Attached files
file | filename |
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EX-23.1 - EX-23.1 - WILLIAMS COAL SEAM GAS ROYALTY TRUST | d70884exv23w1.htm |
EX-10.9 - EX-10.9 - WILLIAMS COAL SEAM GAS ROYALTY TRUST | d70884exv10w9.htm |
EX-23.2 - EX-23.2 - WILLIAMS COAL SEAM GAS ROYALTY TRUST | d70884exv23w2.htm |
EX-32.1 - EX-32.1 - WILLIAMS COAL SEAM GAS ROYALTY TRUST | d70884exv32w1.htm |
EX-99.3 - EX-99.3 - WILLIAMS COAL SEAM GAS ROYALTY TRUST | d70884exv99w3.htm |
EX-31.1 - EX-31.1 - WILLIAMS COAL SEAM GAS ROYALTY TRUST | d70884exv31w1.htm |
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2009
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
COMMISSION FILE NUMBER: 1-11608
WILLIAMS COAL SEAM GAS ROYALTY TRUST
(Exact name of registrant as specified in its charter)
DELAWARE (State or other jurisdiction of incorporation or organization) |
75-6437433 (I.R.S. employer identification number) |
|
Trust Division U.S. Trust, Bank of America Private Wealth Management 901 Main Street, 17th Floor Dallas, Texas (Address of principal executive offices) |
75202 (Zip Code) |
Registrants telephone number, including area code:
(214) 209-2400
(214) 209-2400
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each Class | Name of Each Exchange on Which Registered |
|
Units of Beneficial Interest | New York Stock Exchange, Inc. |
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT
NONE
NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Exchange Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Date File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of
the registrants knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K. þ
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.
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
The aggregate market value of the registrants units of beneficial interest outstanding (based
on the closing sale price on the New York Stock Exchange on June 30, 2009, held by non-affiliates
of the registrant as of the last business day of the registrants most recently completed second
fiscal quarter was approximately $45,088,188.
At March 31, 2010, there were 9,700,000 units of beneficial interest outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Prospectus dated January 13, 1993, which constitutes a part of the
Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662)
filed in connection with the registration of the units of beneficial interest in the registrant,
are incorporated by reference in Part I of this Form 10-K.
TABLE OF CONTENTS
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Commission
and Exclusive Agency Agreement |
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Consent of Ernst & Young LLP |
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Consent of
Miller and Lents, Ltd. |
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Certification Pursuant to Rule 13a-14(a)/15d-14(a) |
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Certification Pursuant to 18 U.S.C. 1350 |
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Reserve Report |
PART I
Item 1. Business.
The following is a glossary of certain defined terms used in this Annual Report on Form 10-K.
GLOSSARY
Administrative Services Agreement means the Administrative Services Agreement, dated
effective December 1, 1992, between Williams and the Trust, a copy of which is filed as an exhibit
to this Form 10-K.
Bcf means billion cubic feet of natural gas. Natural gas volumes are stated herein at the
legal pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit.
Blanco Hub Spot Price means the posted index price of spot gas delivered to pipelines per
MMBtu (dry basis) as published in the first issue of the month during which gas is delivered or
such determination is made, as the case may be, in Inside FERCs Gas Market Report for El Paso
Natural Gas Company, San Juan, or in the event a Blanco Hub posted index price is at some time in
the future reported by Inside FERCs Gas Market Report, then the Blanco Hub posted index price will
be substituted in place of the El Paso Natural Gas Company, San Juan posted index price.
Btu means British Thermal Unit, the common unit of gross heating value measurement.
Citibanks Base Rate means a fluctuating interest rate per annum (compounded quarterly) as
shall be in effect from time to time which rate per annum shall at all times be equal to the rate
of interest announced publicly by Citibank, N.A. in New York, New York, from time to time, as its
base rate.
Confirmation Agreement means the Confirmation Agreement dated effective as of May 1, 1995,
by and among WPC, Williams and the Trust, a copy of which is filed as an exhibit to this Form 10-K.
Conveyance means the Net Profits Conveyance dated effective as of October 1, 1992, by and
among Williams, WPC, the Trustee and the Delaware Trustee, a copy of which is filed as an exhibit
to this Form 10-K.
December 31, 2009 Reserve Report means the Reserve Report, dated February 12, 2010, on the
estimated reserves, estimated future net revenues and the discounted estimated future net revenues
attributable to the Royalty Interests and the Underlying Properties as of December 31, 2009,
prepared by Miller and Lents, Ltd., independent petroleum engineers, a copy of which is filed as an
exhibit to this Form 10-K.
Delaware Code means the Delaware Business Trust Act, Title 12, Chapter 38 of the Delaware
Code, Sections 3801 et seq.
Delaware Trustee means The Bank of New York Mellon Trust Company, N.A. (as successor to
Chemical Bank Delaware), in its capacity as a trustee of the Trust.
Enhanced recovery or similar operations means operations conducted for the purpose of
maintaining, sustaining or enhancing production from the Underlying Properties. These operations
may include additional compression, the injection of carbon dioxide or other gases or hydraulic
fracturing.
Farmout Properties means the 5,348 gross acres in La Plata County, Colorado on which WPC
owns a 35 percent net profits interest, also referred to as the PLA-9 Properties.
Gas Gathering Contract means the Gas Gathering and Treating Agreement, dated October 1,
1992, between WPX Gas Resources (as successor in interest to WGM) and WFS, as amended by the First
Amendment thereto dated as of January 12, 1993, by Amendment #2 effective as of October 1, 1993 and
by Amendment #3 thereto dated as of October 1, 1993, a copy of each of which is filed as an exhibit
to this Form 10-K.
1
Gas Purchase Contract means the Gas Purchase Agreement, dated October 1, 1992, between WPX
Gas Resources (as successor in interest to WGM) and WPC, as amended by the First Amendment thereto
effective as of January 12, 1993, a copy of each of which is filed as an exhibit to this Form 10-K.
Grantor trust means a trust as to which the grantor is treated as the owner of the trust
income and corpus under the applicable provisions of the IRC and the Treasury Regulations
thereunder.
Gross acres means the total number of surface acres of land without regard to ownership.
Gross wells means the total whole number of gas wells without regard to ownership interest.
Index Price means 97 percent of the Blanco Hub Spot Price as of the date the determination
is made.
Infill Net Proceeds consists generally of the aggregate proceeds based on the price at the
Wellhead of gas produced from WPCs net revenue interest in any possible Infill Wells less (a)
WPCs working interest share of property and production taxes on such Infill Wells; (b) WPCs
working interest share of operating costs on such Infill Wells; (c) WPCs working interest share of
capital costs on such Infill Wells, including costs of drilling and completing such Infill Wells
and the costs of associated surface facilities; and (d) interest on the unrecovered portion, if
any, of the foregoing costs at Citibanks Base Rate.
Infill NPI refers to one of the net profits interests conveyed to the Trust, consisting of a
20 percent interest in WPCs Infill Net Proceeds.
Infill Wells means any possible additional well drilled on a producing drilling block when
well spacing rules are effectively modified from the existing 320 acre spacing.
IRC means the Internal Revenue Code of 1986, as amended.
IRR means the annual discount rate (compounded quarterly) that equates the present value of
the Aftertax Cash Flow per Unit to the initial price to the public of the Units in the Public
Offering (which was $20.00 per Unit).
Mcf means thousand cubic feet of natural gas.
Minimum Purchase Price means 97 percent of $1.75 per MMBtu (dry basis).
MMBtu means million Btu.
MMcf means million cubic feet of natural gas.
Net profits interest generally refers to a real property interest entitling the owner to
receive a specified percentage of the net proceeds from the sale of production attributable to the
properties burdened thereby, the amount of which is based on a revenue formula specified in such
net profits interest.
NPI refers to one of the net profits interests conveyed to the Trust, generally entitling
the Trust to receive 60 percent (permanently reduced from 81 percent as described below) of the NPI
Net Proceeds attributable to (i)WPCs net revenue interest (working interest less lease burdens) in
the WI Properties and (ii) the revenue stream received by WPC attributable to its 35 percent net
profits interest in the Farmout Properties. The percentage of the NPI Net Proceeds to which the
Trust was originally entitled was generally 81 percent. However, after certain conditions occurred
as provided in the Conveyance, the percentage of the NPI Net Proceeds to which the Trust is
entitled was permanently reduced from 81 percent to 60 percent beginning in the fourth quarter of
2000 as described under Item 2The Royalty InterestsNPI Percentage Reduction.
NPI Net Proceeds consists generally of the aggregate proceeds attributable to (i) WPCs net
revenue interest based on the sale at the Wellhead of gas produced from the WI Properties and (ii)
the revenue stream
2
received by WPC from its 35 percent net profits interest in the Farmout Properties, less (a)
WPCs working interest share of property and production taxes on the WI Properties; (b) WPCs
working interest share of actual operating costs on the WI Properties to the extent in excess of
those agreed to be paid by WPC as described herein; (c) WPCs working interest share of capital
costs on the WI Properties to the extent in excess of those agreed to be paid by WPC as described
herein; and (d) interest on the unrecovered portion, if any, of the foregoing costs at Citibanks
Base Rate.
Net wells and net acres are calculated by multiplying gross wells or gross acres by the
working interest in such wells or acres.
October 1, 1992 Reserve Report means the Reserve Report, dated November 21, 1992, on the
estimated reserves, estimated future net revenues and the discounted estimated future net revenues
attributable to the Royalty Interests and the Underlying Properties as of October 1, 1992, prepared
by Miller and Lents, Ltd., independent petroleum engineers, a copy of which is filed as an exhibit
to this Form 10-K.
Price Credit means the credit received by WPX Gas Resources from WPC for each MMBtu of
natural gas purchased by WFS Gas Resources when the Index Price is less than the Minimum Purchase
Price on or after January 1, 1994, equal to the difference between the Minimum Purchase Price and
the Index Price.
Price Credit Account means the account established by WPC containing the accrued and
unrecouped amount of any Price Credits.
Price Differential means 50 percent of the excess of the Index Price over $1.94 per MMBtu.
Public Offering has the meaning assigned to such term herein under Item 1Description of
the TrustCreation and Organization of the Trust.
Public Offering Prospectus has the meaning assigned to such term herein defined under Item
1Federal Income Taxation.
Quatro Finale means (a) with respect to the period May 1, 1997 until February 28, 2001,
Quatro Finale LLC, a Delaware limited liability company (which entity acquired and owned the
Underlying Properties from May 1, 1997 until February 1, 2001), and (b) with respect to the period
March 1, 2001 until January 1, 2003, Quatro Finale V LLC, a Delaware limited liability company
(which entity acquired and owned the Underlying Properties from March 1, 2001 until January 1,
2003).
QFIV means Quatro Finale IV LLC, a Delaware limited liability company and a subsidiary of
The Bear Stearns Companies Inc.
Royalty Interests means the NPI and Infill NPI conveyed to the Trust.
Treasury Regulations shall mean the United States treasury regulations promulgated under the
IRC.
Trust means Williams Coal Seam Gas Royalty Trust, a Delaware business trust formed pursuant
to the Trust Agreement.
Trust Agreement means the Trust Agreement, dated as of December 1, 1992, among Williams,
WPC, as grantor, The Bank of New York Mellon Trust Company, N.A. (as successor to Chemical Bank
Delaware), as the Delaware Trustee, and Bank of America, N.A. (as successor to NationsBank of
Texas, N.A.), as the Trustee, as amended by the First Amendment thereto effective as of
December 15, 1992 and by the Second Amendment thereto effective as of January 12, 1993, a copy of
each of which is filed as an exhibit to this Form 10-K.
Trustee means Bank of America, N.A. (as successor to NationsBank, N.A.), in its capacity as
a trustee of the Trust. In 2007 the Bank of America private wealth management group officially
became known as U.S. Trust, Bank of America Private Wealth Management. The legal entity that
serves as Trustee of the Trust did not change,
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and references in this Form 10-K to U.S. Trust, Bank of America Private Wealth Management
shall describe the legal entity Bank of America, N.A.
Underlying Properties means certain proved properties in the Fruitland coal formation in the
San Juan Basin of New Mexico and Colorado as specified in the Conveyance in which WPC has certain
net revenue interests (working interests less lease burdens) and net profits interests.
Units means the 9,700,000 units of beneficial interest issued by, and evidencing the entire
beneficial interest in, the Trust.
Wellhead means at or in the vicinity of the wellhead of gas produced.
WFS means Williams Field Services Company, a wholly-owned indirect subsidiary of Williams
Energy Services (formerly known as Williams Energy Group) (a wholly-owned subsidiary of Williams).
WGM means Williams Gas Marketing Company, formerly a wholly-owned subsidiary of Williams
Field Services Group, Inc. (a wholly-owned subsidiary of Williams) which has been merged into
another affiliate of Williams Field Services Group, Inc.
WGM Gas Resources Payment Obligations has the meaning assigned to such term under Item
2The Royalty InterestsWilliams Performance Assurances.
WHD means Williams Holdings of Delaware, Inc., a wholly-owned subsidiary of Williams. On
July 31, 1999, WHD was merged into Williams and Williams assumed all assets, liabilities and
obligations of WHD.
Williams means The Williams Companies, Inc., a Delaware corporation.
WI Properties means the net revenue interests (working interests less lease burdens) of WPC
in the Underlying Properties including WPCs interests in 12 Federal producing units in New Mexico.
Working interest generally refers to a real property interest entitling the owner to receive
a specified percentage of the proceeds from the sale of oil and gas production or a percentage of
such production, but requiring the owner of such working interest to bear the costs to explore for,
develop and produce such oil and gas.
WPC means Williams Production Company, a wholly-owned indirect subsidiary of Williams.
WPC Payment Obligations LLC has the meaning assigned to such term under Item 2The Royalty
InterestsWilliams Performance Assurances.
WPX Gas Resources means WPX Gas Resources Company (formerly known as WFS Gas Resources
Company), a Delaware corporation and a wholly-owned subsidiary of WPC and Williams.
DESCRIPTION OF THE TRUST
Williams Coal Seam Gas Royalty Trust (the Trust) was formed as a Delaware business trust
under the Delaware Business Trust Act, Title 12, Chapter 38 of the Delaware Code, Sections 3801 et
seq. (the Delaware Code). The following information is subject to the detailed provisions of (i)
the Trust Agreement of Williams Coal Seam Gas Royalty Trust (as amended, the Trust Agreement),
entered into effective as of December 1, 1992, by and among Williams Production Company, a Delaware
corporation (WPC), as trustor; The Williams Companies, Inc., a Delaware corporation (Williams),
as sponsor; The Bank of New York Mellon Trust Company, N.A. (as successor to Chemical Bank
Delaware), a Delaware banking corporation (the Delaware Trustee); and Bank of America, N.A. (as
successor to NationsBank of Texas, N.A.), a national banking association (the Trustee) (the
Delaware Trustee and the Trustee are sometimes referred to collectively as the Trustees), and
(ii) the Net Profits Conveyance (the Conveyance) entered into effective as of October 1, 1992, by
and among WPC, Williams, the Trustee and the Delaware Trustee. In accordance with the terms of the
Trust Agreement, the Trust is required to
4
terminate effective as of March 1, 2010, and the Trustee is required to use best efforts to
sell the Royalty Interests and liquidate the Trust. See Termination and Liquidation of the Trust
below for additional information. Copies of the Trust Agreement and of the Conveyance are filed as
exhibits to this Form 10-K. The provisions governing the Trust are complex and extensive, and no
attempt has been made below to describe or reference all of such provisions. The following is a
general description of the basic framework of the Trust and a summary of the material terms of the
Trust Agreement, and detailed provisions concerning the Trust may be found in the Trust Agreement.
Creation and Organization of the Trust
The Trust was formed effective as of December 1, 1992 under Delaware law pursuant to the terms
of the Trust Agreement to acquire and hold certain net profits interests (the Royalty Interests)
in proved natural gas properties located in the San Juan Basin of New Mexico and Colorado (the
Underlying Properties). The Royalty Interests were conveyed to the Trust on January 21, 1993,
pursuant to the Conveyance, for the benefit of the Unitholders. All of the authorized units of
beneficial interest in the Trust (Units) were issued to WPC on January 21, 1993. On that date,
WPC transferred its Units to its parent, Williams, by dividend. Williams, in turn, sold, by means
of a prospectus dated January 13, 1993, 5,200,000 Units on January 21, 1993, and an additional
780,000 Units on February 16, 1993, to the public through various underwriters (the Public
Offering). In the second quarter of 1993, Williams sold an additional 151,209 Units. During the
second quarter of 1995, Williams transferred its Units to Williams Holdings of Delaware, Inc.
(WHD), a separate holding company for Williams non-regulated businesses. Effective July 31,
1999, WHD was merged into Williams, and by operation of the merger, Williams assumed all assets,
liabilities and obligations of WHD, including without limitation ownership of WHDs Units.
Effective August 11, 2000, Williams sold its Units to Quatro Finale IV LLC, a Delaware limited
liability company (QFIV), in a privately-negotiated transaction. Williams retained the voting
rights and retained a call option on the transferred Units, and QFIV was granted a put option
on the Units. Through a series of exercises of its call option, Williams reacquired an aggregate
of 3,568,791 Units from December 2001 through June 2003. Williams has informed the Trustee that it
has subsequently sold 2,779,500 of these Units through March 1, 2009 and owned a remaining 789,291
Units as of such date.
Except for the commitment by WPC to pay the costs incurred to place into production certain
proved nonproducing wells, neither WPC, Quatro Finale nor the operators of the Underlying
Properties have any contractual commitment to the Trust to further develop the Underlying
Properties, to remain as operator with respect to any of the leases on the Underlying Properties or
to maintain their ownership interest in any of the properties. However, WPC retained an interest
in each of the Underlying Properties immediately after conveyance of the Royalty Interests to the
Trust. As described under Item 2 The Royalty Interests, effective May 1, 1997, WPC sold the
Underlying Properties subject to and burdened by the Royalty Interests to Quatro Finale LLC, an
unaffiliated Delaware limited liability company. Ownership of the Underlying Properties reverted
back to WPC effective February 1, 2001, pursuant to the terms of the May 1, 1997 transaction.
Pursuant to a Purchase and Sale Agreement dated March 14, 2001 (the 2001 Transaction Agreement),
and effective March 1, 2001, WPC sold the Underlying Properties subject to and burdened by the
Royalty Interests to Quatro Finale V LLC, an unaffiliated Delaware limited liability company. The
sale of the Underlying Properties is expressly permitted under the Trust Agreement. Effective
January 1, 2003, ownership of the Underlying Properties once again reverted back to WPC after it
exercised its right to repurchase interests in the Underlying Properties from Quatro Finale V LLC
pursuant to the 2001 Transaction Agreement (as defined in Item 2PropertiesThe Royal Interests).
Unless otherwise dictated by context, references herein to WPC with respect to the ownership of
the Underlying Properties for any period from May 1, 1997 through February 28, 2001, and for the
period from March 1, 2001 through January 1, 2003, shall be deemed to refer to Quatro Finale. For
a description of the Underlying Properties and other information relating to such properties, see
Item 2PropertiesThe Royalty Interests.
The Trustee has powers to collect and distribute proceeds received by the Trust and to pay
Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in the
Trust Agreement and is not empowered to otherwise manage or take part in the business of the Trust.
The Royalty Interests are passive in nature, and neither the Delaware Trustee nor the Trustee has
any control over or any responsibility relating to the operation of the Underlying Properties. The
Delaware Trustee and the Trustee may resign at any time or be removed with or without cause by a
vote of not less than a majority of the outstanding Units. Any successor trustee
5
must be a bank or trust company meeting certain requirements, including having capital,
surplus and undivided profits of at least $20,000,000, in the case of the Delaware Trustee, and
$100,000,000, in the case of the Trustee.
Termination and Liquidation of the Trust
The following is a description of the termination and liquidation provisions in the Trust
Agreement. Please also see Item 7 Trustees Discussion and Analysis of Financial Condition and
Results of Operations and Item 8 Financial Statements and Supplementary Data for information
regarding the current status of the termination events as described below.
Pursuant to the terms of the Trust Agreement, the Trust is required to terminate effective
March 1, 2010 (the Termination Date) because, based on a reserve report as of December 31, 2009,
it was determined that, as of such date, the net present value (discounted at 10 percent) of the
estimated future net revenues (calculated in accordance with criteria established by the SEC) for
proved reserves attributable to the Royalty Interests but using the average monthly Blanco Hub Spot
Price (including no consideration for the Gas Purchase Contract) for the past calendar year less certain gathering costs was equal to or less than $30 million
thereby triggering a termination of the Trust. Based on a report prepared by independent petroleum
engineers, the Trusts computed net present value of the estimated future net revenues for proved
reserves attributable to the Royalty Interests calculated in accordance with the Trust Agreement
was approximately $8.4 million as of December 31, 2009. This calculation does not necessarily
represent the fair value of the Underlying Properties.
Following termination, the Trustee and the Delaware Trustee will continue to act as trustees
of the Trust until all remaining Trust assets have been sold and the net proceeds from such sales,
if any, are distributed to Unitholders.
Upon the termination of the Trust, the Trustee is obligated to use Best Efforts (as defined in
the Trust Agreement) to sell any remaining Royalty Interests for cash pursuant to the procedures
described in the Trust Agreement. The Trustee has retained Albrecht & Associates, Inc., an
investment banking firm (the Advisor), on behalf of the Trust who will assist the Trustee in
selling the remaining Royalty Interests owned by the Trust (the Remaining Royalty Interests).
WPC has the right, but not the obligation, to make a cash offer to purchase all Remaining Royalty
Interests following termination of the Trust as described in the following paragraph.
WPC may, within 60 days following the Termination Date, make a cash offer to purchase all of
the Remaining Royalty Interests then held by the Trust. In the event such an offer is made by WPC,
the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such
offer (in which case no sale to WPC will be made unless a fairness opinion is given by the Advisor
that the purchase price is fair to the Trust and Unitholders) or (ii) defer action on such offer.
If the Trustee defers action on WPCs offer, the offer will be deemed withdrawn and the Trustee
will then use Best Efforts, assisted by the Advisor to obtain alternative offers for the Remaining
Royalty Interests. At the end of a 120-day period following the Termination Date, the Trustee is
required to notify WPC of the highest of any other offers (net of any commissions or other fees
payable by the Trust), acceptable to the Trustee (which must be an all-cash offer), received during
such period (the Highest Acceptable Offer). WPC then has the exclusive right (whether or not it
made an initial offer), but not the obligation, to purchase all Remaining Royalty Interests for a
cash purchase price computed as follows: (i) if the Highest Acceptable Offer is more than 105
percent of WPCs initial offer (or if WPC did not make an initial offer), the purchase price will
be 105 percent of the Highest Acceptable Offer, or (ii) if the Highest Acceptable Offer is equal to
or less than 105 percent of WPCs initial offer, the purchase price will be equal to the Highest
Acceptable Offer. If no other acceptable offers are received for all Remaining Royalty Interests,
the Trustee may request WPC to submit another offer for consideration by the Trustee and may accept
or reject such offer. Acceptance of an offer by the Trustee shall be conditioned upon the opinion
of the Advisor of the fairness of the offer.
If a sale of the Remaining Royalty Interests is made or a definitive contract for sale of the
Remaining Royalty Interests is entered into within a 150-day period following the Termination Date,
the buyer of the Remaining Royalty Interests, and not the Trust or Unitholders, will be entitled to
all proceeds of production attributable to the Remaining Royalty Interests following the
Termination Date. All proceeds of production following the Termination Date attributable to the
Remaining Royalty Interests will be deposited into a non-interest bearing account until they are
paid to the buyer or otherwise distributed in accordance with the Trust Agreement.
6
In the event that WPC does not purchase the Remaining Royalty Interests, the Trustee may
accept any offer for all or any part (not more than six parts) of the Remaining Royalty Interests
as it deems to be in the best interests of the Trust and Unitholders and may continue, for up to
one calendar year after the Termination Date, to attempt to locate a buyer or buyers of the
Remaining Royalty Interests in order to sell such interests in an orderly fashion not involving a
public auction. If any Remaining Royalty Interests have not been sold or a definitive agreement
for sale has not been entered into by the end of such calendar year, the Trustee is required to
sell the Remaining Royalty Interests at public auction to the highest cash bidder, which sale may
be to WPC or any of its affiliates. Notice of such sale by auction shall be mailed at least 30
days prior to such sale to each Unitholder at his address as it appears on the ownership ledger of
the Trustee.
WPCs purchase rights, as described, may be exercised by WPC and each of its
successors-in-interest and assigns. WPCs purchase rights are fully assignable by WPC to any
person. The costs of liquidation, including the fees and expenses of the Advisor, and the
Trustees liquidation fee will be paid by the Trust.
The sale of the Remaining Royalty Interests following the termination of the Trust will be
taxable events to the Unitholders for Federal Income tax purposes. Generally, a Unitholder will
realize gain or loss equal to the difference between the amount realized on the sale of the
Remaining Royalty Interests upon termination of the Trust and his adjusted basis in such Units.
Gain or loss realized by a Unitholder who is not a dealer with respect to such Units and who has a
holding period for the Units of more than one year will be treated as long-term capital gain or
loss except to the extent of any depletion recapture amount, which must be treated as ordinary
income. State tax consequences may also result to Unitholders upon the termination of the Trust
and the sale of the Remaining Royalty Interests. Other Federal and state tax issues concerning the
Trust are discussed herein under Item 1Federal Income Taxation and State Tax Considerations.
Each Unitholder should consult his own tax advisor regarding Trust tax compliance matters,
including Federal and state tax implications concerning the sale of the Remaining Royalty Interests
following the termination of the Trust.
Assets of the Trust
The only assets of the Trust, other than cash and cash equivalents being held for the payment
of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The
Royalty Interests consist primarily of a net profits interest (the NPI) in the Underlying
Properties. The NPI generally entitles the Trust to receive 60 percent of the NPI Net Proceeds
attributable to (i) gas produced and sold from WPCs net revenue interests (working interests less
lease burdens) in the properties in which WPC has a working interest (the WI Properties) and (ii)
the revenue stream received by WPC attributable to its 35 percent net profits interest in 5,348
gross acres in La Plata County, Colorado (the Farmout Properties).
The Royalty Interests also include a 20 percent interest in WPCs Infill Net Proceeds from the
sale of production if well spacing rules are effectively modified and additional wells are drilled
on producing drilling blocks on the WI Properties (the Infill Wells) during the term of the
Trust. Infill Net Proceeds consists generally of the aggregate proceeds, based on the price at
the wellhead, of gas produced from WPCs net revenue interest in any Infill Wells less certain
taxes and costs.
On October 15, 2002 the New Mexico Oil and Gas Commission (NMOCD) revised the field rules for
the Basin Fruitland Coal (Gas) Pool to allow optional second (infill) wells on the standard
320-acre spacing unit in certain designated areas of the pool (the non-fairway wells). On July 17,
2003, the NMOCD further modified the field rules for the Basin Fruitland Coal (Gas) Pool to allow
these infill wells on the standard 320-acre spacing unit in all areas of the pool. The WI
Properties contain 442 infill locations designated as proved locations according to U.S. Securities
and Exchange Commission (SEC) guidelines. As of December 31, 2009, all of these infill locations
represent proved developed producing reserves, while there are no proved undeveloped locations.
WPC has informed the Trustee that the Infill Wells reached payout in the aggregate during
2008. The Trust has received its 20 percent interest in WPCs Infill Net Proceeds for periods
after payout. However, during 2009, WPC informed the Trustee that due to the net deficit
realized by the Infill Wells during the third and fourth quarters, the Infill Net Profit Costs now
exceed the Infill Net Profit Gross Proceeds by approximately $32,500. The Trust will not be liable
for such excess costs, and such excess costs will hereafter constitute Excess Infill Net Profit
Costs until
7
recovered by WPC. The Trust will not receive its 20 percent interest in WPCs Infill Net
Proceeds until such time as the Infill Net Profits Gross Proceeds exceeds the Infill Net Profit
Costs on an aggregate basis.
The complete definitions of Infill Net Proceeds, Infill Net Profit Costs, Excess Infill Net
Profit Costs, and Infill Net Profit Gross Proceeds are set forth in the Conveyance. See
Item 2PropertiesThe Royalty Interests for more information generally and Note 9 to Item
8Financial Statements and Supplementary DataNotes to Financial Statements for information
regarding the net proved reserves attributable to the Trust.
Liabilities of the Trust
Because of the passive nature of the Trust assets and the restrictions on the power of the
Trustee to incur obligations, the only liabilities the Trust generally incurs are those for routine
administrative expenses, such as Trustees fees and accounting, engineering, legal and other
professional fees and the administrative services fee paid to Williams. However, if a court were
to hold that the Trust is taxable as a corporation for Federal income tax purposes, then the Trust
would incur substantial Federal income tax liabilities. See Federal Income Taxation.
Duties and Limited Powers of the Trustee
Under the Trust Agreement, the Trustee receives the payments attributable to the Royalty
Interests and pays all expenses, liabilities and obligations of the Trust. With respect to any
liability that is contingent or uncertain in amount or that otherwise is not currently due and
payable, the Trustee has the discretion to establish a cash reserve for the payment of such
liability. The Trustee is also entitled to cause the Trust to borrow money to pay expenses,
liabilities and obligations that cannot be paid out of cash held by the Trust. Any such borrowings
may be from any source, including from the entity serving as Trustee or Delaware Trustee, provided
that the entity serving as Trustee or Delaware Trustee shall not be obligated to lend to the Trust.
To secure payment of any such indebtedness (including any indebtedness to the entity serving as
Trustee or Delaware Trustee), the Trustee is authorized to (i) mortgage and otherwise encumber the
entire Trust estate or any portion thereof; (ii) carve out and convey production payments;
(iii) include all terms, powers, remedies, covenants and provisions it deems necessary or
advisable, including confession of judgment and the power of sale with or without judicial
proceedings; and (iv) provide for the exercise of those and other remedies available to a secured
lender in the event of a default on such loan. The terms of such indebtedness and security
interest, if funds were loaned by the entity serving as Trustee or Delaware Trustee, must 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 and security interest as if it were not then serving
as trustee.
The Trustee is authorized and directed to sell and convey the Royalty Interests without
Unitholder approval in certain instances as described in the Trust Agreement, including (i) upon
termination of the Trust; (ii) commencing January 1, 2003, if a portion of the NPI ceases to
produce or is not capable of producing in commercially paying quantities (see Item
2PropertiesThe Royalty InterestsSale and Abandonment of Underlying Properties); and (iii) in
connection with payment of a purchase price adjustment for uncompleted wells (see Item
2PropertiesThe Royalty InterestsPurchase Price Adjustments and Title to Properties). The
Trustee is empowered by the Trust Agreement to employ consultants and agents (including WPC and
Williams) and to make payments of all fees for services or expenses out of the assets of the Trust.
The Trust has no employees. The administrative functions of the Trust are performed by the
Trustee.
The Trust Agreement authorizes the Trustee to take such action as in its judgment is necessary
or advisable to achieve the purposes of the Trust. The Trustee is authorized to agree to
modifications of the terms of the Conveyance and to settle disputes with respect thereto, so long
as such modifications or settlements do not result in treatment of the Trust as an association
taxable as a corporation for Federal income tax purposes and such modifications or settlements do
not alter the nature of the Royalty Interests as a right to receive a share of the proceeds of
production from the Underlying Properties which, with respect to the Trust, are free of any
operating rights, expense or cost. The Trust Agreement provides that cash being held by the
Trustee as a reserve for liabilities or for distribution at the next distribution date will be
placed in demand accounts, U.S. government obligations, repurchase agreements secured by such
obligations, or certificates of deposit, but the Trustee is otherwise prohibited from acquiring any
asset other than the Royalty Interests or engaging in any business or investment activity of any
8
kind whatsoever. The Trustee may deposit funds awaiting distribution in an account with the
Trustee or Delaware Trustee provided the interest paid equals the amount paid by the Trustee or
Delaware Trustee on similar deposits.
Liabilities of the Delaware Trustee and the Trustee
Each of the Delaware Trustee and the Trustee may act in its discretion and shall be personally
or individually liable only for fraud or acts or omissions in bad faith or that constitute gross
negligence and will not be otherwise liable for any act or omission of any agent or employee unless
such trustee has acted in bad faith or with gross negligence in the selection and retention of such
agent or employee. Each of the Delaware Trustee and the Trustee will be indemnified from the Trust
assets for any liability, expense, claim, damage or other loss incurred in performing its duties,
unless resulting from gross negligence, fraud or bad faith (the Delaware Trustee or the Trustee
will be indemnified from the Trust assets against its own negligence that does not constitute gross
negligence), and will have a first lien upon the assets of the Trust as security for such
indemnification and for reimbursements and compensation to which it is entitled. WPC and Williams
have agreed to indemnify each of the Delaware Trustee and the Trustee against certain environmental
and securities laws liabilities, respectively, provided that the Trustee and Delaware Trustee are
generally required to first be indemnified from Trust assets before seeking indemnification from
WPC or Williams. Neither the Delaware Trustee nor the Trustee shall be entitled to indemnification
from Unitholders (except in connection with lost or destroyed Unit certificates).
DESCRIPTION OF UNITS
Each Unit represents an equal undivided share of beneficial interest in the Trust and is
evidenced by a transferable certificate issued by the Trustee. Each Unit entitles its holder to
the same rights as the holder of any other Unit, and the Trust has no other authorized or
outstanding class of equity security. At March 1, 2010, there were 9,700,000 Units outstanding.
The Trust may not issue additional Units.
Distributions and Income Computations
In accordance with the Trust Agreement, all proceeds of production attributable to the
Remaining Royalty Interests will be deposited into a separate account effective as of the March 1,
2010 Termination Date. If a sale of the Remaining Royalty Interests is made or a definitive
agreement for sale of the Remaining Royalty Interests is entered into within a 150-day period
following the Termination Date, the buyer of the Remaining Royalty Interests, and not the Trust or
the Unitholders, will be entitled to all proceeds of production attributable to the Remaining
Royalty Interests following the Termination Date. Through the Termination Date, the Trustee
determines for each quarter the amount of cash available for distribution to Unitholders. Such
amount (the Quarterly Distribution Amount) is equal to the excess, if any, of the cash received
by the Trust, on or prior to the last day of the month following the end of each calendar quarter
ending prior to the dissolution of the Trust from the Royalty Interests then held by the Trust
plus, with certain exceptions, any other cash receipts of the Trust during such quarter (which
might include purchase price adjustments paid by WPC, sales proceeds not sufficient in amount to
qualify for a special distribution as described in the next paragraph, and interest), over the
liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the
Trustee during such quarter in any cash reserves established for the payment of contingent or
future obligations of the Trust. Based on the payment procedures relating to the Royalty
Interests, cash received by the Trustee in a particular quarter from the Royalty Interests
generally represents the sum of (i) proceeds from the sale of gas produced from the WI Properties
during the preceding calendar quarter plus (ii) cash received by WPC with respect to the Farmout
Properties either (a) during the preceding calendar quarter or (b) if received in sufficient time
to be paid to the Trust, in the month immediately following such preceding calendar quarter. The
Trustee distributes the Quarterly Distribution Amount within 60 days after the end of each calendar
quarter to each person who was a Unitholder of record on the associated record date (i.e., the
45th day following the end of each calendar quarter or if such day is not a business
day, the next business day thereafter), together with interest expected to be earned on such
Quarterly Distribution Amount from the date of receipt thereof by the Trustee to the payment date.
The Royalty Interests may be sold under certain circumstances and will be sold following
termination of the Trust. Any purchase price adjustments and the proceeds from sales of the
Royalty Interests, less liabilities and expenses of the Trust and amounts used for cash reserves,
will be distributed, together with any interest expected to be earned thereon, to Unitholders of
record on the record date established for such distribution. If applicable, a
9
special distribution will be made of undistributed sales proceeds, purchase price adjustments
and other amounts received by the Trust aggregating in excess of $9,000,000 (a Special
Distribution Amount). The record date for a Special Distribution Amount will be the
15th day following receipt of amounts aggregating a Special Distribution Amount by the
Trust (unless such day is not a business day in which case the record date will be the next
business day thereafter) unless such day is within 10 days of the record date for a Quarterly
Distribution Amount in which case the record date will be the date as is established for the next
Quarterly Distribution Amount. Any applicable distribution to Unitholders would be made no later
than 15 days after the Special Distribution Amount record date.
The terms of the Trust Agreement seek to assure, to the extent practicable, that gross income
attributable to cash being distributed will be reported by the Unitholder who receives such
distributions assuming that such Unitholder is the owner of record on the applicable record date.
In certain circumstances, however, a Unitholder will not receive the cash giving rise to such
income. For example, the Trustee maintains a cash reserve and is authorized to borrow money under
certain conditions to pay or provide for the payment of Trust liabilities. Income associated with
the cash used to increase that reserve or to repay any such borrowings must be reported by the
Unitholder, even though that cash is not distributed to him. Likewise, if a portion of a cash
distribution is attributable to a reduction in the cash reserve maintained by the Trustee, such
cash is treated as a reduction of the Unitholders basis in his Units and is not treated as taxable
income to such Unitholder (assuming such Unitholders basis exceeds the total amount of the cash
distribution).
Transfer of Royalty Interests
WPC or its assigns may, at any time, purchase for cash all Royalty Interests attributable to
Underlying Properties that are uneconomical to operate. See Item 2PropertiesThe Royalty
InterestsTitle to Properties and Sale and Abandonment of Underlying Properties. Upon
termination of the Trust, any remaining Royalty Interests will be sold by the Trust and any such
sales may, and under certain circumstances will, be made to WPC or Williams or their respective
successors or assigns. See Item 1Description of the TrustTermination and Liquidation of the
Trust.
Possible Divestiture of Units
The Trust Agreement imposes no restrictions based on nationality or other status of
Unitholders. However, the Trust Agreement provides that in the event of certain judicial or
administrative proceedings seeking the cancellation or forfeiture of any property in which the
Trust has an interest, or asserting the invalidity of or otherwise challenging any portion of the
Royalty Interests, because of the nationality, citizenship or any other status of any one or more
Unitholders, the Trustee will give written notice thereof to each Unitholder whose nationality,
citizenship or other status is an issue in the proceeding, which notice will constitute a demand
that such Unitholder dispose of his Units within 30 days. If any Unitholder fails to dispose of
his Units in accordance with such notice, the Trustee shall have the right to cancel all
outstanding certificates issued in the name of such Unitholder, transfer all Units held by such
Unitholder to the Trustee and sell such Units (including by private sale). The proceeds of such
sale (net of sales expenses), pending delivery of certificates representing the Units, will be held
by the Trustee in a non-interest bearing account for the benefit of the Unitholder and paid to the
Unitholder upon surrender of such certificates. Cash distributions payable to such Unitholder will
also be held in a non-interest bearing account pending disposition by the Unitholder of the Units
or cancellation of certificates representing the Units by the Trustee.
Periodic Reports to Unitholders
Within 60 days following the end of each of the first three calendar quarters of each calendar
year, the Trustee mails to each party who was a Unitholder of record (i) on the quarterly record
date for such quarter or (ii) on a Special Distribution Amount record date occurring during such
quarter (if any), a report that shows in reasonable detail the assets and liabilities and receipts
and disbursements of the Trust for such quarter. Unitholders are also furnished with comparable
quarterly information with respect to the Underlying Properties. Within 120 days following the end
of each fiscal year or such shorter period of time as may be required by the rules of the New York
Stock Exchange, the Trustee mails to Unitholders of record as of a date to be selected by the
Trustee an annual report containing audited financial statements relating to the Trust.
10
The Trustee files such returns for Federal income tax purposes as it is advised are required
to comply with applicable law. The Trustee mails to each party who was a Unitholder of record (i)
on the quarterly record date for such quarter or (ii) on a Special Distribution Amount record date
occurring during such quarter (if any), a report that shows in reasonable detail the information
necessary to permit each Unitholder to make all calculations reasonably necessary for tax purposes.
The Trustee treats all income, credits and deductions recognized during each quarter as having
been recognized by holders of record on the quarterly record date established for the distribution
unless otherwise advised by counsel. Available year-end tax information permitting each Unitholder
to make all calculations reasonably necessary for tax purposes is distributed by the Trustee to
Unitholders no later than March 15 of the following year. See also Item 1Federal Income
Taxation, WHFIT Reporting Requirements regarding certain reporting requirements imposed upon
middlemen because the Trust is considered a WHFIT for Federal income tax purposes.
Each Unitholder and his duly authorized agents and attorneys have the right during reasonable
business hours to examine and inspect records of the Trust and the Trustee.
Voting Rights of Unitholders
Unitholders have only such voting rights as are provided in the Trust Agreement and such
rights are more limited than those of stockholders of most corporations. Unitholder approval is,
however, required to appoint a successor Trustee or Delaware Trustee. Also, Unitholder approval is
required to amend the Trust Agreement (except for changing the name of the Trust and except to
correct or cure ambiguities in the Trust Agreement that do not adversely affect Unitholders) and to
adopt any amendment to the Gas Gathering Contract relating to production from the Underlying
Properties entered into between WFS (a subsidiary of Williams Energy Services) and WPX Gas
Resources Company (a subsidiary of WPC (formerly known as WFS Resources Company), WPX Gas
Resources) as successor-in-interest to WGM (a former subsidiary of Williams Field Services Group,
Inc., which has been merged into another affiliate of Williams Field Services Group, Inc.) or to
the Gas Purchase Contract relating to production from the Underlying Properties entered into
between WPC and WPX Gas Resources (as successor-in-interest to WGM), if such amendment would
materially adversely affect revenues of the Trust. Unitholders may also remove the Trustee or
Delaware Trustee. Unitholders are not entitled to any rights of appraisal or similar rights in
connection with the termination of the Trust.
The Trust Agreement may be amended, the Delaware Trustee and the Trustee may be removed and
the Trust may be terminated by a vote of holders of a majority of the outstanding Units, but no
provision of the Trust Agreement may be amended that would (i) increase the power of the Delaware
Trustee or the Trustee to engage in business or investment activities, or (ii) alter the rights of
the Unitholders as among themselves. All other actions may be approved by a majority vote of the
Units represented at a meeting at which a quorum, constituting a majority of the outstanding Units,
is present or represented (except that amendment of required voting percentages requires approval
of at least 80 percent of the outstanding Units). The parties to the Trust Agreement may, without
approval of the 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 Unitholders. In addition,
Williams may direct the Trustee to change the name of the Trust, which change shall not require
approval of the Unitholders.
Meetings of Unitholders may be called by the Trustee or by Unitholders owning not less than 10
percent in number of the outstanding Units. All such meetings shall be held in Dallas, Texas, and
written notice of every such meeting setting forth a time and place of the meeting and the matters
proposed to be acted upon shall be given not more than 60 nor less than 20 days before such
meeting. Each Unitholder shall be entitled to one vote for each Unit owned by such holder.
Liability of Unitholders
Consistent with Delaware law, the Trust Agreement provides that the Unitholders will have the
same limitation on personal liability as is accorded under the laws of such state to stockholders
of a corporation for profit. No assurance can be given, however, that the courts in jurisdictions
outside of Delaware will give effect to such limitation.
11
Transfer Agent
The Trustee has appointed American Stock Transfer, as transfer agent and registrar for the
Units (the Transfer Agent).
Website/SEC Filings
The Trust maintains an Internet Website (www.wtu-williamscoalseamgastrust.com), and as a
result provides free of charge website access to its annual reports on Form 10-K, quarterly reports
on Form 10-Q, current reports on Form 8-K and amendments to such reports as soon as reasonably
practicable after it electronically files with or furnishes such material to the SEC.
FEDERAL INCOME TAXATION
THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS WILL DEPEND IN PART ON
THE UNITHOLDERS TAX CIRCUMSTANCES. EACH UNITHOLDER SHOULD THEREFORE CONSULT THE UNITHOLDERS TAX
ADVISOR ABOUT THE FEDERAL, STATE AND LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF
UNITS.
The sections entitled Federal Income Tax Consequences and Risk FactorsTax Considerations
appearing in the Prospectus (the Public Offering Prospectus) dated January 13, 1993, which
constitutes a part of the Registration Statement on Form S-3 of Williams (Registration No.
33-53662) filed in connection with the registration of the Units under the Securities Act of 1933
for offer and sale in the Public Offering, set forth, respectively, a summary of Federal income tax
matters of general application that addresses the material tax consequences of the ownership and
sale of the Units acquired in the Public Offering and a discussion of certain risk factors
associated with matters of Federal income taxation as applied to the Trust and such Unitholders. A
copy of such sections of the Public Offering Prospectus is filed as an exhibit to this Form 10-K
and is incorporated herein by reference.
In connection with the registration of the Units for offer and sale in the Public Offering,
Williams and the underwriters of the Units received certain opinions of counsel to Williams (upon
which the Trustee and the Delaware Trustee were entitled to rely), including, without limitation,
opinions as to the material Federal income tax consequences of the ownership and sale of the Units
acquired in the Public Offering. The opinions of counsel to Williams as to such Federal income tax
consequences were based on provisions of the Internal Revenue Code of 1986, as amended (the IRC),
as of January 21, 1993, the date of the closing of the Public Offering, existing and proposed
regulations thereunder and administrative rulings and court decisions as of January 21, 1993, all
of which are subject to changes that may or may not be retroactively applied. Some of the
applicable provisions of the IRC have not been interpreted by the courts or the Internal Revenue
Service (IRS). In addition, such opinions of counsel to Williams were based on various
representations as to factual matters made by Williams and WPC in connection with the Public
Offering. As is typically the case, these opinions were limited in their application to certain
investors purchasing Units in the Public Offering and, as a result, provide no assurance to
investors purchasing Units following the Public Offering.
Neither counsel to the Trust, the Trustee nor the Delaware Trustee, respectively, has rendered
any opinions with respect to any tax matters associated with the Trust or the Units.
At the time of the Public Offering, no ruling was requested by Williams, as the sponsor of the
Trust, from the IRS with respect to any matter affecting the Trust or Unitholders. No assurance
can be provided that the opinions of counsel to Williams (which do not bind the IRS) will not be
challenged by the IRS or will be sustained by a court if so challenged.
12
Termination and Liquidation of the Trust
In connection with the termination of the Trust and the resulting liquidation of the Trust
pursuant to the provisions of the Trust Agreement, the Trust will not incur any Federal income tax
liability at the Trust level as a result of the sale of the Remaining Royalty Interests or payment
to Unitholders of the net proceeds from such sale. However, for Federal income tax purposes, the
sale of the Remaining Royalty Interests will be taxable to the Unitholders. Each Unitholder will
recognize gain or loss on such sale measured by the difference between the Unitholders share of
the amount realized from the sale of the Remaining Royalty Interests and such Unitholders adjusted
basis in his or her Units. The amount realized from the sale of the Remaining Royalty Interests
will be allocated to Unitholders in the same manner as the Trustee allocates the income received by
the Trust.
Prior to determining the gain or loss resulting from the sale of the Remaining Royalty
Interests following the liquidation of the Trust, each Unitholder should reduce his tax basis (but
not below zero) in the Remaining Royalty Interests (and, correspondingly, his Units) by (1) the
amount of depletion allowable with respect to the Remaining Royalty Interests through the date of
the liquidation, and (2) by the amount of any return of capital, including returns of capital
resulting from a reduction to the cash reserve maintained by the Trust during a quarterly period.
Assuming a Unitholder holds his or her Units as a capital asset, gain or loss from the sale of
the Remaining Royalty Interests will be treated as a capital gain or loss. If the Units have been
held for more than one year, the gain or loss will constitute a long-term capital gain or loss;
otherwise, the gain or loss will constitute a short-term capital gain or loss. Notwithstanding the
foregoing, a Unitholder must, upon the sale of the Remaining Royalty Interests, treat as ordinary
income his or her depletion recapture amount, which is an amount equal to the lesser of (i) the
gain on the sale of the Remaining Royalty Interests or (ii) the sum of the prior depletion
deductions taken with respect to the Remaining Royalty Interests (but not in excess of the initial
basis of such Units allocated to the Remaining Royalty Interests).
The Trust is treated as a grantor trust for Federal income tax purposes. As a result, each
Unitholder will be treated as owning directly an interest in the Remaining Royalty Interests, and
each Unitholder will be taxed directly on his or her pro rata share of income and deductions
attributable to the Remaining Royalty Interests consistent with the Unitholders method of
accounting and without regard to the taxable year or accounting method employed by the Trust.
Since the inception of the Trust, for purposes of reporting income and deductions from the Trust,
both cash and accrual-basis Unitholders have been allocated and treated as realizing income and
incurring deductions only on the quarterly record dates for each quarter. The Trust distributes
cash within 60 days after the end of each calendar quarter to Unitholder of record on the
associated record date.
Upon the termination of the Trust, the Trust Agreement provides that any purchaser of the
Remaining Royalty Interests, regardless of the date of closing of the purchase, shall be entitled
to all proceeds of production attributable to the Remaining Royalty Interests after the date of the
termination of the Trust and neither the Trust nor the Unitholders shall be entitled to any such
proceeds (the Purchaser Allocation Proceeds). However, in the event that all the Remaining
Royalty Interests are not, for any reason, sold or a definitive agreement for sale thereof entered
into prior to the 150th day following the date of the termination of the Trust, the
Purchaser Allocation Proceeds, and all amounts thereafter payable to the Trust, shall be
distributed instead to the Unitholders in accordance with the provisions of the Trust Agreement.
The proceeds from the sale of the Remaining Royalty Interests, less liabilities and expenses
of the Trust and amounts used for cash reserves, will be distributed, together with any interest
expected to be earned thereon, to Unitholders of record on the record date established for such
distribution. No assurances can be given as to the amount, or timing, or distributions, if any, to
Unitholders of the Trust, as such amount and timing would depend in part on the amount of expenses
ultimately payable by the Trust and when such expenses become payable and the net sales price of
the Remaining Royalty Interests and when the sale of the Remaining Royalty Interests occurs.
Unitholders should consult their own tax advisors regarding the Federal income tax
consequences of the sale of the Remaining Royalty Interests following the termination of the Trust.
13
Summary of Certain Federal Income Tax Consequences
The following summary of certain Federal income tax consequences of acquiring, owning and
disposing of Units is based on the opinions of counsel to Williams on Federal income tax matters,
which are set forth in the Public Offering Prospectus, and is qualified in its entirety by express
reference to the sections of the Public Offering Prospectus identified in the first paragraph of
this Federal Income Taxation section. Although the Trust believes that the following summary
contains a description of all of the material matters discussed in the opinions referenced above,
the summary is not exhaustive and many other provisions of the Federal tax laws may affect
individual Unitholders. Furthermore, the summary does not purport to be complete or to address the
tax issues potentially affecting Unitholders acquiring Units other than by purchase through the
Public Offering. Each Unitholder should consult the Unitholders tax advisor with respect to the
effects of the Unitholders ownership of Units on the Unitholders personal tax situation.
Classification and Taxation of the Trust
|
The Trust is a grantor trust for Federal tax purposes and not an association taxable as a corporation. As a grantor trust, the Trust is not subject to Federal income tax. There can be no assurance that the IRS will not challenge this treatment. The tax treatment of the Trust and Unitholders would be materially different if the IRS were to successfully challenge this treatment. | |
Taxation of Unitholders
|
Each Unitholder is taxed directly on his proportionate share of income, deductions and credits of the Trust attributable to the Royalty Interests consistent with such Unitholders taxable year and method of accounting, and without regard to the taxable year or method of accounting employed by the Trust. | |
Income and Deductions
|
The income of the Trust consists primarily of a specified share of the proceeds from the sale of coal seam gas produced from the Underlying Properties. During 2009, the Trust earned interest income on funds held for distribution. The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each Unitholder is entitled to depletion deductions. See Unitholders Depletion Allowance below. | |
Individuals may deduct miscellaneous itemized deductions (including, in general, investment expenses) only to the extent that such expenses exceed 2 percent of the individuals adjusted gross income. Although there are exceptions to the 2 percent limitation, authority suggests that no exceptions apply to expenses passed through from a grantor trust, like the Trust. | ||
Unitholders Depletion Allowance
|
Each Unitholder is entitled to amortize the cost of the Units through cost depletion over the life of the NPI or if greater, through percentage depletion equal to 15 percent of gross income. Unlike cost depletion, percentage depletion is not limited to a Unitholders depletable tax basis in the Units. Rather, a Unitholder is entitled to a percentage depletion deduction as long as the applicable Underlying Properties generate gross income. If any portion of the NPI is treated as a production payment or is not treated as an economic interest, however, a Unitholder will not be entitled to depletion in respect of such portion. | |
Depletion Recapture
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If a taxpayer disposes of any section 1254 property (certain oil, gas, geothermal or other mineral property), and if the adjusted basis of such property includes adjustments for deductions for depletion under Section 611 of the IRC (discussed above), the taxpayer |
14
generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the United States Treasury Regulations govern dispositions of property after March 13, 1995. The IRS will likely take the position that a Unitholder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit. | ||
Non-Passive Activity Income, Credits
and Loss
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The income, credits and expenses of the Trust are not taken into account in computing the passive activity losses and income under Section 469 of the IRC for a Unitholder who acquires and holds Units as an investment and did not acquire them in the ordinary course of a trade or business. | |
Unitholder Reporting Information
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The Trustee furnishes to Unitholders tax information concerning royalty income, depletion and other relevant tax matters on an annual basis. Year-end tax information is furnished to Unitholders no later than March 15 of the following year. See the second paragraph under Description of UnitsPeriodic Reports to Unitholders and WHFIT Reporting Requirements immediately below for additional Unitholder reporting information. | |
WHFIT Reporting Requirements
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Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name, referred to herein collectively as middlemen). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (WHFIT) for U.S. federal income tax purposes. U.S. Trust, Bank of America Private Wealth Management, EIN: 56-0906604, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHIFT. Tax information is also posted by the Trustee at www.wtu-williamscoalseamgastrust.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units, including the issuance of IRS Form 1099 and certain written tax statements. Unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units. |
ERISA CONSIDERATIONS
The section entitled ERISA Considerations appearing in the Public Offering Prospectus sets
forth certain information regarding the applicability of the Employee Retirement Income Security
Act of 1974, as amended (ERISA), and the IRC to pension, profit-sharing and other employee
benefit plans, and to individual retirement
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accounts (collectively, Qualified Plans). A copy of this section of the Public Offering
Prospectus is filed as an exhibit to this Form 10-K and is incorporated herein by reference.
Due to the complexity of the prohibited transaction rules and the penalties imposed upon
persons involved in prohibited transactions, it is important that potential qualified plan
investors consult their counsel regarding the consequences under ERISA and the IRC of their
acquisition and ownership of Units.
STATE TAX CONSIDERATIONS
THE FOLLOWING IS INTENDED AS A BRIEF SUMMARY OF CERTAIN INFORMATION REGARDING STATE INCOME
TAXES AND OTHER STATE TAX MATTERS AFFECTING THE TRUST AND UNITHOLDERS. UNITHOLDERS SHOULD
THEREFORE CONSULT THE UNITHOLDERS TAX ADVISOR REGARDING STATE INCOME TAX FILING AND COMPLIANCE
MATTERS.
Unitholders should consider state and local tax consequences of holding Units. The Trust owns
Royalty Interests burdening gas properties located in New Mexico and Colorado. Both New Mexico and
Colorado have income taxes applicable to individuals and corporations (subject to certain
exceptions for S corporations). A Unitholder is generally required to file state income tax
returns and/or pay taxes in those states and may be subject to penalties for failure to comply with
such requirements. In addition, these states may require the Trust to withhold tax from
distributions to Unitholders to the extent such distributions are attributable to income from
properties located in such states.
The Trustee will provide information concerning the Units sufficient to identify the income
from Units that is allocable to each state. Unitholders should consult their own tax advisors to
determine their income tax filing requirements with respect to their share of income of the Trust
allocable to states imposing an income tax on such income.
The Trust has been structured to cause the Units to be treated for certain state law purposes
essentially the same as other securities, that is, as interests in intangible personal property
rather than as interests in real property. If the Units are held to be real property or an
interest in real property under the laws of either or both of such states, a Unitholder, even if
not a resident of such state, could be subject to devolution, probate and administration laws, and
inheritance or estate and similar taxes, under the laws of such state.
The sale of the Remaining Royalty Interests following the termination of the Trust may be
taxable events to the Unitholders for state tax purposes. Unitholders should consult their own tax
advisors regarding the state tax consequences of the sale of the Remaining Royalty Interests
following the termination of the Trust.
REGULATION AND PRICES
Regulation of Natural Gas
The production, transportation and sale of natural gas from the Underlying Properties are
subject to Federal and state governmental regulation, including regulation of tariffs charged by
pipelines, taxes, the prevention of waste, the conservation of gas, pollution controls and various
other matters.
Legislative Proposals. In the past, Congress has been very active in the area of gas
regulation. Legislation enacted in recent years has repealed incremental pricing requirements and
gas use restraints previously applicable.
Federal and State Regulation of Gas. The Underlying Properties are subject to the
jurisdiction of the Federal Energy Regulatory Commission (FERC) and the Department of Energy
(DOE) with respect to various aspects of gas operations, including marketing and production of
gas but not the wellhead price for natural gas. All sales of natural gas produced from the
Underlying Properties are considered under the Natural Gas Policy Act of 1978 (NGPA) and the
Natural Gas Wellhead Decontrol Act of 1989 to be sold at the wellhead (as opposed to downstream
sales or resales) for purposes of pricing and therefore are not subject to federal regulation.
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The transportation of natural gas in interstate commerce is subject to Federal regulation by
FERC under the Natural Gas Act (NGA) and the NGPA. FERC has initiated a number of regulatory
policy initiatives that have affected the transportation of natural gas from the wellhead to the
market and may promulgate new regulations that affect the marketing of natural gas. Such
initiatives include regulations that are intended to further open access to interstate pipelines by
requiring such pipelines to unbundle their transportation services from sales services and allow
customers to choose and pay for only the services they require, regardless of whether the customer
purchases natural gas from such pipelines or from other suppliers. Although these regulations
should generally facilitate the transportation of natural gas produced from the Underlying
Properties to natural gas markets, the impact of these regulations on prices and costs related to
the marketing production from the Underlying Properties cannot be fully predicted at this time;
however, it is possible such impact could be significant. On August 8, 2005, Congress enacted the
Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the NGA to prohibit
natural gas market manipulation by any entity and allows FERC to facilitate market transparency in
the market for natural gas.
Many state jurisdictions have at times imposed limitations on the production of gas by
restricting the rate of flow for gas wells from their actual capacity to produce and by imposing
acreage limitations for the drilling of a well. State and local jurisdictions have also imposed
permitting requirements or other requirements that may delay the drilling of new wells. Most
states regulate the exploration for and the subsequent production of gas. These regulations
include requirements for obtaining drilling permits, the method of developing new fields,
provisions for the unitization or pooling of gas properties, the spacing, operation, plugging and
abandonment of wells and the prevention of waste of gas resources. The rate of production may be
regulated and the maximum daily production allowable from gas wells may be established on a market
demand or conservation basis or both.
Several states have in past years also enacted or proposed regulations intended to revise
significantly current systems of prorationing gas production. The modified rules may decrease the
total amount of gas produced and could result in an increase in market prices for gas. The
foregoing developments have fostered debate regarding the purpose and effect of the new
prorationing rules, with opponents of such rules arguing that the primary purpose thereof is to
increase gas prices by withholding supplies from the market.
At the present time, it is impossible to predict what potential regulatory proposals, if any,
might actually be enacted by Congress or the various state legislatures or regulatory entities and
what effect, if any, such proposals might have on the Underlying Properties gas or oil prices and
the Trust.
Environmental Regulation
General. Activities on the Underlying Properties are subject to existing Federal, state and
local laws (including case law), rules and regulations governing health, safety, environmental
quality and pollution control. It is anticipated that, absent the occurrence of an extraordinary
circumstance or event, compliance with existing Federal, state and local laws, rules and
regulations regulating health, safety, the release of materials into the environment or otherwise
relating to the protection of the environment will not have a material adverse effect upon the
Trust or Unitholders. The Trustee cannot predict what effect additional regulation or legislation,
enforcement policies thereunder, and claims for damages to property, employees, other persons and
the environment resulting from operations on the Underlying Properties could have on the Trust or
Unitholders. However, pursuant to the terms of the Conveyance, any costs or expenses incurred by
WPC in connection with environmental liabilities arising out of or relating to activities occurring
on, in or in connection with, or conditions existing on or under, the Underlying Properties before
October 1, 1992, will be borne by WPC and not the Trust and will not be deducted in calculating NPI
Net Proceeds or Infill Net Proceeds. Environmental costs or expenses that are attributable to the
Farmout Properties that arise after October 1, 1992, could reduce the revenue paid to WPC and,
therefore, the amount of NPI Net Proceeds.
Solid and Hazardous Waste. The Royalty Interests are carved out of WPCs interests in certain
properties that have produced gas from other formations for many years. WPC, the owner of the
Underlying Properties, has acted as operator for only a small number of the coal seam gas wells,
and for a relatively short period of time. Williams and WPC have advised the Trustee that to their
knowledge, although WPC and the other operators have utilized operating and disposal practices that
were standard in the industry at the time, hydrocarbons or other solid or hazardous wastes may have
been disposed or released on or under the Underlying Properties by the current or
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previous operators. Federal, state and local laws applicable to gas-related wastes and
properties have become increasingly more stringent. Under these laws, WPC or an operator of the
Underlying Properties could be required to remove or remediate previously disposed wastes or
property contamination (including groundwater contamination) or to perform remedial plugging
operations to prevent future contamination.
The operations of the Underlying Properties may generate wastes that are subject to the
Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The
Environmental Protection Agency (the EPA) has limited the disposal options for certain hazardous
wastes and may adopt more stringent disposal standards for nonhazardous wastes.
Superfund. The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA), also known as the superfund law, imposes liability, regardless of fault or the
legality of the original conduct, on certain classes of persons that contributed to the release of
a hazardous substance into the environment. These persons include the current or previous owner
and the current or previous operator of a site and companies that disposed or arranged for the
disposal of, the hazardous substance found at a site. CERCLA also authorizes the EPA and, in some
cases, private parties to take actions in response to threats to the public health or the
environment and to seek recovery from such responsible classes of persons of the costs of such
action. In the course of their operations, the operators of the Underlying Properties have
generated and will generate wastes that may fall within CERCLAs definition of hazardous
substances. Quatro Finale (as a previous owner), WPC or an operator of the Underlying Properties
may be responsible under CERCLA for all or part of the costs to clean up sites at which such
substances have been disposed.
Air Emissions. The operations of the Underlying Properties are subject to Federal, state and
local regulations concerning the control of emissions from sources of air contaminants.
Administrative enforcement actions for failure to comply strictly with air regulations or permits
are generally resolved by payment of a monetary penalty and correction of any identified
deficiencies. Regulatory agencies could require the operators to forego or modify construction or
operation of certain air emission sources. In addition, there is an increased focus by local,
national and international regulatory bodies on green house gas (GHG) emissions and climate change.
Various regulatory bodies have announced their intent to regulate GHG emissions.
OSHA/Right-to-know. The operations of the Underlying Properties are subject to the
requirements of the Federal Occupational Safety and Health Act (OSHA) and comparable state
statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations
under Title III of the Federal Superfund Amendment and Reauthorization Act and similar state
statutes require that information be organized and maintained about hazardous materials used or
produced in the operations. Certain of this information must be provided to employees, state and
local government authorities and citizens.
The Minerals Management Service of the United States Department of the Interior amended the
natural gas valuation regulations in June 2005 for oil and natural gas produced from federal oil
and natural gas leases. The principal effect of the natural gas valuation regulations pertains to
the calculation of transportation deductions and changes necessitated by judicial decisions since
the regulations were last amended. These changes have not had a significant effect on trust
distributions but could have a significant effect on trust distributions in the future.
Competition, Markets and Prices
The revenues of the Trust and the amount of cash distributions to Unitholders depend upon,
among other things, the effect of competition and other factors in the market for natural gas. The
gas industry is highly competitive in all of its phases. WPC encounters competition from major oil
and gas companies, independent oil and gas concerns, and individual producers and operators. Many
of these competitors have greater financial and other resources than WPC. Competition is also
potentially presented by alternative fuel sources, including heating oil and other fossil fuels,
and non-conventional sources such as wind energy.
Demand for natural gas varied over the past several years. These variations were in response
to stronger domestic economic conditions, relatively higher prices for alternative energy sources
such as crude oil, and other factors. However, in the recent short term, decreased demand for
natural gas production in the United States has generally resulted in lower natural gas prices.
The existence or effect of any shortages or excesses of natural gas
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production capacity as may exist in the future cannot be predicted with certainty. See Item
2PropertiesThe Royalty InterestsHistorical Gas Sales Prices and Production.
Demand for natural gas production has historically been seasonal in nature and prices for gas
fluctuate accordingly. Consequently, the amount of cash distributions by the Trust may vary
substantially on a seasonal basis. Generally, gas production volumes and prices tend to be higher
during the first and fourth quarters of the calendar year. Because of the lag between the receipt
of revenues related to the Underlying Properties and the dates on which distributions are made to
Unitholders, however, any seasonality that affects production and prices generally should be
reflected in distributions that are made to Unitholders in later periods. See Description of
UnitsDistributions and Income Computations.
Prices for natural gas are subject to wide fluctuations in response to relatively minor
changes in supply, market uncertainty and a variety of additional factors that are beyond the
control of the Trust, Williams and WPC. These factors include political conditions in the Middle
East, the price and quantity of imported oil and gas, the level of consumer product demand, the
severity of weather conditions, government regulations, the price and availability of alternative
fuels and overall economic conditions. In view of the many uncertainties affecting the supply and
demand for natural gas and natural gas prices, the Trust and Williams are unable to make reliable
predictions of future gas prices, production, or demand or the overall effect they will have on the
Trust.
Item 1A. Risk Factors.
The Trust terminated on March 1, 2010 and will be required to sell its remaining Royalty Interests.
The Trusts computed net present value of the estimated future net revenues for proved
reserves attributable to the Royalty Interests computed in accordance with the Trust Agreement,
using an average 2009 index price of $3.25, by the independent petroleum engineers as of December
31, 2009, was approximately $8.4 million. This calculation does not necessarily represent the fair
value of the Underlying Properties. The results of this computation triggered an early termination
of the Trust as of March 1, 2010 in accordance with the terms of the Trust Agreement. In
accordance with the Trust Agreement, the Trustee is required to use best efforts to sell any
remaining Royalty Interests for cash pursuant to the procedures described in the Trust Agreement.
There can be no assurance that any sale will be on terms acceptable to all Unitholders. See Item
1 Description of the Trust Termination and Liquidation of the Trust.
The Trust will incur expenses in connection with the sale of its remaining Royalty Interests.
The Trust will incur expenses in connection with the sale of its remaining Royalty Interests
and liquidation, including fees and expenses of an investment banking firm to assist with the sale
of the Trusts remaining Royalty Interests, and the expenses could be significant.
If the Trust has not sold all the Royalty Interests by February 28, 2011, the Trustee is required
to sell the remaining Royalty Interests in a public auction.
If any remaining Royalty Interests have not been sold or a definitive agreement for sale has
not been entered into by February 28, 2011, the Trustee is required to sell the remaining Royalty
Interests at public auction to the highest cash bidder. A public auction might not result in as
favorable a price for the Trusts remaining Royalty Interests as an individually negotiated
transaction.
Natural gas prices are volatile and fluctuate in response to a number of factors. Lower prices
could reduce the price a buyer is willing to pay for the Royalty Interests resulting in a reduction
of the amount paid to Unitholders upon liquidation of the Trust.
The price a buyer is willing to pay for the Royalty Interests will be dependent upon the
prices realized from the sale of natural gas and a material decrease in such prices could reduce
the amount paid to Unitholders upon liquidation of the Trust. 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. Factors that contribute to price fluctuation include, among others:
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| political conditions in major oil and gas producing regions, especially the Middle East; | ||
| Worldwide economic conditions; | ||
| weather conditions; | ||
| the supply and price of domestic and foreign natural gas; | ||
| the level of consumer demand; | ||
| the price and availability of alternative fuels; | ||
| the proximity to, and capacity and cost of, transportation facilities; | ||
| the effect of worldwide energy conservation measures; and | ||
| the nature and extent of governmental regulation and taxation. |
When natural gas prices decline, the Trust is affected. First, net income from the Royalty
Interests is reduced. Second, exploration and development activity on the Underlying Properties
may decline as some projects may become uneconomic and are either delayed or eliminated. It is
impossible to predict future natural gas price movements. Approximately 90 percent of the natural
gas produced from the WI Properties, which generates most of the natural gas produced burdened by
the Trusts Royalty Interests, is currently being sold pursuant to the Gas Purchase Contract
entered into at the inception of the Trust whereby a subsidiary of Williams purchases the gas in
accordance with a contractual pricing mechanism. The Gas Purchase Contract expires no later than
December 2012; however, as a result of the early termination of the Trust, it will terminate upon
the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the
Trust. Under this agreement, the adverse impact on Trust revenues that would otherwise result from
low natural gas prices is somewhat mitigated. When it is terminated, revenues attributable to the
Royalty Interests will become increasingly susceptible to fluctuations resulting from changes in
prevailing natural gas prices which may impact the price a buyer is willing to pay for the Royalty
Interests.
Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could
cause both estimated reserves and estimated future net revenues to be too high, leading to
write-downs of estimated reserves.
The value of the Units and the price a buyer is willing to pay for the Royalty Interests will
depend upon, among other things, the reserves attributable to the Royalty Interests in the
Underlying Properties. The calculations of proved reserves included in this Form 10-K are only
estimates, and estimating reserves is inherently uncertain. In addition, the estimates of future
net revenues are based upon various assumptions regarding future production levels, prices and
costs that may prove to be incorrect over time.
The accuracy of any reserve estimate is a function of the quality of available data,
engineering interpretation and judgment, and the assumptions used regarding the quantities of
recoverable natural gas and the future prices of natural gas. Petroleum engineers consider many
factors and make many assumptions in estimating reserves. Those factors and assumptions include:
| historical production from the area compared with production rates from similar producing areas; | ||
| the effects of governmental regulation; | ||
| assumptions about future commodity prices, production and development costs, taxes, and capital expenditures; | ||
| the availability of enhanced recovery techniques; and | ||
| relationships with landowners, working interest partners, pipeline companies and others. |
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Changes in any of these factors and assumptions can materially change reserve and future net
revenue estimates. The Trusts estimate of reserves and future net revenues is further complicated
because the Trust holds net profits interests and does not own a specific percentage of the natural
gas reserves. Ultimately, actual production, revenues and expenditures for the Underlying
Properties, and therefore actual net proceeds payable with respect to the Royalty Interests, will
vary from estimates and those variations could be material. Results of drilling, testing and
production after the date of those estimates may require substantial downward revisions or
write-downs of reserves.
The assets of the Trust are depleting assets and, if the other operators developing the Underlying
Properties do not perform additional development projects, the assets may deplete faster than
expected. In addition, a reduction in depletion tax benefits may reduce the market value of the
Units.
The net proceeds payable to the Trust are derived from the sale of depleting assets. The
reduction in proved reserve quantities is a common measure of depletion. Future maintenance and
development projects on the Underlying Properties will affect the quantity of proved reserves and
can offset the reduction in proved reserves. The timing and size of these projects will depend on
the market prices of natural gas. If the operators developing the Underlying Properties do not
implement additional maintenance and development projects, the future rate of production decline of
proved reserves may be higher than the rate currently expected by the Trust.
Because the net proceeds payable to the Trust are derived from the sale of depleting assets,
the portion of distributions to Unitholders attributable to depletion may be considered a return of
capital as opposed to a return on investment. Distributions that are a return of capital will
ultimately diminish the depletion tax benefits available to the Unitholders, which could reduce the
market value of the Units over time.
Any distributions upon a termination and liquidation of the Trust may not equal or exceed the
purchase price paid by a Unitholder for Units.
The market price for Trust Units is based on a variety of factors outside the control of the
Trustee. There is no guarantee that any distributions upon a termination and liquidation of the
Trust will equal or exceed the purchase price paid by the Unitholder.
Funds held by the Trustee are not insured by the Federal Deposit Insurance Corporation.
Currently, funds are invested in Bank of America money market accounts which are backed by the
good faith and credit of Bank of America, N.A., but are not insured by the Federal Deposit
Insurance Corporation (FDIC). Each Unitholder should independently assess the creditworthiness
of Bank of America, N.A. For more information about the credit rating of Bank of America, N.A.,
please refer to its periodic filings with the SEC. The Trust does not lend money and has limited
ability to borrow money, which the Trustee believes limits the Trusts risk from the current
tightening of credit markets.
The market price for the Units may not reflect the value of the Royalty Interests held by the
Trust.
The public trading price for the Units has historically tended to be tied to recent and
expected levels of cash distribution on the Units. The amounts available for distribution by the
Trust varied in response to numerous factors outside the control of the Trust, including prevailing
prices for natural gas produced from the Trusts Royalty Interests. The market price is not
necessarily indicative of the value that the Trust will realize if it sells those Royalty Interests
to a third party buyer. There is no guarantee that distributions made to a Unitholder upon the
termination and liquidation of the Trust will equal or exceed the purchase price paid by the
Unitholder.
Operational risks and hazards associated with the development of the Underlying Properties may
decrease the price a buyer is willing to pay for the Royalty Interests resulting in a reduction of
the amount paid to Unitholders upon liquidation of the Trust.
There are operational risks and hazards associated with the production and transportation of
natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage
of natural gas, releases of other
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hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar
occurrences could result in the interruption or cessation of operations, personal injury or loss of
life, property damage, damage to productive formations or equipment, damage to the environment or
natural resources, or cleanup obligations. The operation of natural gas properties is also subject
to various laws and regulations. Non-compliance with such laws and regulations could subject the
operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of
the above or similar occurrences could be deducted as a cost of production in calculating the net
proceeds payable with respect to the Royalty Interests and could therefore reduce the price a buyer
is willing to pay for the Royalty Interests resulting in a reduction of the amount paid to
Unitholders upon liquidation of the Trust.
Terrorism and continued hostilities in the Middle East could decrease the market price of the Units
or the price a buyer is willing to pay for the Royalty Interests resulting in a reduction of the
amount paid to Unitholders upon liquidation of the Trust.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as
the military or other actions taken in response, cause instability in the global financial and
energy markets. Terrorism, the war in Iraq and other sustained military campaigns could adversely
affect the market price of the Units or the price a buyer is willing to pay for the Royalty
Interests resulting in a reduction of the amount paid to Unitholders upon liquidation of the Trust.
Unitholders and the Trustee have no influence over the operations on, or future development of, the
Underlying Properties.
Neither the Trustee nor the Unitholders can influence or control the operations on, or future
development of, the Underlying Properties. The failure of an operator to conduct its operations,
discharge its obligations, deal with regulatory agencies or comply with laws, rules and
regulations, including environmental laws and regulations, in a proper manner could have an adverse
effect on the net proceeds payable with respect to the Royalty Interests. The current operators
developing the Underlying Properties are under no obligation to continue operations on the
Underlying Properties. Neither the Trustee nor the Unitholders have the right to replace an
operator.
The operator developing any Underlying Property may transfer its interest in the property without
the consent of the Trust or the Unitholders.
Any operator developing any of the Underlying Properties may at any time transfer all or part
of its interest in the Underlying Properties to another party. Neither the Trust nor the
Unitholders are entitled to vote on any transfer of the properties underlying the Royalty
Interests, and the Trust will not receive any proceeds of any such transfer. Following any
transfer, the transferred property will continue to be subject to the Royalty Interests, but the
net proceeds from the transferred property will be calculated separately and paid by the
transferee. The transferee will be responsible for all of the transferors obligations relating to
calculating, reporting and paying owed with respect to the Royalty Interests from the transferred
property, and the transferor will have no continuing obligation with respect to the Royalty
Interests for that property.
The operator developing any Underlying Property may abandon the property, thereby terminating the
Royalty Interests.
The operators developing the Underlying Properties, or any transferee thereof, may abandon any
well or property without the consent of the Trust or the Unitholders if, in their opinion, such
well or property ceases to produce or is not capable of producing in commercially paying
quantities. This could result in the termination of the Royalty Interests relating to the
abandoned well or property.
Trust Unitholders have limited voting rights and have limited ability to enforce the Trusts rights
against the current or future operators developing the Underlying Properties.
The voting rights of a Unitholder are more limited than those of stockholders of most public
corporations. For example, there is no requirement for annual meetings of Unitholders or for an
annual or other periodic re-election of the Trustee. Unlike corporations which are generally
governed by boards of directors elected by their
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equity holders, the Trust is administered by an institutional trustee in accordance with the Trust
Agreement and other organizational documents. The Trustee has extremely limited discretion in its
administration of the Trust.
Financial information of the Trust is not prepared in accordance with GAAP.
The financial statements of the Trust are prepared on a modified cash basis of accounting,
which is a comprehensive basis of accounting other than accounting principles generally accepted in
the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by
the SEC, the financial statements of the Trust differ from GAAP financial statements because, among
other things, revenues are not accrued in the month of production and loss contingencies are
recognized in the period in which amounts are paid by the Trust.
The limited liability of Trust Unitholders is uncertain.
Consistent with Delaware law, the Trust Agreement provides that the Unitholders will have the
same limitation on personal liability as is accorded under the laws of such state to stockholders
of a corporation for profit. No assurance can be given, however, that the courts in jurisdictions
outside of Delaware will give effect to such limitation.
An increase in payments due to the U.S. Government for gas produced on Federal and Indian lands may
result in a reduction of net proceeds from Royalty Interests.
Approximately 80 percent of the Underlying Properties are burdened by Royalty Interests held
by the Federal government or the Southern Ute Indian Tribe. Royalty payments due to the U.S.
Government for gas produced from Federal and Indian lands included in the Underlying Properties
must be calculated in conformance with its interpretation of regulations issued by the Minerals
Management Service (MMS), a subagency of the U.S. Department of the Interior that administers and
receives revenues from Federal and Indian royalties on behalf of the U.S. Government and as agent
for the Indian tribes. The MMS regulations cover both valuation standards, which establish the
basis for placing a value on production, and cost allowances, which define those post-production
costs that are deductible by the lessee.
The MMS generally audits royalty payments within a 6-year period. Although WPC calculates
royalty payments in accordance with its interpretation of the then applicable MMS regulations, WPC
does not know whether the royalty payments made to the U.S. Government are totally in conformity
with MMS standards until the payments are audited. If an MMS audit, or any other audit by a
Federal or state agency, results in additional royalty charges, together with interest, relating to
production since October 1, 1992, in respect of the Underlying Properties, such charges and
interest will be deducted in calculating NPI Net Proceeds for the quarter in which the charges are
billed and in each quarter thereafter until the full amount of the additional royalty charges and
interest have been recovered.
As more infill wells are drilled, they could cause a reduction in amounts payable with respect to
the Royalty Interests.
The Royalty Interests include a 20 percent net profit interest in infill wells. Infill wells
may recover a portion of the reserves that would otherwise be produced from wells burdened by the
Trusts net profits interests. Since the Trust is entitled to receive 60 percent of the net
proceeds from production burdened by its net profits interests but only 20 percent of the net
profits from infill wells the drilling of infill wells may reduce payments with respect to the
Royalty Interests, and the price a buyer is willing to pay for the Royalty Interests. See Item
1Description of the TrustAssets of the Trust and Item 2The Royalty InterestsThe Infill
Wells for more information.
Item 1B. Unresolved Staff Comments.
The Trust has not received any written comments from the SEC staff regarding its periodic or
current reports under the Act not less than 180 days preceding December 31, 2009, which comments
remain unresolved.
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Item 2. Properties.
THE ROYALTY INTERESTS
The Royalty Interests conveyed to the Trust consist of net profits interests in the Underlying
Properties. The Royalty Interests were conveyed to the Trust by means of a single instrument of
conveyance. The Conveyance was recorded in the appropriate real property records in each county in
New Mexico and Colorado where the Underlying Properties are located so as to give notice of the
Royalty Interests to creditors and transferees, who would take an interest in the Underlying
Properties subject to the Royalty Interests. The Conveyance was intended to convey the Royalty
Interests as real property interests under applicable state law.
On May 7, 1997, effective as of May 1, 1997, WPC transferred the Underlying Properties to
Quatro Finale LLC, a Delaware limited liability company, pursuant to the terms of a Purchase and
Sale Agreement dated as of May 1, 1997 (the 1997 Transaction). Prior to the 1997 Transaction,
WPC had owned the Underlying Properties, subject to and burdened by the Royalty Interests owned by
the Trust, since the inception of the Trust. The sale of the Underlying Properties is expressly
permitted under the Trust Agreement. Neither the Trustee nor the Delaware Trustee has any control
over or responsibility relating to the operation of the Underlying Properties. Under the terms of
the 1997 Transaction, ownership of the Underlying Properties reverted back to WPC effective
February 1, 2001. Pursuant to a Purchase and Sale Agreement dated March 14, 2001 (the 2001
Transaction Agreement) and effective March 1, 2001, WPC transferred the Underlying Properties to
Quatro Finale V LLC, a Delaware limited liability company (the 2001 Transaction). Effective
January 1, 2003, ownership of the Underlying Properties once again reverted back to WPC after it
exercised its right to repurchase interests in the Underlying Properties from Quatro Finale V LLC
pursuant to the 2001 Transaction Agreement. With respect to the ownership of the Underlying
Properties for any period from May 1, 1997 through February 28, 2001, and for the period from March
1, 2001 through January 1, 2003, references herein to WPC should be deemed to refer to Quatro
Finale.
Concurrently with the 2001 Transaction, WPC and Quatro Finale entered into a Management
Services Agreement dated March 1, 2001 (the Management Services Agreement), whereby WPC agreed,
among other things, to continue to manage and operate the Underlying Properties and to handle the
receipt and payment of funds with respect thereto. Following the 2001 Transaction through January
1, 2003, under the Management Services Agreement, WPC collected all revenues on behalf of Quatro
Finale and was obligated to pay to the Trust on behalf of Quatro Finale the amounts payable with
respect to the Royalty Interests. Currently, as it did prior to the 2001 Transaction, WPC receives
all payments relating to the Underlying Properties and, pursuant to the Conveyance, pays to the
Trust the portion thereof attributable to the Royalty Interests through the Termination Date.
Under the Conveyance, the amounts payable with respect to the Royalty Interests are computed
with respect to each calendar quarter ending prior to termination of the Trust, and such amounts
are to be paid to the Trust not later than the last day of the calendar month next following the
end of each calendar quarter. The amount paid to the Trust does not include interest on any
amounts payable with respect to the Royalty Interests that are held by WPC prior to payment to the
Trust. WPC is entitled to retain any amounts attributable to the Underlying Properties that are
not required to be paid to the Trust with respect to the Royalty Interests.
Concurrently with the 2001 Transaction, WPC, Williams, the Trust and Quatro Finale entered
into an Agreement dated March 1, 2001 (the Performance Acknowledgement Agreement), pursuant to
which (i) the parties acknowledged that, although WPC was selling the Underlying Properties to
Quatro Finale, WPC retained all of its duties and obligations under the Trust Agreement, Conveyance
and related documents (the Trust Documents), subject to the terms and conditions set forth in the
2001 Transaction Agreement and the agreements entered into pursuant to the 2001 Transaction
Agreement, (ii) Williams and WPC each confirmed and agreed that, notwithstanding the sale of the
Underlying Properties to Quatro Finale, Williams and WPC would continue to perform their respective
obligations to the Trust pursuant to the Trust Documents, including without limitation the
performance assurances of Williams set forth in the Conveyance, and (iii) Quatro Finale
acknowledged and agreed that it was purchasing the Underlying Properties burdened by the Royalty
Interests owned by the Trust. Accordingly, since the inception of the Trust, WPC and Williams have
continuously retained and been subject to all of their duties and obligations under the Trust
Documents.
24
The following description contains a summary of the material terms of the Conveyance and is
subject to and qualified by the more detailed provisions of the Conveyance, a copy of which is
filed as an exhibit to this Form 10-K.
The Underlying Properties
The Royalty Interests were conveyed by WPC to the Trust from its net revenue interest (working
interest less lease burdens) in the WI Properties and its net profits interest in the Farmout
Properties. Substantially all of the production from the Underlying Properties is from the
Fruitland coal formation in the San Juan Basin. The San Juan Basin (the Basin), one of the
largest gas producing basins in the United States, encompasses approximately 12,000 square miles
in northwest New Mexico and southwest Colorado, just east of the common corner of the states of
Utah, Arizona, New Mexico and Colorado known as the Four Corners. It covers parts of La Plata and
Archuleta counties in Colorado, as well as parts of San Juan, Rio Arriba, McKinley and Sandoval
counties in New Mexico. The Basin has been an active area for coal seam gas development within the
Fruitland coal formation.
Williams acquired its interests in the Underlying Properties in 1983 through the acquisition
of Northwest Pipeline Corporation (Northwest), and such Underlying Properties were transferred to
WPC on December 31, 1990. Northwest originally owned working interests that were burdened by
overriding royalty interests in the Underlying Properties. The overriding royalty interests
resulted in excessive burdens and Northwest negotiated settlements with the owners of the
overriding royalty interests. Pursuant to one of these settlements, Northwest and Amoco Production
Company (now known as BP) entered into a joint venture under which Northwest agreed to assign to
BP certain oil and gas properties in two exploratory areas, one of which (the PLA-9 properties)
comprises the Farmout Properties. In consideration for such assignment, Northwest received an
overriding royalty interest in the Farmout Properties. Northwests rights under the joint venture
agreement were subsequently assigned to WPC, which elected, effective as of October 1, 1992, to
convert the overriding royalty interest in the Farmout Properties to a 35 percent net profits
interest.
Development of the Fruitland coal formation acreage has resulted in the drilling of 1,116
gross coal seam gas wells in the Underlying Properties, 21 of which are producing in the Farmout
Properties. WPC owns mineral rights in the Fruitland coal formation under 214 oil and gas leases.
Under the terms of these leases, WPC has the right to extract oil and gas from the lease
properties. WPC holds either a record title interest, operating right interest or net profits
interest in the leases. Record title and operating right interests are commonly referred to as
working interests. WPC does not operate any of the coal seam gas wells on the Underlying
Properties.
Unitized Areas. Approximately 96 percent of the Fruitland coal formation proved developed
coal seam gas wells on the WI Properties are located within the boundaries of New Mexico Federal
Units (as defined herein). Pursuant to the Federal Mineral Leasing Act of 1920, as amended, and
applicable state regulations, owners of oil and gas leases in New Mexico created large unitized
areas consisting of several contiguous sections for the orderly development and conservation of oil
and gas reserves. The WI Properties participate in production from the 12 unitized areas in New
Mexico referred to in the following table (the Federal Units). Operation and development of the
Federal Units is governed by unit agreements and unit operating agreements (collectively, the Unit
Agreement). Under the Unit Agreement and applicable government regulations, the Federal Unit
operators request regulatory approval from the New Mexico Commission of Public Lands, the New
Mexico Oil Conservation Commission and the Bureau of Land Management to establish or expand
participating areas which produce oil and gas in paying quantities from designated formations. The
interests of participants in a participating area are based on the surface acreage included in the
participating area. Under the terms of the Unit Agreements, the operators, selected by a vote of
the respective working interest owners, perform all operating functions.
In all of the Federal Units, participating areas have been formed for the Fruitland coal
formation. After the wells capable of producing gas in paying quantities from the Fruitland coal
formation are drilled on the undeveloped drill blocks included within a Federal Unit, such wells
are added to the participating area if approved in accordance with the appropriate Unit Agreement.
A delay of at least 18-36 months is usually incurred after a well is completed and producing before
it is added to a participating area. As participating areas are created and expanded, such
modification (which will be effective retroactively to the date production commenced from the wells
causing such expansion) results in a participant owning undivided interests in all of the producing
wells within the participating area. Therefore, WPCs working interest and net revenue interest in
the wells in a Federal Unit or participating area
25
may be modified retroactively, which could affect significantly the amount of NPI Net Proceeds
with respect to production since October 1, 1992. If any well(s) that produced or may have
produced marketable quantities of coal seam gas prior to 1980 is included in or added to a
participating area in which the WI Properties participate, the Conveyance provides that such
well(s) will be treated as, and the Trust will own, a separate net profits interest in such well(s)
(the Pre-80 Production NPI). The net proceeds for such Pre-80 Production NPI would be calculated
in a manner similar to the calculation of Infill Net Proceeds, and the Trusts share of such net
proceeds will be 60 percent.
The following table reflects certain information from the Reserve Report as of December 31,
2009 prepared by Miller and Lents, Ltd. dated February 12, 2010 (the December 31, 2009 Reserve
Report) regarding the Federal Units in which the WI Properties participate. At December 31, 2009,
the WI Properties covered 1,061 gross (111.72 net) coal seam gas wells with working interests
ranging from 0.8334 percent to 75 percent, with an average working interest of approximately 10.53
percent. The Royalty Interests participate in each Federal Unit and participating area in which
the WI Properties participate based on the acreage containing wells with proved reserves on
December 31, 2009.
Underlying Properties | ||||||||||
Estimated | ||||||||||
Discounted | ||||||||||
Future Net | ||||||||||
Net Proved | Revenues | |||||||||
Reserves | (Discounted | |||||||||
Federal Unit | Federal Unit Operator | (Bcf) | at 10%) | |||||||
(In Thousands) | ||||||||||
San Juan 30-5 |
Conoco Phillips Petroleum Company | 4.47 | 1,308.16 | |||||||
San Juan 32-7 |
Conoco Phillips Petroleum Company | 11.07 | 7,037.50 | |||||||
San Juan 32-8 |
Conoco Phillips Petroleum Company | 8.04 | 4,006.74 | |||||||
San Juan 30-6 |
*Burlington Resources | 4.26 | 2,248.92 | |||||||
San Juan 31-6 |
Conoco Phillips Petroleum Company | 1.44 | 286.98 | |||||||
San Juan 29-6 |
Conoco Phillips Petroleum Company | 5.01 | 1,564.96 | |||||||
San Juan 29-7 |
*Burlington Resources | 1.81 | 1,343.47 | |||||||
San Juan 32-9 |
*Burlington Resources | 1.09 | 393.30 | |||||||
Northeast Blanco |
Devon Energy | 0.89 | 420.91 | |||||||
Huerfano |
*Burlington Resources | 0.83 | 360.86 | |||||||
San Juan 29-5 |
Conoco Phillips Petroleum Company | 0.53 | 213.92 | |||||||
San Juan 28-6 |
*Burlington Resources | 0.25 | 95.42 |
* | Burlington Resources is a wholly-owned subsidiary of Conoco Phillips Petroleum Company |
26
Well Count and Acreage Summary. The following table shows as of December 31, 2009, 2008, and
2007, the gross and net wells and acreage by proved producing and nonproducing categories for the
WI Properties.
Number of | ||||||||||||||||
Wells | Acres | |||||||||||||||
December 31, | Gross | Net | Gross | Net | ||||||||||||
2009 |
||||||||||||||||
Producing |
1,102 | 114.4 | 150,988 | 20,681 | ||||||||||||
Nonproducing |
0 | 0 | 0 | 0 | ||||||||||||
Total |
1,102 | 114.4 | 150,988 | 20,681 | ||||||||||||
2008 |
||||||||||||||||
Producing |
1,070 | 113.6 | 150,988 | 20,681 | ||||||||||||
Nonproducing |
5 | 0.5 | 0 | 0 | ||||||||||||
Total |
1,075 | 114.1 | 150,988 | 20,681 | ||||||||||||
2007 |
||||||||||||||||
Producing |
1,086 | 118.7 | 150,988 | 20,681 | ||||||||||||
Nonproducing |
12 | 1.0 | 0 | 0 | ||||||||||||
Total |
1,098 | 119.7 | 150,988 | 20,681 | ||||||||||||
Of the total gross wells described above at December 31, 2009, 1,061 gross wells are located
in unitized areas. In addition to the above, the Farmout Properties have 21 gross wells.
Properties Outside Unitized Areas. The WI Properties also include interests held by WPC in 41
proved developed Fruitland formation coal seam gas wells held in areas outside of Federal Units
that are not reflected in the foregoing tables. As of December 31, 2009, WPCs working interest
and net revenue interests in these wells averaged 8.46 percent and 6.91 percent, respectively.
The Farmout Properties consist of a 35 percent net profits interest on a property farmed out
to BP in La Plata County, Colorado. Such properties are not within any Federal Unit boundary. The
Farmout Properties are owned, and most of the wells thereon are operated, by BP. Neither Williams,
WPC, the Delaware Trustee, the Trustee nor the Unitholders are able to influence or control the
operation or future development of the Farmout Properties. WPC has advised the Trustee that it
believes that a majority of the production from the Farmout Properties is sold by BP under
short-term marketing arrangements at spot market prices and is not subject to the Gas Purchase
Contract. No assurance can be given, however, that BP will not in the future subject production
from the Farmout Properties to long-term sales contracts at non-market responsive prices. A
portion of the production from the Farmout Properties is gathered by WFS pursuant to a gathering
contract at rates and subject to other terms that were negotiated on an arms-length basis. As of
December 31, 2009, 21 gross wells had been drilled on the Farmout Properties. For a further
description of the Farmout Properties, see The NPI.
The NPI
The NPI generally entitles the Trust to receive 60 percent (permanently reduced from 81
percent as described under The NPI Percentage Reduction below) of the NPI Net Proceeds. NPI
Net Proceeds consists generally of the aggregate proceeds attributable to (i) WPCs net revenue
interest based on the sale at the Wellhead of gas produced from the WI Properties and (ii) the
revenue stream received by WPC from its 35 percent net profits interest in the Farmout Properties,
less (a) WPCs working interest share of property and production taxes on the WI Properties; (b)
WPCs working interest share of actual operating costs on the WI Properties to the extent in excess
of those agreed to be paid by WPC as described herein; (c) WPCs working interest share of capital
costs on the WI Properties to the extent in excess of those agreed to be paid by WPC as described
herein; and (d) interest on the unrecovered portion, if any, of the foregoing costs at Citibanks
Base Rate. See Gas Purchase Contract for a discussion of the Gas Purchase Contract and the
impact of the Price Differential on the computation of NPI Net Proceeds.
27
Most of the wells reflected in the December 31, 2009 Reserve Report were drilled prior to
1994. Significant additional capital expenditures were not incurred during the early years of the
production lives of such wells, and it is not anticipated that further significant capital
expenditures will be incurred. Consequently, the December 31, 2009 Reserve Report was prepared on
the basis that there will be no capital expenditures borne by the Royalty Interests for non-infill
wells. Nevertheless, the operators and working interest owners of the wells could elect at any
time to implement measures to increase the producible reserves. These measures, if implemented,
could involve additional compression or enhanced or secondary recovery operations requiring
substantial capital expenditures that would be proportionately borne by the Royalty Interests.
Exhibit B to the Conveyance reflects estimated annual operating expenses for wells on the WI
Properties. No operating expenses in respect of the WI Properties will be deducted in calculating
NPI Net Proceeds except when the actual cumulative operating expenses attributable to WPCs working
interests in the WI Properties exceed the estimated cumulative operating expenses reflected in
Exhibit B to the Conveyance as of the close of a calendar quarter (less the estimated operating
costs in such Exhibit that are allocable to two wells that were repurchased effective as of January
1, 1994, by WPC as a purchase price adjustment or to any wells that are reconveyed to WPC as
uneconomic). The amount by which such actual cumulative operating expenses exceed estimated
cumulative operating expenses reflected in such Exhibit will be deducted in calculating NPI Net
Proceeds and, therefore, will reduce the amounts payable with respect to the NPI.
If, during any period, costs and expenses deductible in calculating the NPI Net Proceeds
exceed gross proceeds, neither the Trust nor Unitholders will be liable for such excess, but no
payments will be received with respect to the NPI until future gross proceeds exceed future costs
and expenses plus the cumulative excess of such costs and expenses plus interest thereon at
Citibanks Base Rate. However, if the excess costs are the result of capital costs incurred for
enhanced recovery or similar operations on the WI Properties, no less than 20 percent of the NPI
Net Proceeds (calculated before such capital costs are deducted) will be received with respect to
the NPI until such excess costs plus interest thereon at Citibanks Base Rate are recovered by WPC
unless such capital costs are $3,000,000 or more, in which event the Trust will only receive
payments equal to the administrative costs of the Trust until such unrecovered costs plus interest
thereon at Citibanks Base Rate are less than $3,000,000.
The calculation of NPI Net Proceeds includes amounts received by WPC in respect of its 35
percent net profits interest in the Farmout Properties. WPCs net profits interest in the Farmout
Properties is calculated on a total operations basis and is defined as lease revenues less burdens,
operating expenses (including overhead as defined in the applicable operating agreement) and all
taxes related to the value of reserves, production, property and equipment (e.g., severance and ad
valorem taxes).
WPC has advised the Trustee that the majority of the coal seam gas from the Farmout Properties
is sold by BP under short-term marketing arrangements at spot market prices and the remainder is
marketed by the other operators of the wells in the Farmout Properties. Neither the Gas Purchase
Contract nor the Gas Gathering Contract covers the volumes produced from the Farmout Properties.
Reserve Report
The following table summarizes net proved reserves estimated as of December 31, 2009, and
certain related information for the Royalty Interests and Underlying Properties from the December
31, 2009 Reserve Report prepared by Miller and Lents, Ltd., independent petroleum engineers.
Miller and Lents, Ltd. is an international oil and gas consulting firm, founded in 1948, offering
services and expertise in many phases of the oil and gas industry. The firm is registered with the
Texas Board of Professional Engineers and is authorized to provide professional engineering
services in the State of Texas. The engineering staff assigned to the Trust are all university
graduates with degrees in engineering. All are licensed professional engineers and each is a
qualified reserve evaluator with over 20 years of diversified experience, including at least eight
years of experience with the Trust. Mr. Stephen M. Hamburg, P.E., a vice president of Miller and
Lents, Ltd., is primarily responsible for overseeing the Trusts reserves audit. A summary of the
December 31, 2009 Reserve Report is filed as an exhibit to this Form 10-K and incorporated herein
by reference. See Note 9 to Item 8Financial Statements and Supplementary DataNotes to
Financial Statements for additional information regarding the net proved reserves of the Trust.
28
A net profits interest does not entitle the Trust to a specific quantity of gas but to a
portion of the net proceeds derived therefrom. Ordinarily, and in the case of the Farmout
Properties, proved reserves attributable to a net profits interest are calculated by deducting an
amount of gas sufficient, if sold at the prices used in preparing the reserve estimates for such
net profits interest, to pay the future estimated costs and expenses deducted in the calculation of
the net proceeds of such interest. Because WPC has agreed to pay certain operating and capital
costs with respect to the WI Properties, no amount of gas in respect of such costs has been
deducted from the amount of reserves attributable to the WI Properties in determining the amount of
reserves attributable to the Royalty Interests. The December 31, 2009 Reserve Report was prepared
in accordance with criteria established by the SEC, and as if the Trust were a going concern, and,
accordingly, is based upon a first of the month contractual price received by the Trust during the
12-month period prior to December 31, 2009, of $2.63 per MMBtu before transportation charges
through 2012. The Gas Purchase Contract expires no later than December 2012; and because the early
termination of the Trust (resulting in the Gas Purchase Contract terminating no later than August
1, 2010) was not triggered until after December 31, 2009, the December 31, 2009 Reserve Report
continues to reflect pricing under the terms of the Gas Purchase Contract through the 2012 period.
Beginning in year 2013, the gas price to the former Trust interest used in the December 31, 2009
Reserve Report is $3.25 per MMBtu, based on the average first of the month Blanco Hub Index Price
during the 12-month period prior to December 31, 2009. Gathering and transportation charges,
taxes, treating, and other costs payable prior to the delivery points were deducted from the index
price in order to determine the wellhead price used in this evaluation. These prices and
deductions were held constant. The December 31, 2009 Reserve Report is also based on the
percentage share of NPI Net Proceeds payable to the Trust continuing at 60 percent for the
remaining life of the reserves and based on the percentage share of Infill Net Proceeds payable to
the Trust continuing at 20 percent for the remaining life of the reserves.
Royalty | Underlying | |||||||
Interests | Properties | |||||||
Net Proved Gas Reserves (Mmcf)(a)(b) |
6,497 | 45,755 | ||||||
Estimated Future Net Revenues (in millions)(c) |
$ | 6,598 | $ | 29,675 | ||||
Discounted Estimated Future Net Revenues (in millions)(c) |
$ | 4,931 | $ | 23,499 |
(a) | Although the prices utilized in preparing the estimates in this table are in accordance with criteria established by the SEC, such prices may not be the most representative prices for estimating future net revenues or related reserve data. | |
(b) | The gas reserves were estimated by Miller and Lents, Ltd. by applying decline curve analyses utilizing type curves for the various areas in the Basin. The bases for the consideration of type curves are the production histories, the water and gas production rates and the initial reservoir pressures of the wells in the separate areas. | |
(c) | Estimated future net revenues are defined as the total revenues attributable to the Underlying Properties and Royalty Interests less applicable royalties, severance and ad valorem taxes, operating costs and future capital expenditures. Overhead costs (beyond the standard overhead charges for the nonoperated properties) have not been included, nor have the effects of depreciation, depletion and Federal income tax. Estimated future net revenues and discounted estimated future net revenues are not intended and should not be interpreted as representing the fair market value for the estimated reserves. |
The Financial Accounting Standards Board requires supplemental disclosure for oil and gas
reserves producers based on a standardized measure of discounted future net cash flows relating to
proved oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by
applying the average prices during the 12-month period prior to fiscal year-end, 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. Future price changes are only considered to the extent provided by contractual
arrangements in existence at year end. The standardized measure of discounted future net cash
flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows
relating to proved oil and gas reserves. The SECs prior rules required proved reserve estimates
to be calculated using prices as of the end of the period and held constant over the life of the
reserves. Application of the new reserve rules resulted in the use of
a lower price at December
31, 2009 for gas than would have resulted under the previous rules. Use of the new 12-month
average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of
approximately
29
4,902 Mmcf, reflected in revisions of previous estimates in the table of
changes in reserves quantities in Note 9.
There are many uncertainties inherent in estimating quantities and values of proved reserves
and in projecting future rates of production and the timing of development expenditures. The
reserve data set forth herein, although prepared by independent petroleum engineers in a manner
customary in the industry, are estimates only, and actual quantities and values of natural gas are
likely to differ from the estimated amounts set forth herein. In addition, the reserve estimates
for the Royalty Interests will be affected by future changes in sales prices for natural gas
produced and costs that are deducted in calculating NPI Net Proceeds and Infill Net Proceeds.
Further, the discounted present values shown herein were prepared using guidelines established by
the SEC for disclosure of reserves and should not be considered representative of the market value
of such reserves or the Units. A market value determination would include many additional factors.
Because the process of estimating oil and gas reserves is complex and requires significant
judgment, the Trustee has developed internal policies and controls for estimating reserves. The
Trust does not have information that would be available to a company with oil and gas operations
because detailed information is not generally available to owners of royalty interests. The Trustee
gathers production information and provides such information to Miller and Lents, Ltd., who
extrapolates from such information estimates of the reserves attributable to the Underlying
Properties based on its expertise in the oil and gas fields where the Underlying Properties are
situated, as well as publicly available information. The Trusts policies regarding reserve
estimates require proved reserves to be in compliance with the SEC definitions and guidance.
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, are contained in Note 9 to Item 8Financial Statements and
Supplementary DataNotes to Financial Statements. Williams has not filed reserve estimates
covering the Underlying Properties with any Federal authority or agency other than the SEC.
Historical Gas Sales Prices and Production
The following table sets forth the actual Underlying Properties net production volumes
attributed from the WI Properties, weighted average lifting costs and information regarding
historical gas sales prices for each of the years ended December 31, 2009, 2008 and 2007:
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Production from the WI Properties (MMcf)(1) |
2,489 | 5,811 | 5,529 | |||||||||
Weighted average lifting costs (dollars per Mcf) |
$ | 3.02 | $ | 1.16 | $ | 0.75 | ||||||
Weighted
average sales price of gas produced from the WI Properties (dollars per Mcf) |
$ | 5.08 | $ | 4.96 | $ | 3.42 | ||||||
Average Blanco Hub Spot Price (dollars per MMBtu) |
$ | 3.25 | $ | 7.21 | $ | 5.97 |
(1) | Production from the WI Properties is exclusive of volumes realized from unit expansion adjustments as described in Note 6 to Item 8 Financial Statements and Supplementary Data Notes to Financial Statements. |
The average first of the month Blanco Hub Spot Price during the 12-month period prior to
December 31, 2009 was $3.25 per MMBtu and the contractual price to the Trust was $2.63 per MMBtu as
previously discussed. Information regarding average wellhead sales prices for production from the
Farmout Properties is not available to WPC, although WPC has advised the Trustee that it believes
production from such properties is currently sold by BP under short-term marketing arrangements at
spot market prices. While Williams may, from time to time, enter into hedge instruments to manage
their price risk associated with natural gas production from the Underlying Properties, the effects
of any such hedge instruments are not used in the determination of the Trusts royalty income
attributable
30
from the net profits interest in the Underlying Properties. The Trust does not engage in any
hedging activities to manage its price risk associated with natural gas production from the
Underlying Properties. Production attributed to the Farmout Properties (in MMcf) was 1,091, 1,204,
and 1,395 in 2009, 2008, and 2007, respectively.
NPI Percentage Reduction
Prior to 2001, the NPI generally entitled the Trust to receive 81 percent of the NPI Net
Proceeds. However, under the terms of the Conveyance, at the point that (i) cumulative gas
production since October 1, 1992, from the Underlying Properties has exceeded 178.5 Bcf and (ii)
the internal rate of return of the Aftertax Cash flow per Unit (as defined below) has equaled or
exceeded 12 percent, the percentage of NPI Net Proceeds payable to the Trust in respect of the NPI
is automatically and permanently reduced to 60 percent. In such event, WPCs retained percentage
of NPI Net Proceeds is correspondingly increased from 19 percent to 40 percent. For purposes
hereof, Aftertax Cash Flow per Unit is equal to the sum of the following amounts that a
hypothetical purchaser of a Unit in the Public Offering would have received or been allocated if
such Unit were held through the date of such determination: (a) total cash distributions per Unit
plus (b) total tax credits available per Unit under Section 29 of the IRC less (c) the net taxes
payable per Unit (assuming a Federal income tax rate of 31 percent, which at the time of the
formation of the Trust was the highest Federal income tax rate applicable to individuals). IRR is
the annual discount rate (compounded quarterly) that equates the present value of the Aftertax Cash
Flow per Unit to the initial price to the public of the Units in the Public Offering (which was
$20.00 per Unit).
Cumulative production since October 1, 1992, from the Underlying Properties has been in excess
of 178.5 Bcf since 1999. The 12 percent internal rate of return of Aftertax Cash Flow per Unit was
reached in the fourth quarter of 2000. Consequently, beginning in the fourth quarter of 2000, the
percentage of NPI Net Proceeds the Trust is entitled to receive under the NPI was permanently
reduced from 81 percent to 60 percent. WPCs retained percentage of NPI Net Proceeds was
correspondingly increased from 19 percent to 40 percent.
Gas Purchase Contract
Under the terms of the Gas Purchase Contract, WPX Gas Resources (as successor in interest to
WGM) purchased the natural gas produced from the WI Properties (except for certain small volumes)
at the Wellhead. The Gas Purchase Contract commenced October 1, 1992, and expires no later than
December 2012; however, as a result of the early termination of the Trust, it will expire on the
earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust.
The Gas Purchase Contract provided for a pricing mechanism during an initial 5-year period
(Primary Term), which expired on December 31, 1997. Following the expiration of the Primary
Term, the pricing mechanism continued for one or more consecutive additional one-year terms (each
such term a Contract Year) unless and until WPX Gas Resources exercises its annual option,
exercisable 15 days prior to the end of each Contract Year, to discontinue purchasing gas from WPC
under the pricing provision of the Gas Purchase Contract and instead purchase gas at a monthly
price equal to the Index Price as described hereafter. For each of the Contract Years 2007, 2008
and 2009, WPX Gas Resources did not exercise this option and therefore the pricing mechanism of the
Primary Term remained in effect for each of those past years and will continue until the earlier of
August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust. Under this
mechanism, the monthly price to be paid by WPX Gas Resources for natural gas purchased pursuant to
the Gas Purchase Contract shall be (a) the $1.70 Minimum Purchase Price, less (b) any costs paid by
WPX Gas Resources to gather, treat and process the gas and deliver it to specified delivery points
and plus (c) under certain circumstances, additional amounts determined as described below:
(i) If the Index Price (as defined below) in any month during any Contract Year, including
2010 (through the earlier of August 1, 2010 or the closing date of the sale of the Royalty
Interests by the Trust), is greater than $1.94 per MMBtu, then WPX Gas Resources will pay
WPC an amount for gas purchased equal to $1.94 per MMBtu, less the costs paid by WPX Gas
Resources to gather and process such gas and deliver it to specified delivery points, plus
50 percent of the excess of the Index Price over $1.94 per MMBtu (the Price Differential),
provided WPX Gas Resources has no accrued Price Credits (as defined below) in the Price
Credit Account (as defined below). If WPX Gas Resources has accrued Price Credits in the
Price Credit Account, then WPX Gas Resources will be entitled to reduce the amount in excess
of the Minimum Purchase Price (before deducting gathering and processing costs and costs to
deliver the gas to specified delivery points) that otherwise would be payable by any accrued
and unrecouped Price Credits in
31
the Price Credit Account, and WPX Gas Resources will not be obligated to pay WPC any amounts
in excess of the Minimum Purchase Price until such time as all accrued Price Credits have
been recouped and a zero balance exists in the Price Credit Account.
(ii) If the Index Price in any month during any Contract Year, including 2010 (through the
earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the
Trust), is greater than the Minimum Purchase Price but less than or equal to $1.94 per
MMBtu, then WPX Gas Resources will pay WPC an amount for each MMBtu purchased equal to the
Index Price less the costs paid by WPX Gas Resources to gather and process such gas and
deliver it to specified delivery points, provided WPX Gas Resources has no accrued Price
Credits in the Price Credit Account. If WPX Gas Resources has accrued Price Credits in the
Price Credit Account, then WPX Gas Resources will be entitled to reduce the amount in excess
of the Minimum Purchase Price (before deducting, gathering and processing costs and costs to
deliver to specified delivery points) that otherwise would be payable by any accrued and
unrecouped Price Credits in the Price Credit Account, and WPX Gas Resources will not be
obligated to pay WPC any amounts in excess of the Minimum Purchase Price until such time as
all accrued Price Credits have been recouped and a zero balance exists in the Price Credit
Account.
(iii) If the Index Price in any month during any Contract Year, including 2010 (through the
earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the
Trust), is less than the Minimum Purchase Price, then WPX Gas Resources will pay for each
MMBtu of gas purchased the Minimum Purchase Price less the costs paid by WPX Gas Resources
to gather and process such gas and deliver it at specified delivery points, and WPX Gas
Resources will receive a credit (the Price Credit) from WPC for each MMBtu of gas
purchased by WPX Gas Resources equal to the difference between the Minimum Purchase Price
and the Index Price. WPC is required to establish and maintain the Price Credit Account
containing the accrued and unrecouped amount of such Price Credits. No Price Credits were
accrued in respect of production purchased by WPX Gas Resources prior to January 1, 1994.
For the year ended December 31, 2009, which is based on production volumes and natural gas
prices for the twelve months ended September 30, 2009, the Index Price exceeded the Minimum
Purchase Price for each month during the year. As of December 31, 2009 and 2008, there were no
remaining unrecouped Price Credits in the Price Credit Account.
To the extent there may in the future be a balance in the Price Credit Account, the
entitlement to recoup Price Credits means that if and when the Index Price is above the Minimum
Purchase Price, future royalty income paid to the Trust would be reduced until such as such Price
Credits have been fully recouped. Corresponding cash distributions to Unitholders would also be
reduced.
Subsequent to the expiration of the Primary Term of the pricing provision of the Gas Purchase
Contract, which occurred on December 31, 1997, WPX Gas Resources has an annual option (which can be
exercised only once during the term of the Gas Purchase Contract) to discontinue purchasing gas
under the pricing provision of the Gas Purchase Contract by giving written notice of its election
to pay solely the Index Price (less the costs paid by WPX Gas Resources to gather, treat and
process such gas and deliver it to specified points). If WPX Gas Resources so elects to
discontinue paying under the pricing provision, WPX Gas Resources will no longer be entitled to
retain the Price Differential when the Index Price exceeds $1.94 per MMBtu and any accrued and
unrecouped Price Credits will be extinguished. Since there is no published price in the San Juan
Basin for wellhead deliveries, the wellhead price in the Gas Purchase Contract is determined by
utilizing a published price that is inclusive of gathering, treating and processing costs. As used
in this Item 2. Properties Reserve Report, Index Price means 97 percent of the first of
month El Paso Natural Gas Co. San Juan Spot Price. The El Paso Natural Gas Co. San Juan Spot
Price is a posted index price per MMBtu (dry basis) published in Inside F.E.R.C.s Gas Market
Report, which is a bi-monthly publication by The McGraw-Hill Companies, Inc. The Gas Purchase
Contract provides WPX Gas Resources a one-time option to convert the Index Price from the first of
month posting of El Paso Natural Gas Co. San Juan Spot Price to the average of the bi-monthly
postings for that same index. The Gas Purchase Contract further provides for an alternative
indexing mechanism in the event the Inside F.E.R.C.s Gas Market Report indices are modified or
discontinued. All prices used as index prices are delivered prices at the specified point of
delivery and are, therefore, before deducting gathering and/or transportation charges, taxes,
treating cots or other costs payable prior to the delivery points. During periods when there is a
Price Differential,
32
WPX Gas Resources will absorb a portion of the gathering charges based on a formula specified
within the Gas Purchase Contract.
A small volume of gas produced from the WI Properties (less than 5 percent) is sold by the
operators of certain wells under gas purchase contracts with other buyers.
The prices paid to WPC pursuant to the Gas Purchase Contract are prices payable for the value
of gas purchased for production at the Wellhead. Title to the gas purchased pursuant to the Gas
Purchase Contract passes to WPX Gas Resources at the Wellhead. WPX Gas Resources is responsible
for gathering, treating, processing and marketing all gas purchased pursuant to the Gas Purchase
Contract. Approximately 90 percent of the production from the WI Properties is gathered by WPX on
behalf of WPX Gas Resources. The balance of the production is gathered on behalf of WPX Gas
Resources by third parties. See Gas Gathering Contract. The price paid to WPC pursuant to the
Gas Purchase Contract is after deducting the costs incurred by WPX Gas Resources to gather, treat
and process such gas (including costs incurred by WPX Gas Resources under the Gas Gathering
Contract). Payments to WPC for gas purchased pursuant to the Gas Purchase Contract are made by WPX
Gas Resources on or before the last day of the first calendar month next following the end of each
calendar quarter.
NPI Net Proceeds and Infill Net Proceeds are calculated on an entitlements or entitled volume
basis, whereby the aggregate proceeds from the sale of gas under applicable gas sales contracts
(excluding production from the Farmout Properties) are determined by WPC as if WPC had produced and
sold its working interest share of production from the WI Properties, even if the actual volumes
delivered to and sold by WPC are different than the entitlement volumes. The effect of such an
entitlements basis calculation is that NPI Net Proceeds or Infill Net Proceeds and, therefore,
the amount thereof paid to the Trust, may include amounts in respect of production not taken by WPC
because of a so-called imbalance (that is, where a working interest owner is delivered more or less
than the actual share of production to which it is entitled).
A copy of the Gas Purchase Contract is filed as an exhibit to this Form 10-K. The foregoing
summary of the material provisions of the Gas Purchase Contract is qualified in its entirety by
reference to the terms of such agreement as set forth in such exhibit.
Gas Gathering Contract
In accordance with the Confirmation Agreement, effective May 1, 1995, WGM assigned to WPX Gas
Resources all of its right, title, interest, duties and obligations under the Gas Gathering
Contract, and WPX Gas Resources assumed all of WGMs right, title, interest, duties and obligations
thereunder.
The Gas Gathering Contract, which will be in effect beyond the termination of the Trust,
covers approximately 90 percent of the production from the WI Properties and commits WFS on behalf
of WPX Gas Resources to gather such production (except production from 19 wells in the San Juan
29-7 unit as described below), at rates starting at $.35 per Mcf (plus a fuel reimbursement
estimated to be 6.2 percent to 7.3 percent of gathered volumes on a Btu equivalent basis, and
subject to increase if the CO2 content of the gas exceeds 10 percent) and adjusted
annually based on average annual price comparisons determined on the basis of the Blanco Hub Spot
Price, provided that the gathering rate will be no less than $.35 per Mcf increased or decreased on
the basis of an increase or decrease in a published index measuring the gross domestic product. A
significant portion of the gas to be gathered pursuant to the Gas Gathering Contract must first be
gathered from the Wellhead to a Federal Unit central delivery point by TEPPCO Partners, L.P.
(TEPPCO). WPX Gas Resources has been assigned a one-year gathering contract (with a monthly
evergreen provision) whereby TEPPCO provides interruptible gathering service at the price of $.44
per Mcf, which escalates annually at $0.015 per year, plus actual fuel used (historically averaging
approximately 7 percent). It is anticipated that WPX Gas Resources will be able to extend the term
of this agreement.
The remainder of the production on the WI Properties is not physically connected to the WFS
system and is not covered by the Gas Gathering Contract. This gas is gathered either by Burlington
Resources Gathering Inc. (Burlington) or El Paso Field Services (EFS) for delivery at the
Blanco Hub or by WFS for delivery at the outlet of the Ignacio Plant in La Plata County, Colorado.
WPC has existing long-term gathering agreements with EFS and short-term gathering agreements with Burlington with rates and terms generally comparable to
the Gas Gathering Contract.
33
The Gas Gathering Contract may not be amended in a manner that would materially adversely
affect the revenues to the Trust without the approval of the holders of a majority of the Units
present or represented at a meeting of Unitholders at which a quorum (consisting of a majority of
the outstanding Units) is present or represented. As noted elsewhere herein, the Units held by
Williams (or an affiliate) immediately after the Public Offering may not be voted on any such
amendment nor will such Units be counted for quorum purposes so long as such Units are held by
Williams (or an affiliate).
The Gas Gathering Contract was twice amended, each effective as of October 1, 1993, with
respect to 19 wells located in the San Juan 29-7 unit. WFS is obligated to gather production from
such wells at a rate of $.36 per Mcf (plus a fuel reimbursement of 5.5 percent of the gas received
at the Wellhead Receipt Points (as defined)). In connection with these amendments to the Gas
Gathering Contract, the Trustee received an opinion of counsel to Williams that such amendments
need not be submitted for approval by vote of the Unitholders.
The Gas Gathering Contract was further amended effective as of April 1, 1997, for the purpose
of increasing the field rights held by the Trust on the Manzanares gathering system. The increase
accommodates incremental gas flow that will occur due to WFSs expansion and enhancement of
gathering facilities.
A copy of the Gas Gathering Contract and each amendment thereto are filed as exhibits to this
Form 10-K. The foregoing summary of the material provisions of the Gas Gathering Contract is
qualified in its entirety by reference to the terms of such agreement as set forth in such exhibit.
Federal and Indian Lands
Approximately 80 percent of the Underlying Properties are burdened by Royalty Interests held
by the Federal government or the Southern Ute Indian Tribe. Royalty payments due to the U.S.
Government for gas produced from Federal and Indian lands included in the Underlying Properties
must be calculated in conformance with its interpretation of regulations issued by the Minerals
Management Service (MMS), a subagency of the U.S. Department of the Interior that administers and
receives revenues from Federal and Indian royalties on behalf of the U.S. Government and as agent
for the Indian tribes. The MMS regulations cover both valuation standards, which establish the
basis for placing a value on production, and cost allowances, which define those post-production
costs that are deductible by the lessee.
Where gas is sold by a lessee to a marketing affiliate, such as WPX Gas Resources, the MMS
regulations essentially ignore the lessee-affiliate transaction and consider the arms-length sale
by the affiliate as the point of valuation for royalty purposes. Accordingly, WPC is required to
calculate royalty payments based on the price WPX Gas Resources receives when it markets the gas
production (Resale Price), notwithstanding the price payable by WPX Gas Resources to WPC pursuant
to the Gas Purchase Contract. With respect to the Farmout Properties, BP pays royalties based on
the price it receives for production from such properties as long as the gas is purchased by
nonaffiliates. The NPI Net Proceeds, a portion of which is payable to the Trust, reflects the
deduction of all royalty and overriding royalty burdens. The ratio of royalties paid on Federal
and Indian lands to the NPI Net Proceeds increases as the Resale Price exceeds the price under the
Gas Purchase Contract.
The MMS regulations permit a lessee to deduct from its gross proceeds its reasonable actual
costs of transportation and processing to transport the gas from the lease to the point of sale in
calculating the market value of its production. Although WPX Gas Resources deducts the gathering
charges paid by it to WFS, Burlington, EFS and Northwest in calculating the wellhead price it pays
to WPC, the MMS could disallow the deduction of some portion of the gathering charges after review
of such charges on audit of WPCs royalty as discussed below. If some portion of the gathering
charges is disallowed, the MMS will likely demand additional royalties plus interest on the amount
of the underpayment.
The MMS generally audits royalty payments within a 6-year period. Although WPC calculates
royalty payments in accordance with its interpretation of the then applicable MMS regulations, WPC
does not know
34
whether the royalty payments made to the U.S. Government are totally in conformity with MMS
standards until the payments are audited. If an MMS audit, or any other audit by a Federal or
state agency, results in additional royalty charges, together with interest, relating to production
since October 1, 1992, in respect of the Underlying Properties, such charges and interest will be
deducted in calculating NPI Net Proceeds for the quarter in which the charges are billed and in
each quarter thereafter until the full amount of the additional royalty charges and interest have
been recovered. The Trusts 2007 distributions were impacted negatively by a settlement with the
MMS as discussed in Note 6 to Item 8 Financial Statements and Supplementary Data Notes to
Financial Statements. This settlement related to production periods through 2006.
Sale and Abandonment of Underlying Properties
WPC (and any transferees) has the right to abandon any well or working interest included in
the Underlying Properties if, in its opinion, such well or property ceases to produce or is not
capable of producing in commercially paying quantities. Since WPC does not operate any of the
wells on the Underlying Properties, WPC does not normally control the timing of plugging and
abandoning wells. The Conveyance provides that WPCs working interest share of the costs of
plugging and abandoning uneconomic wells will be deducted in calculating NPI Net Proceeds.
WPC may sell the Underlying Properties, subject to and burdened by the Royalty Interests,
without the consent of Unitholders. Under the Trust Agreement, WPC has certain rights (but not
obligations) to purchase the Royalty Interests upon termination of the Trust. See Item
1Description of the TrustTermination and Liquidation of the Trust.
WPC has retained the right to repurchase from the Trust, commencing January 1, 2003, any
portion of the NPI conveyed to the Trust if WPCs interest in the Underlying Properties burdened by
such portion of the NPI ceases to produce or is not capable of producing in commercially paying
quantities (ignoring for purposes of such determination the NPI and Infill NPI). The purchase
price payable by WPC will be the fair market value at the date of repurchase of the portion of the
NPI or Infill NPI so purchased, as established on the basis of an appraisal provided by an
independent expert.
The Infill Wells
The only assets of the Trust, other than cash and cash equivalents being held for the payment
of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The
Royalty Interests consist primarily of a net profits interest (the NPI) in the Underlying
Properties. The NPI generally entitles the Trust to receive 60 percent of the NPI Net Proceeds
attributable to (i) gas produced and sold from WPCs net revenue interests (working interests less
lease burdens) in the properties in which WPC has a working interest (the WI Properties) and (ii)
the revenue stream received by WPC attributable to its 35 percent net profits interest in 5,348
gross acres in La Plata County, Colorado (the Farmout Properties).
The Royalty Interests also include a 20 percent interest in WPCs Infill Net Proceeds from the
sale of production if well spacing rules are effectively modified and additional wells are drilled
on producing drilling blocks on the WI Properties (the Infill Wells) during the term of the
Trust. Infill Net Proceeds consists generally of the aggregate proceeds, based on the price at
the wellhead, of gas produced from WPCs net revenue interest in any Infill Wells less certain
taxes and costs.
On October 15, 2002 the New Mexico Oil and Gas Commission (NMOCD) revised the field rules for
the Basin Fruitland Coal (Gas) Pool to allow an optional second (infill) well on the standard
320-acre spacing unit in certain designated areas of the pool (the non-fairway wells). On July 17,
2003 the NMOCD further modified the field rules for the Basin Fruitland Coal (Gas) Pool to allow
these infill wells on the standard 320-acre spacing unit in all areas of the pool. The WI
Properties contain 442 infill locations designated as proved locations according to SEC guidelines.
As of December 31, 2009, 442 infill locations are proved developed producing and zero locations
are proved undeveloped.
35
The Infill Wells reached payout in the aggregate during 2008. The Trust has received its
20 percent interest in WPCs Infill Net Proceeds for periods after payout. However, during 2009,
WPC informed the Trustee that due to the net deficit realized by the Infill Wells during the third
and fourth quarters, the Infill Net Profit Costs now exceed the Infill Net Profit Gross Proceeds by
approximately $32,500. The Trust will not be liable for such excess costs, and such excess costs
will hereafter constitute Excess Infill Net Profit Costs until recovered by WPC. The Trust will
not receive its 20 percent interest in WPCs Infill Net Proceeds until such time as the Infill Net
Profits Gross Proceeds exceeds the Infill Net Profit Costs on an aggregate basis. The complete
definitions of Infill Net Proceeds, Infill Net Profit Costs, Excess Infill Net Profit Costs, and
Infill Net Profit Gross Proceeds are set forth in the Conveyance.
Royalty Trust Reserves
The reserves for the Royalty Trust were determined by Miller and Lents, Ltd in accordance with
SEC guidelines. As of December 31, 2009, total proved reserves were 6,497 MMcf, comprised entirely
of proved developed producing reserves.
As of December 31, 2009 total proved reserves for the 320-acre spaced wells in the Working
Interest Properties were 3,084 MMcf comprised entirely of proved developed producing reserves.
As of December 31, 2009 total proved reserves for the infill wells in the Working Interest
Properties were 453 MMcf, comprised entirely of proved developed producing reserves.
As of December 31, 2009, total proved reserves for the Farmout Properties were 2,960 MMcf, all
of which are proved developed producing.
The following table sets fort the summary of reserves for the Royalty Trust as of December 31,
2009:
RESERVES
Natural Gas | ||||
Reserves Category | (MMcf) | |||
PROVED RESERVES |
||||
Developed |
||||
WI Properties |
3,084 | |||
Infill Properties |
453 | |||
Farmout Properties |
2,960 | |||
Undeveloped |
||||
WI Properties |
-0- | |||
Infill Properties |
-0- | |||
Farmout Properties |
-0- | |||
TOTAL PROVED RESERVES |
6,497 |
Williams Performance Assurances
Pursuant to the Conveyance and the Performance Acknowledgement Agreement, Williams has agreed
to pay each of the following when due and payable: (i) all liabilities and operating and capital
expenses that WPC is required under the Conveyance to pay as owner of the Underlying Properties,
including without limitation WPCs obligation to pay operating expenses in respect of the WI
Properties up to the cumulative amounts specified in Exhibit B to the Conveyance and the capital
costs incurred in respect of the WI Properties to the extent specified in the Conveyance, including
amounts that WPC is obligated to pay with respect to environmental liabilities; (ii) all NPI Net
Proceeds, Infill Net Proceeds and other amounts that WPC is obligated to pay to the Trust under the
Conveyance, including amounts that WPC is obligated to pay with respect to environmental liability;
and (iii) any
36
proceeds from a sale of any remaining Royalty Interests that WPC may elect to purchase upon
termination of the Trust ((i) through (iii) collectively, the WPC Payment Obligations). Williams
has also agreed, to the extent not paid by WPX Gas Resources when due and payable, to pay all
amounts that WPX Gas Resources is required to pay to WPC in respect of production attributable to
the Royalty Interests pursuant to the terms of the Gas Purchase Contract between WPC and WPX Gas
Resources (the WPX Gas Resources Payment Obligations). In the Confirmation Agreement, Williams
expressly confirmed that its agreement to cause the WPX Gas Resources Payment Obligations to be
paid in full when due shall continue in full force and effect notwithstanding the assignments by
WGM of the Gas Purchase Contract and the Gas Gathering Contract.
In the event and to the extent that WPC does not pay any of the WPC Payment Obligations in
full when due and, in the event and to the extent that WPX Gas Resources does not pay any of the
WFS Gas Resources Payment Obligations in full when due, the Trustee (but not Unitholders) is
entitled, following notice to Williams and demand for payment by the Trustee and after a 10-day
cure period, to enforce payment by Williams. Williams assurance obligations terminate upon the
earlier of (i) dissolution of the Trust; (ii) with respect to the WPC Payment Obligations, upon
sale or other transfer by WPC of all or substantially all of the Underlying Properties; (iii) with
respect to the WPC Payment Obligations, upon one or more sales or other transfers of a majority or
more of Williams ownership interests in WPC; and (iv) with respect to the WPX Gas Resources
Payment Obligations, upon one or more sales or other transfers of a majority or more of Williams
ownership interests in WPX Gas Resources; provided that, with respect to (ii), (iii) and (iv)
above, only if the transferee has, at the time of transfer, a rating assigned to outstanding
unsecured long-term debt from Moodys Investor Services of at least Baa3 or from Standard & Poors
Corporation of at least BBB (or an equivalent rating from at least one nationally-recognized
statistical rating organization), or such transferee is approved by holders of a majority of
outstanding Units, and in any case, the transferee unconditionally agrees in writing, to assume and
be bound by Williams remaining assurance obligations.
Title to Properties
Williams has advised the Trustee that it believes that WPCs title to the Underlying
Properties, and the Trusts title to the Royalty Interests, are good and defensible in accordance
with standards generally accepted in the gas industry, subject to exceptions that, in the opinion
of Williams, are not so material as to detract substantially from the use or value of such
Underlying Properties or Royalty Interests. As is customary in the gas industry, only a
perfunctory title examination is performed as a lease is acquired, except leases covering proved
reserves. Generally, prior to drilling a well, a more thorough title examination of the drill site
tract is conducted and curative work is performed with respect to significant title defects, if
any, before proceeding with operations. However, except for the sale and repurchase of the
Underlying Properties from Quatro Finale, WPC (or its predecessor) has owned the leases covering
the Underlying Properties since 1974, and conventional gas has been produced from formations other
than the Fruitland formation covered by all of the leases since the 1950s. Under these
circumstances, WPC conducted an internal review of its title records prior to the drilling of the
coal seam gas wells within the 12 Federal Units but did not conduct title examinations. In
addition to its internal review, WPC, when requested by the operator, participated in title
examinations prior to the drilling of a few coal seam gas wells located outside the Federal Units.
The Underlying Properties are typically subject, in one degree or another, to one or more of
the following: (i) royalties and other burdens and obligations, expressed and implied, under gas
leases; (ii) overriding royalties and other burdens created by WPC or its predecessors in title;
(iii) a variety of contractual obligations (including, in some cases, development obligations)
arising under operating agreements, farmout agreements, production sales contracts and other
agreements that may affect the properties or their titles; (iv) 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; (v) pooling, unitization and
communitization agreements, declarations and orders; and (vi) easements, restrictions,
rights-of-way and other matters that commonly affect property. To the extent that such burdens and
obligations affect WPCs 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 value of the reserves attributable to the Royalty Interests. Except as
noted below, Williams believes that the burdens and obligations affecting the Underlying Properties
and Royalty Interests are conventional in the industry for similar properties, do not, in the
aggregate, materially interfere with the use of the Underlying Properties and will not materially
and adversely affect the value of the Royalty Interests.
37
Although the matter is not entirely free from doubt, Williams has advised the Trustee that it
believes (based upon the opinions of local counsel to WPC with respect to matters of Colorado law
and New Mexico law) that the Royalty Interests should constitute real property interests under
applicable state law. Consistent therewith, the Conveyance states that the Royalty Interests
constitute real property interests and it was recorded in the appropriate real property records of
Colorado and New Mexico, the states in which the Underlying Properties are located, in accordance
with local recordation provisions. If, during the term of the Trust, WPC becomes involved as a
debtor in bankruptcy proceedings, it is not entirely clear that all of the Royalty Interests would
be treated as real property interests under the laws of Colorado and New Mexico. If in such a
proceeding a determination were made that the Royalty Interests constitute real property interests,
the Royalty Interests should be unaffected in any material respect by such bankruptcy proceeding.
If in such a proceeding a determination were made that a Royalty Interest constitutes an executory
contract (a term used, but not defined, in the United States Bankruptcy Code to refer to a contract
under which the obligations of both the debtor and the other party to such contract are so
unsatisfied that the failure of either to complete performance would constitute a material breach
excusing performance by the other) and not a real property interest under applicable state law, and
if such contract were not to be assumed in a bankruptcy proceeding involving WPC, the Trust would
be treated as an unsecured creditor of WPC with respect to such Royalty Interest in the pending
bankruptcy. Although no assurance is given, Williams has advised the Trustee that it does not
believe that the Royalty Interests should be subject to rejection in a bankruptcy proceeding as
executory contracts.
Item 3. Legal Proceedings.
There are no material pending proceedings to which the Trust is a party or to which any of its
properties is the subject. In 2008, WPC notified the Trust that certain royalty matters were being
litigated by a federal regulatory agency and another producer. WPC learned that this case was
decided unfavorably to the producer in October 2009. Neither WPC nor the Trust was a party to this
litigation; however, given the similarities to the Trusts
Underlying Properties, WPC and the Royalty Interests
will more than likely be impacted as well. WPC is currently evaluating the negative impact to the
Trusts NPI. In addition, there are other cases pending against
other producers on related issues that could
potentially have a significant negative impact to future royalty
income with respect to the Royalty Interests, natural gas reserves and reserve value.
Item 4.
Reserved.
PART II
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities.
The Units are listed and traded on the New York Stock Exchange under the symbol WTU. The
following table sets forth, for the periods indicated, the high and low sales prices per Unit and
the amount of quarterly cash distributions per Unit paid by the Trust.
Sales Price | Distributions | |||||||||||
High | Low | per Unit | ||||||||||
2009
|
||||||||||||
First Quarter |
$ | 9.00 | $ | 3.86 | $ | .113811 | ||||||
Second Quarter |
$ | 6.05 | $ | 4.17 | $ | .065169 | ||||||
Third Quarter |
$ | 5.01 | $ | 2.77 | $ | .000000 | ||||||
Fourth Quarter |
$ | 4.09 | $ | 2.92 | $ | .022074 | ||||||
2008
|
||||||||||||
First Quarter |
$ | 10.20 | $ | 8.45 | $ | .179608 | ||||||
Second Quarter |
$ | 11.10 | $ | 9.39 | $ | .187237 | ||||||
Third Quarter |
$ | 11.25 | $ | 8.73 | $ | .349784 | ||||||
Fourth Quarter |
$ | 10.00 | $ | 6.00 | $ | .755888 |
38
At March 1, 2010, there were 9,700,000 Units outstanding and approximately 338 Unitholders of
record. The Trust does not maintain any equity compensation plans. The Trust did not sell nor did
it repurchase any Units during the period covered by this report.
Item 6. Selected Financial Data.
Year Ended December 31, | ||||||||||||||||||||
2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||
Royalty Income |
$ | 2,882,120 | $ | 15,151,993 | $ | 9,496,151 | $ | 13,945,315 | $ | 14,497,187 | ||||||||||
Distributable Income |
$ | 1,871,850 | $ | 14,290,691 | $ | 8,547,300 | $ | 13,032,064 | $ | 13,565,620 | ||||||||||
Distributable Income
per Unit |
$ | 0.19 | $ | 1.47 | $ | 0.88 | $ | 1.34 | $ | 1.40 | ||||||||||
Distributions per Unit |
$ | 0.20 | $ | 1.47 | $ | 0.88 | $ | 1.34 | $ | 1.41 | ||||||||||
Total Assets at Year End |
$ | 4,527,140 | $ | 5,623,413 | $ | 6,944,963 | $ | 8,372,798 | $ | 10,138,644 | ||||||||||
Total Corpus at Year End |
$ | 4,410,799 | $ | 5,592,220 | $ | 6,877,977 | $ | 8,316,439 | $ | 10,091,169 |
Item 7. Trustees Discussion and Analysis of Financial Condition and Results of Operations.
Termination and Liquidation of the Trust
With respect to the Trust termination provisions as outlined in the Trust Agreement, the net
present value of the estimated future net revenues computed in accordance with the Trust Agreement,
using an average 2009 index price of $3.25, by the independent petroleum engineers as of December
31, 2009 was approximately $8.4 million. The results of this computation have triggered an early
termination of the Trust. Because the Trusts computed net present value fell below the $30
million stipulated threshold as of December 31, 2009, the Trust terminated effective March 1, 2010
(the Termination Date).
Following termination, the Trustee and the Delaware Trustee will continue to act as trustees
of the Trust until all remaining Trust assets have been sold and the net proceeds from such sales,
if any, are distributed to Unitholders.
Upon the termination of the Trust, the Trustee will use Best Efforts (as defined in the Trust
Agreement) to sell any remaining Royalty Interests for cash pursuant to the procedures described in
the Trust Agreement. The Trustee has retained Albrecht & Associates, Inc., an investment banking
firm (the Advisor), on behalf of the Trust who will assist the Trustee in selling the remaining
Royalty Interests then owned by the Trust (the Remaining Royalty Interests). WPC has the right,
but not the obligation, to make a cash offer to purchase all Remaining Royalty Interests following
termination of the Trust as described in the following paragraph.
WPC may, within 60 days following the Termination Date, make a cash offer to purchase all of
the Remaining Royalty Interests then held by the Trust. In the event such an offer is made by WPC,
the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such
offer (in which case no sale to WPC will be made unless a fairness opinion is given by the Advisor
that the purchase price is fair to the Trust and Unitholders) or (ii) defer action on such offer.
If the Trustee defers action on WPCs offer, the offer will be deemed withdrawn and the Trustee
will then use Best Efforts, assisted by the Advisor to obtain alternative offers for the Remaining
Royalty Interests. At the end of a 120-day period following the Termination Date, the Trustee is
required to notify WPC of the highest of any other offers (net of any commissions or other fees
payable by the Trust), acceptable to the Trustee (which must be an all-cash offer), received during
such period (the Highest Acceptable Offer). WPC then has the exclusive right (whether or not it
made an initial offer), but not the obligation, to purchase all Remaining Royalty Interests for a
cash purchase price computed as follows: (i) if the Highest Acceptable Offer is more than 105
percent of WPCs initial offer (or if WPC did not make an initial offer), the purchase price will
be 105 percent of the Highest Acceptable Offer, or (ii) if the Highest Acceptable Offer is equal to
or less than 105 percent of WPCs initial offer, the purchase price will be equal to the Highest
Acceptable Offer. If no other acceptable offers are received for all Remaining Royalty Interests,
the Trustee may request WPC to submit another offer for consideration by the Trustee and may accept
or reject such offer. Acceptance of an offer by the Trustee shall be conditioned upon the opinion
of the Advisor of the fairness of the offer.
39
If a sale of the Remaining Royalty Interests is made or a definitive contract for sale of the
Remaining Royalty Interests is entered into within a 150-day period following the Termination Date,
the buyer of the Remaining Royalty Interests, and not the Trust or Unitholders, will be entitled to
all proceeds of production attributable to the Remaining Royalty Interests following the
Termination Date.
In the event that WPC does not purchase the Remaining Royalty Interests, the Trustee may
accept any offer for all or any part (not more than six parts) of the Remaining Royalty Interests
as it deems to be in the best interests of the Trust and Unitholders and may continue, for up to
one calendar year after the Termination Date, to attempt to locate a buyer or buyers of the
Remaining Royalty Interests in order to sell such interests in an orderly fashion not involving a
public auction. If any Remaining Royalty Interests have not been sold or a definitive agreement for
sale has not been entered into by the end of such calendar year, the Trustee is required to sell
the Remaining Royalty Interests at public auction to the highest cash bidder, which sale may be to
WPC or any of its affiliates. Notice of such sale by auction shall be mailed at least 30 days prior
to such sale to each Unitholder at his address as it appears on the ownership ledger of the
Trustee.
WPCs purchase rights, as described, may be exercised by WPC and each of its
successors-in-interest and assigns. WPCs purchase rights are fully assignable by WPC to any
person. The costs of liquidation, including the fees and expenses of the Advisor, and the Trustees
liquidation fee will be paid by the Trust.
The sale of the Remaining Royalty Interests following the termination of the Trust will be
taxable events to the Unitholders for Federal income tax purposes. Generally, a Unitholder will
realize gain or loss equal to the difference between the amount realized on the sale of the
Remaining Royalty Interests upon termination of the Trust and his adjusted basis in such Units.
Gain or loss realized by a Unitholder who is not a dealer with respect to such Units and who has a
holding period for the Units of more than one year will be treated as long-term capital gain or
loss except to the extent of any depletion recapture amount, which must be treated as ordinary
income. State tax consequences may also result to Unitholders upon the termination of the Trust
and the sale of the Remaining Royalty Interests. Each Unitholder should consult his own tax
advisor regarding Trust tax compliance matters, including Federal and state tax implications
concerning the sale of the Remaining Royalty Interests following the termination of the Trust.
Critical Accounting Policies and Estimates
The financial statements of the Trust are prepared on a modified cash basis and are not
intended to present financial position and results of operations in conformity with United States
Generally Accepted Accounting Principles (GAAP). Because of the termination of the Trust
effective March 1, 2010, the Trust is not expected to continue as a going concern; however, no
adjustments have been made to the carrying value or classification of the Royalty Interests as of
December 31, 2009. Preparation of the Trusts financial statements on
such basis includes the following:
| Revenues are recognized in the period in which amounts are received by the Trust. General and administrative expenses are recognized on an accrual basis. | ||
| Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to trust corpus. | ||
| Distributions to Unitholders subject to the occurrence of a termination event, are recorded when declared by the Trustee (see Note 5 to Item 8Financial Statements and Supplementary DataNotes to Financial Statements). | ||
| Loss contingencies are recognized in the period in which amounts are paid by the Trust. |
The financial statements of the Trust differ from financial statements prepared in accordance
with GAAP. For example, royalty income is not accrued in the period of production, amortization of
the Royalty Interests is not charged against operating results, and loss contingencies are not
charged to operating results until paid. This
40
comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for
royalty trusts by the SEC, as specified by Staff Accounting Bulletin Topic 12:E, Financial
Statements of Royalty Trusts.
The Trusts financial statements reflect the selection and application of accounting policies
that require the Trust to make significant estimates and assumptions. The following are some of
the more critical judgment areas in the application of accounting policies that currently affect
the Trusts financial condition and results of operations.
Revenue Recognition. Revenues from Royalty Interests are recognized in the period in which
amounts are received by the Trust. Royalty income received by the Trust in a given calendar year
will generally reflect the proceeds, on an entitlements basis, from natural gas produced for the
12-month period ended September 30th in that calendar year.
Reserve Recognition. Independent petroleum engineers estimate the net proved reserves
attributable to the Royalty Interests. In accordance with the FASB Accounting Standards
Codification Extractive Activities Oil and Gas, estimates of future net revenues from proved
reserves have been prepared using the average monthly contractual gas prices and related costs for
the past calendar year. Numerous uncertainties are inherent in estimating volumes and the value of
proved reserves and in projecting future production rates and the timing of development of
non-producing reserves. Such reserve estimates are subject to change as additional information
becomes available. The reserves actually recovered and the timing of production may be
substantially different from the reserve estimates.
Contingencies. Contingencies related to the Underlying Properties that are unfavorably
resolved would generally be reflected by the Trust as reductions to future royalty income payments
to the Trust with corresponding reductions to cash distributions to Unitholders.
Liquidity and Capital Resources
As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and
neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to
the operation of the Underlying Properties. The Trustee has powers to collect and distribute
proceeds received by the Trust and pay Trust liabilities and expenses, and its actions have been
limited to those activities. The assets of the Trust are passive in nature, and other than the
Trusts ability to periodically borrow money as necessary to pay expenses, liabilities and
obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited
from engaging in borrowing transactions. As a result, other than such borrowings, if any, the
Trust has no source of liquidity or capital resources other than the Royalty Interests. As
described under Termination and Liquidation of the Trust, if a sale of the Royalty Interests
is made or a definitive contract for sale of the Royalty Interests is entered into within a 150-day
period following the Termination Date, the buyer of the Royalty Interests, and not the Trust or
Unitholders, will be entitled to all proceeds of production attributable to the Royalty Interests
following the Termination Date. The Trust is withholding an additional $100,000 for anticipated
expenses relating to the termination process.
Results of Operations
Prior to termination of the Trust, when excess cash was available, the Trust made quarterly
cash distributions to Unitholders. The only assets of the Trust, other than cash and cash
equivalents being held for the payment of expenses and liabilities and for distribution to
Unitholders, are the Royalty Interests. The Royalty Interests owned by the Trust burden the
Underlying Properties, which are owned by WPC and not the Trust.
Distributable income of the Trust generally consists of the excess of royalty income plus
interest income over the general and administrative expenses of the Trust. Upon receipt by the
Trust, royalty income is invested in short-term investments in accordance with the Trust Agreement
until its subsequent distribution to Unitholders. Currently, funds are invested in Bank of America
money market accounts which are backed by the good faith of Bank of America, N.A., but are not
insured by the Federal Deposit Insurance Corporation (FDIC). The Trust does not lend money and
has limited ability to borrow money, which the Trustee believes limits the Trusts risk from the
current tightening of credit markets. Additional risks are described in Item 1A Risk Factors.
41
The amount of distributable income of the Trust for any calendar year may differ from the
amount of cash available for distribution to Unitholders in such year due to differences in the
treatment of the expenses of the Trust in the determination of those amounts. The financial
statements of the Trust are prepared on a modified cash basis pursuant to which general and
administrative expenses of the Trust are recognized when incurred whereas royalty income is
recognized when received. Consequently, the reported distributable income of the Trust for any
year is determined by deducting from the income received by the Trust the amount of expenses
incurred by the Trust during such year. The amount of cash available for distribution to
Unitholders, however, is determined in accordance with the provisions of the Trust Agreement and
reflects the deduction from the income actually received by the Trust of the amount of expenses
actually paid or accrued by the Trust and adjustment for changes in reserves for unpaid
liabilities. See Note 5 to Item 8Financial Statements and Supplementary DataNotes to
Financial Statements for additional information regarding the determination of the amount of cash
available for distribution to Unitholders.
For 2009, royalty income received by the Trust amounted to $2,882,120 as compared to
$15,151,993 and $9,496,151 for 2008 and 2007, respectively. The decrease in royalty income in 2009
compared to 2008 was primarily due to the result of lower natural gas prices, declining production
levels and additional receipts from WPCs processing of unit expansion adjustments in 2008. In the
second quarter 2009, Williams notified the Trust that WPC made an overpayment of $765,816 to the
Trust for the production quarter ending March 31, 2009; however, Williams waived any right to seek
recoupment of the amount of the overpayment or reduce any future payments of royalty income to the
Trust by the amount of the overpayment. The increase in royalty income in 2008 compared to 2007
was primarily due to an additional $3.5 million distribution received from WPC from the
actualization of the unit expansions effecting the Underlying Properties. The increase was also
the result of higher natural gas prices. Net production related to the royalty income received by
the Trust in 2009 was 1,742,713 MMBtu as compared to 3,463,050 MMBtu (exclusive of the above
described unit expansion adjustment) and 3,730,887 MMBtu in 2008 and 2007, respectively. The
average net natural gas price received for royalty income in 2009 was $1.97 per MMBtu as compared
to $3.05 MMBtu (exclusive of the above described unit expansion adjustment) and $2.24 MMBtu in 2008
and 2007, respectively. Interest income for 2009 was $896 as compared to $24,390 and $39,842 for
2008 and 2007. The decrease in interest income for 2009 reflects lower interest rates and less
funds available for investment. The decrease in interest income for 2008 reflects lower interest
rates.
General and administrative expenses for 2009 were $1,011,166, as compared to $885,692 and
$988,693 for 2008 and 2007, respectively. General and administrative expenses in 2009 were higher
due to increased professional expenses compared to 2008. General and administrative expenses in
2008 were lower due to decreased Unitholder reporting costs compared to 2007.
Distributable income for 2009 was $1,871,850 or $0.19 per Unit, compared to $14,290,691 or
$1.47 per Unit for 2008, and $8,547,300 or $0.88 per Unit, for 2007. The decrease in distributable
income in 2009 compared to 2008 was due to lower gas prices and lower production. The increase in
distributable income in 2008 compared to 2007 was primarily due to the actualization of various
unit expansions, as discussed further in Note 6 to Item 8 Financial Statements and
Supplementary Data Notes to Financial Statements and due to higher gas prices.
Because the Trust incurs administrative expenses throughout a quarter but receives its royalty
income only once in a quarter, the Trustee established in the first quarter of 1993 a cash reserve
for the payment of expenses and liabilities of the Trust. The Trustee thereafter has adjusted the
amount of such reserve in certain quarters as required for the payment of the Trusts expenses and
liabilities, in accordance with the provisions of the Trust Agreement. The Trustee has maintained
for the foreseeable future a cash reserve that will be reduced by Trust expenses in excess of
royalty income.
Royalty income received by the Trust in a given calendar year will generally reflect the sum
of (i) net proceeds from the sale of gas produced from the WI Properties during the first three
quarters of that year and the fourth quarter of the preceding calendar year, plus (ii) cash
received by WPC with respect to the Farmout Properties during the first three quarters of that year
(or in the month immediately following the third quarter, if received by WPC in sufficient time to
be paid to the Trust) and the fourth quarter of the preceding calendar year.
Accordingly, the royalty income included in distributable income for the years ended December
31, 2009, 2008 and 2007, was based on production volumes and natural gas prices for the 12 months
ended in September 30,
42
2009, 2008 and 2007, respectively, as shown in the table below. The net
production volumes included in the table
below are for production attributable to net profits of Underlying Properties, and not for
production attributable to the Royalty Interests owned by the Trust, and are net of the amount of
production attributable to WPCs royalty obligations to third parties, which are determined by
contractual arrangement with such parties.
Twelve Months Ended September 30, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Production, Net (MMBtu)(1)(2)
WI Properties |
1,817,880 | 4,453,132 | 5,008,996 | |||||||||
Farmout Properties(3) |
923,558 | 1,043,121 | 1,209,149 | |||||||||
Infill Properties(5) |
489,252 | 826,496 | 0 | (5) | ||||||||
Average Blanco Hub Spot Price ($/MMBtu) |
$ | 3.25 | $ | 7.21 | $ | 5.86 | ||||||
Average Net Profits Price WI
Properties ($/MMBtu)(4)(5) |
$ | 1.90 | $ | 2.76 | $ | 2.24 |
(1) | Million British Thermal Units. | |
(2) | Production volumes for 2008 presented above are exclusive of 6,845,010 MMBtu net production volumes related to the unit expansion adjustment as described in Note 6 to Item 8 Financial Statements and Supplementary Data Notes to Financial Statements. | |
(3) | Includes previously reported estimated amounts for certain months. | |
(4) | Total Gross Proceeds divided by Entitled W.I. Dry MMBtu for 12 months ending on September 30. | |
(5) | No distribution was made for Infill Properties until 2008 when the properties paid out. WPC informed the Trustee that due to the net deficit realized by the Infill Wells during the third and fourth quarters, the Infill Net Profit Costs exceeded the Infill Net Profit Gross Proceeds and received no royalty income from the Infill Properties in those periods. The Trust will not receive its 20 percent interest in WPCs Infill Net Proceeds until such time as the Infill Net Profits Gross Proceeds exceeds the Infill Net Profit Costs on an aggregate basis. |
Production from the WI Properties is generally sold pursuant to the Gas Purchase Contract.
For more information regarding the Gas Purchase Contract and the right of WFS Gas Resources to
recoup certain Price Credits, see Item 2 Properties The Royalty Interests Gas Purchase
Contract in this Form 10-K.
As described under Termination and Liquidation of the Trust, if a sale of the Royalty
Interests is made or a definitive contract for sale of the Royalty Interests is entered into within
a 150-day period following the Termination Date, the buyer of the Royalty Interests, and not the
Trust or Unitholders, will be entitled to all proceeds of production attributable to the Royalty
Interests following the Termination Date.
The information herein concerning production and prices relating to the Underlying Properties
is based on information prepared and furnished by WPC to the Trustee. The Trustee has no control
over and no responsibility relating to the operation of the Underlying Properties.
Off-Balance Sheet Arrangements
As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and
neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to
the operation of the Underlying Properties. The Trustee has powers to collect and distribute
proceeds received by the Trust and pay Trust liabilities and expenses, and its actions have been
limited to those activities. Therefore, the Trust has not engaged in any off-balance sheet
arrangements.
43
Tabular Disclosure of Contractual Obligations
As shown below, the Trust had no obligations and commitments to make future contractual
payments as of December 31, 2009.
Payments Due by Period | ||||||||||||||||||||
Less than | ||||||||||||||||||||
Total | 1 Year | 1 - 3 Years | 3-5 Years | More than 5 Years | ||||||||||||||||
Contractual
Obligations |
$ | -0- | $ | -0- | $ | -0- | $ | -0- | $ | -0- |
Forward-Looking Statements
This Annual Report includes forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
which are intended to be covered by the safe harbor created thereby. All statements other than
statements of historical fact included in this Annual Report are forward-looking statements. Such
statements include, without limitation, factors affecting the price of oil and natural gas
contained in Item 1, Business; certain reserve information and other statements contained in Item
2, Properties; and certain statements regarding the Trusts financial position, industry
conditions, any sale of the Remaining Royalty Interests upon termination of the Trust and other
matters contained in this Item 7. Although the Trustee believes that the expectations reflected in
such forward-looking statements are reasonable, it can give no assurance that such expectations
will prove to have been correct. There are many factors, none of which is within the Trustees
control, that may cause such expectations not to be realized, including, among other things,
factors identified in this Annual Report affecting oil and gas prices and the recoverability of
reserves, general economic conditions, actions and policies of petroleum-producing nations and
other changes in the domestic and international energy markets and the factors identified in Item
1A, Risk Factors.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
The only assets of and sources of income to the Trust are the Royalty Interests, which, prior
to the termination of the Trust, generally entitled the Trust to receive a share of the net profits
from natural gas production from the Underlying Properties. Consequently, the Trusts financial
results are significantly affected by fluctuations in natural gas prices and the Trust has
commodity price risk exposure associated with the natural gas markets in the United States. The
Trust does not engage in any hedging activities to manage its price risk associated with natural
gas production from the Underlying Properties. The Royalty Interests do not entitle the Trust to
control or influence the operation of the Underlying Properties or the sale of gas produced
therefrom. Natural gas produced from the WI Properties, which comprises the majority of production
attributable to the Royalty Interests, is currently sold by WPC pursuant to the terms of the Gas
Purchase Contract. Although the Trust is not a party to the Gas Purchase Contract, the Gas
Purchase Contract significantly impacted revenues to the Trust. Although the Gas Purchase Contract
mitigates the risk to the Trust of low gas prices, it also limits the ability of the Trust to
benefit from the effects of higher gas prices, particularly to the extent a balance exists in the
Price Credit Account. See Item 2 Properties The Royalty Interests Gas Purchase Contract
for detailed information about the Gas Purchase Contract and its impact on the Trust and
Unitholders.
Upon receipt by the Trust, royalty income is invested in short-term investments in accordance
with the Trust Agreement until its subsequent distribution to Unitholders. Currently, funds are
invested in Bank of America money market accounts which are backed by the good faith and credit of
Bank of America, N.A., but are not insured by the FDIC. Each Unitholder should independently
assess the creditworthiness of Bank of America, N.A. For more information about the credit rating
of Bank of America, N.A., please refer to its periodic filings with the SEC. The Trust does not
lend money and has limited ability to borrow money, which the Trustee believes limits the Trusts
risk from the current tightening of credit markets. See Item 1A Risk Factors Funds held by
the Trustee are not insured by the Federal Deposit Insurance Corporation, and future royalty income
may be subject to
44
risks relating to the creditworthiness of third parties. Information contained
in Bank of America, N.As periodic filings with the SEC is not incorporated by reference into this
annual report on Form 10-K and should not be considered part of this report or any other filing
that the Trust makes with the SEC.
The market prices of the Units are determined by the buyers and sellers on the New York Stock
Exchange. The Trust does not make market on any Units and is not in any position to advise any
Unitholder on any market position. Unitholders should be aware that any position of the market
concerning the Units is beyond the Trusts control and on any given day, various market conditions
will affect the market of the Units.
The assets of the Trust are passive in nature, and other than the Trusts ability to
periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust
that cannot be paid out of cash held by the
Trust, the Trust is prohibited from engaging in borrowing transactions. The amount of any
such borrowings is unlikely to be material to the Trust. The Trust periodically holds short-term
investments acquired with funds held by the Trust pending distribution to Unitholders and funds
held in reserve for the payment of Trust expenses and liabilities. Because of the short-term
nature of these borrowings and investments and certain limitations upon the types of such
investments that may be held by the Trust, the Trustee believes that the Trust is not subject to
any material interest rate risk. The Trust does not engage in transactions in foreign currencies
that could expose the Trust or Unitholders to any foreign currency related market risk.
Item 8. Financial Statements and Supplementary Data.
Audited Statements of Assets, Liabilities and Trust Corpus of the Trust as of December 31,
2009 and 2008, and the related Statements of Distributable Income and Changes in Trust Corpus for
each of the 3 years in the period ended December 31, 2009, are included in this Form 10-K.
45
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Trustee
Williams Coal Seam Gas Royalty Trust
Williams Coal Seam Gas Royalty Trust
We have audited the accompanying statements of assets, liabilities and trust corpus of the
Williams Coal Seam Gas Royalty Trust as of December 31, 2009 and 2008, and the related statements
of distributable income and changes in trust corpus for each of the three years in the period ended
December 31, 2009. These financial statements are the responsibility of the Trustees management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits 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 financial statements are free of material
misstatement. We were not engaged to perform an audit of the Williams Coal Seam Gas Royalty
Trusts 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
Williams Coal Seam Gas Royalty Trusts 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.
As described in Note 2 to the financial statements, these financial statements have been
prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other
than U.S. generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the assets, liabilities and trust corpus of the Williams Coal Seam Gas Royalty Trust at
December 31, 2009 and 2008, and its distributable income and its changes in trust corpus for each
of the three years in the period ended December 31, 2009, on the basis of accounting described in
Note 2.
The accompanying financial statements have been prepared assuming that the Trust will continue
as a going concern. As more fully described in Note 2, the computed net present value of the
estimated future net revenues for proved reserves attributable to the Royalty Interests fell below
the termination threshold prescribed by the Trust Agreement at December 31, 2009, triggering a
termination of the Trust effective March 1, 2010. The Trust Agreement provides the Trustee a
one-year period during which to sell all of the Trusts properties before the properties are
otherwise sold at auction. Accordingly, there exists substantial doubt about the Trusts ability
to continue as a going concern. The financial statements do not include any adjustments that might
result from execution of the plan for termination or liquidation of the Trusts assets.
As
discussed in Note 2 to the financial statements, the Trust has changed its
reserve estimates and related disclosures as a result of adopting new oil and gas reserve
estimation and disclosure requirements.
/s/ ERNST & YOUNG LLP | ||||
Tulsa, Oklahoma
March 31, 2010
March 31, 2010
46
Financial Statements
Williams Coal Seam Gas Royalty Trust
Williams Coal Seam Gas Royalty Trust
Statements of Assets, Liabilities and Trust Corpus
December 31, | ||||||||
2009 | 2008 | |||||||
Assets |
||||||||
Current assets cash and cash equivalents |
$ | 52,195 | $ | 45,419 | ||||
Royalty interests in oil and gas properties (less accumulated
amortization of $134,091,719 and $132,988,670 at December 31,
2009 and 2008, respectively) (Note 2) |
4,474,945 | 5,577,994 | ||||||
Total |
$ | 4,527,140 | $ | 5,623,413 | ||||
Liabilities and Trust Corpus |
||||||||
Current liabilities other accounts payable |
$ | 116,341 | $ | 31,193 | ||||
Contingencies (Note 6) |
||||||||
Trust corpus (9,700,000 units of beneficial interest authorized and
outstanding) (Note 2) |
4,410,799 | 5,592,220 | ||||||
Total |
$ | 4,527,140 | $ | 5,623,413 | ||||
Statements of Distributable Income
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Royalty income (Notes 2, 4 and 6) |
$ | 2,882,120 | $ | 15,151,993 | $ | 9,496,151 | ||||||
Interest income |
896 | 24,390 | 39,842 | |||||||||
Total |
2,883,016 | 15,176,383 | 9,535,993 | |||||||||
General and administrative expenses (Note 4) |
(1,011,166 | ) | (885,692 | ) | (988,693 | ) | ||||||
Distributable income |
$ | 1,871,850 | $ | 14,290,691 | $ | 8,547,300 | ||||||
Distributable income per Unit (9,700,000 units) (Note 2) |
$ | 0.19 | $ | 1.47 | $ | 0.88 | ||||||
Distributions per Unit (Note 5) |
$ | 0.20 | $ | 1.47 | $ | 0.88 | ||||||
Statements of Changes in Trust Corpus
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Trust corpus, beginning of year |
$ | 5,592,220 | $ | 6,877,977 | $ | 8,316,439 | ||||||
Amortization of royalty interests (Note 2) |
(1,103,049 | ) | (1,293,038 | ) | (1,440,159 | ) | ||||||
Distributable income |
1,871,850 | 14,290,691 | 8,547,300 | |||||||||
Distributions to Unitholders (Note 5) |
(1,950,222 | ) | (14,283,410 | ) | (8,545,603 | ) | ||||||
Trust corpus, end of year |
$ | 4,410,799 | $ | 5,592,220 | $ | 6,877,977 | ||||||
See
accompanying notes
47
Notes to Financial Statements
1. Trust Organization and Provisions
Williams Coal Seam Gas Royalty Trust (the Trust) was formed as a Delaware business trust
pursuant to the terms of the Trust Agreement of Williams Coal Seam Gas Royalty Trust (as amended,
the Trust Agreement) entered into effective as of December 1, 1992, by and among Williams
Production Company, a Delaware corporation (WPC), as trustor; The Williams Companies, Inc., a
Delaware corporation (Williams), as sponsor; Bank of America, N.A. (as successor to NationsBank
of Texas, N.A.), a national banking association (the Trustee); and The Bank of New York Mellon
Trust Company, N.A. (as successor to Chemical Bank Delaware), a Delaware banking corporation (the
Delaware Trustee) (the Trustee and the Delaware Trustee are sometimes referred to
collectively as the Trustees). The Trustees are independent financial institutions.
The Trust was formed to acquire and hold certain net profits interests (the Royalty
Interests) in proved natural gas properties located in the San Juan Basin of New Mexico and
Colorado (the Underlying Properties) owned by WPC. The Trust was initially created effective as
of December 1, 1992, with a $100 contribution by WPC. On January 21, 1993, the Royalty Interests
were conveyed to the Trust by WPC pursuant to the Net Profits Conveyance (the Conveyance) entered
into effective as of October 1, 1992, by and among WPC, Williams, the Trustee and the Delaware
Trustee, in consideration for all the 9,700,000 authorized units of beneficial interest in the
Trust (Units). WPC transferred its Units by dividend to its parent, Williams, which sold an
aggregate of 5,980,000 Units to the public through various underwriters in January and February
1993 (the Public Offering). Subsequently, Williams sold to the public an additional 151,209
Units. During the second quarter of 1995, Williams transferred its remaining Units to Williams
Holdings of Delaware, Inc. (WHD), a separate holding company for Williams non-regulated
businesses. Effective July 31, 1999, WHD was merged into Williams, and by operation of the merger,
Williams assumed all assets, liabilities and obligations of WHD, including without limitation
ownership of WHDs Units. Effective August 11, 2000, Williams sold its Units to Quatro Finale IV
LLC, a Delaware limited liability company (QFIV), in a privately negotiated transaction.
Williams retained the voting rights and retained a call option on the transferred Units, and QFIV
was granted a put option on the Units. Through a series of exercises of its call option,
Williams reacquired an aggregate of 3,568,791 Units from December 2001 through June 2003. Williams
has informed the Trustee that it has subsequently sold 2,779,500 of these Units through March 15,
2010 and owned a remaining 789,291 Units as of such date.
Effective May 1, 1997, WPC sold the Underlying Properties subject to and burdened by the
Royalty Interests to Quatro Finale LLC, an unaffiliated Delaware limited liability company.
Ownership of the Underlying Properties reverted back to WPC effective February 1, 2001, pursuant to
the terms of the May 1, 1997 transaction. Pursuant to a Purchase and Sale Agreement dated March
14, 2001 (the 2001 Transaction Agreement), and effective March 1, 2001, WPC sold the Underlying
Properties subject to and burdened by the Royalty Interests to Quatro Finale V LLC, an unaffiliated
Delaware limited liability company. The sale of the Underlying Properties is expressly permitted
under the Trust Agreement. Effective January 1, 2003, ownership of the Underlying Properties once
again reverted back to WPC after it exercised its right to repurchase interests in the Underlying
Properties from Quatro Finale V LLC pursuant to the 2001 Transaction Agreement. Unless otherwise
dictated by context, references herein to WPC with respect to the ownership of the Underlying
Properties for any period from May 1, 1997 through February 1, 2001, and for the period from March
1, 2001 through December 31, 2002, shall be deemed to refer to Quatro Finale.
The Trustee has the power to collect and distribute the proceeds received by the Trust and to
pay Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in
the Trust Agreement and is not empowered to otherwise manage or take part in the business of the
Trust. The Royalty Interests are passive in nature, and neither the Delaware Trustee nor the
Trustee has any control over or any responsibility relating to the operation of the Underlying
Properties.
The only assets of the Trust, other than cash and cash equivalents being held for the payment
of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The
Royalty Interests consist primarily of a net profits interest (the NPI) in the Underlying
Properties. The NPI generally entitles the Trust to receive 60 percent of the NPI Net Proceeds, as
defined below, attributable to (i) gas produced and sold from WPCs net revenue interests (working
interests less lease burdens) in the properties in which WPC has a working interest (the
48
WI Properties) and (ii) the revenue stream received by WPC attributable to its 35 percent net
profits interest in 5,348 gross acres in La Plata County, Colorado (the Farmout Properties).
The Royalty Interests also include a 20 percent interest in WPCs Infill Net Proceeds from the
sale of production since well spacing rules have been effectively modified and additional wells are
drilled on producing drilling blocks on the WI Properties (the Infill Wells) during the term of
the Trust. Infill Net Proceeds consists generally of the aggregate proceeds, based on the price
at the wellhead, of gas produced from WPCs net revenue interest in any Infill Wells less certain
taxes and costs.
On October 15, 2002, the New Mexico Oil and Gas Commission (NMOCD) revised the field rules for
the Basin Fruitland Coal (Gas) Pool to allow optional second (infill) wells on the standard
320-acre spacing unit in certain designated areas of the pool (the non-fairway wells). On July 17,
2003, the NMOCD further modified the field rules for the Basin Fruitland Coal (Gas) Pool to allow
these infill wells on the standard 320-acre spacing unit in all areas of the pool. The WI
Properties contain 442 infill locations designated as proved locations according to SEC guidelines.
As of December 31, 2009, all of these infill locations represent proved developed producing
reserves, while there are no proved undeveloped locations.
WPC has informed the Trustee that the Infill Wells reached payout in the aggregate during
2008. The Trust has received its 20 percent interest in WPCs Infill Net Proceeds for the periods
after payout. However, during 2009, WPC informed the Trustee that due to the net deficit realized
by the Infill Wells during the third and fourth quarters, the Infill Net Profit Costs now exceed
the Infill Net Profit Gross Proceeds by approximately $32,500. The Trust will not be liable for
such excess costs, and such excess costs will hereafter constitute Excess Infill Net Profit Costs
until recovered by WPC. The Trust will not receive its 20 percent interest in WPCs Infill Net
Proceeds until such time as the Infill Net Profits Gross Proceeds exceeds the Infill Net Profit
Costs on an aggregate basis. The complete definitions of Infill Net Proceeds, Infill Net Profit
Costs, Excess Infill Net Profit Costs, and Infill Net Profit Gross Proceeds are set forth in the
Conveyance.
2. Basis of Accounting and Future Operations
The Trust terminated effective March 1, 2010 (the Termination Date), pursuant to the terms
of the Trust Agreement. Cancellation of the Trust will occur following the Termination Date when
all Trust assets have been sold and the net proceeds there from distributed to holders of Units in
the Trust (Unitholders).
The Trust Agreement required termination of the Trust in the event that when a computation is
performed as of each December 31, the net present value (discounted at 10 percent) of the estimated
future net revenues (calculated in accordance with criteria established by the SEC) for proved
reserves attributable to the Royalty Interests but using the average monthly Blanco Hub Spot Price
for the past calendar year less certain gathering costs, is equal to or less than $30 million. The
net present value of the estimated future net revenues computed as described above by the
independent petroleum engineers as of December 31, 2009 was approximately $8.4 million. The
results of this computation triggered an early termination of the Trust.
Because the Trusts computed net present value fell below the $30 million stipulated threshold
as of December 31, 2009, the Trust terminated effective March 1, 2010. The accompanying financial
statements have been prepared on a going concern basis and do not include any adjustments, costs
and expenses or other matters that might result from the outcome of this termination.
Following termination of the Trust, the Trustee will continue to act as Trustee of the Trust
until all Trust assets are sold and the net proceeds from such sales distributed to Unitholders.
The Trustee will use best efforts to sell the Trusts assets in accordance with the procedures set
forth in the Trust Agreement.
The Trustee has retained Albrecht & Associates, Inc., an investment banking firm (the
Advisor), on behalf of the Trust who will assist the Trustee in selling the remaining Royalty
Interests owned by the Trust (the Remaining Royalty Interests). WPC has the right, but not the
obligation, to make a cash offer to purchase all Remaining Royalty Interests following termination
of the Trust as described in the following paragraph.
49
WPC may, within 60 days following the Termination Date, make a cash offer to purchase all of
the Remaining Royalty Interests then held by the Trust. In the event such an offer is made by WPC,
the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such
offer (in which case no sale to WPC will be made unless a fairness opinion is given by the Advisor
that the purchase price is fair to the Trust and Unitholders) or (ii) defer action on such offer.
If the Trustee defers action on WPCs offer, the offer will be deemed withdrawn and the Trustee
will then use Best Efforts, assisted by the Advisor to obtain alternative offers for the Remaining
Royalty Interests. At the end of a 120-day period following the Termination Date, the Trustee is
required to notify WPC of the highest of any other offers (net of any commissions or other fees
payable by the Trust), acceptable to the Trustee (which must be an all-cash offer), received during
such period (the Highest Acceptable Offer). WPC then has the exclusive right (whether or not it
made an initial offer), but not the obligation, to purchase all Remaining Royalty Interests for a
cash purchase price computed as follows: (i) if the Highest Acceptable Offer is more than 105
percent of WPCs initial offer (or if WPC did not make an initial offer), the purchase price will
be 105 percent of the Highest Acceptable Offer, or (ii) if the Highest Acceptable Offer is equal to
or less than 105 percent of WPCs initial offer, the purchase price will be equal to the Highest
Acceptable Offer. If no other acceptable offers are received for all Remaining Royalty Interests,
the Trustee may request WPC to submit another offer for consideration by the Trustee and may accept
or reject such offer. Acceptance of an offer by the Trustee shall be conditioned upon the opinion
of the Advisor of the fairness of the offer.
If a sale of the Remaining Royalty Interests is made or a definitive contract for sale of the
Remaining Royalty Interests is entered into within a 150-day period following the Termination Date,
the buyer of the Remaining Royalty Interests, and not the Trust or Unitholders, will be entitled to
all proceeds of production attributable to the Remaining Royalty Interests following the
Termination Date. All proceeds of production following the Termination Date attributable to the
Remaining Royalty Interests will be deposited into a non-interest bearing account until they are
paid to the buyer or otherwise distributed in accordance with the Trust Agreement.
In the event that WPC does not purchase the Remaining Royalty Interests, the Trustee may
accept any offer for all or any part (not more than six parts) of the Remaining Royalty Interests
as it deems to be in the best interests of the Trust and Unitholders and may continue, for up to
one calendar year after the Termination Date, to attempt to locate a buyer or buyers of the
Remaining Royalty Interests in order to sell such interests in an orderly fashion not involving a
public auction. If any Remaining Royalty Interests have not been sold or a definitive agreement
for sale has not been entered into by the end of such calendar year, the Trustee is required to
sell the Remaining Royalty Interests at public auction to the highest cash bidder, which sale may
be to WPC or any of its affiliates. Notice of such sale by auction shall be mailed at least 30
days prior to such sale to each Unitholder at his address as it appears on the ownership ledger of
the Trustee.
The Trust is withholding an additional $100,000 for anticipated expenses relating to this
termination process.
The financial statements of the Trust are prepared on a modified cash basis and are not
intended to present financial position and results of operations in conformity with United States
Generally Accepted Accounting Principles (GAAP). Preparation of the Trusts financial statements
on such basis includes the following:
| Revenues are recognized in the period in which amounts are received by the Trust. General and administrative expenses are recognized on an accrual basis. | |
| Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to trust corpus. | |
| Distributions to Unitholders are recorded when declared by the Trustee (see Note 5 to Item 8Financial Statements and Supplementary DataNotes to Financial Statements). | |
| Loss contingencies are recognized in the period in which amounts are paid by the Trust. |
The financial statements of the Trust differ from financial statements prepared in accordance
with GAAP. For example, royalty income is not accrued in the period of production, amortization of
the Royalty Interests is not
50
charged against operating results, and loss contingencies are not charged to operating results
until paid. This comprehensive basis of accounting other than GAAP corresponds to the accounting
permitted for royalty trusts by the SEC, as specified by Staff Accounting Bulletin Topic 12:E,
Financial Statements of Royalty Trusts.
The
Trust adopted new oil and gas accounting guidance (Accounting
Standards Update 2010-03) in 2009 that requires valuation of reserves
using an average first-day-of-the-month price. Adoption of the new rules resulted in the use
of a lower price at December 31, 2009 for natural gas than would have
resulted under previous rules (see further discussion in Note 9).
3. Federal Income Taxes
The Trust is a grantor trust for Federal income tax purposes. As a grantor trust, the Trust
is not required to pay Federal income taxes. Accordingly, no provision for income taxes has been
made in these financial statements.
Because the Trust is treated as a grantor trust, and because a Unitholder is treated as
directly owning an interest in the Royalty Interests, each Unitholder is taxed directly on his per
Unit pro rata share of income attributable to the Royalty Interests consistent with the
Unitholders method of accounting and without regard to the taxable year or accounting method
employed by the Trust.
Each Unitholder should consult his tax advisor regarding Trust tax compliance matters.
4. Related Party Transactions
Williams provides accounting, bookkeeping and informational services to the Trust in
accordance with an Administrative Services Agreement effective December 1, 1992. The fee is
$50,000 per quarter, escalating 3 percent each October 1 commencing October 1, 1993. Aggregate
fees incurred by the Trust to Williams in 2009, 2008 and 2007 were $320,941, $311,593, and
$302,518, respectively. The amount owed to WPC at December 31, 2009 was $80,235. Substantially
all production from the WI Properties is sold to a Williams subsidiary. Additionally, all royalty
income is received from Williams.
The interests of Williams and its affiliates and the interests of the Trust and the
Unitholders with respect to the Underlying Properties could at times be different. As a working
interest owner in the WI Properties, WPC could have interests that conflict with the interests of
the Trust and Unitholders. For example, such conflicts could be due to a number of factors
including, but not limited to, future budgetary considerations and the absence of any contractual
obligation on the part of WPC to spend for development of the WI Properties, except as noted
herein. Such decisions may have the effect of changing the amount or timing of future
distributions to Unitholders. WPCs interests may also conflict with those of the Trust and
Unitholders in situations involving the sale or abandonment of Underlying Properties. WPC has the
right at any time to sell any of the Underlying Properties subject to the Royalty Interests and,
under certain circumstances, may abandon any of the WI Properties. Such sales or abandonment may
not be in the best interests of the Trust. In addition, WPX Gas Resources (hereinafter defined)
has the right, exercisable in its sole discretion, to terminate its Minimum Purchase Price
commitment under the Gas Purchase Contract prior to the expiration of the Gas Purchase Contract
upon the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the
Trust. Williams interest could conflict with those of the Trust and Unitholders to the extent the
interests of WPX Gas Resources (hereinafter defined), under the Gas Purchase Contract, or WFS and
WPX Gas Resources (hereinafter defined), under the Gas Gathering Contract, differ from the
interests of the Trust and the Unitholders. Except for amendments to the Gas Gathering Contract or
Gas Purchase Contract that must be approved by the vote of a majority of the Unitholders present at
a meeting at which a quorum is present if such amendment would materially adversely affect Trust
revenues, no mechanism or procedure has been included to resolve potential conflicts of interest
between the Trust, Williams, WPC or their affiliates.
Aggregate fees paid by the Trust to the trustees in 2009, 2008 and 2007 were $60,067, $58,497
and $56,972, respectively.
5. Distributions to Unitholders
Through the Termination Date, the Trustee determines for each quarter the amount of cash
available for distribution to Unitholders. Such amount (the Quarterly Distribution Amount) is an
amount equal to the excess, if any, of the cash received by the Trust, on or prior to the last day
of the month following the end of each calendar quarter from the Royalty Interests, plus, with
certain exceptions, any other cash receipts of the Trust during such quarter, over the liabilities
of the Trust paid during such quarter, subject to adjustments for changes made by the
Trustee during such quarter in any cash reserves established for the payment of contingent or
future obligations of the Trust.
51
The Trustee distributes the Quarterly Distribution Amount within 60 days after the end of each
calendar quarter to each person who was a Unitholder of record on the associated record date (i.e.,
the 45th day following the end of each calendar quarter or if such day is not a business day, the
next business day thereafter), together with interest estimated to be earned on such amount from
the date of receipt thereof by the Trustee to the payment date.
In addition to the regular quarterly distributions, under certain circumstances specified in
the Trust Agreement (such as upon a purchase price adjustment, if any, or pursuant to the sale of a
Royalty Interest) the Trust would make a special distribution (a Special Distribution Amount).
If applicable, a Special Distribution Amount would be made when amounts received by the Trust under
such circumstances aggregated in excess of $9,000,000. The record date for a Special Distribution
Amount will be the 15th day following receipt of amounts aggregating a Special Distribution Amount
by the Trust (unless such day is not a business day in which case the record date will be the next
business day thereafter or unless such day is within 10 days of the record date for a Quarterly
Distribution Amount in which case the record date will be the date as is established for the next
Quarterly Distribution Amount). Any applicable distribution to Unitholders of a Special
Distribution Amount would be made no later than 15 days after the Special Distribution Amount
record date. See Note 6 below for description of distributions in 2008 and 2007 that are not
recurring.
6. Contingencies
WPX Gas Resources Company (WPX Gas Resources, as successor in interest to Williams Gas
Marketing Company) purchases natural gas produced from the WI Properties (except for certain small
volumes) at the wellhead under the terms of a gas purchase contract dated October 1, 1992, as
amended (the Gas Purchase Contract). The Gas Purchase Contract provides for a pricing mechanism
during an initial 5-year period, which expired on December 31, 1997, and continuing for one or more
consecutive additional 1-year terms unless and until WPX Gas Resources exercises its annual option,
exercisable 15 days prior to the end of each contract year, to discontinue purchasing gas under the
pricing mechanism of the Gas Purchase Contract and instead purchase gas at a monthly market-based
price. WPX Gas Resources has not exercised this option, and therefore, the pricing mechanism will
continue to remain in effect through the expiration of the Gas Purchase Contract upon the earlier
of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust.
Under the pricing mechanism of the Gas Purchase Contract, when the market price was less than
$1.70 per MMBtu (the Minimum Purchase Price), the Trust was paid the Minimum Purchase Price for
the gas and an account (the Price Credit Account) was maintained to identify the accrued and
unrecouped amount of payments made to the Trust in excess of the market price. Any amounts in the
Price Credit Account were subject to future recoupment when the market price exceeded the Minimum
Purchase Price. As of December 31, 2009 and 2008, there were no remaining unrecouped Price Credits
in the Price Credit Account.
While the terms of the Gas Purchase Agreement pricing mechanism remained in place and no
balance existed in the Price Credit Account, when the market price for natural gas exceeded $1.94
per MMBtu (as was the case during all months in 2009, 2008 and 2007), the Trust received only 50
percent of the excess of the market price over the $1.94 price per MMBtu before reduction for
gathering, processing and certain other costs.
In 2008, WPC notified the Trust that certain royalty matters were being litigated by a federal
regulatory agency and another producer. WPC learned that this case was decided unfavorably to the
producer in October 2009. Neither WPC nor the Trust was a party to this litigation; however, given
the similarities to the Trusts Underlying Properties, WPC and
the Royalty Interests will more than likely be
impacted as well. WPC is currently evaluating the negative impact to the Trusts NPI. In
addition, there are other cases pending against other producers on related issues that could potentially have a
significant negative impact to future royalty income with respect to
the Royalty Interests, natural gas
reserves and reserve value.
The majority of the production attributable to the Trust is within Federal Units. Unit
participating areas are formed by pooling production from the participating area. Entitlement to
the pooled production is based on each partys acreage in the participating area divided by the
total participating acreage. Wells drilled outside the
52
participating area may create an enlargement to the participating area and a revision of the
Unit ownership entitlement. The Bureau of Land Management (BLM) must approve Unit participating
area expansions. The effective date for Unit expansions is retroactive to the date the well
creating the expansion was tested. WPC informed the Trustee in 2007 that it estimated the impact
of various retroactive unit expansions to the Trust and paid the Trust an adjusted amount, based on
the estimate, in the third quarter of 2007. This adjustment was the result of numerous expansions
coming from the BLM that impacted the Trusts royalty income. These expansions are retroactive to
production periods beginning in 1994. WPC had previously informed the Trustee that it was
researching the manner in which capital costs impacted the expansion computations. During 2008,
WPC informed the Trustee that it completed its research related to past capital costs incurred
pertaining to wells included in this and previous unit expansions and consistent with past
application concluded that capital costs should not be considered as a reduction in computing the
net proceeds due the Trust. WPC completed the accounting for these expansions which resulted in an
additional $3.5 million in the Trusts 2008 royalty income. The Trusts 2007 royalty income
considered the Trusts $5 million portion of the CO2 settlement, which was substantially offset by
a $4.8 million amount paid to the Trust by WPC for the unit expansions (actualized during 2008 as
described above). The net effect on these items resulted in an approximate $180,000 decrease to
the Trusts 2007 royalty income. In the second quarter 2009, Williams notified the Trust that WPC
made an overpayment of $765,816 to the Trust for the production quarter ending March 31, 2009;
however, Williams waived any right to seek recoupment of the amount of the overpayment or reduce
any future payments of royalty income to the Trust by the amount of the overpayment.
The royalty income presented in the accompanying statements of distributable income is on an
entitlement basis and reflects WPCs estimated impact of the most recent BLM participating area
approvals through December 31, 2009.
7. Subsequent Event
The Trustee has evaluated events occurring subsequent to December 31, 2009 through the time of
filing. Subsequent to December 31, 2009, the Trust declared the following distribution:
Quarterly Record Date | Payment Date | Distribution per Unit | ||
February 16, 2010 | March 1, 2010 | $0.016972 |
Subsequent to December 31, 2009, the Trustee announced that the Trust would terminate
effective March 1, 2010, as described in Note 2.
8. Quarterly Financial Data (Unaudited)
The following table sets forth the royalty income, distributable income and distributions per
Unit of the Trust for each quarter in the years ended December 31, 2009 and 2008 (in thousands,
except per Unit amounts):
Calendar Quarter | Royalty Income | Distributable Income | Distributions per Unit | |||||||||
2009 |
||||||||||||
First |
$ | 1,393 | $ | 1,022 | $ | 0.113811 | ||||||
Second |
932 | 666 | 0.065169 | |||||||||
Third |
78 | (104 | ) | 0.000000 | ||||||||
Fourth |
479 | 288 | 0.022074 | |||||||||
TOTAL |
$ | 2,882 | $ | 1,872 | $ | 0.201054 | ||||||
2008 |
||||||||||||
First |
$ | 2,035 | $ | 1,739 | $ | 0.179608 | ||||||
Second |
2,112 | 1,866 | 0.187237 | |||||||||
Third |
3,629 | 3,480 | 0.349784 | |||||||||
Fourth |
7,376 | 7,206 | 0.755888 | |||||||||
TOTAL |
$ | 15,152 | $ | 14,291 | $ | 1.472517 | ||||||
53
Selected 2009 fourth quarter data are as follows (in thousands except per Unit amounts):
2009 | 2008 | |||||||
Royalty income |
$ | 479 | $ | 7,376 | ||||
Interest income |
1 | 11 | ||||||
General and administrative expenses |
(192 | ) | (181 | ) | ||||
Distributable income |
$ | 288 | $ | 7,206 | ||||
Distributable income per Unit (9,700,000 units) |
$ | .03 | $ | .74 | ||||
Distributions per Unit |
$ | .02 | $ | .76 |
Royalty Income reported for the fourth quarter 2008 includes the impact of the $3.5 million
unit expansion adjustment described in Note 6. During 2009 WPC notified the Trust that Royalty Income for the second
quarter 2009 includes an overpayment of approximately $766,000. However, Williams waived any right to seek
recoupment of the amount or reduce any future payments of royalty income to the Trust by the amount of
overpayment.
9. Supplemental Oil and Gas Information (Unaudited)
The Trusts net profits interest entitles the Trust to a portion of the net proceeds derived
from the underlying quantities of gas. Therefore, the estimated volumes net to the Trusts
interest are impacted by the level of revenue attributable to and costs deducted in calculating the
net profits interest of the Trust. The net proved reserves attributable to the Royalty Interests
have been estimated as of December 31, 2009, 2008 and 2007, by Miller and Lents, Ltd., independent
petroleum engineers. In accordance with FASB guidance, estimates of future net revenues from
proved reserves for 2008 and 2007 have been prepared using contractual gas prices
and related costs in effect at year end. For 2009, estimates of future net revenues from
proved reserves have been prepared using the average
first-day-of-the-month price during the 12-month period prior to
December 31, 2009, as discussed below. The Blanco Hub Spot Price was $5.24 and $6.43 per MMBtu at December 31, 2008,
and 2007, respectively. The average first-day-of-the-month price during the 12-month period prior to December 31, 2009
was $3.25. These methodologies resulted in a weighted average wellhead price, after adjustments for certain
costs and provisions of the Gas Purchase Contract, of $2.625, $3.620 and $4.215 per Mcf for 2009, 2008, and 2007, respectively. For the working interest properties, the Trusts
reserves as of December 31, 2009, are computed based on a going concern basis, thus giving effect
to the Gas Purchase Contract price through December 31, 2012. Thereafter, the price used in the
reserve computation reverts to the average beginning of the month Blanco Hub Spot Price to estimate
the remaining quantities net to the net profits interests of the Unitholders. The standardized
measure of discounted future net revenues below has been reduced by operating and development
costs, which are paid by Williams and are included in computing the royalty income of the Trust.
The standardized measure has not been reduced for income taxes as no income taxes are paid by the
Trust (see Note 3).
The Financial Accounting Standards Board requires supplemental disclosure for oil and gas
reserves producers based on a standardized measure of discounted future net cash flows relating to
proved oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by
applying the average prices during the 12-month period prior to fiscal year-end, 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. Future price changes are only considered to the extent provided by contractual
arrangements in existence at year end. The standardized measure of discounted future net cash
flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows
relating to proved oil and gas reserves. The SECs prior rules required proved reserve estimates
to be calculated using prices as of the end of the period and held constant over the life of the
reserves. Application of the new reserve rules resulted in the use of
a lower price at December
31, 2009 for gas than would have resulted under the previous rules. Use of the new 12-month
average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of
approximately
4,902
Mmcf, reflected in revisions of previous estimates in the table below.
54
Numerous uncertainties are inherent in estimating volumes and value of proved reserves and in
projecting future production rates and timing of development expenditures. Such reserve estimates
are subject to change as additional information becomes available. The reserves actually recovered
and the timing of production may be substantially different from the reserve estimates. This table
reflects calendar year activity and will differ from the financial statement presentation which is
lagging by 3 months.
Natural Gas (MMcf) | ||||
Proved gas reserves at December 31, 2006 |
24,267 | |||
Production |
(4,155 | ) | ||
Extensions and revisions of previous estimates |
1,968 | |||
Proved gas reserves at December 31, 2007 |
22,080 | |||
Production |
(3,838 | ) | ||
Extensions and revisions of previous estimates |
(5,521 | ) | ||
Proved gas reserves at December 31, 2008 |
12,721 | |||
Production |
(1,871 | ) | ||
Extensions and revisions of previous estimates |
(4,353 | ) | ||
Proved gas reserves at December 31, 2009 |
6,497 | |||
Proved developed oil and gas reserves at December 31, 2009 |
6,497 | |||
Proved gas reserves at December 31, 2009 are comprised entirely of proved developed reserves.
Proved gas reserves at December 31, 2008, include 96 MMcf of proved undeveloped reserves. The 2008
revisions of previous estimates are a result of the impact of lower prices and increased costs in
calculating the quantities associated with the net profits interest as discussed above. Proved gas
reserves at December 31, 2007, include 479 MMcf of proved undeveloped reserves.
Proved oil and gas reserves are 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.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods.
The following table sets forth the standardized measure of discounted future net revenues at
December 31, 2009, 2008 and 2007 relating to proved reserves (in thousands):
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Future cash inflows |
$ | 9,579 | $ | 38,764 | $ | 80,828 | ||||||
Future production taxes |
(2,981 | ) | (9,261 | ) | (16,093 | ) | ||||||
Future development costs |
-0- | (1,098 | ) | (1,218 | ) | |||||||
Future net cash flows |
6,598 | 28,405 | 63,517 | |||||||||
10% discount factor |
(1,667 | ) | (9,340 | ) | (24,775 | ) | ||||||
Standardized measure of discounted future net revenues |
$ | 4,931 | $ | 19,065 | $ | 38,742 | ||||||
The following table sets forth the changes in the aggregate standardized measure of discounted
future net revenues from proved reserves during the years ended December 31, 2009, 2008 and 2007
(in thousands):
2009 | 2008 | 2007 | ||||||||||
Balance at January 1 |
$ | 19,065 | $ | 38,742 | $ | 33,689 | ||||||
Increase (decrease) due to: |
||||||||||||
Net sales of coal seam gas |
(2,338 | ) | (10,611 | ) | (8,720 | ) | ||||||
Net changes in prices and costs |
(11,285 | ) | (4,336 | ) | 4,240 | |||||||
Development costs incurred |
85 | 176 | (453 | ) | ||||||||
Changes in estimated future development cost |
856 | 15 | 1,366 | |||||||||
Extensions and revisions of previous quantity estimates |
(3,321 | ) | (8,740 | ) | 3,727 | |||||||
Accretion of discount |
1,741 | 3,588 | 3,369 | |||||||||
Other |
128 | 231 | 1,525 | |||||||||
(14,134 | ) | (19,677 | ) | 5,054 | ||||||||
Balance at December 31 |
$ | 4,931 | $ | 19,065 | $ | 38,742 | ||||||
55
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures. The Trust maintains a set of disclosure controls and
procedures designed to ensure that information required to be disclosed by the Trust in reports
that it files or submits under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC rules and forms. In addition,
the disclosure controls and procedures are designed to ensure that the information required to be
disclosed by the Trust is accumulated and communicated to the Trustee to allow timely decisions
regarding required disclosure. As of the end of the period covered by this report, the Trustee
carried out an evaluation of the effectiveness of the design and operation of the Trusts
disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15. Based upon
that evaluation, the Trustee concluded that the Trusts disclosure controls and procedures are
effective in recording, processing, summarizing and reporting, on a timely basis, information
required to be disclosed by the Trust in the reports that it files or submits under the Exchange
Act and are effective in ensuring that information required to be disclosed by the Trust in the
reports that it files or submits under the Securities Act of 1934 is accumulated and communicated
to the Trustee to allow timely decisions regarding required disclosure. In its evaluation of
disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on
information provided by WPC.
Changes in Internal Control over Financial Reporting. There has not been any change in the
Trusts internal control over financial reporting during the fourth quarter of 2009 that has
materially affected, or is reasonably likely to materially affect, the Trusts internal control
over financial reporting.
Trustees Report on Internal Control Over Financial Reporting. The Trustee is responsible for
establishing and maintaining adequate control over financial reporting, as such term is defined in
Rule 13a-15 promulgated under the Securities Exchange Act of 1934, as amended. The Trustee
conducted an evaluation of the effectiveness of the Trusts internal control over financial
reporting based on the criteria established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustees
evaluation under the framework in Internal Control-Integrated Framework, the Trustee concluded that
the Trusts internal control over financial reporting was effective as of December 31, 2009. This
Annual Report does not include an attestation report of the Trusts registered public accounting
firm regarding internal control over financial reporting. The Trustees report was not subject to
attestation by the Trusts registered public accounting firm pursuant to temporary rules of the
Securities and Exchange Commission that permit the Trust to provide only the Trustees report in
this Annual Report.
Item 9B. Other Information.
None.
56
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Directors and Executive Officers. The Trust has no directors or executive officers. Each of
the Trustee and the Delaware Trustee is a corporate trustee that may be removed as trustee under
the Trust Agreement, with or without cause, at a meeting duly called and held by the affirmative
vote of Unitholders of not less than a majority of all the Units then outstanding. Any such
removal of the Delaware Trustee shall be effective only at such time as a successor Delaware
Trustee fulfilling the requirements of Section 3807(a) of the Delaware Code has been appointed and
has accepted such appointment, and any such removal of the Trustee shall be effective only at such
time as a successor Trustee has been appointed and has accepted such appointment.
Code of Ethics. Because the Trust has no employees, it does not have a code of ethics.
Employees of the Trustee, Bank of American, N.A., must comply with the banks code of ethics, a
copy of which will be provided to Unitholders, without charge, upon request made to U.S. Trust,
Bank of America Private Wealth Management, 901 Main Street, 17th Floor, Dallas, Texas 75202,
Attention: Ron Hooper.
Audit Committee. The Trust has no directors and therefore has no audit committee or audit
committee financial expert.
Nominating Committee. The Trust has no directors and therefore has no nominating committee.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires the Trusts directors, officers
or beneficial owners of more than 10 percent of a registered class of the Trusts equity securities
to file reports of ownership and changes in ownership with the SEC and to furnish the Trust with
copies of all such reports.
The Trust has no directors or officers, and based solely on its review of the reports received
by it, the Trust believes that during the fiscal year of 2009, no person who was a beneficial owner
of more than 10 percent the Trusts Units failed to file on a timely basis any report required by
Section 16(a).
Item 11. Executive Compensation.
The following is a description of certain fees and expenses anticipated to be paid or borne by
the Trust, including fees expected to be paid to Williams, the Trustee, the Delaware Trustee,
Mellon Investor Service, L.L.C. (as successor to Chemical Shareholder Services Group, Inc.) (the
Transfer Agent), or their affiliates.
Ongoing Administrative Expenses. The Trust is responsible for paying all legal, accounting,
engineering and stock exchange fees, printing costs and other administrative and out-of-pocket
expenses incurred by or at the direction of the Trustee or the Delaware Trustee and the
out-of-pocket expenses of the Transfer Agent.
Compensation of the Trustee, Delaware Trustee and Transfer Agent. The Trust Agreement
provides for compensation to the Trustee and the Delaware Trustee for administrative services, out
of the Trust assets. The Trustee was paid a 2009 base amount of $53,918, plus an hourly charge for
services in excess of a combined total of 300 hours annually at the Trustees then standard rate.
The Delaware Trustee is paid a fixed annual amount, which was initially set at $5,000. The Trustee
and the Delaware Trustee received total compensation for 2009 of $53,918 and $6,149, respectively.
The base amount of the Trustees fee and the amount of the Delaware Trustees fee for
administrative services escalate at the rate of 3 percent per year. The Trustee and the Delaware
Trustee are each entitled to reimbursement for out-of-pocket expenses. Upon termination of the
Trust, the Trustee will receive, in addition to its out-of-pocket expenses, a termination fee in
the amount of $8,000.
The Transfer Agent receives a transfer agency fee of $5.50 annually per account (minimum of
$15,000 annually), subject to change each December, based upon the change in the Producers Price
Index as published by
57
the United States Department of Labor, Bureau of Labor Statistics, plus $1.00 for each
certificate issued in excess of 10,000 annually. The total fees paid by the Trust to the Transfer
Agent in 2009 were $32,614.
Fees to Williams. Williams will receive, throughout the term of the Trust, an administrative
services fee for accounting, bookkeeping and informational services relating to the Royalty
Interests as described below in Item 13Certain Relationships and Related
TransactionsAdministrative Services Agreement.
Compensation Committee. The Trust has no directors and therefore has no compensation
committee.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.
(a) Security Ownership of Certain Beneficial Owners. The following table sets forth as of
March 1, 2010 information with respect to the only Unitholder who was known to the Trustee to be a
beneficial owner of more than 5 percent of the outstanding Units.
Number of Units | Percent | |||||||
Name and Address of Beneficial Owner | Beneficially Owned | of Class | ||||||
The Williams Companies, Inc. |
789,291 | 8.14 | % | |||||
One Williams Center |
||||||||
Tulsa, Oklahoma 74172 (1) |
(1) | This information was provided to the SEC and to the Trustee in a Schedule 13D/A filed with the SEC on August 4, 2005, on behalf of The Williams Companies, Inc. |
(b) Securities Authorized for Issuance under Equity Compensation Plans. The Trust has no
equity compensation plans.
Williamss Voting Authority Over Units
Although Williams has the voting authority over the Units it holds, with respect to the vote
on any amendment to the Gas Purchase Contract or the Gas Gathering Contract, the Units held by
Williams (or its affiliates) immediately after the Public Offering may not be voted nor will such
Units be counted for purposes of determining if a quorum is present so long as such Units continue
to be held by Williams (or its affiliates). This voting limitation will not be applicable to Units
Williams (or its affiliates) may acquire, if any, after the date of the Public Offering.
In addition, as noted below, certain potential conflicts of interest exist between Williams
and its affiliates and the interests of the Trust and the Unitholders (see Item 13 Certain
Relationships and Related Transactions Potential Conflicts of Interest). To the extent that any
matters are brought to a vote of Unitholders where the interests of Williams conflict, or
potentially conflict, with the interests of the Trust or Unitholders, Williams (or its affiliates)
can be expected to vote in its own self-interest and under certain circumstances as noted above,
may have sufficient votes to control the outcome.
(b) Security Ownership of Management. The Trust has no directors or executive officers and
does not maintain any equity compensation plans. As of March 1, 2010, Bank of America, N.A., the
Trustee, held an aggregate of 18,444 Units in various fiduciary capacities, with no investment
or voting powers. As of March 1, 2010, Bank of New York Mellon Trust Company, N.A. (as successor
to Chemical Bank Delaware), the Delaware Trustee, did not beneficially own any Units.
(c) Changes in Control. Subject to the discussion above in this Item 12 under Williamss
Voting Authority Over Units, the Trustee knows of no arrangements the operation of which may at a
subsequent date result in a change in control of the Trust.
58
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Administrative Services Agreement
Pursuant to the Trust Agreement, Williams and the Trust entered into an Administrative
Services Agreement effective December 1, 1992. A copy of the Administrative Services Agreement is
filed as an exhibit to this Form 10-K.
The Administrative Services Agreement obligates the Trust to pay to Williams each quarter an
administrative services fee for accounting, bookkeeping and informational services relating to the
Royalty Interests. The administrative services fee was $50,000 per calendar quarter commencing
October 1, 1993, through and including the quarter ended September 30, 1994, and increases 3
percent each October 1. Accordingly, the total of the administrative services fees paid by the
Trust to Williams in 2009 was $320,941. The amount owed to WPC at December 31, 2009 was $80,235.
Potential Conflicts of Interest
The interests of Williams and its affiliates and the interests of the Trust and the
Unitholders with respect to the Underlying Properties could at times be different. As a working
interest owner in the WI Properties, WPC could have interests that conflict with the interests of
the Trust and Unitholders. For example, such conflicts could be due to a number of factors
including, but not limited to, future budgetary considerations and the absence of any contractual
obligation on the part of WPC to spend for development of the WI Properties, except as noted
herein. Such decisions may have the effect of changing the amount or timing of future
distributions to Unitholders. WPCs interests may also conflict with those of the Trust and
Unitholders in situations involving the sale or abandonment of Underlying Properties. WPC has the
right at any time to sell any of the Underlying Properties subject to the Royalty Interests and
under certain circumstances may abandon any of the WI Properties. Such sales or abandonment may
not be in the best interest of the Trust. In addition, prior to the expiration of the Gas Purchase
Contract on the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests
by the Trust, WPX Gas Resources has the right, exercisable in its sole discretion, to terminate its
Minimum Purchase Price commitment under the Gas Purchase Contract. Williams interests could
conflict with those of the Trust and Unitholders to the extent the interests of WPX Gas Resources,
under the Gas Purchase Contract, or WFS and WPX Gas Resources, under the Gas Gathering Contract,
differ from the interests of the Trust and the Unitholders. Except for amendments to the Gas
Gathering Contract or Gas Purchase Contract that must be approved by the vote of a majority of the
Unitholders present at a meeting at which a quorum is present if such amendment would materially
adversely affect Trust revenues, no mechanism or procedure has been included to resolve potential
conflicts of interest between the Trust, Williams, WPC or their affiliates.
Item 14. Principal Accounting Fees and Services.
Fees for services performed by Ernst & Young LLP for the years ended December 31, 2009 and
2008 are:
2009 | 2008 | |||||||
Audit Fees |
$ | 171,000 | $ | 168,400 | ||||
Audit-Related Fees |
$ | 0 | $ | 0 | ||||
Tax Fees |
$ | 0 | $ | 0 | ||||
All Other Fees |
$ | 0 | $ | 0 |
The Trust has no audit committee, and as a result, has no audit committee pre-approval policy
with respect to fees paid to Ernst & Young LLP.
59
PART IV
Item 15. | Exhibits and Financial Statement Schedules. |
(a) The following documents are filed as a part of this report:
1. Financial Statements (included in Item 8 of this report)
Page In This | ||||
Report | ||||
Report of Independent Registered Public Accounting Firm |
46 | |||
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2009 and 2008 |
47 | |||
Statements of Distributable Income for each of the three years in the period ended |
47 | |||
December 31, 2009 |
||||
Statements of Changes in Trust Corpus for each of the three years in the period ended |
47 | |||
December 31, 2009 |
||||
Notes to Financial Statements |
48-55 |
2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions under which
they are required or because the required information is included in the financial statements and
notes thereto.
3. Exhibits
Exhibit | ||||
Number | Exhibit | |||
3.1
|
| Certificate of Trust of Williams Coal Seam Gas Royalty Trust (filed as Exhibit 3.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
4.1
|
| Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of December 1, 1992, by and among Williams Production Company, The Williams Companies, Inc. and Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), as trustees (filed as Exhibit 4.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
4.2
|
| First Amendment to the Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of December 15, 1992, by and among Williams Production Company, The Williams Companies, Inc., Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 4.2 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
4.3
|
| Second Amendment to the Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of January 12, 1993, by and among Williams Production Company, The Williams Companies, Inc., Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 4.3 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). |
60
Exhibit | ||||
Number | Exhibit | |||
4.4
|
| Net Profits Conveyance effective as of October 1, 1992, by and among Williams Production Company, The Williams Companies, Inc., and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), and Chemical Bank Delaware (filed as Exhibit 4.4 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.1
|
| Administrative Services Agreement effective December 1, 1992, by and between The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.2
|
| Gas Purchase Agreement dated October 1, 1992, by and between Williams Gas Marketing Company and Williams Production Company (filed as Exhibit 10.2 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.3
|
| First Amendment to the Gas Purchase Agreement effective January 12, 1993, by and between Williams Gas Marketing Company and Williams Production Company (filed as Exhibit 10.3 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.4
|
| Gas Gathering and Treating Agreement effective October 1, 1992, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.4 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.5
|
| First Amendment to the Gas Gathering and Treating Agreement effective as of January 12, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.5 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.6
|
| Amendment #2 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.6 to the Registrants Form 10-K for the year ended December 31, 1993 and incorporated herein by reference). | ||
10.7
|
| Amendment #3 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.7 to the Registrants Form 10-K for the year ended December 31, 1993 and incorporated herein by reference). | ||
10.8
|
| Confirmation Agreement effective as of May 1, 1995 by and among Williams Production Company, The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrants Form 10-Q for the quarter ended June 30, 1995 and incorporated herein by reference). | ||
10.9
|
| Commission and Exclusive Agency Agreement dated as of March 18, 2010 by and between Bank of America, N.A. and Albrecht & Associates, Inc. | ||
23.1
|
| Consent of Ernst & Young LLP. | ||
23.2
|
| Consent of Miller and Lents, Ltd. | ||
31.1
|
| Certification by Ron E. Hooper, Senior Vice President and Administrator of Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 31, 2010, and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
61
Exhibit | ||||
Number | Exhibit | |||
32.1
|
| Certificate by Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 31, 2010, and submitted pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
99.1
|
| The information under the section captioned Tax Considerations on pages 20-21, and the information under the sections captioned Federal Income Tax Consequences and ERISA Considerations on pages 45-52 of the Prospectus dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662) (filed as Exhibit 28.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
99.2
|
| Reserve Report, dated November 21, 1992, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of October 1, 1992, prepared by Miller and Lents, Ltd., independent petroleum engineers, included as Exhibit A of the Prospectus dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662) (filed as Exhibit 28.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
99.3
|
| Reserve Report, dated February 12, 2010 estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of December 31, 2009, prepared by Miller and Lents, Ltd., independent petroleum engineers. |
62
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
Williams Coal Seam Gas Royalty Trust |
||||
By: | Bank of America, N.A., Trustee | |||
By: | /s/ Ron E. Hooper | |||
Ron E. Hooper | ||||
Date: March 31, 2010 | Senior Vice President and Administrator | |||
(The Registrant has no directors or executive officers.)
63
INDEX TO EXHIBITS
Exhibit | ||||
Number | Description | |||
3.1
|
___ | Certificate of Trust of Williams Coal Seam Gas Royalty Trust (filed as Exhibit 3.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
4.1
|
___ | Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of December 1, 1992, by and among Williams Production Company, The Williams Companies, Inc. and Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), as trustees (filed as Exhibit 4.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
4.2
|
___ | First Amendment to the Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of December 15, 1992, by and among Williams Production Company, The Williams Companies, Inc., Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 4.2 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
4.3
|
___ | Second Amendment to the Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of January 12, 1993, by and among Williams Production Company, The Williams Companies, Inc., Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 4.3 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
4.4
|
___ | Net Profits Conveyance effective as of October 1, 1992, by and among Williams Production Company, The Williams Companies, Inc., and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), and Chemical Bank Delaware (filed as Exhibit 4.4 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.1
|
___ | Administrative Services Agreement effective December 1, 1992, by and between The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.2
|
___ | Gas Purchase Agreement dated October 1, 1992, by and between Williams Gas Marketing Company and Williams Production Company (filed as Exhibit 10.2 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.3
|
___ | First Amendment to the Gas Purchase Agreement effective January 12, 1993, by and between Williams Gas Marketing Company and Williams Production Company (filed as Exhibit 10.3 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.4
|
___ | Gas Gathering and Treating Agreement effective October 1, 1992, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.4 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.5
|
___ | First Amendment to the Gas Gathering and Treating Agreement effective as of January 12, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.5 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
10.6
|
___ | Amendment #2 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.6 to the Registrants Form 10-K for the year ended December 31, 1993 and incorporated herein by reference). |
64
Exhibit | ||||
Number | Description | |||
10.7
|
___ | Amendment #3 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.7 to the Registrants Form 10-K for the year ended December 31, 1993 and incorporated herein by reference). | ||
10.8
|
___ | Confirmation Agreement effective as of May 1, 1995 by and among Williams Production Company, The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrants Form 10-Q for the quarter ended June 30, 1995 and incorporated herein by reference). | ||
10.9
|
| Commission and Exclusive Agency Agreement dated as of March 18, 2010 by and between Bank of America, N.A. and Albrecht & Associates, Inc. | ||
23.1
|
___ | Consent of Ernst & Young LLP. | ||
23.2
|
___ | Consent of Miller and Lents, Ltd. | ||
31.1
|
___ | Certification by Ron E. Hooper, Senior Vice President and Administrator of Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 31, 2010, and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
32.1
|
___ | Certificate by Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 31, 2010, and submitted pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
99.1
|
___ | The information under the section captioned Tax Considerations on pages 20-21, and the information under the sections captioned Federal Income Tax Consequences and ERISA Considerations on pages 45-52 of the Prospectus dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662) (filed as Exhibit 28.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
99.2
|
___ | Reserve Report, dated November 21, 1992, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of October 1, 1992, prepared by Miller and Lents, Ltd., independent petroleum engineers, included as Exhibit A of the Prospectus dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662) (filed as Exhibit 28.1 to the Registrants Form 10-K for the year ended December 31, 1992 and incorporated herein by reference). | ||
99.3
|
___ | Reserve Report, dated February 12, 2010, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of December 31, 2009, prepared by Miller and Lents, Ltd., independent petroleum engineers. |
65