
83
|
|
|
|
65
|
|
|
|
(18
|
)
|
|
|
(21.7
|
)%
|
Average sales price received ($/Bbl)
|
|
$
|
60.10
|
|
|
$
|
92.37
|
|
|
$
|
32.27
|
|
|
|
53.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
4,988
|
|
|
$
|
6,004
|
|
|
$
|
1,016
|
|
|
|
20.4
|
%
|
Hedging
|
|
|
15,201
|
|
|
|
2,417
|
|
|
|
(12,784
|
)
|
|
|
(84.1
|
)%
|
Other
|
|
|
216
|
|
|
|
277
|
|
|
|
61
|
|
|
|
28.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales (in thousands)
|
|
$
|
84,429
|
|
|
$
|
96,514
|
|
|
$
|
12,085
|
|
|
|
14.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregation revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,724
|
|
|
|
12,607
|
|
|
|
(117
|
)
|
|
|
(0.9
|
)%
|
Average sales price received ($/MMBtu)
|
|
$
|
7.27
|
|
|
$
|
8.73
|
|
|
$
|
1.46
|
|
|
|
20.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
92,500
|
|
|
$
|
110,029
|
|
|
$
|
17,529
|
|
|
|
19.0
|
%
|
Pipeline revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
11,800
|
|
|
|
12,863
|
|
|
|
1,063
|
|
|
|
9.0
|
%
|
Average sales price received ($/MMBtu)
|
|
$
|
2.38
|
|
|
$
|
2.55
|
|
|
$
|
0.17
|
|
|
|
7.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
28,049
|
|
|
$
|
32,796
|
|
|
$
|
4,747
|
|
|
|
16.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
120,549
|
|
|
$
|
142,825
|
|
|
$
|
22,276
|
|
|
|
18.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregation gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,724
|
|
|
|
12,607
|
|
|
|
(117
|
)
|
|
|
(0.9
|
)%
|
Average price paid ($/MMBtu)
|
|
$
|
7.20
|
|
|
$
|
8.49
|
|
|
$
|
1.29
|
|
|
|
17.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
91,669
|
|
|
$
|
107,058
|
|
|
$
|
15,389
|
|
|
|
16.8
|
%
|
Pipeline gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
4,422
|
|
|
|
3,407
|
|
|
|
(1,015
|
)
|
|
|
(23.0
|
)%
|
Average price paid ($/MMBtu)
|
|
$
|
4.20
|
|
|
$
|
7.04
|
|
|
$
|
2.84
|
|
|
|
67.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
18,557
|
|
|
$
|
23,993
|
|
|
$
|
5,436
|
|
|
|
29.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
110,226
|
|
|
$
|
131,051
|
|
|
$
|
20,825
|
|
|
|
18.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES. Total revenues increased
$35.1 million or 16.6% between the years. The increase was
due to a 14.3% increase in oil and natural gas sales, an 18.5%
increase in natural gas aggregation and pipeline sales, and a
10.8% increase in well operations and service revenues.
Revenues from oil and natural gas sales increased
$12.1 million from $84.4 million for the year ended
June 30, 2007 to $96.5 million for the year ended
June 30, 2008. Natural gas sales increased
$23.8 million and oil sales $1.0 million. The increase
is a result of an increase in both average sales price received
and production. The price increase corresponds with the change
in related indexes. The increase in production is primarily the
result of new wells drilled and the reduction of shut-in volumes
compared to the prior period. The recognized gains on related
derivative instrument hedging transactions on natural gas and
oil production decreased by
ECA-15
$12.8 million from $15.2 million for the year ended
June 30, 2007 as compared to $2.4 million for the year
ended June 30, 2008. The average price per Mcfe, after
hedging, was $9.03 and $8.76 for the years ended June 30,
2008 and 2007, respectively.
Revenues from natural gas aggregation and pipeline sales
increased $22.3 million from $120.6 million during the
period ended June 30, 2007 to $142.8 million for the
period ended June 30, 2008. Gas aggregation revenue
increased $17.5 million while pipeline revenue, which has a
sales and a transportation component, increased
$4.8 million. The increase in natural gas aggregation and
pipeline sales is attributable to the increase in average sales
price received and an increase in pipeline volumes. The price
increase corresponds with the increase in the related index
price of natural gas.
COSTS AND EXPENSES. The Companys costs
and expenses increased $23.9 million or 13.9% between the
years. The net increase was due to a 3.0% increase in field and
lease operating expenses, an 18.9% increase in natural gas
aggregation and pipeline costs, a 1.1% increase in general and
administrative expenses, a 19.6% increase in taxes other than
income, a 15.6% increase in oil and natural gas related
depletion, an 18.0% increase in depreciation and amortization
expenses of pipelines, property and equipment, a 64.3% decrease
in exploration and impairment costs, and a decrease in the gain
on sale of property of 30.3%.
Field and lease operating expenses increased $0.5 million.
The increase is primarily related to an increase in payroll and
associated tax costs and land delay rentals for newly acquired
acreage.
Gas aggregation and pipeline costs increased $20.8 million.
Gas aggregation cost increased $15.4 million while pipeline
cost increased by $5.4 million. The increase in natural gas
aggregation cost is attributable to the increase in average
purchase price during the period. The increase in pipeline costs
is a result of the increase in price and volumes. The increase
in price corresponds with the increase in related indexes.
Taxes other than income increased $0.9 million primarily as
a result of increased wellhead oil and natural gas sales.
Depletion, depreciation and amortization of oil and natural gas
properties expense increased $2.8 million as a result of
increased production and a higher depletion rate.
Depletion, depreciation and amortization of pipelines, property
and equipment expense increased $0.9 million due to a
change in the estimated useful life for certain pipeline assets
and the acquisition of other fixed assets.
Exploration and impairment costs decreased $5.5 million.
The decrease is a result of a reduction in impairment expense
and various other geological and geophysical costs.
Gain on sale of property decreased $3.2 million primarily
due to the sale of certain properties during the year ended
June 30, 2007.
INTEREST EXPENSE. Interest expense increased
$2.4 million primarily due to an increase in outstanding
borrowings for the year ended June 30, 2008.
INTEREST INCOME AND OTHER. Other
non-operating expense increased by $13.3 million primarily
as a result of an increase in derivative
mark-to-market
adjustments and settlement losses for the year ended
June 30, 2008.
ECA-16
INCOME TAX. Income tax expense increased
$3.0 million primarily as a result of recording a tax
benefit during the year ended June 30, 2007 for expiring
tax contingency items.
Comparison
of Results of Operations for the Nine Months Ended
March 31, 2010 and 2009
The Company realized net income of $4.5 million for the
nine months ended March 31, 2010 compared to net income of
$22.4 million for the nine months ended March 31,
2009. The decrease of $17.9 million was primarily
attributable to the net effect of a $38.8 million decrease
in revenue, a $33.2 million decrease in costs and expenses,
a $0.4 decrease in interest expense, a $26.5 million
decrease in interest and other income and a $13.8 million
decrease in income tax expense.
Production, aggregation and pipeline volumes, revenue and
average sales prices for the nine months ended March 31 and
their related variances are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
|
|
March 31
|
|
|
Variance
|
|
|
|
2010
|
|
|
2009
|
|
|
Amount
|
|
|
Percent
|
|
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MMcf)
|
|
|
7,991
|
|
|
|
7,033
|
|
|
|
958
|
|
|
|
13.6
|
%
|
Average sales price received ($/Mcf)
|
|
$
|
4.37
|
|
|
$
|
7.82
|
|
|
$
|
(3.45
|
)
|
|
|
(44.1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
34,915
|
|
|
$
|
54,973
|
|
|
$
|
(20,058
|
)
|
|
|
(36.5
|
)%
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MBbl)
|
|
|
35
|
|
|
|
36
|
|
|
|
(1
|
)
|
|
|
(2.8
|
)%
|
Average sales price received ($/Bbl)
|
|
$
|
65.17
|
|
|
$
|
67.50
|
|
|
$
|
(2.33
|
)
|
|
|
(3.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
2,281
|
|
|
$
|
2,430
|
|
|
$
|
(149
|
)
|
|
|
(6.1
|
)%
|
Hedging
|
|
|
29,814
|
|
|
|
11,172
|
|
|
|
18,642
|
|
|
|
166.9
|
%
|
Other
|
|
|
174
|
|
|
|
200
|
|
|
|
(26
|
)
|
|
|
(13.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales (in thousands)
|
|
$
|
67,184
|
|
|
$
|
68,775
|
|
|
$
|
(1,591
|
)
|
|
|
(2.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregation revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
10,408
|
|
|
|
9,889
|
|
|
|
519
|
|
|
|
5.2
|
%
|
Average sales price received ($/MMBtu)
|
|
$
|
4.85
|
|
|
$
|
7.95
|
|
|
$
|
(3.10
|
)
|
|
|
(39.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
50,435
|
|
|
$
|
78,665
|
|
|
$
|
(28,230
|
)
|
|
|
(35.9
|
)%
|
Pipeline revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
10,196
|
|
|
|
9,083
|
|
|
|
1,113
|
|
|
|
12.3
|
%
|
Average sales price received ($/MMBtu)
|
|
$
|
1.20
|
|
|
$
|
2.34
|
|
|
$
|
(1.14
|
)
|
|
|
(48.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
12,247
|
|
|
$
|
21,261
|
|
|
$
|
(9,014
|
)
|
|
|
(42.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
62,682
|
|
|
$
|
99,926
|
|
|
$
|
(37,244
|
)
|
|
|
(37.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
|
|
March 31
|
|
|
Variance
|
|
|
|
2010
|
|
|
2009
|
|
|
Amount
|
|
|
Percent
|
|
|
Aggregation gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
10,408
|
|
|
|
9,889
|
|
|
|
519
|
|
|
|
5.2
|
%
|
Average price paid ($/MMBtu)
|
|
$
|
4.59
|
|
|
$
|
7.65
|
|
|
$
|
(3.06
|
)
|
|
|
(40.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
47,744
|
|
|
$
|
75,612
|
|
|
$
|
(27,868
|
)
|
|
|
(36.9
|
)%
|
Pipeline gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
1,841
|
|
|
|
2,193
|
|
|
|
(352
|
)
|
|
|
(16.1
|
)%
|
Average price paid ($/MMBtu)
|
|
$
|
3.46
|
|
|
$
|
6.44
|
|
|
$
|
(2.98
|
)
|
|
|
(46.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
6,364
|
|
|
$
|
14,133
|
|
|
$
|
(7,769
|
)
|
|
|
(55.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
54,108
|
|
|
$
|
89,745
|
|
|
$
|
(35,637
|
)
|
|
|
(39.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES. Total revenues decreased
$38.8 million or 22.3% between the periods. The decrease
was due to a 2.3% decrease in oil and natural gas sales, a 37.3%
decrease in natural gas aggregation and pipeline sales, while
well operations and service revenues remained relatively
constant.
Revenues from oil and natural gas sales decreased
$1.6 million from $68.8 million for the nine months
ended March 31, 2009 to $67.2 million for the nine
months ended March 31, 2010. Natural gas sales decreased
$20.1 million and oil sales decreased $0.1 million.
The decrease in natural gas sales is a result of a decrease in
the average sales price received and was partially offset by an
increase in production. The price decline corresponds with the
change in related indexes. The increase in production is
primarily the result of new wells drilled and the reduction of
shut-in volumes compared to the prior period. The decrease in
production revenue was largely offset by an increase in
recognized gains on related derivative instrument hedging
transactions on natural gas and oil production which totaled
$29.8 million for the nine months ended March 31, 2010
as compared to a gain of $11.2 million for the nine months
ended March 31, 2009. The average price per Mcfe, after
hedging, was $8.10 and $9.46 for the nine months ended
March 31, 2010 and 2009 respectively.
Revenues from natural gas aggregation and pipeline sales
decreased $37.2 million from $99.9 million during the
period ended March 31, 2009 to $62.7 million for the
period ended March 31, 2010. Gas aggregation revenue
decreased $28.2 million while pipeline revenue, which has a
sales and a transportation component, decreased
$9.0 million. The decrease in natural gas aggregation and
pipeline sales is attributable to the decline in average sales
price received and was partially offset by an increase volumes.
The price decrease corresponds with the decline in the related
index price of natural gas.
COSTS AND EXPENSES. The Companys costs
and expenses decreased $33.2 million or 22.6% between the
periods. The net decrease was due to a 4.7% decrease in field
and lease operating expenses, a 39.7% decrease in natural gas
aggregation and pipeline costs, a 6.1% decrease in general and
administrative expenses, an 68.6% decrease in taxes other than
income, a 45.7% increase in oil and natural gas related
depletion, a 3.9% increase in depreciation and amortization
expenses of pipelines, property and equipment, a 5.9% increase
in exploration and impairment costs, and an increase in the gain
on sale of property of 29.0%.
Field and lease operating expenses decreased $0.7 million.
The decrease is primarily related to a decline in workover costs
and the elimination of certain compressors and equipment related
to the dismantling of an amine plant previously operated by the
Company.
ECA-18
Gas aggregation and pipeline costs decreased $35.6 million.
Gas aggregation cost decreased $27.9 million while pipeline
cost decreased by $7.8 million. The decrease in natural gas
aggregation cost is attributable to the decline in average
purchase price partially offset by an increase in volumes
aggregated during the period. The decrease in pipeline costs is
a result of a decrease in price and volumes. The decline in
price corresponds with the decrease in related indexes.
General and administrative expenses decreased $0.9 million
primarily as a result of a decrease in employee related
benefits, vehicle fuel and other costs, and a reduction in legal
fees.
Taxes other than income decreased $2.8 million primarily as
a result of decreased wellhead oil and natural gas sales and
certain wells being classified as exempt from severance taxes.
Depletion, depreciation and amortization of oil and natural gas
properties expense increased $8.1 million due to an
increase in production and depletion rates recognized by the
Company.
Exploration and impairment costs increased $0.6 million.
The increase is a result of higher expenses primarily related to
lease expirations which was partially offset by a decrease in
dry hole cost and geological and geophysical cost.
Gain on sale of property increased $2.1 million primarily
as a result of the sale of a working interest in certain New
Zealand properties. This increase was partially offset by a
decrease in incentive distributions related to a certain term
royalty conveyance.
INTEREST EXPENSE. Interest expense decreased
$0.4 million due to lower interest rates, offset partially
by an increase in outstanding borrowings.
INTEREST INCOME AND OTHER. Other
non-operating income decreased by $26.5 million primarily
as a result of derivative
mark-to-market
adjustments and settlement gains.
INCOME TAX. Income tax expense decreased
$13.8 million primarily as a result of the decrease in
income before tax.
Liquidity
and Capital Resources
Stockholders equity has decreased from $100.9 million
at June 30, 2009 to $91.3 million at March 31,
2010. The Companys cash decreased from $2.0 million
at June 30, 2009 to $1.4 million at March 31,
2010. The change in cash during the nine months of approximately
$0.6 million resulted from various operating, investing and
financing activities of the Company. The activities were
primarily comprised of the net borrowing of $31.8 million
under the Companys revolving credit facility; the
investment of approximately $46.9 million; proceeds from
the sale of assets of approximately $4.9 million; payments
of approximately $7.6 million for the payment of dividends;
and approximately $17.2 million of cash provided by
operations during the nine months.
The Company entered into a First Amendment to Second Amended and
Restated Credit Agreement effective August 4, 2008 (the
Credit Agreement), with Wells Fargo Foothill, Inc.
(Foothill), Bank of America, N.A. and U.S. Bank
National Association (U.S. Bank). The credit
facility provides for a Maximum Loan Amount of
$250 million, consisting of a revolving facility of
$150 million and a single advance term loan of
$100 million, which is an increase of $50 million on
the revolving facility from June 30, 2008. The term loan
contains requirements for principal payments of $1 million
each at July 10, 2009, 2010, and 2011 and the Maturity Date
of the Credit
ECA-19
Agreement is July 10, 2012. At March 31, 2010, the
Company classified $1 million of the term loan that is due
on July 10, 2010 as long-term debt as a result of having a
Credit Agreement in place that allowed the Company to refinance
the debt on a long-term basis. Depending on the Companys
level of borrowing under the Credit Agreement, the applicable
interest rates for base rates are based on Wells Fargos
prime rate plus 0.75% to 1.25%. The Company also has the ability
under the Credit Agreement to designate certain loans as LIBOR
Rate Loans at interest rates based upon the rate at which dollar
deposits are offered to major banks in the London interbank
market plus 2.50% to 3.00%.
The obligations under the Credit Agreement are secured by
certain of the existing proved producing oil and natural gas
assets of the Company. The Credit Agreement, among other things,
restricts the ability of the Company and its subsidiaries to
incur new debt, grant additional security interests in its
collateral, engage in certain merger or reorganization
activities, or dispose of certain assets.
As disclosed in Use of Proceeds, ECA will use a
portion of the proceeds it receives as a result of the offering
to repay approximately $24 million of its outstanding term loan
and approximately $130 million of its outstanding borrowings
under its Credit Facility. In order to reduce both commitment
fees and principal and interest payments, the Company, has
entered into a second Amendment to the Credit Agreement (the
Second Amendment). Effective upon the closing of
this offering and the application of the proceeds from this
offering as described in Use of proceeds, the Second
Amendment will reduce the total available capacity under to the
revolving facility to $125 million and the term loan will be
permanently reduced to $75 million. The Company believes that
upon completion of this offering it no longer requires as large
a credit facility. The Company also does not believe these
reductions in total borrowing capacity will negatively impact
its ability to fund its ongoing working capital and capital
expenditure needs, including fulfilling its drilling obligations
to the Trust.
The Company has an unsecured revolving line of credit totaling
$2.0 million with a financial institution with a variable
interest rate equal to 3.50% in excess of the LIBOR
Rate the interest rate fixed by the British Bankers
Association at 11:00 a.m., London time, relating to
quotations for the one month London InterBank Offered Rates on
U.S. Dollar deposits as published on Bloomberg LP (or any
successor). As of March 31, 2010, there was a
$1.0 million outstanding balance on this line of credit.
At March 31, 2010, the Companys principal source of
liquidity consisted of $1.0 million available under an
unsecured credit facility currently in place, plus
$18.5 million available under the revolving loan of the
Credit Agreement. At June 7, 2010, no amounts were
outstanding or committed through letters of credit under the
credit facility, $130.3 million was outstanding on the
revolving loan, $99.0 million was outstanding on the term
loan under the Credit Agreement and $1.0 million in
outstanding borrowings under the unsecured revolving line of
credit. Additional borrowings must comply with the terms of the
Credit Agreement.
Management utilizes earnings before interest, taxes,
depreciation, depletion, amortization and exploration and
impairment cost (EBITDAX) to evaluate the operation
of each business segment.
ECA-20
Reconciliation of the non-GAAP financial measure is as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
|
|
Ended
|
|
|
|
Year Ended June 30,
|
|
|
March 31,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
|
$
|
22,362
|
|
|
$
|
4,482
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
8,245
|
|
|
|
10,688
|
|
|
|
9,986
|
|
|
|
7,661
|
|
|
|
7,268
|
|
Depletion and depreciation of oil and gas properties
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
|
|
17,716
|
|
|
|
25,805
|
|
Depreciation of property, plant and equipment
|
|
|
4,961
|
|
|
|
5,852
|
|
|
|
6,119
|
|
|
|
4,572
|
|
|
|
4,748
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
|
|
10,132
|
|
|
|
10,730
|
|
Income tax expense
|
|
|
4,815
|
|
|
|
7,855
|
|
|
|
17,355
|
|
|
|
17,684
|
|
|
|
3,863
|
|
Unrealized (gain) loss on financial instruments
|
|
|
923
|
|
|
|
16,887
|
|
|
|
(18,166
|
)
|
|
|
(24,234
|
)
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
|
|
$
|
64,597
|
|
|
$
|
76,737
|
|
|
$
|
78,946
|
|
|
$
|
55,893
|
|
|
$
|
56,899
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys net cash requirements will fluctuate based on
timing and the extent of the interplay of capital expenditures,
cash generated by operations, cash generated by the sale of
assets and interest expense. Management believes that cash
generated from oil and natural gas operations, together with the
liquidity provided by existing cash balances, permitted
borrowings and the approximate $156.8 million of proceeds
it will receive from this offering (net of $4.2 million
used to purchase common units from the Private Investors as
outlined in Certain Transactions), will be
sufficient to satisfy expected capital expenditures, debt
service obligations, working capital needs and other cash
requirements for the next twelve months, including the drilling
of PUD Wells targeted for drilling during such period. In the
event this offering is not completed or the proceeds therefrom
are reduced to the extent that management believes it would be
unable to meet its capital expenditure obligations, management
would limit its capital expenditure obligations to those which
the Company could fund solely with existing cash balances and
permitted borrowings for the next twelve months.
The Company believes that its existing capital resources and its
expected results of operations and cash flows from operating
activities will be sufficient for the Company to remain in
compliance with the requirements of its Credit Agreement.
The Credit Agreement requires the Company to maintain certain
financial covenants. The Company is required to maintain a
minimum EBITDAX (as defined in the Credit Agreement) of
$55.0 million at the close of each fiscal quarter.
Compliance with the EBITDAX covenant is tested quarterly on a
rolling four quarter basis. The Company also is required to
maintain a Net Book Worth (as defined in the Credit Agreement)
of at least $37.0 million at the close of each fiscal
quarter (excluding all unrealized losses over all unrealized
profits arising under hedging agreements). Compliance with the
Book Net Worth covenant is tested quarterly.
For the four quarters ended March 31, 2010, EBITDAX was
$73.6 million. At March 31, 2010 Book Net Worth was
$92.4 million. However, since future results of operations,
cash flow from operating activities, debt service capability,
levels and availability of capital resources and continuing
liquidity are dependent on future weather patterns, oil and
natural gas prices and production volume levels, future
exploration and development drilling success and successful
acquisition transactions, no assurance can be given that the
Company will remain in compliance with the requirements of its
Credit Agreement.
ECA-21
Quantitative
and Qualitative Disclosures about Market Risk
Commodity
Risk
The Companys operations consist primarily of exploring
for, producing, gathering, aggregating and selling natural gas
and oil. Contracts to deliver natural gas at pre-established
prices mitigate the risk to the Company of falling prices but at
the same time limit the Companys ability to benefit from
the effects of rising prices. The Company strategically uses
derivative instruments to hedge commodity price risk. The
Company hedges a portion of its projected natural gas production
through a variety of financial and physical arrangements
intended to support natural gas prices at targeted levels and to
manage its exposure to price fluctuations. The Company may use
futures contracts, swaps, options and fixed price physical
contracts to hedge commodity prices. Realized gains and losses
from the Companys price risk management activities are
recognized in oil and natural gas sales when the associated
production occurs. Unrecognized gains and losses are included as
a component of other comprehensive income. Ineffectiveness is
recorded in current earnings. The Company does not hold or issue
derivative instruments for trading purposes. The Company
currently has elected to enter into derivative hedge
transactions that covers approximately 30% of its estimated
production through June 30, 2014.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Total Volumes
|
|
|
Contract/Strike
|
|
|
Unrealized
|
|
|
|
Market Index
|
|
|
(MMBtu)
|
|
|
Price
|
|
|
(Gain) Loss
|
|
|
Time period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2010 June 2010
|
|
|
NYMEX
|
|
|
|
682,500
|
|
|
$
|
8.83
|
|
|
$
|
(3,327,551
|
)
|
April 2010 June 2010 (1)
|
|
|
NYMEX
|
|
|
|
728,000
|
|
|
|
9.20
|
|
|
|
(3,835,020
|
)
|
April 2010 June 2010 (1)
|
|
|
NYMEX
|
|
|
|
227,500
|
|
|
|
10.00
|
|
|
|
(1,379,050
|
)
|
July 2010 June 2011 (2)
|
|
|
NYMEX
|
|
|
|
547,500
|
|
|
|
6.59
|
|
|
|
(912,553
|
)
|
July 2010 June 2012 (2)
|
|
|
NYMEX
|
|
|
|
2,193,000
|
|
|
|
6.54
|
|
|
|
(2,673,801
|
)
|
July 2010 June 2012 (2)
|
|
|
NYMEX
|
|
|
|
2,193,000
|
|
|
|
7.03
|
|
|
|
(3,654,372
|
)
|
July 2011 June 2012 (2)
|
|
|
NYMEX
|
|
|
|
549,000
|
|
|
|
6.94
|
|
|
|
(643,324
|
)
|
Natural Gas Floors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 2010 March 2014 (2)
|
|
|
NYMEX
|
|
|
|
11,268,000
|
|
|
|
5.00
|
|
|
|
1,155,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Hedged Production
|
|
|
|
|
|
|
18,388,500
|
|
|
|
|
|
|
$
|
(15,270,493
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Natural gas swaps attributable to
approximately 682,500 MMBtu of gas will be conveyed to the
trust at the closing of this offering at an average contract
price of $6.75 per MMBtu.
|
|
(2)
|
|
All such natural gas swaps and
floors will be conveyed to the trust at the closing of this
offering.
|
Notwithstanding the above, the Companys future cash flows
from natural gas and oil production are exposed to significant
volatility as commodity prices change. Assuming total oil and
natural gas production, pricing, and the percentage of natural
gas production hedged under physical delivery contracts and
derivative instruments remain at March 2010 levels, a 10%
change in the average unhedged prices realized would change the
Companys natural gas and oil revenues by approximately
$0.3 million on a quarterly basis.
ECA-22
Interest
Rate Risk
Interest rate risk is attributable to the Companys debt.
The Company utilizes United States dollar denominated borrowings
to fund working capital and investment needs. There is inherent
rollover risk for borrowings as they mature and are renewed at
current market rates. The extent of this risk is not predictable
because of the variability of future interest rates and the
Companys future financing needs. During November 2007 and
January 2008, the Company entered into three interest rate swap
agreements with Foothill, in an effort to reduce the potential
impact of increases in interest rates on floating-rate long-term
debt. The three-year agreements cover $100 million in
long-term debt and fix the one-month London Interbank Offered
Rate (LIBOR) over a range of 3.67%
4.05%. The Company has partially hedged its exposure to the
variability in future cash flows through January 2011. Assuming
the variable interest debt remain at the March 31, 2010
level, a 10% change in rates would have a $0.04 million
impact on interest expense on an annual basis.
Foreign
Currency Exchange Risk
Some of the Companys transactions are denominated in New
Zealand dollars. For foreign operations with the local currency
as the functional currency, assets and liabilities are
translated at the period end exchange rates, and statements of
income are translated at the average exchange rates during the
period. Gains and losses resulting from foreign currency
translation are included as a component of other comprehensive
income.
LEGAL
PROCEEDINGS
The Company is involved in legal actions and claims arising in
the ordinary course of business. While the outcome of these
lawsuits against the Company cannot be predicted with certainty,
management does not expect these matters to have a material
adverse effect on the Companys operations or financial
position.
ECA-23
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
INDEX TO
FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Pages
|
HISTORICAL CONSOLIDATED FINANCIAL STATEMENTS OF ENERGY
CORPORATION OF AMERICA
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
ECA-25
|
|
Consolidated Balance Sheets as of June 30, 2008 and 2009
|
|
|
ECA-26
|
|
Consolidated Statements of Operations for the Years Ended
June 30, 2007, 2008 and 2009
|
|
|
ECA-28
|
|
Consolidated Statements of Stockholders Equity for the
Years Ended June 30, 2007, 2008 and 2009
|
|
|
ECA-29
|
|
Consolidated Statements of Cash Flows for the Years Ended
June 30, 2007, 2008 and 2009
|
|
|
ECA-30
|
|
Consolidated Statements of Comprehensive Income (Loss) for the
Years Ended June 30, 2007, 2008 and 2009
|
|
|
ECA-31
|
|
Notes to Consolidated Financial Statements
|
|
|
ECA-32
|
|
UNAUDITED INTERIM FINANCIAL STATEMENTS OF ENERGY CORPORATION OF
AMERICA
|
|
|
|
|
Consolidated Balance Sheets as of June 30, 2009 and
March 31, 2010 (unaudited)
|
|
|
ECA-55
|
|
Unaudited Consolidated Statements of Operations for the Nine
Months Ended March 31, 2009 and 2010
|
|
|
ECA-57
|
|
Unaudited Consolidated Statements of Cash Flows for the Nine
Months Ended March 31, 2009 and 2010
|
|
|
ECA-58
|
|
Unaudited Consolidated Statements of Comprehensive Income (Loss)
for the Nine Months Ended March 31, 2009 and 2010
|
|
|
ECA-59
|
|
Notes to Unaudited Consolidated Financial Statements for the
Periods Ended March 31, 2009 and 2010
|
|
|
ECA-60
|
|
ECA-24
Report of
Independent Registered Public Accounting Firm
The Board of
Directors and Stockholders
Energy Corporation of America:
We have audited the accompanying consolidated balance sheets of
Energy Corporation of America and subsidiaries (the Company) as
of June 30, 2009 and 2008, and the related consolidated
statements of operations, stockholders equity, cash flows,
and comprehensive income (loss) for each of the three years in
the period ended June 30, 2009. These financial statements
are the responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards of
the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial
statements are free of material misstatement. We were not
engaged to perform an audit of the Companys internal
control over financial reporting. Our audits included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the
overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Energy Corporation of America and
subsidiaries at June 30, 2009 and 2008, and the
consolidated results of their operations and cash flows for each
of the three years in the period ended June 30, 2009 in
conformity with U.S. generally accepted accounting
principles.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
March 12, 2010
ECA-25
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Financial Statements for the Years Ended June 30, 2009,
2008 and 2007
CONSOLIDATED
BALANCE SHEETS
AS OF JUNE 30
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands)
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6,988
|
|
|
$
|
1,979
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
13,488
|
|
|
|
3,110
|
|
Gas aggregation and pipeline
|
|
|
27,054
|
|
|
|
8,040
|
|
Other
|
|
|
13,319
|
|
|
|
5,140
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
53,861
|
|
|
|
16,290
|
|
Less allowances for doubtful accounts
|
|
|
(833
|
)
|
|
|
(737
|
)
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net of allowances
|
|
|
53,028
|
|
|
|
15,553
|
|
Inventory
|
|
|
1,883
|
|
|
|
4,752
|
|
Income taxes receivable
|
|
|
1,973
|
|
|
|
1,884
|
|
Deferred income tax asset
|
|
|
2,440
|
|
|
|
1,359
|
|
Deferred taxes other comprehensive loss
|
|
|
25,307
|
|
|
|
|
|
Notes receivable, related party
|
|
|
172
|
|
|
|
70
|
|
Derivatives
|
|
|
593
|
|
|
|
30,640
|
|
Prepaid and other current assets
|
|
|
1,041
|
|
|
|
574
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
93,425
|
|
|
|
56,811
|
|
NET PROPERTY, PLANT AND EQUIPMENT (Note 2)
|
|
|
451,742
|
|
|
|
479,722
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Deferred financing costs, less accumulated amortization of
$2,111 and $2,583
|
|
|
1,033
|
|
|
|
1,057
|
|
Deferred taxes other comprehensive loss
|
|
|
5,994
|
|
|
|
237
|
|
Notes receivable, related party
|
|
|
350
|
|
|
|
262
|
|
Derivatives
|
|
|
154
|
|
|
|
651
|
|
Other
|
|
|
5,282
|
|
|
|
4,979
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
12,813
|
|
|
|
7,186
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
557,980
|
|
|
$
|
543,719
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-26
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Balance Sheets
AS OF
JUNE 30
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands, except share amounts)
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
46,982
|
|
|
$
|
32,417
|
|
Current portion of long-term debt
|
|
|
198
|
|
|
|
212
|
|
Current portion of non-recourse debt
|
|
|
442
|
|
|
|
470
|
|
Funds held for future distribution
|
|
|
36,293
|
|
|
|
13,620
|
|
Accrued taxes, other than income
|
|
|
13,042
|
|
|
|
10,838
|
|
Deferred taxes other comprehensive income
|
|
|
|
|
|
|
11,052
|
|
Deferred revenue
|
|
|
304
|
|
|
|
262
|
|
Deferred gain
|
|
|
7,483
|
|
|
|
6,992
|
|
Derivatives
|
|
|
66,037
|
|
|
|
3,331
|
|
Other current liabilities
|
|
|
823
|
|
|
|
1,614
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
171,604
|
|
|
|
80,808
|
|
LONG-TERM OBLIGATIONS:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
180,347
|
|
|
|
201,826
|
|
Non-recourse debt
|
|
|
16,778
|
|
|
|
16,308
|
|
Deferred revenue
|
|
|
919
|
|
|
|
655
|
|
Deferred gain
|
|
|
75,122
|
|
|
|
68,277
|
|
Deferred income tax liability
|
|
|
37,210
|
|
|
|
53,609
|
|
Derivatives
|
|
|
30,145
|
|
|
|
1,237
|
|
Other long-term obligations
|
|
|
21,189
|
|
|
|
20,064
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
533,314
|
|
|
|
442,784
|
|
COMMITMENTS AND CONTINGENCIES (Note 11)
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY:
|
|
|
|
|
|
|
|
|
Common stock, par value $1.00; 2,000 shares authorized;
730,039 shares issued and 520,712 outstanding
|
|
|
730
|
|
|
|
730
|
|
Class A non-voting common stock, no par value;
100,000 shares authorized; 91,982 and 91,224 shares
issued and 64,276 and 65,895 shares outstanding
|
|
|
9,452
|
|
|
|
9,787
|
|
Additional paid-in capital
|
|
|
5,503
|
|
|
|
5,503
|
|
Retained earnings
|
|
|
82,043
|
|
|
|
96,414
|
|
Treasury stock
|
|
|
(26,140
|
)
|
|
|
(25,892
|
)
|
Accumulated other comprehensive (loss) income
|
|
|
(46,030
|
)
|
|
|
15,645
|
|
Notes receivable from the issuance of Class A stock
|
|
|
(892
|
)
|
|
|
(1,252
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
24,666
|
|
|
|
100,935
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
557,980
|
|
|
$
|
543,719
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-27
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Statements of Operations
FOR THE
YEARS ENDED JUNE 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands,
|
|
|
|
except per share data)
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
84,429
|
|
|
$
|
96,514
|
|
|
$
|
92,262
|
|
Gas aggregation and pipeline sales
|
|
|
120,549
|
|
|
|
142,825
|
|
|
|
116,730
|
|
Well operation and service revenues
|
|
|
6,976
|
|
|
|
7,732
|
|
|
|
7,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
211,954
|
|
|
|
247,071
|
|
|
|
216,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating expenses
|
|
|
17,700
|
|
|
|
18,234
|
|
|
|
18,772
|
|
Gas aggregation and pipeline cost of sales
|
|
|
110,226
|
|
|
|
131,051
|
|
|
|
104,685
|
|
General and administrative
|
|
|
17,742
|
|
|
|
17,933
|
|
|
|
18,858
|
|
Taxes, other than income
|
|
|
4,519
|
|
|
|
5,406
|
|
|
|
4,629
|
|
Depletion and depreciation of oil and gas properties
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
Depreciation of pipelines, other property and equipment
|
|
|
4,961
|
|
|
|
5,852
|
|
|
|
6,119
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
Gain on sale of assets
|
|
|
(10,454
|
)
|
|
|
(7,287
|
)
|
|
|
(9,114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171,296
|
|
|
|
195,159
|
|
|
|
185,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
40,658
|
|
|
|
51,912
|
|
|
|
30,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER (INCOME) AND EXPENSE:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
8,245
|
|
|
|
10,688
|
|
|
|
9,986
|
|
Other
|
|
|
8,547
|
|
|
|
21,884
|
|
|
|
(18,722
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,792
|
|
|
|
32,572
|
|
|
|
(8,736
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
23,866
|
|
|
|
19,340
|
|
|
|
39,086
|
|
Income tax expense
|
|
|
4,815
|
|
|
|
7,855
|
|
|
|
17,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share, basic and diluted
|
|
$
|
33.66
|
|
|
$
|
19.93
|
|
|
$
|
36.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-28
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Statements of Stockholders Equity
FOR THE
YEARS ENDED JUNE 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
|
|
|
|
|
|
|
|
|
|
Class A
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Received /
|
|
|
Accum. Other
|
|
|
Total
|
|
|
|
Common
|
|
|
Common
|
|
|
Paid-In
|
|
|
Retained
|
|
|
Treasury
|
|
|
Issuance of
|
|
|
Comprehensive
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Stock
|
|
|
Capital
|
|
|
Earnings
|
|
|
Stock
|
|
|
Stock
|
|
|
Income (Loss)
|
|
|
Equity
|
|
|
|
(Amounts in thousands)
|
|
|
Balance, June 30, 2006
|
|
$
|
730
|
|
|
$
|
8,081
|
|
|
$
|
5,503
|
|
|
$
|
65,105
|
|
|
$
|
(28,274
|
)
|
|
$
|
|
|
|
$
|
1,339
|
|
|
$
|
52,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,051
|
|
Foreign currency translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(124
|
)
|
|
|
(124
|
)
|
Unrealized gain on derivatives (net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains arising during period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,256
|
|
|
|
12,256
|
|
Reclassification adjustment for losses included in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,201
|
)
|
|
|
(9,201
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,347
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,347
|
)
|
Issuance of stock Class A
|
|
|
|
|
|
|
429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
429
|
|
Issuance of stock Common
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
980
|
|
|
|
|
|
|
|
|
|
|
|
980
|
|
Restricted stock amortization
|
|
|
|
|
|
|
463
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
463
|
|
Purchase of stock Class A
|
|
|
|
|
|
|
(52
|
)
|
|
|
|
|
|
|
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2007
|
|
$
|
730
|
|
|
$
|
8,921
|
|
|
$
|
5,503
|
|
|
$
|
77,809
|
|
|
$
|
(27,342
|
)
|
|
$
|
|
|
|
$
|
4,270
|
|
|
|
69,891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,485
|
|
Foreign currency translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(146
|
)
|
|
|
(146
|
)
|
Unrealized loss on derivatives (net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized losses arising during period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(48,906
|
)
|
|
|
(48,906
|
)
|
Reclassification adjustment for losses included in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,248
|
)
|
|
|
(1,248
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38,815
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,233
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,233
|
)
|
Issuance of stock Class A
|
|
|
|
|
|
|
89
|
|
|
|
|
|
|
|
(19
|
)
|
|
|
1,594
|
|
|
|
|
|
|
|
|
|
|
|
1,664
|
|
Restricted stock amortization
|
|
|
|
|
|
|
475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
475
|
|
Purchase of stock Class A
|
|
|
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
(392
|
)
|
|
|
|
|
|
|
|
|
|
|
(425
|
)
|
Issuance of notes receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(892
|
)
|
|
|
|
|
|
|
(892
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2008
|
|
$
|
730
|
|
|
$
|
9,452
|
|
|
$
|
5,503
|
|
|
$
|
82,043
|
|
|
$
|
(26,140
|
)
|
|
$
|
(892
|
)
|
|
$
|
(46,030
|
)
|
|
$
|
24,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,731
|
|
Foreign currency translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(200
|
)
|
|
|
(200
|
)
|
Unrealized gains on derivatives (net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains arising during period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75,510
|
|
|
|
75,510
|
|
Reclassification adjustment for losses included in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,635
|
)
|
|
|
(13,635
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,360
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,360
|
)
|
Issuance of stock Class A
|
|
|
|
|
|
|
67
|
|
|
|
|
|
|
|
|
|
|
|
906
|
|
|
|
|
|
|
|
|
|
|
|
973
|
|
Restricted stock amortization
|
|
|
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
301
|
|
Purchase of stock Class A
|
|
|
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
(658
|
)
|
|
|
59
|
|
|
|
|
|
|
|
(632
|
)
|
Issuance of notes receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(452
|
)
|
|
|
|
|
|
|
(452
|
)
|
Notes receivable principal payments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
|
|
|
|
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2009
|
|
$
|
730
|
|
|
$
|
9,787
|
|
|
$
|
5,503
|
|
|
$
|
96,414
|
|
|
$
|
(25,892
|
)
|
|
$
|
(1,252
|
)
|
|
$
|
15,645
|
|
|
$
|
100,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-29
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Statements of Cash Flows
FOR THE
YEARS ENDED JUNE 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
23,076
|
|
|
|
26,789
|
|
|
|
29,564
|
|
Gain on sale of assets
|
|
|
(10,454
|
)
|
|
|
(10,981
|
)
|
|
|
(9,114
|
)
|
Deferred income taxes
|
|
|
4,638
|
|
|
|
7,844
|
|
|
|
17,480
|
|
Exploration and impairment
|
|
|
8,047
|
|
|
|
2,896
|
|
|
|
17,863
|
|
Derivatives
|
|
|
922
|
|
|
|
16,888
|
|
|
|
(18,166
|
)
|
Other, net
|
|
|
(722
|
)
|
|
|
35
|
|
|
|
(570
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,558
|
|
|
|
54,956
|
|
|
|
58,788
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(4,145
|
)
|
|
|
(26,153
|
)
|
|
|
37,477
|
|
Inventory
|
|
|
(227
|
)
|
|
|
(332
|
)
|
|
|
(2,869
|
)
|
Income taxes receivable
|
|
|
176
|
|
|
|
150
|
|
|
|
89
|
|
Income taxes payable
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
Prepaid and other assets
|
|
|
101
|
|
|
|
(521
|
)
|
|
|
465
|
|
Accounts payable and accrued expenses
|
|
|
10,613
|
|
|
|
10,390
|
|
|
|
(14,571
|
)
|
Funds held for future distributions
|
|
|
3,082
|
|
|
|
10,983
|
|
|
|
(22,673
|
)
|
Other
|
|
|
480
|
|
|
|
928
|
|
|
|
(2,764
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
54,538
|
|
|
|
50,401
|
|
|
|
53,942
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures for property, plant and equipment
|
|
|
(93,620
|
)
|
|
|
(100,810
|
)
|
|
|
(73,688
|
)
|
Proceeds from sale of assets, net of costs
|
|
|
10,173
|
|
|
|
5,489
|
|
|
|
1,788
|
|
Notes receivable and other
|
|
|
(12,198
|
)
|
|
|
(8,305
|
)
|
|
|
128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities from operations
|
|
|
(95,645
|
)
|
|
|
(103,626
|
)
|
|
|
(71,772
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
113,490
|
|
|
|
160,396
|
|
|
|
99,201
|
|
Principal payment on long-term debt
|
|
|
(66,478
|
)
|
|
|
(97,919
|
)
|
|
|
(78,150
|
)
|
Purchase of treasury stock and other financing activities
|
|
|
202
|
|
|
|
(337
|
)
|
|
|
(876
|
)
|
Dividends paid
|
|
|
(5,917
|
)
|
|
|
(7,208
|
)
|
|
|
(7,354
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities from operations
|
|
|
41,297
|
|
|
|
54,932
|
|
|
|
12,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
190
|
|
|
|
1,707
|
|
|
|
(5,009
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
5,091
|
|
|
|
5,281
|
|
|
|
6,988
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
5,281
|
|
|
$
|
6,988
|
|
|
$
|
1,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-30
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Statements of Comprehensive Income (Loss)
FOR THE
YEARS ENDED JUNE 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands)
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current period change
|
|
|
(124
|
)
|
|
|
(146
|
)
|
|
|
(200
|
)
|
Oil and gas derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current period transactions
|
|
|
12,127
|
|
|
|
(48,242
|
)
|
|
|
78,978
|
|
Reclassification to earnings
|
|
|
(8,960
|
)
|
|
|
(1,424
|
)
|
|
|
(15,034
|
)
|
Interest rate hedging:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current period transactions
|
|
|
129
|
|
|
|
(664
|
)
|
|
|
(3,468
|
)
|
Reclassification to earnings
|
|
|
(241
|
)
|
|
|
176
|
|
|
|
1,399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax
|
|
|
2,931
|
|
|
|
(50,300
|
)
|
|
|
61,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
21,982
|
|
|
$
|
(38,815
|
)
|
|
$
|
83,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-31
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and 2007
|
|
1.
|
NATURE OF
ORGANIZATION
|
Energy Corporation of America (the Company) was
formed in June 1993 through an exchange of shares with the
common stockholders of Eastern American Energy Corporation
(Eastern American), successor to Pacific States
Gas & Oil, Inc. which was incorporated on
September 9, 1964. The Company is an independent energy
company. All references to the Company include Energy
Corporation of America and its consolidated subsidiaries.
|
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
The following is a summary of the significant accounting
policies followed by the Company.
Principles of Consolidation The
consolidated financial statements include the accounts of the
Company and its subsidiaries. The Company has investments in oil
and natural gas limited partnerships and joint ventures and has
recognized its proportionate share of these entities
revenues, expenses, assets and liabilities. All significant
intercompany transactions have been eliminated in consolidation.
Cash and Cash Equivalents Cash and
cash equivalents include short-term investments maturing in
three months or less from the date acquired.
Inventory The Companys inventory
balance consists of natural gas stored underground and materials
and supplies recorded at the lower of cost or market. At
June 30, 2009, $0.4 million of the inventory balance
relates to natural gas inventory, $3.6 million to
production casing and $0.8 million to other materials and
supplies. At June 30, 2008, $0.3 million of the
inventory balance relates to natural gas inventory,
$0.6 million to production casing and $0.9 million to
other materials and supplies.
Property, Plant and Equipment Oil and
natural gas properties are accounted for using the successful
efforts method of accounting. Under this method, certain
expenditures such as exploratory geological and geophysical
costs, exploratory dry hole costs, delay rentals and other costs
related to exploration are recognized currently as expenses. All
direct and certain indirect costs relating to property
acquisition, successful exploratory wells, development costs,
and support equipment and facilities are capitalized. The
Company computes depletion, depreciation and amortization of
capitalized oil and natural gas property costs on the
units-of-production
method. Direct production costs, production overhead and other
costs are charged against income as incurred. Gains and losses
on the sale of oil and natural gas property interests are
generally recognized in operating income.
Other property, equipment, pipelines and buildings are stated at
cost and are depreciated using straight-line and accelerated
methods over estimated useful lives ranging from three to forty
years.
Repair and maintenance costs are charged against income as
incurred; significant renewals and betterments are capitalized.
Gains and losses on dispositions of property, equipment,
pipelines and buildings are recognized in operating income.
ECA-32
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
At June 30 property, plant and equipment consisted of the
following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Oil and gas properties
|
|
$
|
546,029
|
|
|
$
|
585,376
|
|
Other property and equipment
|
|
|
41,341
|
|
|
|
41,894
|
|
Pipelines
|
|
|
50,853
|
|
|
|
53,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
638,223
|
|
|
|
680,946
|
|
Less accumulated depletion, depreciation and amortization
|
|
|
(186,481
|
)
|
|
|
(201,224
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
451,742
|
|
|
$
|
479,722
|
|
|
|
|
|
|
|
|
|
|
Long-Lived Assets Statement of
Financial Accounting Standards (SFAS) No. 144,
Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of, requires all companies
to assess long-lived assets and assets to be disposed of for
impairment. For the years ended June 30, 2009, 2008, and
2007, the impairments recognized by the Company primarily
consists of oil and natural gas property of $0.4 million,
$0.4 million, and $3.7 million, respectively.
Deferred Financing Costs Certain
legal, underwriting fees and other direct expenses associated
with the issuance of credit agreements, lines of credit and
other financing transactions have been capitalized. These
financing costs are being amortized over the term of the related
credit agreements.
Foreign Currency Translation The
translation of applicable foreign currencies into
U.S. dollars is performed for accounts using current
exchange rates in effect at the balance sheet date and for the
income statement as of the transaction date. The translation
adjustment is included in stockholders equity as a
component of other comprehensive income.
Income Taxes Deferred income taxes
reflect the impact of temporary differences between assets and
liabilities recognized for financial reporting purposes and such
amounts as measured by tax laws. These temporary differences are
determined in accordance with SFAS No. 109, Accounting
For Income Taxes. A valuation allowance is established for
any portion of a deferred tax asset for which it is more likely
than not that a tax benefit will not be realized.
Deferred Revenue In 1993, the Company
sold a net profits interest in certain Appalachian natural gas
properties in connection with the formation of the Eastern
American Natural Gas Trust (the Royalty Trust). A
portion of the proceeds from the sale of these interests,
representing term net profits interest, was accounted for as a
production payment and was classified as deferred trust revenue.
The deferred revenue is recognized as production occurs for the
term properties.
Deferred Gain In 2005,
the Company consummated a Term Royalty Conveyance for a term of
twenty (20) years, in certain oil and natural gas
properties located in West Virginia, Kentucky, and Pennsylvania
to Black Stone Acquisitions Partners II, L.P., Black Stone
Acquisitions Partners II-B, L.P., and Hatfield Royalty, L.P.
(collectively referred to as Black Stone). The
proceeds, net of certain costs and expenses and the carrying
value of assets sold, were classified as a deferred gain and are
being recognized as production occurs related to the Black Stone
Term Royalty
ECA-33
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Conveyance. The Company recognized $8.9 million,
$7.1 million, and $5.9 million in gain on sale of
assets for the years ended June 30, 2009, 2008 and 2007,
respectively.
Revenues and Gas Costs Oil and natural
gas sales, and aggregation and pipeline revenues are recognized
as income when the oil or natural gas is produced and sold.
Monthly, the Company makes estimates of the amount of production
delivered to the purchaser and the price to be received. The
Company uses its knowledge of properties, historical
performance, NYMEX and local spot market prices and other
factors as the basis for these estimates. Gas costs are expensed
as incurred.
Stock Compensation During June 2008,
ECA granted all full-time employees the opportunity to purchase
a specified number of Class A stock shares at the then
current share price of $140 per share. The stock issued as a
result of this program has certain vesting restrictions that
expire over a specified period of time, with the last of those
restrictions expiring October 1, 2013. As a result of this
program, the Company issued 15,060 shares of stock.
During June 2006, ECA granted all full-time employees the
opportunity to purchase Class A stock having certain
restrictions that expire January 1, 2012. Employees were
awarded the right to purchase a specified number of shares and
were required to make an election prior to August 1, 2006.
As a result of this program, the Company issued
17,126 shares of stock with a $45 per share purchase price.
During October 2003, the Company offered its employees that were
participants in the 2003 Profit Sharing program, the opportunity
to purchase Class A stock having certain restrictions.
Employees were awarded the right to purchase a specified number
of shares, with the restrictions expiring over a specified
period of time. As of January 1, 2009 all restrictions
related to this stock offering have expired. As a result of this
program, 16,850 shares of restricted stock were issued for
$15 per share vesting over five years.
Compensation expense is recognized based on the fair value of
the stock at issuance and is being amortized over the applicable
vesting periods with $0.3 million of expense recognized for
the year ended June 30, 2009 and $0.5 million of
expense for each of the years ended June 30, 2008 and 2007.
As of June 30, 2009, unrecognized compensation expense
related to awards that will vest in future fiscal years
approximated $0.3 million.
The Company measures compensation costs related to stock
issuances to Company directors at fair value. Accordingly, stock
compensation of $0.3 million, $0.2 million, and
$0.1 million was recognized for the years ended
June 30, 2009, 2008, and 2007 respectively.
Use of Estimates The preparation of
financial statements in conformity with U.S. generally
accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
The Companys financial statements are based on a number of
significant estimates including oil and natural gas reserve
quantities, which are the basis for the calculation of
depletion, depreciation, amortization and impairment of oil and
natural gas properties. Management
ECA-34
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
emphasizes that reserve estimates are inherently imprecise. In
addition, realization of deferred tax assets is based largely on
estimates of future taxable income.
Derivatives In accordance with
SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended, all derivative
instruments are recorded as assets or liabilities in the
Companys balance sheet and measurement of those
instruments at its estimated fair value. The accounting
treatment of changes in fair value is dependent upon whether or
not a derivative instrument is designated as a hedge and if so,
the type of hedge. For derivatives designated as cash flow
hedges, changes in fair value are recognized in other
comprehensive income to the extent the hedge is effective, until
the hedged item is recognized in earnings. Hedge effectiveness
is measured monthly based on the relative changes in fair value
between the derivative contract and the hedged item over time.
Any change in fair value resulting from ineffectiveness and any
derivatives not qualifying as hedges are recognized immediately
in earnings in other income and expense. In the event the
Company has cash collateral held by a derivative counterparty as
a result of a margin call, the amount is reflected in other
accounts receivable.
Accumulated Other Comprehensive Income
(Loss) At June 30, accumulated other
comprehensive income (loss) (net of tax) consisted of the
following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Foreign currency translation
|
|
$
|
(44
|
)
|
|
$
|
(243
|
)
|
Oil and gas hedging
|
|
|
(45,504
|
)
|
|
|
18,439
|
|
Interest rate hedging
|
|
|
(482
|
)
|
|
|
(2,551
|
)
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive (loss) income
|
|
$
|
(46,030
|
)
|
|
$
|
15,645
|
|
|
|
|
|
|
|
|
|
|
Concentration of Credit Risk The
Company maintains its cash accounts primarily with a single bank
and invests cash in money market accounts, which the Company
believes to have minimal risk. As operator of jointly owned oil
and natural gas properties, the Company sells oil and natural
gas production to numerous U.S. oil and natural gas
purchasers, and pays vendors on behalf of joint owners for oil
and natural gas services. Both purchasers and joint owners are
located primarily in the northeastern United States and Texas.
The risk of nonpayment by the purchasers or joint owners is
considered minimal and has been considered in the Companys
allowance for doubtful accounts.
Environmental Concerns The Company is
continually taking actions it believes necessary in its
operations to ensure conformity with applicable federal, state
and local environmental regulations. As of June 30, 2009,
2008 and 2007, the Company had not been fined or cited for any
environmental violations, which would have a material adverse
effect upon capital expenditures, operating results or the
competitive position of the Company.
Recent Accounting Pronouncements In
June 2006, the Financial Accounting Standards Board
(FASB) issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109, Accounting for
Income Taxes (FIN 48), to create a single
model to address accounting for uncertainty in tax positions.
FIN 48 clarifies the accounting for income taxes by
prescribing a minimum recognition threshold that a tax position
is required to meet before being recognized in the financial
statements. FIN 48 also provides guidance on measurement
and derecognition of tax benefits, balance sheet classification
interest
ECA-35
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
and penalties, disclosure and transition. This Interpretation
initially was effective for fiscal years beginning after
December 15, 2006. In January 2008, the FASB approved the
deferral of the effective date of FIN 48 for certain
nonpublic companies to annual financial statements for fiscal
years beginning after December 15, 2007. In December 2008,
the FASB provided for an additional deferral of the effective
date of FIN 48 for certain nonpublic companies to annual
financial statements for fiscal years beginning after
December 15, 2008. The Company elected the initial and
additional deferrals and on July 1, 2009, the Company
adopted FIN 48. Adoption of this interpretation did not
have a material impact on the Companys financial position.
The Companys policy is to reflect potential interest and
penalties related to uncertain tax positions as part of interest
and penalty expense, respectively, when and if they become
applicable.
In March 2008, the FASB issued Statement of Financial Accounting
Standards No. 161, Disclosures about Derivative Instruments
and Hedging Activities an Amendment of FASB
Statement 133 which modifies and enhances required disclosures
regarding derivative and hedging activities related to how an
entity uses derivative instruments, as well as how these
instruments affect an entitys financial position,
performance, and cash flows. The statement requires disclosure
of the objectives for using derivative instruments, the fair
value of these instruments and their gains and losses (in
tabular format), and certain credit-risk-related features.
SFAS No. 161 is effective for fiscal years beginning after
November 15, 2008. The adoption of SFAS No. 161 as of
July 1, 2009 did not have a material impact on the
Companys financial statement disclosures.
Asset Retirement Obligations The
Company accounts for its asset retirement obligations according
to SFAS No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 provides the accounting
requirements for retirement obligations associated with tangible
long-lived assets. When the liability is initially recorded, the
entity capitalizes the cost, thereby increasing the carrying
amount of the related long-lived asset. Over time, the liability
is accreted, and the capitalized cost is depreciated over the
useful life of the related asset.
For the Company, asset retirement obligations primarily relate
to the abandonment of oil and natural gas producing facilities.
While assets such as pipelines and marketing assets may have
retirement obligations covered by SFAS No. 143,
certain of those obligations are not recognized since the fair
value cannot be estimated due to the uncertainty of the
settlement date of the obligation. Amounts reflected as
Change in estimate include revisions to the
Companys plugging assumptions, based upon the current
facts and circumstances associated with the Companys well
portfolio and with current market conditions.
ECA-36
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The following table presents a reconciliation of the beginning
and ending carrying amounts of the asset retirement obligations
for the year ended June 30, 2009 which is included in other
long-term obligations (in thousands):
|
|
|
|
|
Asset retirement obligation as of the beginning of the year
|
|
$
|
15,100
|
|
Accretion expense
|
|
|
825
|
|
Liabilities incurred
|
|
|
117
|
|
Liabilities settled
|
|
|
(65
|
)
|
Change in estimate
|
|
|
75
|
|
|
|
|
|
|
Asset retirement obligation as of the end of the year
|
|
$
|
16,052
|
|
|
|
|
|
|
Supplemental Disclosures of Cash Flow
Information Supplemental cash flow
information for the years ended June 30 is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Cash paid for:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
8,120
|
|
|
$
|
10,646
|
|
|
$
|
7,634
|
|
Income taxes, net of amounts refunded
|
|
|
100
|
|
|
|
54
|
|
|
|
4
|
|
Noncash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared and unpaid at year end
|
|
$
|
1,803
|
|
|
$
|
1,828
|
|
|
$
|
1,833
|
|
Notes receivable from the issuance of Class A stock
|
|
|
|
|
|
|
892
|
|
|
|
452
|
|
Liabilities settled through assignment
|
|
|
980
|
|
|
|
|
|
|
|
|
|
Natural
Gas & Oil Hedging Instruments
The Companys overall objective in its hedging program is
to assure a return on capital invested in long-lived assets in
excess of the Companys cost of capital. The various
derivative commodity instruments used by the Company to hedge
its exposure to variability in expected future cash flows
associated with the fluctuations in the price of oil and natural
gas related to the Companys forecasted sale of equity
production and forecasted natural oil and natural gas purchases
and sales have been designated and qualify as cash flow hedges.
Futures contracts obligate the Company to buy or sell a
designated commodity at a future date for a specified price and
quantity at a specified location.
Swap agreements involve payments to or receipts from
counterparties based on the differential between a fixed and
variable price for the commodity. Collar agreements require the
counterparty to pay the Company if the index price falls below
the floor price and the Company to pay the counterparty if the
index price rises above the cap price. Certain swap and option
instruments used by the Company do not qualify as cash flow
hedges. Exchange-traded instruments are generally settled with
offsetting positions. Over the counter (OTC)
arrangements require settlement in cash.
ECA-37
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The fair value of the Companys derivative commodity
instruments for the years ended June 30 is presented below (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Asset
|
|
$
|
593
|
|
|
$
|
31,291
|
|
Liability
|
|
|
(95,218
|
)
|
|
|
(282
|
)
|
|
|
|
|
|
|
|
|
|
Net asset (liability)
|
|
$
|
(94,625
|
)
|
|
$
|
31,009
|
|
|
|
|
|
|
|
|
|
|
These amounts are included in the Consolidated Balance Sheets as
derivatives at fair value. The net fair value of derivative
instruments changed during fiscal year 2009 primarily as a
result of a decrease in natural gas and oil prices. The absolute
quantities of the Companys derivative commodity
instruments that have been designated and qualify as cash flow
hedges totaled 10.3 million MMBtu for natural gas
derivatives and 18,000 Bbl for oil derivatives as of
June 30, 2009. As of June 30, 2008, the related
volumes were 19.1 million MMBtu and 108,400 Bbl. The
open positions at June 30, 2009 had maturities for natural
gas swaps extending through June 2012 and for oil swaps through
December 2009.
As of June 30, 2009, the Company deferred net gains of
$18.4 million in accumulated other comprehensive income,
net of tax, for derivatives associated with the effective
portion of the change in fair value of its derivative
instruments designated as cash flow hedges. As of June 30,
2008, net losses of $45.5 million for natural gas
derivatives were so deferred. Assuming no change in price or new
transactions, the Company estimates that approximately
$18.0 million of net unrealized gains on its derivatives
reflected in accumulated other comprehensive income, net of tax,
as of June 30, 2009 will be recognized in earnings during
the next twelve months due to the physical settlement of hedged
transactions.
Ineffectiveness associated with the Companys derivative
instruments designated as cash flow hedges increased earnings by
approximately $44,000 for the year ended June 30, 2009,
decreased earnings by approximately $95,000 for the year ended
June 30, 2008, and increased earnings by $29,000 for the
year ended June 30, 2007. These amounts are included in
other income and expense in the Consolidated Statements of
Operations.
Changes in fair value associated with derivative contracts that
do not qualify for hedge accounting treatment are recognized in
other income and expense. Accordingly, the Company recognized
net gains of approximately $18.1 million for derivatives
for the year ended June 30, 2009, and net losses of
approximately $16.8 million and $1.0 million for
derivatives for the years ended June 30, 2008 and 2007,
respectively. These amounts are included in other income and
expense in the Consolidated Statement of Operations.
Interest
Rate Swaps
During November 2007 and January 2008, Company entered into
three interest rate swap agreements with Wells Fargo Foothill,
Inc. (Foothill), in an effort to reduce the
potential impact of increases in interest rates on floating-rate
long-term debt. The three-year agreements cover
$100 million in long-term debt and fix the one-month London
Interbank Offered Rate (LIBOR) over a range of
3.67% 4.05%. The Company has partially hedged
its exposure to the variability in future cash flows through
January 2011.
ECA-38
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The interest rate swaps are included in the Consolidated Balance
Sheets as derivatives, at fair value. Fair values of
$3.1 million and $1.2 million were reported as current
and long-term liabilities, respectively, at June 30, 2009.
Fair values of $1.0 million and $0.2 million were
reported as current liabilities and long-term assets,
respectively, at June 30, 2008. The Company deferred net
losses of $2.6 million and $0.5 million in accumulated
other comprehensive loss, net of tax, as of June 30, 2009
and 2008, respectively and deferred net gains of $6,000 in
accumulated other comprehensive gain, net of tax, as of
June 30, 2007.
Long-Term Debt At June 30 long-term
debt consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Term credit agreements, variable rates
|
|
$
|
100,000
|
|
|
$
|
100,000
|
|
Revolving credit agreements, variable rates
|
|
|
77,553
|
|
|
|
99,244
|
|
Non-recourse debt
|
|
|
17,220
|
|
|
|
16,778
|
|
Installment notes payable, at imputed interest rates ranging
from
6.0% to 8.0%
|
|
|
2,992
|
|
|
|
2,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
197,765
|
|
|
|
218,816
|
|
Less current portion
|
|
|
(640
|
)
|
|
|
(682
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
197,125
|
|
|
$
|
218,134
|
|
|
|
|
|
|
|
|
|
|
Scheduled maturities of the Companys long-term debt at
June 30, 2009 for each of the next five years and
thereafter are as follows (in thousands):
|
|
|
|
|
2010
|
|
$
|
1,883
|
|
2011
|
|
|
1,883
|
|
2012
|
|
|
201,126
|
|
2013
|
|
|
1,883
|
|
2014
|
|
|
1,866
|
|
Thereafter
|
|
|
18,770
|
|
|
|
|
|
|
Total payments
|
|
|
227,411
|
|
Less: imputed interest
|
|
|
8,595
|
|
|
|
|
|
|
Present value of scheduled maturities
|
|
$
|
218,816
|
|
|
|
|
|
|
Revolving Credit and Term Loan The
Company entered into a First Amendment to Second Amended and
Restated Credit Agreement effective August 4, 2008 (the
Credit Agreement), with Wells Fargo Foothill, Inc.
(Foothill), Bank of America, N.A. and U.S. Bank
National Association. The credit facility provides for a Maximum
Loan Amount of $250 million, consisting of a revolving
facility of $150 million and a single advance term loan of
$100 million, which is an increase of $50 million on
the revolving facility from June 30, 2008. The term loan
contains requirements for principal payments of $1 million
each at July 10, 2009, 2010, and 2011 and the Maturity Date
of the Credit Agreement is July 10, 2012. At June 30,
2009, the Company classified
ECA-39
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
$1 million of the term loan that was due on July 10,
2009 as long-term debt as a result of having a Credit Agreement
in place that allowed the Company to refinance the debt on a
long-term basis. Depending on the Companys level of
borrowing under the Credit Agreement, the applicable interest
rates for base rates are based on Wells Fargos prime rate
minus 0.25% to plus 0.25%. The Company also has the ability
under the Credit Agreement to designate certain loans as LIBOR
Rate Loans at interest rates based upon the rate at which dollar
deposits are offered to major banks in the London interbank
market plus 1.50% to 2.00%.
The obligations under the Credit Agreement are secured by
certain of the existing proved producing oil and natural gas
assets of the Company. The Credit Agreement, among other things,
restricts the ability of the Company and its subsidiaries to
incur new debt, grant additional security interests in its
collateral, engage in certain merger or reorganization
activities, or dispose of certain assets.
Other Credit Facilities The Company
has an unsecured revolving line of credit totaling
$2.0 million with a financial institution with a variable
interest rate equal to the Prime Rate quoted in the
Wall Street Journal (or comparable source) plus 0.25% per annum,
except that upon presentment of any letter of credit, such rate
shall be equal to the prime rate plus 2%. As of June 30,
2009, there was no outstanding balance on this line of credit
while there was $30,000 committed through letters of credit at
June 30, 2008.
Other Notes In August 2005 the Company
purchased an office building and associated land for
$3.5 million, which included the assumption of a note with
the principal balance of approximately $2.4 million. The
note stipulated that the Company will pay fifty-five consecutive
equal monthly payments with the first payment to be made by the
Company on September 15, 2005 and the final scheduled
payment on March 15, 2010 with the remaining balance due on
April 8, 2010. In March 2007, the Company remodeled the
existing office building and assumed a promissory note with a
principal balance of $0.3 million. The note stipulated that
the Company will pay thirty six consecutive equal monthly
payments with the first payment made by the Company on
April 15, 2007 and the final scheduled payment on
March 15, 2010 with the remaining balance due on
April 8, 2010. As of June 30, 2009 and June 30,
2008, the balance due was $2.4 million and
$2.5 million, respectively. The Company intends to
negotiate an extension of this note. As of June 30, 2009,
the Company has classified the loan as long-term debt as a
result of having a Credit Agreement in place that allows the
Company to refinance the debt on a long-term basis.
Non-Recourse Loan The Company has
entered into a non-recourse loan for the purchase of certain
transportation equipment. The loan, in the aggregate principal
amount of $17.5 million, was disbursed to the Company in
four tranches. As of June 30, 2007 the first two tranches
totaling $11.8 million were funded. The third tranche of
$3.3 million was funded on August 15, 2007 and the
fourth and final tranche of $2.4 million was funded upon
delivery of the equipment to the Company, which occurred in
October 2007. The term of the loan will be 10 years from
the date of disbursement of the fourth tranche. The loan is
being repaid by a fixed monthly payment of principal and
interest which was calculated at the time of disbursement of the
fourth tranche based upon a 250 month amortization at an
interest rate equal to 6.22%. The first scheduled payment on
this loan was made in November 2007. The loan is secured by the
transportation equipment acquired by the Company. As of
June 30, 2009 and June 30, 2008, the balance due was
$16.8 million and $17.2 million, respectively.
ECA-40
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The following table summarizes components of the Companys
provision for income taxes for the years ended June 30 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(38
|
)
|
|
$
|
11
|
|
|
$
|
(125
|
)
|
State
|
|
|
215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
177
|
|
|
|
11
|
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
3,207
|
|
|
|
6,643
|
|
|
|
13,627
|
|
State
|
|
|
1,431
|
|
|
|
1,201
|
|
|
|
3,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
4,638
|
|
|
|
7,844
|
|
|
|
17,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision for income taxes
|
|
$
|
4,815
|
|
|
$
|
7,855
|
|
|
$
|
17,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A reconciliation of the provision for income taxes computed at
the statutory rate to the provision for income taxes as shown in
the consolidated statements of operations for the years ended
June 30 is summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Tax provision at the federal statutory rate
|
|
$
|
8,353
|
|
|
$
|
6,769
|
|
|
$
|
13,680
|
|
State taxes, net of federal tax benefit
|
|
|
1,476
|
|
|
|
806
|
|
|
|
2,376
|
|
State tax credits
|
|
|
152
|
|
|
|
|
|
|
|
|
|
Excess statutory depletion
|
|
|
(168
|
)
|
|
|
(103
|
)
|
|
|
(59
|
)
|
Non-deductible entertainment
|
|
|
53
|
|
|
|
224
|
|
|
|
134
|
|
Change in valuation allowance, net
|
|
|
|
|
|
|
|
|
|
|
1,342
|
|
Change in tax contingency
|
|
|
(5,013
|
)
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
(38
|
)
|
|
|
159
|
|
|
|
(118
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision for income taxes
|
|
$
|
4,815
|
|
|
$
|
7,855
|
|
|
$
|
17,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-41
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Components of the Companys deferred tax assets and
liabilities at June 30 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
338
|
|
|
$
|
181
|
|
Profit sharing plan liability
|
|
|
2,008
|
|
|
|
2,007
|
|
Royalty Trust agreements
|
|
|
2,268
|
|
|
|
1,831
|
|
Derivative instruments
|
|
|
7,294
|
|
|
|
|
|
Restricted stock compensation
|
|
|
286
|
|
|
|
196
|
|
Asset retirement obligation
|
|
|
6,498
|
|
|
|
6,955
|
|
Litigation settlement liability
|
|
|
|
|
|
|
849
|
|
State and federal income tax benefit
|
|
|
2,048
|
|
|
|
3,327
|
|
Tax credits and carryforwards
|
|
|
15,934
|
|
|
|
22,432
|
|
Other
|
|
|
343
|
|
|
|
273
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
37,017
|
|
|
|
38,051
|
|
Valuation allowance
|
|
|
|
|
|
|
(1,342
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets net of valuation allowance
|
|
|
37,017
|
|
|
|
36,709
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
(50,110
|
)
|
|
|
(66,265
|
)
|
Black Stone Term Royalty Conveyance
|
|
|
(21,642
|
)
|
|
|
(21,342
|
)
|
Derivative instruments
|
|
|
|
|
|
|
(1,313
|
)
|
Other
|
|
|
(35
|
)
|
|
|
(39
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(71,787
|
)
|
|
|
(88,959
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(34,770
|
)
|
|
$
|
(52,250
|
)
|
|
|
|
|
|
|
|
|
|
Current deferred tax asset
|
|
$
|
2,440
|
|
|
$
|
1,359
|
|
Long-term deferred tax liability
|
|
|
(37,210
|
)
|
|
|
(53,609
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(34,770
|
)
|
|
$
|
(52,250
|
)
|
|
|
|
|
|
|
|
|
|
ECA-42
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
At June 30, the Company had the following federal and state
tax credits and carryforwards (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
|
|
|
Year of
|
|
|
|
|
|
Year of
|
|
|
|
Amount
|
|
|
Expiration
|
|
|
Amount
|
|
|
Expiration
|
|
|
AMT tax credits
|
|
$
|
2,082
|
|
|
|
None
|
|
|
$
|
1,957
|
|
|
|
None
|
|
Net operating loss carryforwards
|
|
|
5,711
|
|
|
|
2025-2028
|
|
|
|
10,567
|
|
|
|
2025-2029
|
|
Charitable contribution carryforwards
|
|
|
3,033
|
|
|
|
2009-2013
|
|
|
|
3,851
|
|
|
|
2009-2014
|
|
Percentage depletion carryforwards
|
|
|
2,173
|
|
|
|
None
|
|
|
|
2,318
|
|
|
|
None
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total federal credits and carryforwards
|
|
$
|
12,999
|
|
|
|
|
|
|
$
|
18,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State net operating loss carryforwards
|
|
$
|
2,035
|
|
|
|
2009-2028
|
|
|
$
|
2,701
|
|
|
|
2009-2029
|
|
State charitable contribution carryforwards
|
|
|
506
|
|
|
|
2009-2013
|
|
|
|
632
|
|
|
|
2009-2014
|
|
State percentage depletion carryforwards
|
|
|
394
|
|
|
|
None
|
|
|
|
406
|
|
|
|
None
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total state carryforwards
|
|
$
|
2,935
|
|
|
|
|
|
|
$
|
3,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total federal and state credits and carryforwards
|
|
$
|
15,934
|
|
|
|
|
|
|
$
|
22,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended June 30, 2009, the Company established a
valuation allowance of $1.3 million related to the
charitable contribution carryforwards as the Company does not
currently believe that it is more likely than not that all of
the federal and state charitable contribution carryforwards will
be fully utilized during their respective statutory carryforward
periods. The determination of the valuation allowance amount was
based on all positive and negative evidence available as of the
year-end. The Company will reassess the valuation allowance
annually and if future evidence allows for a decrease or
increase of the valuation allowance then a tax benefit or
expense, respectively, will be recorded.
In prior years, the State of West Virginia Department of Revenue
(WV DOR) notified the Company that it was initiating
an audit of the Companys state income/franchise tax
returns for the open tax years. As of June 30, 2009 and
2008, the WV DOR had not begun nor requested information from
the Company pertaining to the audit of the Companys state
income/franchise tax returns. The Company has not received any
notices of proposed adjustments pertaining to the audit and
believes that it has adequately provided for any potential tax
liability that may be assessed by the WV DOR.
The Company and its subsidiaries file income tax returns in the
U.S. federal jurisdiction, in various states, and in one
foreign jurisdiction, each with varying statutes of limitations.
The 2006 through 2009 tax years generally remain subject to
examination by the federal and state tax authorities. The 2005
through 2009 tax years generally remain subject to examination
by the foreign tax authority.
Though not included in the tables or discussion above, the
Company has a foreign net deferred tax asset of
$15.8 million in New Zealand. The foreign net deferred tax
asset is comprised of a $16.2 million foreign deferred tax
asset related to the Companys New Zealand net operating
loss carryforward (NZ NOL), net of a
$0.4 million foreign deferred tax liability related to
property, plant and equipment. The foreign tax benefit of this
NZ NOL that may be carried
ECA-43
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
forward indefinitely, subject to certain ownership restrictions,
is dependent on future New Zealand taxable income. Accordingly,
the Company established in prior years and continues to provide
a full valuation allowance equal to the $15.8 million
foreign net deferred tax asset as the Company does not currently
believe that it is more likely than not that the NZ NOL will be
fully utilized. The NZ NOL available to reduce future New
Zealand taxable income was approximately $49.2 million
($76.0 million NZD) and $48.5 million
($63.8 million NZD) at June 30, 2009 and 2008,
respectively.
|
|
6.
|
EMPLOYEE
BENEFIT PLANS
|
The Company and certain subsidiaries, have a Profit
Sharing/Incentive Stock Plan (the Plan) for the
stated purpose of expanding and improving profits and prosperity
and to assist the Company in attracting and retaining key
personnel. The Plan is noncontributory, and its continuance from
year to year is at the discretion of the Companys board of
directors. The annual profit sharing pool is based on
calculations set forth in the Plan. Generally, to be eligible to
participate, an employee must have been continuously employed
for two or more years; however, employees with less than two
years of employment may participate under certain circumstances.
The Company recognized $5.8 million and $5.4 million
of profit sharing expense in other income and expense during the
years ended June 30, 2009 and June 30, 2008,
respectively, and $5.6 million for the year ended
June 30, 2007.
The Company sponsors a Section 401(k) plan covering all
full-time employees who elect to participate. The plan provides
for matching, at various percentages of the employees
contribution, based on each participants length of service
with the Company. The Companys contributions are expensed
as incurred, which totaled approximately $0.7 million for
each of the years ended June 30, 2009 and June 30,
2008 and $0.6 million for the year ended June 30, 2007.
Voting Common Stock In May 1995, the
Company was reincorporated in the State of West Virginia. As
part of this reincorporation, each outstanding share of then
existing no-par value common stock was converted to one share of
$1 par value common stock.
Class A Non-Voting Common Stock
In August 1998, the Company amended its articles of
incorporation authorizing the issuance of up to
100,000 shares of Class A non-voting common stock.
In June 2008, ECA granted all full-time employees the
opportunity to purchase a specified number of shares of
Class A stock at the then current share price of $140 per
share. The stock issued as a result of this program vests over a
specified period of time, with the full vesting to occur
October 1, 2013. Pursuant to this program, the Company
issued 15,060 shares of Class A stock.
In June 2006, ECA granted all full-time employees the
opportunity to purchase a specified number of shares of
Class A stock having certain restrictions that expire
January 1, 2012. The Company issued 17,126 shares of
stock with a $45 per share purchase price pursuant to this
program. The Company repurchased 740, 685, and 875 of the
Class A shares during the years ended June 30, 2009,
2008, and 2007, respectively.
ECA-44
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
During October 2003, ECA offered its employees that were
participants in the 2003 Profit Sharing program the opportunity
to purchase shares of Class A stock having certain
restrictions expiring over a specified period of time. As of
January 1, 2009 all restrictions related to these
Class A shares have expired. Pursuant to this program,
16,850 shares of restricted Class A Stock were issued for
$15 per share vesting over five years. The Company repurchased
18, 162, and 815 shares of the Class A Stock during
the years ended June 30, 2009, 2008, and 2007,
respectively. During the years ended June 30, 2009, 2008,
and 2007, 4,449 shares, 4,996 shares, and
5,249 shares, respectively, became fully vested.
Treasury Stock At June 30, 2009,
the Company had 209,327 shares of voting common stock in
treasury, carried at cost. The Company did not purchase any
shares of voting common stock during the years ended
June 30, 2009 and 2007 and purchased 1,600 shares
during the year ended June 30, 2008. At June 30, 2009,
the Company had 25,329 shares of non-voting Class A
stock in treasury, carried at cost. The Company purchased 4,499,
1,524, and 462 shares of non-voting Class A stock
during the years ended June 30, 2009, 2008, and 2007,
respectively. The Company reissued 6,876 and 12,128 shares
of non-voting Class A stock during the years ended
June 30, 2009 and 2008, respectively. No shares of
non-voting Class A stock were reissued during the year
ended June 30, 2007.
In accordance with SFAS No. 128, Earnings Per
Share, basic earnings per share has been computed based
upon the weighted average shares outstanding.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares, basic and diluted
|
|
|
566,070
|
|
|
|
576,313
|
|
|
|
587,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income per common share
|
|
$
|
33.66
|
|
|
$
|
19.93
|
|
|
$
|
36.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company has noncancelable operating lease agreements for the
rental of office space, computers and other equipment. Certain
of these leases contain purchase options or renewal clauses.
Rental expense for operating leases was approximately
$2.4 million, $2.0 million, and $1.8 million for
the years ended June 30, 2009, 2008, and 2007, respectively.
ECA-45
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
At June 30, 2009 future minimum lease payments for each of
the next five years and thereafter are as follows (in thousands):
|
|
|
|
|
2010
|
|
$
|
752
|
|
2011
|
|
|
459
|
|
2012
|
|
|
217
|
|
2013
|
|
|
175
|
|
2014
|
|
|
116
|
|
Thereafter
|
|
|
280
|
|
|
|
|
|
|
|
|
$
|
1,999
|
|
|
|
|
|
|
|
|
10.
|
RELATED
PARTY TRANSACTIONS
|
The Company has advanced funds to a certain officer at 6.75% to
7.5% interest. Balances totaled $0.2 million and
$0.4 million for the years ended June 30, 2009 and
June 30, 2008, respectively. The balances are due in full,
unless sooner paid, ranging from two to five years, depending on
the agreement.
Certain directors and employees of the Company and members of
their families regularly participate in the wells drilled by the
Company on an actual cost basis and share in the costs and
revenues on the same basis as the Company. The Company has the
right to select the wells drilled and each participant is
involved in all wells included within a Company drilling program
and cannot selectively choose the wells in which to participate.
The Company has issued promissory notes to certain employees as
part of a Class A Stock Award Agreement, whereby employees
had the option to finance eighty percent of the cost of the
shares they elected to purchase at $140 per share. The carrying
value of the notes was $1.3 million and $0.9 million
as of June 30, 2009 and June 30, 2008, respectively.
The notes, which are full recourse, have an interest rate of
3.5% with a term of five years with principal payments due and
payable at the end of years three, four and five.
|
|
11.
|
COMMITMENTS
AND CONTINGENCIES
|
On June 10, 2005, the Company consummated a Term Royalty
Conveyance, pursuant to which Eastern American transferred a
term royalty interest, for a term of twenty years in certain oil
and natural gas properties located in West Virginia, Kentucky,
and Pennsylvania to Black Stone. The deferred gain related to
the sale is classified as current and long-term liabilities and
is being recognized as production occurs. The remaining deferred
gain in current and long-term liabilities totaled
$75.3 million and $82.6 million at June 30, 2009
and 2008, respectively. The transaction included interests in
312 producing properties. In addition, the Company entered into
a Development Agreement that obligated the Company to drill, or
cause to be drilled, 180 completed development wells by
March 31, 2008. As of June 30, 2008, the Company had
satisfied its drilling obligation under the Development
Agreement.
In connection with the transaction, the Company entered into a
Credit Line Deed of Trust in the amount of $24 million. The
indebtedness reduces proportionately under the terms of the
ECA-46
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Development Agreement and the lien was partially released as
completed development wells were drilled. As a result of the
Companys satisfaction of the drilling commitment, the
indebtedness under the terms of the Credit Line Deed of Trust
has been eliminated. The Company has obtained a full release
from Black Stone of the Credit Line Deed of Trust.
The Company is involved in various legal actions and claims
arising in the ordinary course of business. Management does not
expect that any matter pending against the Company will have a
material adverse effect on the Companys financial position
or results of operations and has established reserves that it
believes are adequate.
The Company was involved in a lawsuit filed by an individual on
behalf of himself and on behalf of a class of all similarly
situated individuals and entities, alleging that the Company
improperly deducted post-production expenses in calculating
royalty payments. The Company settled this lawsuit and is
distributing the settlement proceeds in five annual
distributions. As part of the settlement, the parties to the
litigation and the Company agreed upon a methodology for
calculating royalty payments in the future with respect to
natural gas produced from the wells subject to this lawsuit. The
first distribution of settlement proceeds occurred during the
fiscal year ended June 30, 2009 with the remaining
distributions scheduled to be funded over the next four years.
This settlement did not significantly impact the Companys
financial position or operating results and will not
significantly impact the Companys future cash flows.
|
|
12.
|
FINANCIAL
INSTRUMENTS
|
In September 2006, the Financial Accounting Standards Board
issued SFAS No. 157 which established a framework for
measuring fair value in accordance with generally accepted
accounting principles and expanded disclosures about fair value
measurements. The Company adopted the provisions of
SFAS No. 157 on July 1, 2008. The adoption of
SFAS No. 157 has had no impact on the Companys
financial statement measurements with respect to financial
instruments.
In accordance with SFAS No. 157, the Company has
categorized its financial instruments into a three-level fair
value hierarchy, based on the priority of the inputs to the
valuation technique. The fair value hierarchy gives the highest
priority to quoted prices in active markets for identical assets
and liabilities (Level 1) and the lowest priority to
unobservable inputs (Level 3).
Derivative
Financial Instruments
All of the Companys derivative contracts, consisting of
commodity and interest rate swaps, are included in Level 2.
The fair value of financial instruments included in Level 2
is based on industry models that use significant observable
inputs that, for the Company, include quoted NYMEX market prices
for commodity futures and one-month London Interbank Offering
Rate (LIBOR) futures. At June 30, 2009 and June 30,
2008, derivative assets and liabilities at fair values were
$31.1 million and $4.6 million and $0.7 million
and $96.2 million, respectively.
Gains and losses related to derivative commodity instruments
reported in the Consolidated Statements of Operations for the
period are included in oil and natural gas sales for those
instruments qualifying for hedge accounting, and in other income
and expense for other
ECA-47
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
contracts. Gains and losses related to interest rate swaps are
included in interest expense. There were no gains or losses for
the period included in earnings attributable to the change in
unrealized gains or losses relating to derivative assets and
liabilities still held as of June 30, 2009. See Note 3
for additional information regarding the Companys
derivative holdings.
Notes
Receivable
The notes receivable accrue interest at a fixed rate. The
carrying value approximates fair value which was estimated using
discounted cash flows based on current interest rates for notes
with similar credit characteristics and maturities.
Long-term
Debt
At June 30, 2009 the Companys long-term debt is
primarily comprised of revolving lines of credit with variable
rates while fixed rate facilities incur interest at rates that
approximate fair value.
The Companys reportable business segments have been
identified based on the differences in products and service
provided. Revenues for the exploration and production segment
are derived from the production and sale of natural gas and
crude oil. Revenues for the aggregation and pipeline segment
arise from the aggregation of both Company and third party
produced natural gas volumes and the related transportation. The
Other category includes items related to corporate
activities. Management utilizes earnings before interest, income
taxes, depreciation, depletion, amortization and impairment and
exploratory costs (EBITDAX), a non-GAAP financial
measure, to evaluate each segments operations.
Reconciliation of non-GAAP financial measure is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
8,245
|
|
|
|
10,688
|
|
|
|
9,986
|
|
Depletion and depreciation of oil and gas properties
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
Depreciation of property, plant and equipment
|
|
|
4,961
|
|
|
|
5,852
|
|
|
|
6,119
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
Income tax expense
|
|
|
4,815
|
|
|
|
7,855
|
|
|
|
17,355
|
|
Change in fair value derivatives
|
|
|
923
|
|
|
|
16,887
|
|
|
|
(18,166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
|
|
$
|
64,597
|
|
|
$
|
76,737
|
|
|
$
|
78,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-48
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Summarized financial information for the Companys
reportable segments is shown in the following table (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
Aggregation and
|
|
|
|
|
|
|
Production
|
|
Pipeline
|
|
Other
|
|
Consolidated
|
|
Fiscal Year 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
$
|
91,405
|
|
|
$
|
120,549
|
|
|
$
|
|
|
|
$
|
211,954
|
|
Depreciation, depletion, amortization
|
|
|
19,560
|
|
|
|
2,405
|
|
|
|
1,111
|
|
|
|
23,076
|
|
Impairment and exploratory costs
|
|
|
8,487
|
|
|
|
|
|
|
|
|
|
|
|
8,487
|
|
Operating profit (loss)
|
|
|
27,194
|
|
|
|
5,418
|
|
|
|
8,046
|
|
|
|
40,658
|
|
Interest (net)
|
|
|
15,195
|
|
|
|
(6,613
|
)
|
|
|
(432
|
)
|
|
|
8,150
|
|
Other (income) & expense
|
|
|
2,027
|
|
|
|
|
|
|
|
6,616
|
|
|
|
8,643
|
|
EBITDAX
|
|
|
40,503
|
|
|
|
12,922
|
|
|
|
11,172
|
|
|
|
64,597
|
|
Total assets
|
|
|
343,952
|
|
|
|
42,096
|
|
|
|
27,273
|
|
|
|
413,321
|
|
Capital expenditures
|
|
|
87,557
|
|
|
|
5,349
|
|
|
|
714
|
|
|
|
93,620
|
|
Fiscal Year 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
|
104,247
|
|
|
|
142,825
|
|
|
|
|
|
|
|
247,072
|
|
Depreciation, depletion, amortization
|
|
|
22,440
|
|
|
|
3,159
|
|
|
|
1,190
|
|
|
|
26,789
|
|
Impairment and exploratory costs
|
|
|
3,033
|
|
|
|
|
|
|
|
|
|
|
|
3,033
|
|
Operating profit (loss)
|
|
|
37,486
|
|
|
|
5,318
|
|
|
|
9,108
|
|
|
|
51,912
|
|
Interest (net)
|
|
|
18,450
|
|
|
|
(7,269
|
)
|
|
|
(575
|
)
|
|
|
10,606
|
|
Other (income) & expense
|
|
|
18,924
|
|
|
|
|
|
|
|
3,042
|
|
|
|
21,966
|
|
EBITDAX
|
|
|
44,133
|
|
|
|
14,128
|
|
|
|
18,476
|
|
|
|
76,737
|
|
Total assets
|
|
|
468,189
|
|
|
|
55,327
|
|
|
|
34,464
|
|
|
|
557,980
|
|
Capital expenditures
|
|
|
93,364
|
|
|
|
6,868
|
|
|
|
578
|
|
|
|
100,810
|
|
Fiscal Year 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
|
99,490
|
|
|
|
116,730
|
|
|
|
|
|
|
|
216,220
|
|
Depreciation, depletion, amortization
|
|
|
25,012
|
|
|
|
3,239
|
|
|
|
1,313
|
|
|
|
29,564
|
|
Impairment and exploratory costs
|
|
|
18,476
|
|
|
|
|
|
|
|
|
|
|
|
18,476
|
|
Operating profit (loss)
|
|
|
14,940
|
|
|
|
5,502
|
|
|
|
9,908
|
|
|
|
30,350
|
|
Interest (net)
|
|
|
16,035
|
|
|
|
(7,965
|
)
|
|
|
1,778
|
|
|
|
9,848
|
|
Other (income) & expense
|
|
|
(25,733
|
)
|
|
|
4
|
|
|
|
7,145
|
|
|
|
(18,584
|
)
|
EBITDAX
|
|
|
52,028
|
|
|
|
14,670
|
|
|
|
12,248
|
|
|
|
78,946
|
|
Total assets
|
|
|
475,444
|
|
|
|
37,391
|
|
|
|
30,884
|
|
|
|
543,719
|
|
Capital expenditures
|
|
|
70,153
|
|
|
|
2,824
|
|
|
|
711
|
|
|
|
73,688
|
|
Operating profit represents revenues less costs which are
directly associated with such operations. Revenues are priced
and accounted for consistently for both unaffiliated and
intersegment sales.
ECA-49
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Revenues from two purchasers of the Companys production
during the year ended June 30, 2009 represent
$43.2 million and $19.6 million respectively of the
Companys consolidated revenues within the Exploration and
Production and Gas Aggregation and Pipeline segments. During the
year ended June 30, 2008, revenues from three purchasers of
the Companys production represented $42.6 million,
$22.2 million and $21.0 million respectively of the
Companys consolidated revenues within the Exploration and
Production and Gas Aggregation and Pipeline segments. During the
year ended June 30, 2007, revenues from two purchasers of
the Companys production represented $30.0 million,
and $22.8 million respectively of the Companys
consolidated revenues within the Exploration and Production and
Gas Aggregation and Pipeline segments.
SUPPLEMENTAL
INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Costs The following tables set forth
capitalized costs and costs incurred, including capitalized
overhead, for oil and natural gas producing activities for the
years ended June 30 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Capitalized costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
433,297
|
|
|
$
|
536,122
|
|
|
$
|
571,748
|
|
Unproved properties
|
|
|
12,302
|
|
|
|
9,908
|
|
|
|
13,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
445,599
|
|
|
|
546,030
|
|
|
|
585,377
|
|
Less accumulated depletion and depreciation
|
|
|
(136,658
|
)
|
|
|
(155,182
|
)
|
|
|
(165,146
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
308,941
|
|
|
$
|
390,848
|
|
|
$
|
420,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of proved and unproved properties
|
|
$
|
320
|
|
|
$
|
24
|
|
|
$
|
19
|
|
Development costs
|
|
|
50,211
|
|
|
|
84,572
|
|
|
|
66,560
|
|
Exploration costs
|
|
|
12,771
|
|
|
|
6,219
|
|
|
|
1,658
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
63,302
|
|
|
$
|
90,815
|
|
|
$
|
68,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-50
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Results of Operations The results of
operations for oil and natural gas producing activities,
excluding corporate overhead and interest costs for the years
ended June 30 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Revenues from sale of oil and gas
|
|
$
|
84,429
|
|
|
$
|
96,514
|
|
|
$
|
92,262
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
10,872
|
|
|
|
10,738
|
|
|
|
10,486
|
|
Production taxes
|
|
|
4,352
|
|
|
|
5,076
|
|
|
|
4,264
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
Depletion, depreciation and amortization
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
Income tax expense
|
|
|
16,935
|
|
|
|
22,976
|
|
|
|
14,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from oil and gas operations
|
|
$
|
25,668
|
|
|
$
|
33,754
|
|
|
$
|
21,177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs include those costs incurred to operate and
maintain productive wells and related equipment and include
costs such as labor, repairs and maintenance, materials,
supplies, fuel consumed and insurance. Production costs are net
of well tending fees, which are included in well operations
revenues in the accompanying consolidated statements of
operations.
Exploration and impairment expenses include the costs of
geological and geophysical activity, unsuccessful exploratory
wells and leasehold impairment allowances. Depletion,
depreciation and amortization include costs associated with
capitalized acquisitions, exploration and development costs.
The provision for income taxes is computed at the statutory
federal income tax rate and is reduced to the extent of
permanent differences which have been recognized in the
Companys tax provision, such as investment tax credits,
and the utilization of Federal tax credits permitted for fuel
produced from a non-conventional source.
Reserve Quantity Information Reserve
estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the
projection of future rates of production and timing of
development expenditures. The accuracy of such estimates is a
function of the quality of available data and of engineering and
geological interpretation and judgment. Results of subsequent
drilling, testing and production may cause either upward or
downward revisions of previous estimates. Further, the volumes
considered commercially recoverable fluctuate with changes in
prices and operating costs. Reserve estimates, by their nature,
are generally less precise than other financial statement
disclosures.
ECA-51
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The following table sets forth information for the years
indicated with respect to changes in the Companys proved
reserves, substantially all of which are in the United States.
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (Mmcf)
|
|
Crude Oil (Mbbls)
|
|
Proved reserves
|
|
|
|
|
|
|
|
|
June 30, 2006
|
|
|
161,809
|
|
|
|
484
|
|
Revisions of previous estimates
|
|
|
1,033
|
|
|
|
80
|
|
Extensions and discoveries
|
|
|
17,532
|
|
|
|
65
|
|
Sales of reserves in place
|
|
|
(611
|
)
|
|
|
(71
|
)
|
Production
|
|
|
(9,138
|
)
|
|
|
(83
|
)
|
|
|
|
|
|
|
|
|
|
June 30, 2007
|
|
|
170,625
|
|
|
|
475
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(1,261
|
)
|
|
|
(42
|
)
|
Extensions and discoveries
|
|
|
15,326
|
|
|
|
11
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
Production
|
|
|
(10,294
|
)
|
|
|
(65
|
)
|
|
|
|
|
|
|
|
|
|
June 30, 2008
|
|
|
174,396
|
|
|
|
379
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates (1)
|
|
|
(29,065
|
)
|
|
|
(21
|
)
|
Extensions and discoveries
|
|
|
7,200
|
|
|
|
11
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
Production
|
|
|
(9,364
|
)
|
|
|
(47
|
)
|
|
|
|
|
|
|
|
|
|
June 30, 2009
|
|
|
143,167
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
June 30, 2007
|
|
|
170,625
|
|
|
|
475
|
|
June 30, 2008
|
|
|
174,396
|
|
|
|
379
|
|
June 30, 2009
|
|
|
143,167
|
|
|
|
322
|
|
|
|
|
(1)
|
|
The large revision in reserves
between the July 1, 2008 and July 1, 2009 reports is
due primarily to the large change in commodity prices during
this time. The average first year oil price in the 2008 report
was $135.02/bbl compared to $64.17/bbl in the 2009 report. The
average first year gas price in the 2008 report was $14.31/mcf
vs. $3.82/mcf in the 2009 report. Due to the large drop in
commodity prices, many of the properties evaluated had a shorter
economic life, and therefore lower total reserves, in the 2009
report when compared to the 2008 report.
|
Standardized Measure of Discounted Future Net Cash
Flows Estimated discounted future net cash
flows and changes therein were determined in accordance with
SFAS No. 69, Disclosures About Oil and Gas
Producing Activities. Certain information concerning the
assumptions used in computing the valuation of proved reserves
and their inherent limitations are discussed below. The Company
believes such information is essential for a proper
understanding and assessment of the data presented. Future cash
inflows are computed by applying period-end prices of oil and
natural gas relating to the Companys proved reserves to
the period-end quantities of those reserves. Future price
changes are considered only to the extent provided by
contractual arrangements in existence at period-end.
ECA-52
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The assumptions used to compute estimated future net revenues do
not necessarily reflect the Companys expectations of
actual revenues or costs, or their present worth. In addition,
variations from the expected production rates also could result
directly or indirectly from factors outside of the
Companys control, such as unintentional delays in
development, changes in prices or regulatory controls. The
reserve valuation further assumes that all reserves will be
disposed of by production. However, if reserves are sold in
place, this could affect the amount of cash eventually realized.
Future development and production costs are computed by
estimating the expenditures to be incurred in developing and
producing the proved oil and natural gas reserves at the end of
the year, based on period-end costs and assuming continuation of
existing economic conditions. Future income tax expenses are
computed by applying the appropriate year-end statutory tax
rates and existing tax credits, with consideration of future tax
rates already legislated, to the future pretax net cash flows
relating to the Companys proved oil and natural gas
reserves.
An annual discount rate of 10% was used to reflect the timing of
the future net cash flows relating to proved oil and natural gas
reserves.
Information with respect to the Companys estimated
discounted future net cash flows related to its proved oil and
natural gas reserves as of June 30 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Future cash in flows
|
|
$
|
1,317,154
|
|
|
$
|
2,591,109
|
|
|
$
|
581,996
|
|
Future production and development costs
|
|
|
(283,845
|
)
|
|
|
(525,260
|
)
|
|
|
(211,575
|
)
|
Future income tax expense
|
|
|
(296,000
|
)
|
|
|
(703,000
|
)
|
|
|
(12,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows before discount
|
|
|
737,309
|
|
|
|
1,362,849
|
|
|
|
358,421
|
|
10% discount to present value
|
|
|
(476,080
|
)
|
|
|
(870,179
|
)
|
|
|
(209,748
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows related
to proved oil and gas reserves
|
|
$
|
261,229
|
|
|
$
|
492,670
|
|
|
$
|
148,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-53
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Principal changes in the standardized measure of discounted
future net cash flow for the years ended June 30 are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Standardized measure of discounted future net cash flows at
beginning of period
|
|
$
|
200,238
|
|
|
$
|
261,229
|
|
|
$
|
492,670
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(62,378
|
)
|
|
|
(73,207
|
)
|
|
|
(69,225
|
)
|
Net changes in prices and production costs
|
|
|
72,014
|
|
|
|
366,774
|
|
|
|
(558,968
|
)
|
Changes in production rates and other
|
|
|
21,544
|
|
|
|
31
|
|
|
|
(29,217
|
)
|
Extensions, discoveries and other additions, net of future
production and development costs
|
|
|
37,843
|
|
|
|
65,065
|
|
|
|
7,716
|
|
Sale of reserves in place
|
|
|
(3,112
|
)
|
|
|
|
|
|
|
|
|
Changes in estimated future development costs
|
|
|
(47,622
|
)
|
|
|
(84,572
|
)
|
|
|
(66,992
|
)
|
Development costs incurred
|
|
|
50,211
|
|
|
|
84,572
|
|
|
|
66,560
|
|
Revisions of previous quantity estimates
|
|
|
3,189
|
|
|
|
(6,393
|
)
|
|
|
(30,996
|
)
|
Purchase of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
19,772
|
|
|
|
26,302
|
|
|
|
50,498
|
|
Net change in income taxes
|
|
|
(30,470
|
)
|
|
|
(147,131
|
)
|
|
|
286,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discount future net cash flows at end of
period
|
|
$
|
261,229
|
|
|
$
|
492,670
|
|
|
$
|
148,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-54
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Balance Sheets
AS OF THE
PERIODS ENDED
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(Amounts in thousands)
|
|
|
ASSETS
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
Cash (overdraft) and cash equivalents
|
|
$
|
1,979
|
|
|
$
|
1,378
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
3,110
|
|
|
|
6,280
|
|
Gas aggregation and pipeline
|
|
|
8,040
|
|
|
|
12,520
|
|
Other
|
|
|
5,140
|
|
|
|
5,737
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
16,290
|
|
|
|
24,537
|
|
Less allowance for doubtful accounts
|
|
|
(737
|
)
|
|
|
(737
|
)
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net of allowance
|
|
|
15,553
|
|
|
|
23,800
|
|
Inventory
|
|
|
4,752
|
|
|
|
4,830
|
|
Income taxes receivable
|
|
|
1,884
|
|
|
|
1,658
|
|
Deferred income tax asset
|
|
|
1,359
|
|
|
|
1,496
|
|
Notes receivable, related party
|
|
|
70
|
|
|
|
47
|
|
Derivatives
|
|
|
30,640
|
|
|
|
12,707
|
|
Prepaid and other current assets
|
|
|
574
|
|
|
|
782
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
56,811
|
|
|
|
46,698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET PROPERTY, PLANT AND EQUIPMENT (Note 2)
|
|
|
479,722
|
|
|
|
486,039
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
Deferred financing costs, less accumulated amortization of
$2,583 and $2,970
|
|
|
1,057
|
|
|
|
681
|
|
Deferred taxes other comprehensive loss
|
|
|
237
|
|
|
|
|
|
Notes receivable, related party
|
|
|
262
|
|
|
|
292
|
|
Derivatives
|
|
|
651
|
|
|
|
7,640
|
|
Other
|
|
|
4,979
|
|
|
|
4,971
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
7,186
|
|
|
|
13,584
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
543,719
|
|
|
$
|
546,321
|
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-55
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Balance Sheets
AS OF THE
PERIODS ENDED
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(Amounts in thousands)
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
32,417
|
|
|
$
|
14,984
|
|
Current portion of long-term debt
|
|
|
212
|
|
|
|
222
|
|
Current portion of non-recourse debt
|
|
|
470
|
|
|
|
493
|
|
Funds held for future distribution
|
|
|
13,620
|
|
|
|
17,982
|
|
Accrued taxes, other than income
|
|
|
10,838
|
|
|
|
9,406
|
|
Deferred income tax liability
|
|
|
|
|
|
|
137
|
|
Deferred taxes other comprehensive income
|
|
|
11,052
|
|
|
|
4,077
|
|
Deferred revenue
|
|
|
262
|
|
|
|
246
|
|
Deferred gain
|
|
|
6,992
|
|
|
|
6,757
|
|
Derivatives
|
|
|
3,331
|
|
|
|
2,696
|
|
Other current liabilities
|
|
|
1,614
|
|
|
|
6,193
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
80,808
|
|
|
|
63,193
|
|
LONG-TERM OBLIGATIONS:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
201,826
|
|
|
|
233,961
|
|
Non-recourse debt
|
|
|
16,308
|
|
|
|
15,936
|
|
Deferred revenue
|
|
|
655
|
|
|
|
453
|
|
Deferred gain
|
|
|
68,277
|
|
|
|
63,164
|
|
Deferred income tax liability
|
|
|
53,609
|
|
|
|
57,472
|
|
Deferred taxes other comprehensive income
|
|
|
|
|
|
|
1,183
|
|
Derivatives
|
|
|
1,237
|
|
|
|
|
|
Other long-term obligations
|
|
|
20,064
|
|
|
|
19,688
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
442,784
|
|
|
|
455,050
|
|
COMMITMENTS AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY:
|
|
|
|
|
|
|
|
|
Common stock, par value $1.00; 2,000 shares authorized;
730 shares issued and 571 outstanding
|
|
|
730
|
|
|
|
730
|
|
Class A non-voting common stock, no par value;
100 shares authorized; 91 shares issued and 66 and
65 shares outstanding
|
|
|
9,787
|
|
|
|
9,867
|
|
Additional paid-in capital
|
|
|
5,503
|
|
|
|
5,503
|
|
Retained earnings
|
|
|
96,414
|
|
|
|
95,178
|
|
Treasury stock
|
|
|
(25,892
|
)
|
|
|
(25,946
|
)
|
Accumulated other comprehensive income
|
|
|
15,645
|
|
|
|
7,136
|
|
Notes receivable from the issuance of Class A stock
|
|
|
(1,252
|
)
|
|
|
(1,197
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
100,935
|
|
|
|
91,271
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
543,719
|
|
|
$
|
546,321
|
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-56
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Unaudited
Consolidated Statements of Operations
FOR THE
NINE MONTHS ENDED MARCH 31
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(Amounts in thousands, except per share data)
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
68,775
|
|
|
$
|
67,184
|
|
Gas aggregation and pipeline sales
|
|
|
99,926
|
|
|
|
62,682
|
|
Well operations and service revenues
|
|
|
5,431
|
|
|
|
5,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174,132
|
|
|
|
135,351
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
Field operating expenses
|
|
|
14,050
|
|
|
|
13,390
|
|
Gas aggregation and pipeline cost of sales
|
|
|
89,745
|
|
|
|
54,108
|
|
General and administrative
|
|
|
14,069
|
|
|
|
13,212
|
|
Taxes, other than income
|
|
|
4,021
|
|
|
|
1,261
|
|
Depletion and depreciation of oil and gas properties
|
|
|
17,716
|
|
|
|
25,805
|
|
Depreciation of pipelines, other property and equipment
|
|
|
4,572
|
|
|
|
4,748
|
|
Exploration and impairment
|
|
|
10,132
|
|
|
|
10,730
|
|
Gain on sale of assets
|
|
|
(7,360
|
)
|
|
|
(9,497
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
146,945
|
|
|
|
113,757
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
27,187
|
|
|
|
21,594
|
|
|
|
|
|
|
|
|
|
|
OTHER (INCOME) AND EXPENSE:
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
7,661
|
|
|
|
7,268
|
|
Other
|
|
|
(20,520
|
)
|
|
|
5,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,859
|
)
|
|
|
13,249
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
40,046
|
|
|
|
8,345
|
|
Income tax expense
|
|
|
17,684
|
|
|
|
3,863
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
22,362
|
|
|
$
|
4,482
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share, basic and diluted
|
|
$
|
38.06
|
|
|
$
|
7.64
|
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-57
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Unaudited
Consolidated Statements of Cash Flows
FOR THE
NINE MONTHS ENDED MARCH 31
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(Amounts in thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
22,362
|
|
|
$
|
4,482
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
22,288
|
|
|
|
30,553
|
|
Gain on sale of assets
|
|
|
(7,360
|
)
|
|
|
(9,497
|
)
|
Deferred income taxes
|
|
|
17,684
|
|
|
|
3,863
|
|
Exploration and impairment
|
|
|
9,529
|
|
|
|
10,617
|
|
Derivatives
|
|
|
(24,234
|
)
|
|
|
|
|
Other, net
|
|
|
(409
|
)
|
|
|
(232
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
39,860
|
|
|
|
39,786
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
35,383
|
|
|
|
(8,247
|
)
|
Inventory
|
|
|
(3,612
|
)
|
|
|
(79
|
)
|
Income taxes receivable
|
|
|
164
|
|
|
|
227
|
|
Prepaid and other assets
|
|
|
1,745
|
|
|
|
(206
|
)
|
Accounts payable and accrued expenses
|
|
|
(33,064
|
)
|
|
|
(15,600
|
)
|
Funds held for future distributions
|
|
|
(19,441
|
)
|
|
|
4,362
|
|
Other
|
|
|
(2,690
|
)
|
|
|
(3,074
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
18,345
|
|
|
|
17,169
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Expenditures for property, plant and equipment
|
|
|
(42,483
|
)
|
|
|
(46,873
|
)
|
Proceeds from sale of assets, net of costs
|
|
|
1,792
|
|
|
|
4,915
|
|
Notes receivable and other
|
|
|
128
|
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities from operations
|
|
|
(40,563
|
)
|
|
|
(41,988
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
77,493
|
|
|
|
89,018
|
|
Principal payment on long-term debt
|
|
|
(57,478
|
)
|
|
|
(57,223
|
)
|
Purchase of treasury stock and other financing activities
|
|
|
(703
|
)
|
|
|
(26
|
)
|
Dividends paid
|
|
|
(5,514
|
)
|
|
|
(7,551
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities from operations
|
|
|
13,798
|
|
|
|
24,218
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(8,420
|
)
|
|
|
(601
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
6,988
|
|
|
|
1,979
|
|
|
|
|
|
|
|
|
|
|
Cash (overdraft) and cash equivalents, end of period
|
|
$
|
(1,432
|
)
|
|
$
|
1,378
|
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-58
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Unaudited
Consolidated Statements of Comprehensive Income (Loss)
FOR THE
NINE MONTHS ENDED MARCH 31
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
|
(Amounts in thousands)
|
|
|
Net income
|
|
$
|
22,362
|
|
|
$
|
4,482
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment
|
|
|
|
|
|
|
|
|
Current period change
|
|
|
(269
|
)
|
|
|
(36
|
)
|
Oil and gas derivatives:
|
|
|
|
|
|
|
|
|
Current period transactions
|
|
|
77,630
|
|
|
|
7,733
|
|
Reclassification to earnings
|
|
|
(6,586
|
)
|
|
|
(17,245
|
)
|
Interest rate hedging:
|
|
|
|
|
|
|
|
|
Current period transactions
|
|
|
(3,402
|
)
|
|
|
(586
|
)
|
Reclassification to earnings
|
|
|
875
|
|
|
|
1,625
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax
|
|
|
68,248
|
|
|
|
(8,509
|
)
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
90,610
|
|
|
$
|
(4,027
|
)
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-59
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended March 31, 2010 and 2009
|
|
1.
|
NATURE OF
ORGANIZATION
|
Energy Corporation of America (the Company) was
formed in June 1993 through an exchange of shares with the
common stockholders of Eastern American Energy Corporation
(Eastern American), successor to Pacific States
Gas & Oil, Inc. which was incorporated on
September 9, 1964. The Company is an independent energy
company. All references to the Company include Energy
Corporation of America and its consolidated subsidiaries.
|
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Reference is hereby made to the Companys audited financial
statements for the fiscal year ended June 30, 2009, which
contain a summary of major accounting policies the Company
follows in preparation of its consolidated financial statement.
Those policies were also followed in preparing the unaudited
interim consolidated financial statements included herein.
Management of the Company believes that all adjustments,
consisting of only normal recurring accruals, necessary for a
fair presentation of the results of such interim periods have
been made. The results of operations for the nine months ended
March 31, 2010 are not necessarily indicative of the
results to be expected for the full year.
Recent Accounting Pronouncements In June
2009, the FASB issued a statement that establishes the FASB
Accounting Standards Codification as the source of authoritative
U.S. generally accepted accounting principles
(U.S. GAAP). The Codification, which changes the
referencing of financial standards, became effective for the
period ended June 30, 2010. The Codification did not change
or alter existing U.S. GAAP.
On July 1, 2009, the Company adopted FASB Interpretation
No. 48, Accounting for Uncertainty in Income
Taxes, now codified in Accounting Standards Codification
(ASC)
740-10,
which clarifies the accounting for uncertainty in income taxes.
Adoption of this interpretation did not have a material impact
on the Companys financial position. The Companys
policy is to reflect potential interest and penalties related to
uncertain tax positions as part of interest and penalty expense,
respectively, when and if they become applicable.
In January 2010, the FASB issued ASU
2010-03
Extractive Activities Oil and Gas, (Topic
932): Oil and Gas Reserve Estimation in order to align the
oil and natural gas reserve estimation and disclosure
requirements with the SECs final rule Modernization
of the Oil and Gas Requirements. ASU
2010-03 is
effective for annual reporting periods ending on or after
December 31, 2009. The statement amends the definition of
proved oil and natural gas reserves and requires all entities to
use the average
first-day-of-month
price during the twelve months period before the ending date
when estimating reserve quantities.
The Companys reportable business segments have been
identified based on the differences in products and service
provided. Revenues for the exploration and production segment
are derived from the production and sale of natural gas and
crude oil. Revenues for the aggregation and pipeline segment
arise from the aggregation of both Company and third party
produced natural gas volumes and the related transportation. The
Other column includes items related to
ECA-60
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended March 31, 2010 and
2009 (Continued)
corporate activities. Management utilizes earnings before
interest, income taxes, depreciation, depletion, amortization
and impairment and exploratory costs (EBITDAX), a
non-GAAP financial measure, to evaluate each segments
operations.
Reconciliation of non-GAAP financial measure is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
March 31,
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
Net income
|
|
$
|
22,362
|
|
|
$
|
4,482
|
|
Add:
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
7,661
|
|
|
|
7,268
|
|
Depletion and depreciation of oil and gas properties
|
|
|
17,716
|
|
|
|
25,805
|
|
Depreciation of pipelines, other property and equipment
|
|
|
4,572
|
|
|
|
4,748
|
|
Exploration and impairment
|
|
|
10,132
|
|
|
|
10,730
|
|
Income tax expense
|
|
|
17,684
|
|
|
|
3,863
|
|
Change in fair value derivatives
|
|
|
(24,234
|
)
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
|
|
$
|
55,893
|
|
|
$
|
56,899
|
|
|
|
|
|
|
|
|
|
|
Summarized financial information for the Companys
reportable segments is shown in the following table (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
|
Aggregation and
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
Pipeline
|
|
|
Other
|
|
|
Consolidated
|
|
|
Nine Months Ended March 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
$
|
74,206
|
|
|
$
|
99,926
|
|
|
$
|
|
|
|
$
|
174,132
|
|
Depreciation, depletion, amortization
|
|
|
18,906
|
|
|
|
2,410
|
|
|
|
972
|
|
|
|
22,288
|
|
Exploratory costs
|
|
|
10,132
|
|
|
|
|
|
|
|
|
|
|
|
10,132
|
|
Operating profit
|
|
|
14,299
|
|
|
|
5,358
|
|
|
|
7,530
|
|
|
|
27,187
|
|
Interest (net)
|
|
|
13,193
|
|
|
|
(5,928
|
)
|
|
|
289
|
|
|
|
7,554
|
|
Other (income) & expense
|
|
|
(25,784
|
)
|
|
|
|
|
|
|
5,370
|
|
|
|
(20,414
|
)
|
EBITDAX
|
|
|
33,135
|
|
|
|
12,279
|
|
|
|
10,479
|
|
|
|
55,893
|
|
Total assets
|
|
|
471,387
|
|
|
|
42,486
|
|
|
|
31,111
|
|
|
|
544,984
|
|
Capital expenditures
|
|
|
40,077
|
|
|
|
2,228
|
|
|
|
178
|
|
|
|
42,483
|
|
ECA-61
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended March 31, 2010 and
2009 (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
|
Aggregation and
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
Pipeline
|
|
|
Other
|
|
|
Consolidated
|
|
|
Nine Months Ended March 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
$
|
72,670
|
|
|
$
|
62,681
|
|
|
$
|
|
|
|
$
|
135,351
|
|
Depreciation, depletion, amortization
|
|
|
26,972
|
|
|
|
2,609
|
|
|
|
972
|
|
|
|
30,553
|
|
Exploratory costs
|
|
|
10,730
|
|
|
|
|
|
|
|
|
|
|
|
10,730
|
|
Operating profit
|
|
|
16,426
|
|
|
|
3,095
|
|
|
|
2,073
|
|
|
|
21,594
|
|
Interest (net)
|
|
|
5,819
|
|
|
|
(3,922
|
)
|
|
|
5,319
|
|
|
|
7,216
|
|
Other (income) & expense
|
|
|
217
|
|
|
|
(4
|
)
|
|
|
5,819
|
|
|
|
6,032
|
|
EBITDAX
|
|
|
49,820
|
|
|
|
7,928
|
|
|
|
(849
|
)
|
|
|
56,899
|
|
Total assets
|
|
|
469,612
|
|
|
|
44,766
|
|
|
|
31,943
|
|
|
|
546,321
|
|
Capital expenditures
|
|
|
42,266
|
|
|
|
4,543
|
|
|
|
64
|
|
|
|
46,873
|
|
Operating profit represents revenues less costs which are
directly associated with such operations.
The Company is exposed to certain risks relating to its ongoing
business operations. The primary risks managed by using
derivative instruments are commodity price risk and interest
rate risk. Swaps and agreements on natural gas and oil
commodities are entered into to manage the price risk associated
with forecasted sales. Interest rate swaps are entered into to
manage interest rate risk associated with the Companys
variable-rate borrowings.
Companies are required to recognize all derivative instruments
as either assets or liabilities at fair value in the statement
of financial position (balance sheet). The Company designates
commodity swap agreements as cash flow hedges of forecasted
sales of commodities and interest rate swaps as cash flow hedges
of variable-rate borrowings.
Cash
flow hedges
For derivative instruments that are designated and qualify a
cash flow hedge, the effective portion of the gain or loss on
the derivative is reported as a component of other comprehensive
income and reclassified into earnings in the same period or
periods during which the hedged transaction affects earnings.
Gains and losses on the derivative representing hedge
ineffectiveness are recognized in current earnings. All parts of
gain or loss on these derivatives are included in the assessment
of hedge effectiveness.
Commodity swap agreements involve payments to or receipts from
counterparties based on the differential between a fixed and
variable price for the commodity. Certain swap instruments used
by the Company do not qualify as cash flow hedges.
Exchange-traded instruments are generally settled with
offsetting positions. Over the counter (OTC) arrangements
require settlement in cash.
ECA-62
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended March 31, 2010 and
2009 (Continued)
As of March 31, 2010 and June 30, 2009, the Company
had the following outstanding commodity swaps and floors that
were entered into to hedge forecasted sales:
|
|
|
|
|
|
|
|
|
|
|
Volumes
|
Commodity
|
|
March 31, 2010
|
|
June 30, 2009
|
|
Natural gas swaps
|
|
|
7,120,500 MMBtu
|
|
|
|
10,332,000 MMBtu
|
|
Natural gas floors
|
|
|
11,268,000 MMBtu
|
|
|
|
MMBtu
|
|
Oil
|
|
|
Bbl
|
|
|
|
18,000 Bbl
|
|
The open positions at March 31, 2010 had maturities for
natural gas swaps extending through June 2012 and maturities for
floors extending through March 2014. We expect that $7,288,000
of deferred net gains on commodity swaps in other comprehensive
income at March 31, 2010 will be reclassified as earnings
during the next twelve months.
Interest rate swap agreements involve payments to or receipts
from counterparties based on the differential between a fixed
interest rate and a variable interest rate applicable to a
specified amount of debt. During November 2007 and January 2008,
the Company entered into three interest-rate swap agreements
with Wells Fargo Foothill, Inc. in an effort to reduce the
potential impact of increases in interest rates on floating-rate
long-term debt.
The three-year agreements cover $100 million in long-term
debt and fix the one-month London Interbank Offered Rate
(LIBOR) over a range of 3.67% to 4.05%. The Company
has partially hedged its exposure to the variability in future
cash flows through January 2011. We expect that $1,512,000 of
deferred net losses on interest rate swaps in other
comprehensive income at March 31, 2010 will be reclassified
into earnings during the next twelve months.
ECA-63
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended March 31, 2010 and
2009 (Continued)
Fair values for derivatives are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
Liability Derivatives
|
|
Derivatives Designated as Hedging
|
|
03/31/10
|
|
|
06/30/09
|
|
|
03/31/10
|
|
|
06/30/09
|
|
Instruments under ASC 815
|
|
Fair Value
|
|
|
Fair Value
|
|
|
Fair Value
|
|
|
Fair Value
|
|
|
Current: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
12,707
|
|
|
$
|
30,640
|
|
|
$
|
112
|
|
|
$
|
281
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
2,584
|
|
|
|
3,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,707
|
|
|
|
30,640
|
|
|
|
2,696
|
|
|
|
3,331
|
|
Long-term: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
|
7,640
|
|
|
|
651
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,640
|
|
|
|
651
|
|
|
|
|
|
|
|
1,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Derivatives designated as
hedging instruments under ASC 815
|
|
$
|
20,347
|
|
|
$
|
31,291
|
|
|
$
|
2,696
|
|
|
$
|
4,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Derivatives not Designated
|
|
|
|
|
|
|
|
|
|
|
|
|
as hedging instruments under ASC 815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Long-term: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Derivatives not designated as
hedging instruments under ASC 815
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
20,347
|
|
|
$
|
31,291
|
|
|
$
|
2,696
|
|
|
$
|
4,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Included in Derivatives under
Current Assets and Current Liabilities.
|
|
(2)
|
|
Included in Derivatives under Other
Assets and Long-term Obligations.
|
All of the Companys derivative instruments are classified
as level 2 fair value measurements.
ECA-64
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended March 31, 2010 and
2009 (Continued)
The following table shows the gains (losses) recognized related
to derivatives in ASC 815 cash flow hedging relationships:
The
Effect of Derivative Instruments on the Statement of
Operations
for the Nine Months Ended March 31, 2010 and March 31,
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain
|
|
|
|
|
|
|
|
|
|
or (Loss) Reclassified
|
|
|
|
Amount of Gain or
|
|
|
from Accumulated
|
|
|
|
(Loss) Recognized in OCI on Derivative
|
|
|
OCI into Income
|
|
Derivatives in ASC 815
|
|
(Effective Portion)
|
|
|
(Effective Portion) (1)
|
|
Cash Flow Hedging Relationships
|
|
3/31/10
|
|
|
3/31/09
|
|
|
3/31/10
|
|
|
3/31/09
|
|
|
Commodity contracts
|
|
$
|
13,219
|
|
|
$
|
130,471
|
|
|
$
|
29,479
|
(2)
|
|
$
|
11,070
|
|
Interest rate contracts
|
|
|
(1,002
|
)
|
|
|
(5,718
|
)
|
|
|
(2,779
|
) (3)
|
|
|
(1,470
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
12,217
|
|
|
$
|
124,753
|
|
|
$
|
26,700
|
|
|
$
|
9,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain or
|
|
|
|
(Loss) Recognized in
|
|
Derivatives in ASC 815
|
|
Income on Derivative (Ineffective Portion)
|
|
Cash Flow Hedging Relationships
|
|
3/31/10
|
|
|
3/31/09
|
|
|
Commodity contracts
|
|
$
|
(2
|
) (4)
|
|
$
|
282
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(2
|
) (4)
|
|
$
|
282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain
|
|
|
|
or (Loss) Recognized in Income
|
|
Derivatives not Designated as
|
|
on Derivative
|
|
Hedging Instruments Under ASC 815
|
|
3/31/10
|
|
|
3/31/09
|
|
|
Commodity contracts
|
|
$
|
27
|
(4)
|
|
$
|
27,661
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
If gains and losses associated with
a type of contract (for example, commodity contracts) are
displayed in multiple line items in the income statement, the
entity is required to disclose the amount included in each line
item.
|
|
(2)
|
|
Included in Oil and gas sales.
|
|
(3)
|
|
Included in Interest expense.
|
|
(4)
|
|
Included in Other (income) expense.
|
|
|
5.
|
COMMITMENTS
AND CONTINGENCIES
|
The Company is involved in various legal actions and claims
arising in the ordinary course of business. Management does not
expect that any matter pending against the Company will have a
material adverse effect on the Companys financial position
or results of operations and has established reserves that it
believes are adequate.
ECA-65
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended March 31, 2010 and
2009 (Continued)
|
|
6.
|
OTHER
COMPREHENSIVE INCOME (LOSS)
|
At March 31, 2010 and June 30, 2009 accumulated other
comprehensive income (loss) (net of tax) consisted of the
following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
March 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
Foreign currency translation
|
|
$
|
(243
|
)
|
|
$
|
(279
|
)
|
Oil and gas hedging
|
|
|
18,439
|
|
|
|
8,927
|
|
Interest rate hedging
|
|
|
(2,551
|
)
|
|
|
(1,512
|
)
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income
|
|
$
|
15,645
|
|
|
$
|
7,136
|
|
|
|
|
|
|
|
|
|
|
For the nine months ended March 31, 2010 and 2009, the
Company established a valuation allowance of $0.4 million
and $1.5 million, respectively, related to the
Companys charitable contribution carryforwards as the
Company does not currently believe that it is more likely than
not that all of the federal and state charitable contribution
carryforwards will be fully utilized during their respective
statutory carryforward periods.
|
|
8.
|
FAIR
VALUE MEASUREMENTS
|
The Company has categorized its financial statements into a
three-level fair value hierarchy based on the priority of the
inputs to the valuation technique. All of the Companys
derivative contracts (see Note 3) are included in
Level 2. The Companys carrying value for Notes
Receivable and Long-term Debt approximate fair value.
ECA-66
ANNEX A
SUMMARY
RESERVE REPORTS
May 26, 2010
Energy Corporation of America
501 56th Street
Charleston, West Virginia 25304
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared
an estimate of the proved reserves, future production, and
income attributable to certain leasehold and royalty interests
in the underlying properties of the ECA Marcellus Trust I
as of March 31, 2010. The subject properties are located in
the state of Pennsylvania. The reserves and income data were
estimated based on the definitions and disclosure guidelines of
the United States Securities and Exchange Commission (SEC)
contained in Title 17, Code of Federal Regulations,
Modernization of Oil and Gas Reporting, Final Rule released
January 14, 2009 in the Federal Register (SEC regulations).
The results of our third party study are presented herein. The
properties reviewed by Ryder Scott represent 100 percent of
the total net proved gas reserves of the underlying properties
of the ECA Marcellus Trust I.
The estimated reserves and future net income amounts presented
in this report, as of March 31, 2010 are related to
hydrocarbon prices. The hydrocarbon prices used in the
preparation of this report are based on the average prices
during the
12-month
period prior to the ending date of the period covered in this
report, determined as unweighted arithmetic averages of the
prices in effect on the
first-day-of-the-month
for each month within such period, unless prices were defined by
contractual arrangements as required by the SEC regulations.
Actual future prices may vary significantly from the prices
required by SEC regulations; therefore, volumes of reserves
actually recovered and the amounts of income actually received
may differ significantly from the estimated quantities presented
in this report. The results of this study are summarized below.
SEC
PARAMETERS
Estimated
Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
ECA Marcellus Trust I Underlying
Properties
As of March 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
|
Developed
|
|
|
|
|
|
|
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Undeveloped
|
|
|
Total Proved
|
|
|
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas MMCF
|
|
|
21,593
|
|
|
|
20,426
|
|
|
|
159,933
|
|
|
|
201,952
|
|
Income Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Gross Revenue
|
|
$
|
91,856,287
|
|
|
$
|
86,890,454
|
|
|
$
|
680,336,862
|
|
|
$
|
859,083,603
|
|
Deductions
|
|
|
13,631,533
|
|
|
|
26,213,563
|
|
|
|
283,803,746
|
|
|
|
323,648,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Income (FNI)
|
|
$
|
78,224,754
|
|
|
$
|
60,676,891
|
|
|
$
|
396,533,116
|
|
|
$
|
535,434,761
|
|
Discounted FNI @ 10%
|
|
$
|
41,333,031
|
|
|
$
|
25,401,481
|
|
|
$
|
108,665,636
|
|
|
$
|
175,400,148
|
|
A-1
Energy Corporation of America
May 26, 2010
Page 2
All gas volumes are reported on an as sold basis
expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas
reserves are located.
The estimates of the reserves, future production, and income
attributable to properties in this report were prepared using
the economic software package PHDWin Petroleum Economic
Evaluation Software, a copyrighted program of TRC Consultants
L.C. Ryder Scott has found this program to be generally
acceptable, but notes that certain summaries and calculations
may vary due to rounding and may not exactly match the sum of
the properties being summarized. Furthermore, one line economic
summaries may vary slightly from the more detailed cash flow
projections of the same properties, also due to rounding. The
rounding differences are not material.
The future gross revenue is normally after the deduction of
production taxes but in the State of Pennsylvania there is no
production tax. The deductions incorporate the normal direct
costs of operating the wells, gas transportation costs,
completion costs and development costs. The future net income is
before the deduction of state and federal income taxes and
general administrative overhead, and has not been adjusted for
outstanding loans that may exist nor does it include any
adjustment for cash on hand or undistributed income. Gas
reserves account for the remaining 100 percent of total
future gross revenue from proved reserves.
The discounted future net income shown above was calculated
using a discount rate of 10 percent per annum compounded
monthly. Future net income was discounted at four other discount
rates which were also compounded monthly. These results are
shown in summary form as follows.
|
|
|
|
|
|
|
Discounted Future Net Income
|
|
|
|
As of March 31, 2010
|
|
Discount Rate Percent
|
|
Total Proved
|
|
|
5
|
|
$
|
290,377,123
|
|
8
|
|
$
|
212,681,985
|
|
12
|
|
$
|
145,886,934
|
|
15
|
|
$
|
111,868,628
|
|
The results shown above are presented for your information and
should not be construed as our estimate of fair market value.
Reserves
Included in This Report
The proved reserves included herein conform to the definition as
set forth in the Securities and Exchange Commissions
Regulations
Part 210.4-10(a).
An abridged version of the SEC reserves definitions from
210.4-10(a) entitled Petroleum Reserves Definitions
is included as an attachment to this report.
The various reserve status categories are defined under the
attachment entitled Petroleum Reserves Definitions
in this report. The developed non-producing reserves included
herein consist of the behind pipe and shut-in categories.
A-2
Energy Corporation of America
May 26, 2010
Page 3
No attempt was made to quantify or otherwise account for any
accumulated gas production imbalances that may exist. The gas
volumes included herein do not attribute gas consumed in
operations as reserves.
Reserves are those estimated remaining quantities of petroleum
which are anticipated to be economically producible, as of a
given date, from known accumulations under defined conditions.
All reserve estimates involve some degree of uncertainty. The
uncertainty depends chiefly on the amount of reliable geologic
and engineering data available at the time of the estimate and
the interpretation of these data. The relative degree of
uncertainty may be conveyed by placing reserves into one of two
principal classifications, either proved or unproved. Unproved
reserves are less certain to be recovered than proved reserves
and may be further
sub-classified
as probable and possible reserves to denote progressively
increasing uncertainty in their recoverability. At ECA Marcellus
Trust Is request, this report addresses only the
proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible from a given date forward. The reserves included
herein were estimated using deterministic methods.
Reserves estimates will generally be revised as additional
geologic or engineering data become available or as economic
conditions change. Moreover, estimates of reserves may increase
or decrease as a result of future operations, effects of
regulation by governmental agencies or economic risks. As a
result, the estimates of oil and gas reserves have an intrinsic
uncertainty. The reserves included in this report are therefore
estimates only and should not be construed as being exact
quantities. They may or may not be actually recovered, and if
recovered, the revenues therefrom, and the actual costs related
thereto, could be more or less than the estimated amounts.
The estimates of reserves presented herein were based upon a
detailed study of the underlying properties in which ECA
Marcellus Trust I and Energy Corporation of America owns an
interest; however, we have not made any field examination of the
properties. No consideration was given in this report to
potential environmental liabilities that may exist nor were any
costs included for potential liability to restore and clean up
damages, if any, caused by past operating practices.
Estimates
of Reserves
The estimation of reserves involves two distinct determinations.
The first determination results in the estimation of the
quantities of recoverable oil and gas and the second
determination results in the estimation of the uncertainty
associated with those estimated quantities in accordance with
the definitions set forth by the Securities and Exchange
Commissions Regulations
Part 210.4-10(a).
The process of estimating the quantities of recoverable oil and
gas reserves relies on the use of certain generally accepted
analytical procedures. These analytical procedures fall into
three broad categories or methods: (1) performance-based
methods, (2) volumetric-based methods and (3) analogy.
These methods may be used singularly or in combination by the
reserve evaluator in the process of estimating the quantities of
reserves. The reserve evaluator must select the method or
combination of methods which in their professional judgment is
most appropriate given the nature and amount of reliable
geoscience and engineering data available at the time of the
estimate, the established or anticipated performance
A-3
Energy Corporation of America
May 26, 2010
Page 4
characteristics of the reservoir being evaluated and the stage
of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and
engineering data and the subsequent interpretation of this data
may indicate a range of possible outcomes in an estimate
irrespective of the method selected by the evaluator. When a
range in the quantity of reserves is identified, the evaluator
must determine the uncertainty associated with the incremental
quantities of the reserves. If the reserve quantities are
estimated using the deterministic incremental approach, the
uncertainty for each discrete incremental quantity of the
reserves is addressed by the reserve category assigned by the
evaluator. Therefore, it is the categorization of reserve
quantities as proved, probable
and/or
possible that addresses the inherent uncertainty in the
estimated quantities reported. All quantities of reserves within
the same reserve category have the same level of uncertainty
under the SEC definitions.
Estimates of reserves quantities and their associated reserve
categories may be revised in the future as additional geoscience
or engineering data become available. Furthermore, estimates of
reserves quantities and their associated reserve categories may
also be revised due to other factors such as changes in economic
conditions, results of future operations, effects of regulation
by governmental agencies or economic risks as previously noted
herein.
The reserves for the properties included herein were estimated
by performance methods or by analogy. In general, reserves
attributable to producing wells were estimated by performance
methods such as decline curve analysis which utilized
extrapolations of historical production through April, 2010. In
certain cases, producing reserves were estimated by a
combination of performance and analogy if there was inadequate
historical performance data to establish a definitive trend and
where the use of production performance data as the sole basis
for the reserve estimates was considered to be inappropriate.
Reserves attributable to non-producing and undeveloped reserves
included herein were estimated by the analogy method which
utilized all pertinent well and seismic data available through
April, 2010.
To estimate economically recoverable oil and gas reserves and
related future net cash flows, we consider many factors and
assumptions including, but not limited to, the use of reservoir
parameters derived from geological and engineering data which
cannot be measured directly, economic criteria based on current
costs and SEC pricing requirements, and forecasts of future
production rates. Under the SEC regulations 210.4-10(a)(22)(v)
and (26), proved reserves must be anticipated to be economically
producible based on existing economic conditions including the
prices and costs at which economic producibility from a
reservoir is to be determined. While it may reasonably be
anticipated that the future prices received for the sale of
production and the operating costs and other costs relating to
such production may also increase or decrease from existing
levels, such changes were, in accordance with rules adopted by
the SEC, omitted from consideration in making this evaluation.
Energy Corporation of America has informed us that they have
furnished us all of the accounts, records, geological and
engineering data, and reports and other data required for this
investigation. In preparing our forecast of future production
and income, we have relied upon data furnished by Energy
Corporation of America with respect to property interests owned,
production and well tests from examined wells, normal direct
costs of operating the wells or leases, other costs such as
transportation
and/or
processing fees, ad valorem and production taxes, completion and
development costs, product prices based on the SEC regulations.
Ryder
A-4
Energy Corporation of America
May 26, 2010
Page 5
Scott reviewed such factual data for its reasonableness;
however, we have not conducted an independent verification of
the data supplied by Energy Corporation of America. We consider
the assumptions, data, methods and procedures used in this
report appropriate for the purpose hereof, and we have used all
such methods and procedures that we consider necessary and
appropriate to prepare the estimates of reserves and future net
revenues herein.
Future
Production Rates
Our forecasts of future production rates are based on historical
performance from wells now on production. Test data and other
related information were used to estimate the anticipated
initial production rates for those wells or locations that are
not currently producing. If no production decline trend has been
established, future production rates were held constant, or
adjusted for the effects of curtailment where appropriate, until
a decline in ability to produce was anticipated. An estimated
rate of decline was then applied to depletion of the reserves.
If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves
not yet on production, sales were estimated to commence at an
anticipated date furnished by Energy Corporation of America.
The future production rates from wells now on production may be
more or less than estimated because of changes in market demand
or allowables set by regulatory bodies. Wells or locations that
are not currently producing may start producing earlier or later
than anticipated in our estimates.
Hydrocarbon
Prices
As previously stated, the hydrocarbon prices used herein are
based SEC price parameters using the average prices during the
12-month
period prior to the ending date of the period covered in this
report, determined as the unweighted arithmetic averages of the
prices in effect on the
first-day-of-the-month
for each month within such period, unless prices were defined by
contractual arrangements. For hydrocarbon products sold under
contract, the contract prices including fixed and determinable
escalations, exclusive of inflation adjustments, were used until
expiration of the contract. Upon contract expiration, the prices
were adjusted to the
12-month
unweighted arithmetic average as previously described. Product
prices which were actually used for each property reflect
adjustment for gravity, quality, local conditions,
and/or
distance from market.
The effects of derivative instruments designated as price hedges
of oil and gas quantities are not reflected in our individual
property evaluations.
Costs
Operating costs for the leases and wells in this report are
supplied by Energy Corporation of America and include only those
costs directly applicable to the leases or wells. The operating
costs include a portion of general and administrative costs
allocated directly to the leases and wells. For operated
properties, the operating costs include an appropriate level of
corporate general administrative and overhead costs. No
deduction was made for loan repayments, interest expenses, or
exploration and development prepayments that were not charged
directly to the leases or wells.
A-5
Energy Corporation of America
May 26, 2010
Page 6
Development costs were furnished to us by Energy Corporation of
America and are based on authorizations for expenditure for the
proposed work or actual costs for similar projects. Energy
Corporation of Americas estimates of zero abandonment
costs after salvage value were used in this report. Ryder Scott
has not performed a detailed study of the abandonment costs or
the salvage value and makes no warranty for Energy
Corporation of Americas estimate.
Because of the direct relationship between volumes of proved
undeveloped reserves and development plans, we include in the
proved undeveloped category only reserves assigned to
undeveloped locations that we have been assured will definitely
be drilled. Energy Corporation of America has assured us of
their intent and ability to proceed with the development
activities included in this report, and that they are not aware
of any legal, regulatory, political or economic obstacles that
would significantly alter their plans.
Current costs used by Energy Corporation of America were held
constant throughout the life of the properties.
Standards
of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting
firm that has been providing petroleum consulting services
throughout the world for over seventy years. Ryder Scott is
employee-owned and maintains offices in Houston, Texas; Denver,
Colorado; and Calgary, Alberta, Canada. We have over eighty
engineers and geoscientists on our permanent staff. By virtue of
the size of our firm and the large number of clients for which
we provide services, no single client or job represents a
material portion of our annual revenue. We do not serve as
officers or directors of any publicly-traded oil and gas company
and are separate and independent from the operating and
investment decision-making process of our clients. This allows
us to bring the highest level of independence and objectivity to
each engagement for our services.
Ryder Scott actively participates in industry related
professional societies and organizes an annual public forum
focused on the subject of reserves evaluations and SEC
regulations. Many of our staff have authored or co-authored
technical papers on the subject of reserves related topics. We
encourage our staff to maintain and enhance their professional
skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott
requires that staff engineers and geoscientists have received
professional accreditation in the form of a registered or
certified professional engineers license or a registered
or certified professional geoscientists license, or the
equivalent thereof, from an appropriate governmental authority
or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to ECA
Marcellus Trust I and Energy Corporation of America.
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to do this work
nor the compensation is contingent on our estimates of reserves
for the properties which were reviewed.
The professional qualifications of the undersigned, the
technical person primarily responsible for evaluating the
reserves information discussed in this report, are included as
an attachment to this letter.
A-6
Energy Corporation of America
May 26, 2010
Page 7
Terms of
Usage
The results of our third party study, presented in report form
herein, were prepared in accordance with the disclosure
requirements set forth in the SEC regulations and intended for
public disclosure as an exhibit in filings made with the SEC by
ECA Marcellus Trust I. We have provided our written consent
to ECA Marcellus Trust I for the references to our name as
well as to the references to our third party report in filings
made by ECA Marcellus Trust I with the SEC. Our consent for
such use is included as a separate exhibit to the filings made
with the SEC by ECA Marcellus Trust I.
We have provided ECA Marcellus Trust I with a digital
version of the original signed copy of this report letter. In
the event there are any differences between the digital version
included in filings made by ECA Marcellus Trust I and the
original signed report letter, the original signed report letter
shall control and supersede the digital version.
The data and work papers used in the preparation of this report
are available for examination by authorized parties in our
offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration
No. F-1580
Managing Senior Vice President
/sm
A-7
May 26, 2010
Energy Corporation of America
501 56th Street
Charleston, West Virginia 25304
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared
an estimate of the proved reserves, future production, and
income attributable to certain royalty interests of ECA
Marcellus Trust I as of March 31, 2010. The subject
properties are located in the state of Pennsylvania. The
reserves and income data were estimated based on the definitions
and disclosure guidelines of the United States Securities and
Exchange Commission (SEC) contained in Title 17, Code of
Federal Regulations, Modernization of Oil and Gas Reporting,
Final Rule released January 14, 2009 in the Federal
Register (SEC regulations). The results of our third party study
are presented herein. The properties reviewed by Ryder Scott
represent 100 percent of the total net proved gas reserves
of ECA Marcellus Trust I.
The estimated reserves and future net income amounts presented
in this report, as of March 31, 2010 are related to
hydrocarbon prices. The hydrocarbon prices used in the
preparation of this report are based on the average prices
during the
12-month
period prior to the ending date of the period covered in this
report, determined as unweighted arithmetic averages of the
prices in effect on the
first-day-of-the-month
for each month within such period, unless prices were defined by
contractual arrangements as required by the SEC regulations.
Actual future prices may vary significantly from the prices
required by SEC regulations; therefore, volumes of reserves
actually recovered and the amounts of income actually received
may differ significantly from the estimated quantities presented
in this report. The results of this study are summarized below.
SEC
PARAMETERS
Estimated
Net Reserves and Income Data
Certain Royalty Interests of
ECA Marcellus Trust I
As of March 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
|
Developed
|
|
|
|
|
|
|
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Undeveloped
|
|
|
Total Proved
|
|
|
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas MMCF
|
|
|
18,052
|
|
|
|
17,096
|
|
|
|
73,492
|
|
|
|
108,640
|
|
Income Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Gross Revenue
|
|
$
|
76,792,991
|
|
|
$
|
72,722,589
|
|
|
$
|
312,629,676
|
|
|
$
|
462,145,256
|
|
Deductions
|
|
|
9,668,851
|
|
|
|
9,156,355
|
|
|
|
39,362,574
|
|
|
|
58,187,780
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Income (FNI)
|
|
$
|
67,124,140
|
|
|
$
|
63,566,233
|
|
|
$
|
273,267,102
|
|
|
$
|
403,957,475
|
|
Discounted FNI @ 10%
|
|
$
|
37,513,570
|
|
|
$
|
35,046,066
|
|
|
$
|
133,315,041
|
|
|
$
|
205,874,677
|
|
All gas volumes are reported on an as sold basis
expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas
reserves are located.
A-8
Energy Corporation of America
May 26, 2010
Page 2
The estimates of the reserves, future production, and income
attributable to properties in this report were prepared using
the economic software package PHDWin Petroleum Economic
Evaluation Software, a copyrighted program of TRC Consultants
LC. Ryder Scott has found this program to be generally
acceptable, but notes that certain summaries and calculations
may vary due to rounding and may not exactly match the sum of
the properties being summarized. Furthermore, one line economic
summaries may vary slightly from the more detailed cash flow
projections of the same properties, also due to rounding. The
rounding differences are not material.
The future gross revenue is normally after the deduction of
production taxes but in the State of Pennsylvania this is zero.
For ECA Marcellus Trust I, the deductions only incorporate
gas transportation costs since the Trust will own only a royalty
interest. The future net income is before the deduction of state
and federal income taxes and general administrative overhead,
and has not been adjusted for outstanding loans that may exist
nor does it include any adjustment for cash on hand or
undistributed income. Gas reserves account for the remaining
100 percent of total future gross revenue from proved
reserves.
The discounted future net income shown above was calculated
using a discount rate of 10 percent per annum compounded
monthly. Future net income was discounted at four other discount
rates which were also compounded monthly. These results are
shown in summary form as follows.
|
|
|
|
|
|
|
Discounted Future Net Income
|
|
|
As of March 31, 2010
|
Discount Rate Percent
|
|
Total Proved
|
|
5
|
|
$
|
274,464,023
|
|
8
|
|
$
|
228,920,835
|
|
12
|
|
$
|
186,931,751
|
|
15
|
|
$
|
164,145,346
|
|
The results shown above are presented for your information and
should not be construed as our estimate of fair market value.
Reserves
Included in This Report
The proved reserves included herein conform to the definition as
set forth in the Securities and Exchange Commissions
Regulations
Part 210.4-10(a).
An abridged version of the SEC reserves definitions from
210.4-10(a) entitled Petroleum Reserves Definitions
is included as an attachment to this report.
The various reserve status categories are defined under the
attachment entitled Petroleum Reserves Definitions
in this report. The developed non-producing reserves included
herein consist of the behind pipe and shut-in categories.
No attempt was made to quantify or otherwise account for any
accumulated gas production imbalances that may exist. The gas
volumes included herein do not attribute gas consumed in
operations as reserves.
A-9
Energy Corporation of America
May 26, 2010
Page 3
Reserves are those estimated remaining quantities of petroleum
which are anticipated to be economically producible, as of a
given date, from known accumulations under defined conditions.
All reserve estimates involve some degree of uncertainty. The
uncertainty depends chiefly on the amount of reliable geologic
and engineering data available at the time of the estimate and
the interpretation of these data. The relative degree of
uncertainty may be conveyed by placing reserves into one of two
principal classifications, either proved or unproved. Unproved
reserves are less certain to be recovered than proved reserves
and may be further
sub-classified
as probable and possible reserves to denote progressively
increasing uncertainty in their recoverability. At ECA Marcellus
Trust Is request, this report addresses only the
proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible from a given date forward. The reserves included
herein were estimated using deterministic methods.
Reserves estimates will generally be revised as additional
geologic or engineering data become available or as economic
conditions change. Moreover, estimates of reserves may increase
or decrease as a result of future operations, effects of
regulation by governmental agencies or economic risks. As a
result, the estimates of oil and gas reserves have an intrinsic
uncertainty. The reserves included in this report are therefore
estimates only and should not be construed as being exact
quantities. They may or may not be actually recovered, and if
recovered, the revenues therefrom, and the actual costs related
thereto, could be more or less than the estimated amounts.
The estimates of reserves presented herein were based upon a
detailed study of the properties in which ECA Marcellus
Trust I owns an interest; however, we have not made any
field examination of the properties. No consideration was given
in this report to potential environmental liabilities that may
exist nor were any costs included for potential liability to
restore and clean up damages, if any, caused by past operating
practices.
Estimates
of Reserves
The estimation of reserves involves two distinct determinations.
The first determination results in the estimation of the
quantities of recoverable oil and gas and the second
determination results in the estimation of the uncertainty
associated with those estimated quantities in accordance with
the definitions set forth by the Securities and Exchange
Commissions Regulations
Part 210.4-10(a).
The process of estimating the quantities of recoverable oil and
gas reserves relies on the use of certain generally accepted
analytical procedures. These analytical procedures fall into
three broad categories or methods: (1) performance-based
methods, (2) volumetric-based methods and (3) analogy.
These methods may be used singularly or in combination by the
reserve evaluator in the process of estimating the quantities of
reserves. The reserve evaluator must select the method or
combination of methods which in their professional judgment is
most appropriate given the nature and amount of reliable
geoscience and engineering data available at the time of the
estimate, the established or anticipated performance
characteristics of the reservoir being evaluated and the stage
of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and
engineering data and the subsequent interpretation of this data
may indicate a range of possible outcomes in an estimate
A-10
Energy Corporation of America
May 26, 2010
Page 4
irrespective of the method selected by the evaluator. When a
range in the quantity of reserves is identified, the evaluator
must determine the uncertainty associated with the incremental
quantities of the reserves. If the reserve quantities are
estimated using the deterministic incremental approach, the
uncertainty for each discrete incremental quantity of the
reserves is addressed by the reserve category assigned by the
evaluator. Therefore, it is the categorization of reserve
quantities as proved, probable
and/or
possible that addresses the inherent uncertainty in the
estimated quantities reported. All quantities of reserves within
the same reserve category have the same level of uncertainty
under the SEC definitions.
Estimates of reserves quantities and their associated reserve
categories may be revised in the future as additional geoscience
or engineering data become available. Furthermore, estimates of
reserves quantities and their associated reserve categories may
also be revised due to other factors such as changes in economic
conditions, results of future operations, effects of regulation
by governmental agencies or economic risks as previously noted
herein.
The reserves for the properties included herein were estimated
by performance methods or by analogy. In general, reserves
attributable to producing wells were estimated by performance
methods such as decline curve analysis which utilized
extrapolations of historical production through April, 2010. In
certain cases, producing reserves were estimated by a
combination of performance and analogy if there was inadequate
historical performance data to establish a definitive trend and
where the use of production performance data as the sole basis
for the reserve estimates was considered to be inappropriate.
Reserves attributable to non-producing and undeveloped reserves
included herein were estimated by the analogy method which
utilized all pertinent well and seismic data available through
April, 2010.
To estimate economically recoverable oil and gas reserves and
related future net cash flows, we consider many factors and
assumptions including, but not limited to, the use of reservoir
parameters derived from geological and engineering data which
cannot be measured directly, economic criteria based on current
costs and SEC pricing requirements, and forecasts of future
production rates. Under the SEC regulations 210.4-10(a)(22)(v)
and (26), proved reserves must be anticipated to be economically
producible based on existing economic conditions including the
prices and costs at which economic producibility from a
reservoir is to be determined. While it may reasonably be
anticipated that the future prices received for the sale of
production and the operating costs and other costs relating to
such production may also increase or decrease from existing
levels, such changes were, in accordance with rules adopted by
the SEC, omitted from consideration in making this evaluation.
Energy Corporation of America has informed us that they have
furnished us all of the accounts, records, geological and
engineering data, and reports and other data required for this
investigation. In preparing our forecast of future production
and income, we have relied upon data furnished by Energy
Corporation of America with respect to property interests owned,
production and well tests from examined wells, normal direct
costs of operating the wells or leases, other costs such as
transportation
and/or
processing fees, ad valorem and production taxes, completion and
development costs, product prices based on the SEC regulations.
Ryder Scott reviewed such factual data for its reasonableness;
however, we have not conducted an independent verification of
the data supplied by Energy Corporation of America. We consider
the assumptions, data, methods and procedures used in this
report appropriate for the purpose hereof, and we have used all
such methods and procedures that we consider necessary and
appropriate to prepare the estimates of reserves and future net
revenues herein.
A-11
Energy Corporation of America
May 26, 2010
Page 5
Future
Production Rates
Our forecasts of future production rates are based on historical
performance from wells now on production. Test data and other
related information were used to estimate the anticipated
initial production rates for those wells or locations that are
not currently producing. If no production decline trend has been
established, future production rates were held constant, or
adjusted for the effects of curtailment where appropriate, until
a decline in ability to produce was anticipated. An estimated
rate of decline was then applied to depletion of the reserves.
If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves
not yet on production, sales were estimated to commence at an
anticipated date furnished by Energy Corporation of America.
The future production rates from wells now on production may be
more or less than estimated because of changes in market demand
or allowables set by regulatory bodies. Wells or locations that
are not currently producing may start producing earlier or later
than anticipated in our estimates.
Hydrocarbon
Prices
As previously stated, the hydrocarbon prices used herein are
based SEC price parameters using the average prices during the
12-month
period prior to the ending date of the period covered in this
report, determined as the unweighted arithmetic averages of the
prices in effect on the
first-day-of-the-month
for each month within such period, unless prices were defined by
contractual arrangements. For hydrocarbon products sold under
contract, the contract prices including fixed and determinable
escalations, exclusive of inflation adjustments, were used until
expiration of the contract. Upon contract expiration, the prices
were adjusted to the
12-month
unweighted arithmetic average as previously described. Product
prices which were actually used for each property reflect
adjustment for gravity, quality, local conditions,
and/or
distance from market.
The effects of derivative instruments designated as price hedges
of oil and gas quantities are not reflected in our individual
property evaluations.
Costs
Operating costs for the leases and wells in this report are
supplied by Energy Corporation of America and include only those
costs directly applicable to the leases or wells. The operating
costs include a portion of general and administrative costs
allocated directly to the leases and wells. For operated
properties, the operating costs include an appropriate level of
corporate general administrative and overhead costs. No
deduction was made for loan repayments, interest expenses, or
exploration and development prepayments that were not charged
directly to the leases or wells.
Development costs were furnished to us by Energy Corporation of
America and are based on authorizations for expenditure for the
proposed work or actual costs for similar projects. Energy
Corporation of Americas estimates of zero abandonment
costs after salvage value were used in this report. Ryder Scott
has not performed a detailed study of the abandonment costs or
the salvage value and makes no warranty for Energy
Corporation of Americas estimate.
A-12
Energy Corporation of America
May 26, 2010
Page 6
Because of the direct relationship between volumes of proved
undeveloped reserves and development plans, we include in the
proved undeveloped category only reserves assigned to
undeveloped locations that we have been assured will definitely
be drilled. Energy Corporation of America has assured us of
their intent and ability to proceed with the development
activities included in this report, and that they are not aware
of any legal, regulatory, political or economic obstacles that
would significantly alter their plans.
Current costs used by Energy Corporation of America were held
constant throughout the life of the properties.
It should be noted that ECA Marcellus Trust I, which owns
only a royalty interest, is only subject to the gas
transportation costs and all other costs are paid by the working
interest owners and for this analysis only impact the
calculation of the economic limit of the properties.
Standards
of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting
firm that has been providing petroleum consulting services
throughout the world for over seventy years. Ryder Scott is
employee-owned and maintains offices in Houston, Texas; Denver,
Colorado; and Calgary, Alberta, Canada. We have over eighty
engineers and geoscientists on our permanent staff. By virtue of
the size of our firm and the large number of clients for which
we provide services, no single client or job represents a
material portion of our annual revenue. We do not serve as
officers or directors of any publicly-traded oil and gas company
and are separate and independent from the operating and
investment decision-making process of our clients. This allows
us to bring the highest level of independence and objectivity to
each engagement for our services.
Ryder Scott actively participates in industry related
professional societies and organizes an annual public forum
focused on the subject of reserves evaluations and SEC
regulations. Many of our staff have authored or co-authored
technical papers on the subject of reserves related topics. We
encourage our staff to maintain and enhance their professional
skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott
requires that staff engineers and geoscientists have received
professional accreditation in the form of a registered or
certified professional engineers license or a registered
or certified professional geoscientists license, or the
equivalent thereof, from an appropriate governmental authority
or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to ECA
Marcellus Trust I and Energy Corporation of America.
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to do this work
nor the compensation is contingent on our estimates of reserves
for the properties which were reviewed.
The professional qualifications of the undersigned, the
technical person primarily responsible for evaluating the
reserves information discussed in this report, are included as
an attachment to this letter.
A-13
Energy Corporation of America
May 26, 2010
Page 7
Terms of
Usage
The results of our third party study, presented in report form
herein, were prepared in accordance with the disclosure
requirements set forth in the SEC regulations and intended for
public disclosure as an exhibit in filings made with the SEC by
ECA Marcellus Trust I. We have provided our written consent
to ECA Marcellus Trust I for the references to our name as
well as to the references to our third party report in filings
made by ECA Marcellus Trust I with the SEC. Our consent for
such use is included as a separate exhibit to the filings made
with the SEC by ECA Marcellus Trust I.
We have provided ECA Marcellus Trust I with a digital
version of the original signed copy of this report letter. In
the event there are any differences between the digital version
included in filings made by ECA Marcellus Trust I and the
original signed report letter, the original signed report letter
shall control and supersede the digital version.
The data and work papers used in the preparation of this report
are available for examination by authorized parties in our
offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration
No. F-1580
Managing Senior Vice President
/sm
A-14
ANNEX
B
CALCULATION
OF TARGET DISTRIBUTIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly Target Distributions
|
Quarter
|
|
Subordination
|
|
Target
|
|
Incentive
|
|
Quarter
|
|
Target
|
Ending
|
|
Threshold(1)
|
|
Distribution
|
|
Threshold(1)
|
|
Ending
|
|
Distribution
|
|
June 30, 2010
|
|
$
|
0.181
|
|
|
$
|
0.227
|
|
|
$
|
0.272
|
|
|
June 30, 2020
|
|
$
|
0.442
|
|
September 30, 2010
|
|
|
0.334
|
|
|
|
0.417
|
|
|
|
0.501
|
|
|
September 30, 2020
|
|
|
0.441
|
|
December 31, 2010
|
|
|
0.478
|
|
|
|
0.597
|
|
|
|
0.716
|
|
|
December 31, 2020
|
|
|
0.434
|
|
March 31, 2011
|
|
|
0.446
|
|
|
|
0.558
|
|
|
|
0.669
|
|
|
March 31, 2021
|
|
|
0.418
|
|
June 30, 2011
|
|
|
0.451
|
|
|
|
0.564
|
|
|
|
0.676
|
|
|
June 30, 2021
|
|
|
0.417
|
|
September 30, 2011
|
|
|
0.550
|
|
|
|
0.688
|
|
|
|
0.825
|
|
|
September 30, 2021
|
|
|
0.415
|
|
December 31, 2011
|
|
|
0.565
|
|
|
|
0.706
|
|
|
|
0.847
|
|
|
December 31, 2021
|
|
|
0.409
|
|
March 31, 2012
|
|
|
0.574
|
|
|
|
0.717
|
|
|
|
0.861
|
|
|
March 31, 2022
|
|
|
0.394
|
|
June 30, 2012
|
|
|
0.602
|
|
|
|
0.752
|
|
|
|
0.903
|
|
|
June 30, 2022
|
|
|
0.392
|
|
September 30, 2012
|
|
|
0.624
|
|
|
|
0.780
|
|
|
|
0.937
|
|
|
September 30, 2022
|
|
|
0.391
|
|
December 31, 2012
|
|
|
0.701
|
|
|
|
0.876
|
|
|
|
1.051
|
|
|
December 31, 2022
|
|
|
0.385
|
|
March 31, 2013
|
|
|
0.756
|
|
|
|
0.945
|
|
|
|
1.135
|
|
|
March 31, 2023
|
|
|
0.371
|
|
June 30, 2013
|
|
|
0.754
|
|
|
|
0.942
|
|
|
|
1.131
|
|
|
June 30, 2023
|
|
|
0.370
|
|
September 30, 2013
|
|
|
0.701
|
|
|
|
0.876
|
|
|
|
1.052
|
|
|
September 30, 2023
|
|
|
0.368
|
|
December 31, 2013
|
|
|
0.659
|
|
|
|
0.824
|
|
|
|
0.989
|
|
|
December 31, 2023
|
|
|
0.363
|
|
March 31, 2014
|
|
|
0.610
|
|
|
|
0.763
|
|
|
|
0.915
|
|
|
March 31, 2024
|
|
|
0.353
|
|
June 30, 2014
|
|
|
0.589
|
|
|
|
0.736
|
|
|
|
0.883
|
|
|
June 30, 2024
|
|
|
0.348
|
|
September 30, 2014
|
|
|
0.571
|
|
|
|
0.713
|
|
|
|
0.856
|
|
|
September 30, 2024
|
|
|
0.346
|
|
December 31, 2014
|
|
|
0.549
|
|
|
|
0.687
|
|
|
|
0.824
|
|
|
December 31, 2024
|
|
|
0.341
|
|
March 31, 2015
|
|
|
0.519
|
|
|
|
0.649
|
|
|
|
0.779
|
|
|
March 31, 2025
|
|
|
0.328
|
|
June 30, 2015
|
|
|
|
|
|
|
0.637
|
|
|
|
|
|
|
June 30, 2025
|
|
|
0.327
|
|
September 30, 2015
|
|
|
|
|
|
|
0.626
|
|
|
|
|
|
|
September 30, 2025
|
|
|
0.326
|
|
December 31, 2015
|
|
|
|
|
|
|
0.609
|
|
|
|
|
|
|
December 31, 2025
|
|
|
0.321
|
|
March 31, 2016
|
|
|
|
|
|
|
0.588
|
|
|
|
|
|
|
March 31, 2026
|
|
|
0.309
|
|
June 30, 2016
|
|
|
|
|
|
|
0.575
|
|
|
|
|
|
|
June 30, 2026
|
|
|
0.308
|
|
September 30, 2016
|
|
|
|
|
|
|
0.569
|
|
|
|
|
|
|
September 30, 2026
|
|
|
0.307
|
|
December 31, 2016
|
|
|
|
|
|
|
0.558
|
|
|
|
|
|
|
December 31, 2026
|
|
|
0.302
|
|
March 31, 2017
|
|
|
|
|
|
|
0.535
|
|
|
|
|
|
|
March 31, 2027
|
|
|
0.290
|
|
June 30, 2017
|
|
|
|
|
|
|
0.532
|
|
|
|
|
|
|
June 30, 2027
|
|
|
0.289
|
|
September 30, 2017
|
|
|
|
|
|
|
0.529
|
|
|
|
|
|
|
September 30, 2027
|
|
|
0.287
|
|
December 31, 2017
|
|
|
|
|
|
|
0.520
|
|
|
|
|
|
|
December 31, 2027
|
|
|
0.280
|
|
March 31, 2018
|
|
|
|
|
|
|
0.500
|
|
|
|
|
|
|
March 31, 2028
|
|
|
0.271
|
|
June 30, 2018
|
|
|
|
|
|
|
0.498
|
|
|
|
|
|
|
June 30, 2028
|
|
|
0.265
|
|
September 30, 2018
|
|
|
|
|
|
|
0.496
|
|
|
|
|
|
|
September 30, 2028
|
|
|
0.262
|
|
December 31, 2018
|
|
|
|
|
|
|
0.489
|
|
|
|
|
|
|
December 31, 2028
|
|
|
0.256
|
|
March 31, 2019
|
|
|
|
|
|
|
0.471
|
|
|
|
|
|
|
March 31, 2029
|
|
|
0.244
|
|
June 30, 2019
|
|
|
|
|
|
|
0.469
|
|
|
|
|
|
|
June 30, 2029
|
|
|
0.242
|
|
September 30, 2019
|
|
|
|
|
|
|
0.468
|
|
|
|
|
|
|
September 30, 2029
|
|
|
0.239
|
|
December 31, 2019
|
|
|
|
|
|
|
0.461
|
|
|
|
|
|
|
December 31, 2029
|
|
|
0.234
|
|
March 31, 2020
|
|
|
|
|
|
|
0.449
|
|
|
|
|
|
|
*March 31, 2030
|
|
|
2.890
|
|
|
|
|
(*)
|
|
Distribution includes net proceeds
from the sale of Perpetual Royalties after the Termination Date.
|
|
|
|
(1)
|
|
For each quarter, the Subordination
Threshold equals 80% of the Target Distribution, and the
Incentive Threshold equals 120% of the Target Distribution.
|
B-1
TABLE OF CONTENTS
|
|
|
|
|
Summary
|
|
|
1
|
|
Risk factors
|
|
|
19
|
|
Forward-looking statements
|
|
|
41
|
|
Use of proceeds
|
|
|
42
|
|
Natural gas fundamentals in the Marcellus Shale
|
|
|
43
|
|
Energy Corporation of America
|
|
|
46
|
|
The trust
|
|
|
55
|
|
Target distributions and subordination and incentive thresholds
|
|
|
58
|
|
The underlying properties
|
|
|
70
|
|
Description of the royalty interests
|
|
|
85
|
|
Description of the trust agreement
|
|
|
91
|
|
Description of the trust units
|
|
|
97
|
|
Trust units eligible for future sale
|
|
|
101
|
|
Federal income tax considerations
|
|
|
103
|
|
State tax considerations
|
|
|
122
|
|
ERISA considerations
|
|
|
123
|
|
Selling trust unitholder
|
|
|
124
|
|
Underwriting
|
|
|
125
|
|
Certain transactions
|
|
|
130
|
|
Legal matters
|
|
|
133
|
|
Experts
|
|
|
133
|
|
Where you can find more information
|
|
|
133
|
|
Glossary of certain oil and natural gas terms and terms related
to the trust
|
|
|
134
|
|
Index to financial statements
|
|
|
F-1
|
|
Information about Energy Corporation of America
|
|
|
ECA-1
|
|
Summary reserve reports
|
|
|
A-1
|
|
Calculation of target distributions
|
|
|
B-1
|
|
ECA Marcellus
Trust I
8,802,500 Common
Units
PROSPECTUS
RAYMOND JAMES
CITI
OPPENHEIMER &
CO.
RBC CAPITAL MARKETS
BAIRD
,
2010
PART II
INFORMATION
REQUIRED IN THE REGISTRATION STATEMENT
|
|
Item 13.
|
Other
Expenses Of Issuance And Distribution.
|
Set forth below are the expenses (other than underwriting
discounts and commissions) expected to be incurred in connection
with the issuance and distribution of the securities registered
hereby. With the exception of the Securities and Exchange
Commission registration fee, the FINRA filing and the NYSE
listing fee, the amounts set forth below are estimates.
|
|
|
|
|
Registration fee
|
|
$
|
15,498
|
|
FINRA filing fee
|
|
$
|
22,235
|
|
NYSE listing fee
|
|
$
|
250,000
|
|
Printing and engraving expenses
|
|
$
|
500,000
|
|
Fees and expenses of legal counsel
|
|
$
|
1,800,000
|
|
Accounting fees and expenses
|
|
$
|
500,000
|
|
Transfer agent and registrar fees
|
|
$
|
25,000
|
|
Miscellaneous
|
|
$
|
87,267
|
|
|
|
|
|
|
Total
|
|
$
|
3,200,000
|
|
|
|
|
|
|
|
|
|
*
|
|
To be provided by amendment
|
|
|
Item 14.
|
Indemnification
Of Directors And Officers.
|
The trust agreement provides that the trustee and its officers,
agents and employees shall be indemnified from the assets of the
trust against and from any and all liabilities, expenses,
claims, damages or loss incurred by it individually or as
trustee in the administration of the trust and the trust assets,
including, without limitation, any liability, expenses, claims,
damages or loss arising out of or in connection with any
liability under environmental laws, or in the doing of any act
done or performed or omission occurring on account of it being
trustee or acting in such capacity, except such liability,
expense, claims, damages or loss as to which it is liable under
the trust agreement. In this regard, the trustee shall be liable
only for fraud or gross negligence or for acts or omissions in
bad faith and shall not be liable for any act or omission of any
agent or employee unless the trustee has acted in bad faith or
with gross negligence in the selection and retention of such
agent or employee. The trustee is entitled to indemnification
from the assets of the trust and shall have a lien on the assets
of the trust to secure it for the foregoing indemnification.
The West Virginia Business Corporation Act also allows a
corporation to indemnify any person who was or is threatened to
be made party to any action or suit brought by or in the right
of the corporation against all expenses, fines, judgments and
payments made in settlement, including legal fees. The person
must have acted in good faith with no reason to believe the
actions taken were in opposition to the corporation.
Indemnification is not permitted in situations where the party
seeking the indemnity was adjudged liable for negligence or
misconduct regarding tax matters.
The West Virginia Business Corporation Act also provides that
corporations may purchase and maintain insurance to cover
possible indemnities, regardless of whether the corporation is
otherwise allowed to indemnify the party under its provisions.
Article XI of Energy Corporation of Americas
Certificate of Incorporation provides that no director of Energy
Corporation of America shall be liable to Energy Corporation of
America or its stockholders for monetary damages for breach of
fiduciary duty as a director, except for liability (i) for
any breach of
II-1
the directors duty of loyalty to Energy Corporation of
America or its stockholders, (ii) for acts or omissions not
in good faith or which involve intentional misconduct or a
knowing violation of law, (iii) under Section 9 of the
Corporation Act or (iv) for any transaction from which the
director derived an improper personal benefit.
|
|
Item 15.
|
Recent
Sales Of Unregistered Securities.
|
None.
The following documents are filed as exhibits to this
registration statement:
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1**
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1*
|
|
|
|
Certificate of Trust of ECA Marcellus Royalty Trust I
|
|
3
|
.2*
|
|
|
|
Articles of Incorporation of Energy Corporation of America.
|
|
3
|
.3*
|
|
|
|
Amended Articles of Incorporation of Energy Corporation of
America dated July 31, 1998.
|
|
3
|
.4*
|
|
|
|
Amended Articles of Incorporation of Energy Corporation of
America dated December 10, 1998.
|
|
3
|
.5*
|
|
|
|
Amended Bylaws of Energy Corporation of America.
|
|
4
|
.1*
|
|
|
|
Trust Agreement dated March 19, 2010.
|
|
4
|
.2*
|
|
|
|
First Amendment to the Trust Agreement dated May 7, 2010.
|
|
4
|
.3***
|
|
|
|
Form of Amended and Restated Trust Agreement among Energy
Corporation of America
and .
|
|
5
|
.1**
|
|
|
|
Opinion of Richards, Layton & Finger, P.A. relating to the
validity of the trust units
|
|
8
|
.1**
|
|
|
|
Opinion of Vinson & Elkins L.L.P. relating to tax matters
|
|
10
|
.1*
|
|
|
|
Second Amended and Restated Credit Agreement dated September 7,
2007 by and among Energy Corporation of America, the Lenders
signatory thereto and Wells Fargo Foothill, Inc. (now Wells
Fargo Capital Finance, Inc.), as the Arranger and Administrative
Agent.
|
|
10
|
.2*
|
|
|
|
First Amendment to Second Amended and Restated Credit Agreement
dated August 4, 2008, 2009 by and among Energy Corporation
of America, the Lenders signatory thereto and Wells Fargo
Foothill, Inc. (now Wells Fargo Capital Finance, Inc.), as the
Arranger and Administrative Agent.
|
|
10
|
.3***
|
|
|
|
Second Amendment to Second Amended and Restated Credit Agreement
dated June 17, 2010 by and among Energy Corporation of
America, the Lenders signatory thereto and Wells Fargo Foothill,
Inc. (now Wells Fargo Capital Finance, Inc.), as the Arranger
and Administrative Agent.
|
|
10
|
.4***
|
|
|
|
Form of Term Overriding Royalty Interest Conveyance (PDP)
|
|
10
|
.5***
|
|
|
|
Form of Term Overriding Royalty Conveyance (PUD)
|
|
10
|
.6***
|
|
|
|
Form of Perpetual Overriding Royalty Interest Conveyance (PDP)
|
|
10
|
.7***
|
|
|
|
Form of Perpetual Overriding Royalty Conveyance (PUP)
|
|
10
|
.8***
|
|
|
|
Form of Private Investor Assignment and Conveyance
|
|
10
|
.9***
|
|
|
|
Form of Private Investor Conveyance
|
|
10
|
.10***
|
|
|
|
Form of Administrative Services Agreement
|
|
10
|
.11***
|
|
|
|
Form of Development Agreement
|
|
10
|
.12***
|
|
|
|
Form of Swap Agreement
|
|
10
|
.13***
|
|
|
|
Form of Drilling Support Lien
|
II-2
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
10
|
.14***
|
|
|
|
Form of Royalty Interest Lien
|
|
10
|
.15***
|
|
|
|
Form of Registration Rights Agreement
|
|
21
|
.1*
|
|
|
|
Subsidiaries of Energy Corporation of America
|
|
23
|
.1***
|
|
|
|
Consent of Ernst & Young LLP
|
|
23
|
.2**
|
|
|
|
Consent of Richards, Layton & Finger, P.A. (contained in
Exhibit 5.1)
|
|
23
|
.3**
|
|
|
|
Consent of Vinson & Elkins, L.L.P. (contained in Exhibit
8.1)
|
|
23
|
.4*
|
|
|
|
Consent of Ryder Scott
|
|
24
|
.1*
|
|
|
|
Power of Attorney set forth on the signature page contained in
Part II
|
|
|
|
*
|
|
Previously filed
|
|
**
|
|
To be filed by amendment
|
|
***
|
|
Filed herewith
|
The undersigned registrants hereby undertake that:
(1) For the purpose of determining liability under the
Securities Act to any purchaser, each prospectus filed pursuant
to Rule 424(b) as part of a registration statement relating
to an offering, other than registration statements relying on
Rule 430B or other than prospectuses filed in reliance on
Rule 430A, shall be deemed to be part of and included in
the registration statement as of the date it is first used after
effectiveness. Provided, however, that no statement made in a
registration statement or prospectus that is part of the
registration statement or made in a document incorporated or
deemed incorporated by reference into the registration statement
or prospectus that is part of the registration statement will,
as to a purchaser with a time of contract of sale prior to such
first use, supersede or modify any statement that was made in
the registration statement or prospectus that was part of the
registration statement or made in any such document immediately
prior to such date of first use.
(2) For the purpose of determining liability of the
registrant under the Securities Act to any purchaser in the
initial distribution of the securities, the undersigned
registrant undertakes that in a primary offering of securities
of the undersigned registrant pursuant to this registration
statement, regardless of the underwriting method used to sell
the securities to the purchaser, if the securities are offered
or sold to such purchaser by means of any of the following
communications, the undersigned registrant will be a seller to
the purchaser and will be considered to offer or sell such
securities to such purchaser:
|
|
|
i. |
|
Any preliminary prospectus or prospectus of the undersigned
registrant relating to the offering required to be filed
pursuant to Rule 424; |
|
ii. |
|
Any free writing prospectus relating to the offering prepared by
or on behalf of the undersigned registrant or used or referred
to by the undersigned registrant; |
|
iii. |
|
The portion of any other free writing prospectus relating to the
offering containing material information about the undersigned
registrant or its securities provided by or on behalf of the
undersigned registrant; and |
|
iv. |
|
Any other communication that is an offer in the offering made by
the undersigned registrant to the purchaser. |
II-3
(3) For purposes of determining any liability under the
Securities Act of 1933, the information omitted from the form of
prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in a form of
prospectus filed by the registrants pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act shall be deemed to be part of this registration statement as
of the time it was declared effective.
(4) For the purpose of determining any liability under the
Securities Act of 1933, each post-effective amendment that
contains a form of prospectus shall be deemed to be a new
registration statement relating to the securities offered
therein, and the offering of such securities at that time shall
be deemed to be the initial bona fide offering thereof.
The undersigned registrants hereby undertake that, for purposes
of determining any liability under the Securities Act of 1933,
each filing of the registrants annual report pursuant to
section 13(a) or section 15(d) of the Securities
Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plans annual report pursuant to
section 15(d) of the Securities Exchange Act of
1934) that is incorporated by reference in the registration
statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of
such securities at that time shall be deemed to be the initial
bona fide offering thereof.
The undersigned registrants hereby undertake to provide to the
underwriter at the closing specified in the underwriting
agreements certificates in such denominations and registered in
such names as required by the underwriter to permit prompt
delivery to each purchaser.
Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors,
officers, and controlling persons of the registrants pursuant to
the foregoing provisions, or otherwise, the registrants have
been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the
registrants of expenses incurred or paid by a director, officer
or controlling person of a registrant in the successful defense
of any action, suit, or proceeding) is asserted by such
director, officer or controlling person in connection with the
securities being registered, the registrants will, unless in the
opinion of their respective counsel the matter has been settled
by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by them
is against public policy as expressed in the Securities Act of
1933 and will be governed by the final adjudication of such
issue.
II-4
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
registrant has duly caused this registration statement to be
signed on its behalf by the undersigned thereunto duly
authorized, in the City of Austin, State of Texas, on
June 21, 2010.
ECA Marcellus Trust I
|
|
|
|
By:
|
The Bank of New York Mellon
Trust Company, N.A.
|
|
|
By:
|
/s/ Mike
J. Ulrich
|
Name: Mike J. Ulrich
II-5
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
registrant has duly caused this registration statement to be
signed on its behalf by the undersigned thereunto duly
authorized, in the City of Denver, State of Colorado, on
June 21, 2010.
Energy Corporation of America
Name: John Mork
|
|
|
|
Title:
|
President and Chief Executive Officer
|
Pursuant to the requirements of the Securities Act of 1933, this
registration statement has been signed below by the following
persons in the capacities as of the date indicated above.
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
/s/ John
Mork
John
Mork
|
|
President and Chief Executive Officer
(Principal executive officer)
|
|
|
|
/s/ Donald
C. Supcoe
Donald
C. Supcoe
|
|
Senior Vice President; Secretary and
General Counsel
|
|
|
|
/s/ Michael
S. Fletcher
Michael
S. Fletcher
|
|
Chief Financial Officer
(Principal accounting and financial officer)
|
|
|
|
*
W.
Gaston Caperton, III
|
|
Director
|
|
|
|
*
Peter
H. Coors
|
|
Director
|
|
|
|
*
L.B.
Curtis
|
|
Director
|
|
|
|
*
John
J. Dorgan
|
|
Director
|
|
|
|
*
John
Fischer
|
|
Director
|
|
|
|
*
Thomas
R. Goodwin
|
|
Director
|
|
|
|
*
F.H.
McCullough, III
|
|
Director
|
II-6
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
*
Julie
Mork
|
|
Director
|
|
|
|
*
Jerry
Neely
|
|
Director
|
|
|
|
*
Arthur
C. Nielsen, Jr.
|
|
Director
|
|
|
|
*
Jay
S. Pifer
|
|
Director
|
|
|
|
|
|
*By:
|
|
/s/ Donald
C. Supcoe
Donald
C. Supcoe
Attorney-in-fact
|
|
|
II-7