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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[x] Annual Report Pursuant to Section 13 or 15 (d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 2003
[ ] Transition Report Pursuant to Section 13 of 15(d) of the
Securities Exchange Act of 1934
For the transition period from ________ to _________.
Commission File Number: 0 - 13305
PARALLEL PETROLEUM CORPORATION
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(Exact Name of Registrant as Specified in its Charter)
Delaware 75-1971716
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(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
1004 N. Big Spring, Suite 400
Midland, Texas 79701
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(Address of Principal Executive Offices (Zip Code)
Registrant's Telephone Number, Including Area Code: (432) 684-3727
Securities Registered Pursuant to Section 12(b) of the Act: None
Securities Registered Pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
Common Stock Purchase Warrants
Rights to Purchase Series A Preferred Stock
(Title of Class)
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 X No
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Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's 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. [ ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2).
Yes No X
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The aggregate market value of voting and non-voting common equity held
by non-affiliates of the Registrant as of June 30, 2003 was approximately
$71,608,313, based on the last sale price of the common stock on the same date.
At March 1, 2004 there were 25,224,005 shares of common stock
outstanding.
FORM 10-K
PARALLEL PETROLEUM CORPORATION
TABLE OF CONTENTS
Item No.
PART I
Item 1. Business .........................................................1
Item 2. Properties.......................................................35
Item 3. Legal Proceedings................................................38
Item 4. Submission of Matters to a Vote of Security Holders..............38
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities...................39
Item 6. Selected Financial Data..........................................41
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.........................43
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk...........................................62
Item 8. Financial Statements and Supplementary Data......................64
Item 9. Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure..........65
Item 9A. Controls and Procedures..........................................66
PART III
Item 10. Directors and Executive Officers of the Registrant...............67
Item 11. Executive Compensation...........................................73
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters .............82
Item 13. Certain Relationships and Related Transactions ..............85
Item 14. Principal Accountant Fees and Services...........................86
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K.................................................87
(i)
Cautionary Statement Regarding Forward Looking Statements
Some statements contained in this Annual Report on Form 10-K are
"forward-looking statements". All statements other than statements of historical
facts included in this report, including, without limitation, statements
regarding planned capital expenditures, the availability of capital resources to
fund capital expenditures, estimates of proved reserves, our financial position,
business strategy and other plans and objectives for future operations, are
forward-looking statements. You can identify forward-looking statements by the
use of forward-looking terminology like "may," "will," "expect," "intend,"
"anticipate," "budget", "estimate," "continue," "present value," "future" or
"reserves" or other variations or comparable terminology. We believe the
assumptions and expectations reflected in these forward-looking statements are
reasonable. However, we cannot give any assurance that our expectations will
prove to be correct or that we will be able to take any actions that are
presently planned. All of these statements involve assumptions of future events
and risks and uncertainties. Risks and uncertainties associated with
forward-looking statements include, but are not limited to:
. fluctuations in prices of oil and gas;
. future capital requirements and availability of financing;
. geological concentration of our reserves;
. risks associated with drilling and operating wells;
. competition;
. general economic conditions;
. governmental regulations;
. receipt of amounts owed to us by purchasers of our production and
counterparties to our hedging contracts;
. hedging decisions, including whether or not to hedge;
. events similar to 911;
. actions of third party co-owners of interests in properties in
which we also own an interest; and
. fluctuations in interest rates and availability of capital.
For these and other reasons, actual results may differ materially from
those projected or implied. We caution you against putting undue reliance on
forward-looking statements or projecting any future results based on such
statements.
Before you invest in our common stock, you should be aware that there
are various risks associated with an investment. We have described some of these
risks in other sections of this Annual Report and under "Risks Related to Our
Business" beginning on page 21.
(ii)
PART I
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ITEM 1. BUSINESS
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About Our Company
Parallel Petroleum Corporation is engaged in the acquisition,
development, exploitation and production of oil and natural gas and, to a lesser
extent, the domestic exploration for oil and natural gas. These activities are
concentrated in three core areas:
. the Permian Basin of west Texas and New Mexico;
. Liberty County in east Texas; and
. the onshore gulf coast area of south Texas.
In 2003, we spent approximately $14.9 million on oil and gas related
capital expenditures, a decrease of approximately 76% over that expended in
2002. See Note 3 to the Financial Statements. In December 2002, we acquired
producing oil and gas properties located in Andrews County, Texas for a total of
$46.1 million.
Throughout this report, we refer to some terms that are commonly used
and understood in the oil and gas industry. These terms are:
. Mcf - thousand cubic feet of natural gas;
. MMcf - million cubic feet of natural gas;
. Bcf - billion cubic feet of natural gas;
. Bbls - barrels of oil or other liquid hydrocarbons;
. MBbl - thousand barrels of oil or other liquid hydrocarbons;
. BOE - equivalent barrel of oil or 6 Mcf of natural gas for one
barrel of oil; and
. MBOE - thousand BOE.
Parallel was incorporated in Texas on November 26, 1979, and
reincorporated in the State of Delaware on December 18, 1994.
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Our executive offices are located at 1004 N. Big Spring, Suite 400,
Midland, Texas 79701. Our telephone number is (432) 684-3727.
Available Information
You may read and copy any materials we file with the SEC at the SEC's
Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may
obtain information on the operation of the Public Reference Room by calling the
SEC at 1-800-SEC-0330. The SEC maintains an Internet site (http://www.sec.gov)
that contains reports, proxy and information statements, and other information
regarding issuers, including Parallel, that file electronically with the SEC.
Our Internet address is http://www.parallel-petro.com.
We make available free of charge on our Internet website our annual
reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form
8-K, and amendments to those reports filed or furnished pursuant to Section
13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably
practicable after we electronically file such material with, or furnish it to,
the SEC.
We will provide electronic or paper copies of our SEC filings free of
charge upon request made to: Cindy Thomason, Manager of Investor Relations,
cindyt@parallel-petro.com, 1-800-299-3727.
Recent Developments
On December 23, 2003 we completed a private placement of 4.0 million
shares of common stock at a price of $3.25 per share for total gross proceeds of
$13.0 million before offering expenses.
On November 25, 2003, our Board of Directors approved in principle the
adoption of an employee retention/severance plan that will become effective
January 1, 2004. The aggregate payments to all officers and employees will
generally be 5% of an amount equal to the positive difference between the amount
by which our net asset value per share at the time of the occurrence of a change
of control exceeds the net asset value per share as of January 1, 2004,
compounded annually at a rate equal to the annual industry average growth rate,
plus 2%. Generally, we contemplate that a "change in control" will include
events such as a merger, reorganization, liquidation or sale of substantially
all of the assets of Parallel, or the acquisition by a third party of 50% or
more of our outstanding voting securities.
Proved Reserves as of December 31, 2003
Cawley Gillespie & Associates, Inc., an independent engineering firm,
estimated the total proved reserves attributable to all of our oil and gas
properties to be 12.1 million Bbls of oil and 16.3 Bcf of natural gas as of
December 31, 2003. Based on oil and gas prices at December 31, 2003 and current
operating and development costs, the present value of our pretax future net
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revenues from these properties, discounted at 10%, was estimated to be
approximately $147.8 million as of December 31, 2003.
Approximately 82% of our proved reserves are oil and approximately 74%
are categorized as proved developed reserves.
About Our Strategy and Business
From 1993 until mid 2002, our activities were concentrated in the
onshore gulf coast area of south Texas. In June, 2002 we reexamined and revised
our business strategy. We shifted the balance of our investments from properties
having high rates of production in early years to properties with more
consistent production over a longer term. We now emphasize reducing drilling
risks by dedicating a smaller portion of our capital to high risk projects,
while reserving the majority of our available capital for exploitation,
enhancement and development drilling opportunities. Obtaining positions in
long-lived oil and gas reserves is given priority over properties that might
provide more cash flow in the early years of production, but which have shorter
reserve lives. Our risk reduction efforts also include emphasizing acquisition
possibilities over high risk exploration projects.
Since the latter part of 2002, we have reduced the emphasis on high
risk exploration efforts and we now focus on established geologic trends where
we can utilize the engineering, operational, financial and technical expertise
of our entire staff. Although we will continue to participate in exploratory
drilling activities from time to time, reducing financial, reservoir, drilling
and geological risks and diversifying our property portfolio are the principal
criteria in the execution of our business plan.
In summary, our current business plan:
. focuses on projects having less geological risk;
. emphasizes exploitation and enhancement activities;
. focuses on acquiring producing properties; and
. expands the scope of our operations by diversifying our
exploratory and development efforts, both in and outside of our
current areas of operation.
An integral part of our business strategy includes exploitation and
enhancement activities. Exploitation and enhancement activities include:
. operational enhancements, such as surface facility
reconfiguration, and the installation of new or additional
compression equipment;
. workovers;
. well recompletions;
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. behind-pipe recompletions;
. refracing (restimulating a producing formation within an existing
wellbore to enhance production and add reserves);
. installation of injection wells and related facilities;
. development well drilling (infill drilling);
. cost reduction programs; and
. secondary recovery operations, including waterfloods.
When we initiate exploitation and enhancement activities on our
existing producing properties, we first establish and maintain an ongoing
program of oil and gas well reviews with the objective of maximizing the output
of existing wells. Oil and gas wells usually generate their highest volumes
during the earlier stages of production after which production begins to
decline. Enhancement and remedial work can be undertaken to restore varying
amounts of the lost production or reduce the rate of production decline.
Our approach to producing property acquisitions, and the size and
timing of any acquisition, is dependent upon market conditions in the domestic
oil and gas industry. Generally, during periods of moderate to high prices for
oil and gas, we believe that oil and gas acquisition opportunities are not as
favorable to a prospective purchaser as they are when market conditions are
depressed.
Producing properties that we identify and attempt to acquire will
include properties that have proved undeveloped and behind-pipe reserves,
operational enhancement potential, long-lived reserves, multiple pay-zone
exploitation and development drilling opportunities, and the potential for
operating control. Selecting and acquiring producing properties having these
characteristics will diversify and improve the quality of our property
portfolio.
Although purchases of producing properties involve less risk than
drilling, there is a risk that estimates of future prices or costs, reserves,
production rates or other criteria upon which we have based our investment
decision may prove to be inaccurate.
In addition to acquisitions of producing properties, our business
strategy also includes seeking opportunities to negotiate and enter into work to
earn, joint venture and similar agreements with third parties for development
operations on producing properties.
Our sources for possible acquisitions of leases and prospects include
independent landmen, independent oil and gas operators, geologists and
engineers. We also evaluate properties that become available for purchase from
major oil companies. If our review of an undeveloped lease or prospect or a
producing property indicates that it may have geological characteristics
favorable for 3-D seismic analysis, we may decide to acquire a working interest
in
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the property or an option to acquire a working interest. In the case of
producing properties, we also seek properties that we believe are
underperforming relative to their potential. To reduce our financial exposure in
any one prospect, we may enter into co-ownership arrangements with third
parties. These arrangements are common in the industry and enable us to
participate in more prospects and share the drilling and related costs and
dry-hole risks with other participants. From time to time, we sell prospects to
third parties or farm-out prospects and retain an interest in revenues from
these prospects.
As we have in the past, we will continue to:
(1) Use Advanced Technologies. We believe the use of 3-D seismic
surveys and other advanced technologies provides us with a risk management tool.
We believe that our use of these technologies in exploring for and developing
oil and gas properties can:
. reduce drilling risks;
. lower finding costs;
. provide for more efficient production of oil and natural gas from
our properties; and
. increase the probability of locating reserves that might not
otherwise be discovered.
Generally, 3-D seismic surveys provide more accurate and comprehensive
information to evaluate drilling prospects than conventional 2-D seismic
technology. We evaluate substantially all of our exploratory prospects using 3-D
seismic technology. On some exploratory prospects, we also use amplitude versus
offset, or AVO analysis. AVO analysis shows the high contrast between sands and
shales and assists in determining the presence of natural gas in potential
reservoir sands.
We believe that using 3-D seismic, AVO and other technologies gives us
a competitive advantage because of the increased likelihood of successful
drilling. When we evaluate exploratory prospects in geographical areas where the
use of 3-D seismic and other advanced technologies are not likely to provide any
advantages, we use traditional evaluation methods, such as 2-D seismic
technology.
(2) Serve as Geophysical Operator. We prefer to serve as the
geophysical operator on projects located in areas where we have experience using
3-D seismic technology. By doing so, we control the design, acquisition,
processing and interpretation of 3-D surveys and, in most cases, determine
drilling locations and well depths. The integrity of 3-D seismic analysis in our
projects is enhanced by emphasizing quality controls throughout the data
acquisition, processing and interpretation phases.
We retain experienced outside consultants and participate with
knowledgeable joint working interest owners when we acquire, process and
interpret 3-D seismic surveys. When
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possible, we also attempt to correlate or model the interpretations of 3-D
seismic surveys with wells previously drilled on or near the prospect being
evaluated.
(3) Conduct Exploratory Activities. Although we do not intend to
emphasize exploratory drilling to the extent we have in the past, when we do
undertake exploratory projects, we will continue to focus on prospects:
. having known geological and reservoir characteristics;
. being in close proximity to existing wells so data from the
existing wells can be correlated with seismic data on or near the
prospect being evaluated; and
. having a potentially meaningful impact on our reserves.
When economic conditions are favorable and when we have sufficient
capital resources, we believe we can maximize the value of our properties by
accelerating drilling activities. This provides us an opportunity to replace
reserves at a more rapid pace than existing reserves are produced.
Drilling, Production and Other Activities in 2003
2003 Drilling Activity
Number of Number of Wells
Gross Waiting on Completion Gross Gross
Area Depth Range (feet) Wells Drilled at December 31, 2003 Productive Wells Dry Wells
- --------------------------------- ---------------------- --------------- ---------------------- ----------------- -----------
North Texas
Barnett Shale 7,000 - 8,000 1 1 - -
Permian Basin
Abo Gas 4,300 - 4,500 1 1 - -
Diamond M (Shallow) 2,400 - 3,500 3 - 3 -
East Texas
Cook Mountain 11,000 - 15,000 5 - 2 3
Onshore Gulf Coast of Texas
Yegua 6,300 - 13,000 0 - - -
Shallow Frio 3,000 - 6,300 14 4 6 4
Deep Frio 8,000 - 11,000 2 1 - 1
Other 6,000 - 6,000 1 - - 1
------- -------- ------- -------
27 7 11 9
======= ======== ======= =======
From 1993 until mid 2002, we concentrated our activities in the
Yegua/Frio/Wilcox gas trends in the onshore Gulf Coast area of south Texas in
Dewitt, Jackson, Lavaca, Victoria and Wharton Counties. Substantially all of our
drilling success in south Texas has been in the Yegua/Frio gas trend and we
intend to continue drilling additional lower risk 3-D seismic development wells
in this trend. Although the successful wells we drilled in the Yegua/Frio trend
provided quick payouts of our drilling and completion costs, the reserve lives
of the properties in this area have proven to be very short as compared to our
properties in the Permian Basin.
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As we announced in October 2003, consistent with our strategy of
reducing geologic risk, we began to diversify our exploration efforts into other
oil and gas trends. However, and as planned, the majority of our drilling in
2003 was in south and east Texas.
We believe we can more fully develop our existing producing properties
in the Permian Basin of west Texas, which have been proven by previous drilling.
Collectively, our Permian Basin properties include approximately 39,000 gross
(29,000 net) developed acres, which will provide significant exploitation and
development opportunities for both oil and gas. Additionally, our Permian Basin
properties have longer reserve lives than our South Texas properties. Our
exploitation and enhancement efforts are conducted primarily on our properties
in the Permian Basin of west Texas. We own working interests in these properties
ranging from 15.0% to 100%.
During 2003, our Permian Basin activities included:
. recompleting existing wellbores;
. restimulating producing reservoirs;
. identifying potential infill drilling locations;
. making mechanical improvements to surface facilities and downhole
equipment; and
. reviewing the feasibility of applying new drilling and production
technologies that could either improve recovery potential or
result in the discovery of a new reservoir.
As part of our remedial and enhancement operations in the Permian
Basin, we routinely review the performance and economics of our oil and gas
properties and, from time to time, we may also renegotiate gas purchase
contracts or reconfigure gathering lines. When necessary, we take corrective
action, such as:
. shutting in temporarily uneconomic properties;
. plugging wells we believe to be permanently impaired or depleted;
. terminating oil and gas leases that are uneconomic under existing
operating conditions; and/or
. selling properties to third parties.
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Drilling and Acquisition Costs
The table below shows our oil and gas property acquisition, exploration
and development costs for the periods indicated.
Year Ended December 31,
--------------------------------------------------------------------
2003 2002 2001 2000(1) 1999(1)
------------ ------------ ------------ ------------ ------------
(in thousands)
Transfers from (to) undeveloped
eases held for sale(1) $ - $ - $ - $ 2,128 $ (2,128)
Proved property acquisition costs 2,209 48,044 27 23 42
Unproved property acquisition costs 3,831 2,295 3,420 3,372 1,979
Exploration costs 3,240 1,291 6,820 2,163 1,856
Development costs 5,650 9,308 1,203 1,087 639
-------- -------- -------- -------- --------
$ 14,930 $ 60,938 $ 11,470 $ 8,773 $ 2,388
======== ======== ======== ======== ========
__________
(1) Reflects costs associated with assets being held for sale in 1999 and
transferred back to oil and gas property in 2000. Actual capital
expenditures during 2000 and 1999, excluding transfers, were approximately
$6.6 million and $4.5 million, respectively.
Capital Investments for 2004
Our 2004 capital investment budget for properties we owned at March 1,
2004 is estimated to be approximately $17.0 million, which includes less than
$1.0 million for the purchase of undeveloped leasehold acreage in our areas of
activity. The budget will be funded from our estimated operating cash flows,
which is based on anticipated commodity prices and forecasted production
volumes. The amount and timing of expenditures are subject to change based upon
market conditions, results of expenditures, new opportunities and other factors.
On a geographic basis, approximately 59% of our projected 2004 capital
investment program will be directed toward oil and gas reserves in the Permian
Basin, 24% to gas reserves in east Texas and in the Yegua/Frio/Wilcox gas trend
onshore the Gulf Coast area of south Texas, 15% for north Texas Barnett Shale
gas project, and 2% to other projects.
Permian Basin of West Texas
The Permian Basin of west Texas generated approximately 57% of our 2003
production and represented approximately 84% of our reserve value as of
December 31, 2003. Our significant producing properties in the Permian
Basin are described below.
. Fullerton Field, Andrews County -We acquired this non-operated
property in December 2002 and it represented approximately 37% of
our 2003 production and 57% of our reserve value as of December
31, 2003. Production is from the San Andres formation at a depth
of 4,400 feet and consists of 128 producing wells supported by 80
water injection wells located on nine contiguous leases
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containing approximately 3,640 gross acres.
A total of 41 water-frac stimulations were performed during the
period from mid-February 2003 through the end of January 2004. We
have accelerated activity to two refracs per week and expect to
refrac an additional 80 wells through the end of 2004.
We are also evaluating the potential for infill drilling the
San Andres formation at a depth of approximately 4,500 feet.
Our working interest in these properties ranges from 25% to 85%.
We have budgeted approximately $2.0 million, net to our interest,
for this project in 2004.
. Diamond M Shallow Leases, Scurry County - This operated property
was acquired in December, 2001. It represented less than 1% of
our 2003 production and approximately 8% of our reserve value as
of December 31, 2003. Eight shallow leases comprise approximately
2,600 gross productive acres in the Glorietta, Clearfork and
Wichita Albany intervals, which range in depth from 2,450 feet to
4,000 feet. Prior to our acquisition of this property, these
intervals had produced approximately 4.0 million barrels of oil
from a total of 130 wells on 20 acre spacing and a random
waterflood pattern.
In January 2004, we commenced a 30 well infill drilling program
that we expect to complete by the fourth quarter of 2004.
Depending upon the results of this program, we presently
anticipate drilling approximately 60 additional wells prior to
the end of 2005. We anticipate that we will spend on this
project, net to our 66% working interest, approximately $19.0
million over the next three years, $6.5 million of which is
budgeted for 2004.
. Lion Diamond M Canyon Unit, Scurry County - This operated
property includes the same surface acreage as our Diamond M
Shallow leases and is in its early stage of development. It
generated approximately 4% of our 2003 production and represented
approximately 3% of our reserve value as of December 31, 2003.
The Lion Diamond M Canyon Unit consists of approximately 5,500
gross acres in the Canyon Reef formation at a depth of
approximately 6,700 feet, and is located between the Kinder
Morgan, Inc. operated SACROC Unit to the north and the ExxonMobil
Corporation operated Sharon Ridge Unit to the south. The SACROC
Unit and Sharon Ridge Unit were both discovered in 1948 and have
produced approximately 1.3 billion barrels of oil and 250.0
million barrels of oil, respectively. The Lion Diamond M Canyon
Unit, also discovered in 1948, has produced 44.0 million barrels
of oil. Most of the original 145 wells initially penetrated only
the top 50 feet of the reef, with deeper evaluation accomplished
through a limited number of well deepenings. The unit was pumping
a total of 150 barrels of oil per day from 15 producing wells
prior to commencement of our operations and is currently spaced
on 40 acre proration units.
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We have identified 42 mechanically viable Canyon Reef wells as
deepening candidates. The first two of these workovers have
recently been completed. Both wells were deepened approximately
150 feet. The combined current production rate of the two wells
has stabilized at approximately 50 gross (30 net) BOE per day. We
are currently expanding the field's injection and facility fluid
handling capacity to accommodate increased volumes from future
workovers.
We are also preparing to shoot a 3-D seismic survey utilizing
both compressional and shear wave technology. We anticipate that
we will spend on this project, net to our 66% working interest,
approximately $8.0 million over the next three years, of which
$1.0 million is budgeted for 2004. However, this program and our
expenditures could be accelerated if future deepenings exceed our
current economic model.
Onshore Gulf Coast of South Texas
This area generated approximately 27% of our 2003 production and
represented approximately 12% of our reserve value as of December 31, 2003.
From 1993 to June 2002, this area had been our primary focus. However,
because of the high decline rate and short-lived reserves, we are
decreasing our re-investment in this area and are now re-deploying a
majority of the cash flow from this area to the acquisition, development
and exploitation of longer-lived oil and natural gas reserves.
. Yegua/Frio Gas Project, Jackson and Wharton Counties - This
non-operated project primarily focuses on natural gas production
from the Yegua and Frio trends at depths ranging from 3,000 feet
to 16,000 feet. A new deep Frio prospect well, the Cornelius No.
1, is currently drilling to a projected depth of 16,000 feet. Our
working interest in the well is approximately 20%.
We have approximately 3 Yegua and 7 Frio 3-D seismic natural gas
prospects remaining to be drilled. We expect drilling operations
on 1 Yegua prospect to begin in the second quarter of 2004. Our
working interest in the well is approximately 30%. We have
budgeted $2.0 million, net to our interest, for the drilling of
these prospects, the majority of which will be spent in 2004.
East Texas
. Cook Mountain Gas Project, Liberty County - We commenced this
non-operated project in 2002 and it represented approximately 13%
of our 2003 production and 3% of our reserve value as of December
31, 2003. We have participated in eight Cook Mountain natural gas
wells, five of which have been successful.
We have approximately 5 additional 3-D seismic Cook Mountain
natural gas prospects remaining to be drilled. We have revised
the budget and plan to spend $1.0 million for the drilling of
these prospects, the majority of which will be spent in 2004.
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New Undeveloped Projects
All four of the following new projects have been acquired since June
2002 and no production or proved reserves have been recognized on these
projects as of December 31, 2003.
. North Texas Barnett Shale Gas Project, Tarrant County - We
acquired our initial interest in this non-operated project in
April 2003 and drilled an initial well in May 2003. We are in the
process of acquiring additional leasehold on the project and
drilling activity is anticipated to resume during the third
quarter of 2004. Our current leasehold on the project is
approximately 5,000 gross acres with natural gas targets at a
depth of approximately 8,000 feet. We anticipate that we will
spend on this project, net to our 28% working interest,
approximately $16.0 million over the next three years, of which
$2.5 million is budgeted for 2004.
. Utah Oil and Gas Project - We have increased our acreage position
in this project to approximately 125,000 gross acres. It is a
multiple zone project consisting of both oil and natural gas
targets at a depth of less than 6,000 feet. We continue to build
our leasehold position and geological data base. We expect to
spud the first exploratory well in this project as early as the
third quarter of 2004. We own and operate 100% of this project
and estimate that the cost to drill and complete a well will be
approximately $0.5 million. Our budget on this project for 2004
is approximately $0.5 million.
. New Mexico Gas Project - This non-operated project consists of
approximately 50,000 gross acres with the primary target being
the Abo formation at a depth of approximately 5,000 feet. The Abo
formation is a known natural gas-producing reservoir but
historically has been marginally economic due to low per-well
producing rates and low natural gas prices.
Since December 2003, we have participated in three Abo formation
natural gas wells that have been drilled and are in the process
of being completed. We expect this project to become commercial
because of the application of new horizontal drilling and
hydraulic fracture stimulation technologies. Depending on
production results, we expect accelerated development in 2004 of
this potential long-life natural gas project. Our working
interest in the project is approximately 8.5%. Our budget on this
project for 2004 is approximately $0.5 million.
. Cotton Valley Reef Gas Project, Texas - We acquired an interest
in this non-operated 3-D seismic natural gas project in November
2003. The objective is the Cotton Valley barrier reef facies
found between the depths of 16,000 and 18,000 feet on the flank
of the east Texas Basin as it existed in the Jurassic time.
Nearby, existing long-life natural gas fields, with impressive
production profiles, produce from Cotton Valley patch reef
facies; however, this project targets a much larger, seaward
barrier reef reservoir. This project consists of approximately
5,000 gross acres and the first well is expected to spud during
the second quarter of 2004. We
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have budgeted approximately $1.0 million in 2004, net to our
working interest, for the drilling of the first of nine potential
prospects within this project. Our working interest in the
remaining prospects will be approximately 12.0%.
Oil and Natural Gas Prices
Our revenues, profitability and cash flows are highly dependent on the
prices we receive for our oil and natural gas. Generally, oil and natural gas
prices improved and stabilized during the period from mid-2000 to the third
quarter of 2001, when prices began to decline. During the first quarter of 2002,
prices began to increase again and this upward trend in price has continued.
The average prices we received for the oil and natural gas we produced
in 2003, 2002 and 2001 are shown in the table below.
Average Price Received for the
Year Ended December 31,
----------------------------------------
2003 2002 2001
------------ ------------ ------------
Oil (Bbl) $ 29.11 $ 24.59 $ 24.80
Natural gas (Mcf) $ 5.40 $ 3.33 $ 4.41
The average price we received for our oil sales at March 1, 2004 was
approximately $30.92 per Bbl, excluding our hedging activities. At the same
date, the average price we were receiving for our natural gas was approximately
$5.19 per Mcf, excluding our hedging activities.
There is substantial uncertainty regarding future oil and gas prices
and we can provide no assurance that prices will remain at current levels. We
have entered into hedge contracts in an attempt to reduce the risk of
fluctuating oil and gas prices and interest rates.
In 2003, approximately 47% of our daily production was natural gas and
53% was oil.
Executive Officers of Parallel
At March 11, 2004, Parallel's executive officers were Thomas R.
Cambridge, Larry C. Oldham, Donald E. Tiffin, Eric A. Bayley, John S. Rutherford
and Steven D. Foster.
Thomas R. Cambridge, age 68, is the Chairman of the Board of Directors
of Parallel. He is an independent petroleum geologist engaged in the exploration
for, development and production of oil and natural gas. From 1970 until 1990,
such activities were carried out primarily through Cambridge & Nail Partnership,
a Texas general partnership. Since 1990, such activities have been carried out
through Cambridge Production, Inc., a Texas corporation. Mr. Cambridge has
served as a Director of Parallel since February 1985; as President and Chief
Executive Officer during the period from October 1985 to October 1994 and
October 1985 to January 2004 respectively; and as Chairman of the Board of
Directors since October 1985. He
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received a Bachelors degree in geology from the University of Nebraska in 1958
and a Masters of Science degree in 1960.
Larry C. Oldham, age 50, is a founder of Parallel. He has served as an
officer and Director since Parallel's formation in 1979. He served as Executive
Vice President until October, 1994 when he became President. As of January 1,
2004 he replaced Thomas R. Cambridge as Chief Executive Officer and continued
his current position as President. Before Parallel's formation, Mr. Oldham was
employed by Dorchester Gas Corporation from 1976 to 1979 and KPMG Peat Marwick
LLP during 1975 to 1976. He received a Bachelor of Business Administration
degree from West Texas State University in 1975. Mr. Oldham is a member of the
Permian Basin Landman's Association.
Donald E. Tiffin, age 46, served as Vice President of Business
Development from June, 2002 until January, 2004 when he became the Chief
Operating Officer of Parallel. From August, 1999 until May, 2002, Mr. Tiffin
served as General Manager of First Permian, L.P. From July, 1993 to July, 1999,
Mr. Tiffin was the Drilling and Production Manager in the Midland, Texas office
of Fina Oil and Chemical Company. Mr. Tiffin graduated from the University of
Oklahoma in 1979 with a Bachelor of Science degree in Petroleum Engineering.
Eric A. Bayley, age 55, has been Vice President of Corporate
Engineering since July, 2001. From October, 1993 until July, 2001, Mr. Bayley
was employed as Manager of Engineering. From June, 1990 to October, 1993, Mr.
Bayley was an independent consulting engineer and devoted substantially all of
his time to Parallel. Mr. Bayley graduated from Texas A&M University in 1978
with a Bachelor of Science degree in Petroleum Engineering. He graduated from
the University of Texas of the Permian Basin in 1984 with a Master's of Business
Administration degree.
John S. Rutherford, age 44, has been Vice President of Land and
Administration of Parallel since July, 2001. From October, 1993 until July,
2001, Mr. Rutherford was employed as Manager of Land/Administration. From May,
1991 to October, 1993, Mr. Rutherford served as a consultant to Parallel,
devoting substantially all of his time to Parallel's business. Mr. Rutherford
graduated from Oral Roberts University in 1982 with a degree in Education, and
in 1986 he graduated from Baylor University with a Master's degree in Business
Administration.
Steven D. Foster, age 48, has been the Chief Financial Officer of
Parallel since June, 2002. From November, 2000 to May, 2002, Mr. Foster was the
Controller and Assistant Secretary of First Permian, L.P. From September, 1997
to November 2000, he was employed by Pioneer Natural Resources, USA in the
capacities of Director of Revenue Accounting and Manager of Joint Interest
Accounting. Mr. Foster graduated from Texas Tech University in 1977 with a
Bachelor of Business Administration degree in accounting. He is a certified
public accountant.
The term of our officers expires at Parallel's annual meeting of
Directors or when their respective successors are duly elected and qualified.
There are no family relationships among our executive officers.
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Employees
In 2003, we added nine new employees. At March 1, 2004, Parallel had
twenty-four full time employees. Mr. Cambridge serves in the capacity of a
consultant and not as a full-time employee. Parallel also retains independent
land, geological, geophysical and engineering consultants and expects to
continue to do so in the future. Additionally, Parallel retains four contract
pumpers on a month-to-month basis.
We consider our employee relations to be satisfactory. None of our
employees are represented by a union and we have not experienced work stoppages
or strikes.
Wells Drilled
The following table shows certain information concerning the number of
gross and net wells we drilled during the three-year period ended December 31,
2003.
Exploratory Wells (1) Development Wells (2)
----------------------------------- -----------------------------------
Productive Dry Productive Dry
----------------- ----------------- ----------------- -----------------
Year Ended
December 31, Gross Net Gross Net Gross Net Gross Net
------------ -------- ------- -------- -------- -------- -------- -------- --------
2003 15.0 5.05 8.0 2.09 3.0 2.6 1.0 0.25
2002 12.0 3.10 3.0 0.70 4.0 2.3 - -
2001 18.0 4.10 13.0 3.41 - - - -
----------------
(1) An exploratory well is a well drilled to find and produce oil or
gas in an unproved area, to find a new reservoir in a field
previously found to be productive of oil or gas in another
reservoir, or to extend a known reservoir.
(2) A development well is a well drilled within the proved area of
an oil or gas reservoir to the depth of a stratigraphic horizon
known to be productive.
All of our drilling is performed on a contract basis by third-party
drilling contractors. We do not own any drilling equipment.
At March 3, 2004, we were participating in the completion of 7 gross
(3.68 net) gas wells in Jackson, Liberty, Scurry and Tarrant Counties, Texas and
Eddy County, New Mexico.
Volumes, Prices and Lifting Costs
The following table shows certain information about our oil and gas
production, average sales prices per Mcf of gas and Bbl of oil and the average
lifting cost per BOE for the three-year period ended December 31, 2003.
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Year Ended December 31,
----------------------------------------------
2003 2002 2001
--------------- -------------- --------------
(in thousands except per unit data)
Production, Prices and Lifting Costs:
Oil (Bbls) 629 131 138
Natural gas (Mcf) 3,356 2,670 3,266
BOE 1,188 576 682
Oil price (per Bbl)(1) $ 29.11 $ 24.59 $ 24.80
Natural gas price (per Mcf)(1) $ 5.40 $ 3.33 $ 4.41
BOE price(1) $ 30.66 $ 21.03 $ 26.13
Average Production (lifting) Cost per BOE(2) $ 7.07 $ 5.00 $ 5.74
_____________
(1) Average price received at the wellhead for our oil and natural gas.
(2) The increase in 2003 is attributable to increased lifting costs
associated with our waterflood projects.
The following summarizes our revenue for each of the three years ended
December 31 by product sold.
2003 2002 2001
------------ ------------- -------------
(in thousands)
Oil revenue $ 18,300 $ 3,217 $ 3,429
Oil hedge (1,659) - -
Gas revenue 18,121 8,889 14,411
Gas hedge (907) - -
------------ ------------- -------------
$ 33,855 $ 12,106 $ 17,840
============ ============= =============
Our gas sales in 2003 represented approximately 50% of our combined oil
and gas sales for the year ended December 31, 2003 as compared to 73% in 2002.
Markets and Customers
Our oil and gas production is sold at the well site on an as produced
basis at market- related prices in the areas where the producing properties are
located. We do not refine or process any of the oil or natural gas we produce
and all of our production is sold to unaffiliated purchasers on a month-to-month
basis.
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In the table below, we show the purchasers that accounted for 10% or
more of our revenues during the specified years.
2003 2002 2001
------------- ------------ ------------
Allegro Investments, Inc. 30% 31% 38%
Pure Resources, Inc. - 16% 23%
Sue Ann Production - 11% 25%
Texland Petroleum, Inc. 33% - -
We do not believe the loss of any one of our purchasers would
materially affect our ability to sell the oil and gas we produce. Other
purchasers are available in our areas of operations.
Our future ability to market our oil and gas production depends upon
the availability and capacity of gas gathering systems and pipelines and other
transportation facilities. We do not currently own or operate our own pipelines
or transportation facilities. We are dependent on third parties to transport our
products.
We are not obligated to provide a fixed and determinable quantity of
oil or natural gas under any existing arrangements or contracts.
Our business does not require us to maintain a backlog of products,
customer orders or inventory.
Office Facilities
Our principal executive offices are located in Midland, Texas, where we
lease approximately 14,882 square feet of office space at 1004 North Big Spring,
Suite 400, Midland, Texas 79701. Our current rental rate is $8,931 per month. In
December 2003, we amended our lease to add an additional 6,758 square feet of
space. Commencing August 1, 2004, the total monthly rental rate for our office
space will be $13,474. The lease expires August 31, 2006. From January through
May, 2003, we continued to make monthly lease payments of $4,489 for our former
office space. The lease agreement was terminated May 31, 2003.
Competition
The oil and gas industry is highly competitive, particularly in the
areas of acquiring exploration and development prospects and producing
properties. The principal means of competing for the acquisition of oil and gas
properties are the amount and terms of the consideration offered. Our
competitors include major oil companies, independent oil and gas firms and
individual producers and operators. Many of our competitors have financial
resources, staffs and facilities much larger than ours.
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We are also affected by competition for drilling rigs and the
availability of related equipment. With relatively high oil and gas prices, the
oil and gas industry typically experiences shortages of drilling rigs,
equipment, pipe and qualified field personnel. We are unable to predict when or
to what extent our exploration and development activities will be affected by
rig, equipment or personnel shortages.
Intense competition among independent oil and gas producers requires us
to react quickly to available exploration and acquisition opportunities. We try
to position for these opportunities by maintaining:
. adequate capital resources for projects in our primary areas of
operations;
. the technological capabilities to conduct a thorough evaluation
of a particular project; and
. a small staff that can respond quickly to exploration and
acquisition opportunities.
The principal resources we need for acquiring, exploring, developing,
producing and selling oil and gas are:
. leasehold prospects under which oil and gas reserves may be
discovered;
. drilling rigs and related equipment to explore for such reserves;
and
. knowledgeable and experienced personnel to conduct all phases of
oil and gas operations.
Oil and Gas Regulations
Our operations are regulated by certain federal and state agencies. Oil
and gas production and related operations are or have been subject to:
. price controls;
. taxes; and
. environmental and other laws relating to the oil and gas
industry.
We cannot predict how existing laws and regulations may be interpreted
by enforcement agencies or court rulings, whether additional laws and
regulations will be adopted, or the effect such interpretations or new laws and
regulations may have on our business, financial condition or results of
operations.
Our oil and gas exploration, production and related operations are
subject to extensive rules and regulations that are enforced by federal, state
and local agencies. Failure to comply with these rules and regulations can
result in substantial penalties. The regulatory burden on the oil and gas
industry increases our cost of doing business and affects our profitability.
Because
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these rules and regulations are frequently amended or reinterpreted, we
are not able to predict the future cost or impact of compliance with these laws.
Texas and many other states require drilling permits, bonds and
operating reports. Other requirements relating to the exploration and production
of oil and gas are also imposed. These states also have statutes or regulations
addressing conservation matters, including provisions for:
. the unitization or pooling of oil and gas properties;
. the establishment of maximum rates of production from oil and gas
wells; and
. the regulation of spacing, plugging and abandonment of wells.
Sales of natural gas we produce are not regulated and are made at
market prices. However, the Federal Energy Regulatory Commission regulates
interstate and certain intrastate gas transportation rates and services
conditions, which affect the marketing of our gas, as well as the revenues we
receive for sales of our production. Since the mid-1980s, FERC has issued a
series of orders, culminating in Order Nos. 636, 636-A, 636-B and 636-C. These
orders, commonly known as Order 636, have significantly altered the marketing
and transportation service, including the unbundling by interstate pipelines of
the sales, transportation, storage and other components of the city-gate sales
services these pipelines previously performed.
One of FERC's purposes in issuing the orders was to increase
competition in all phases of the gas industry. Order 636 and subsequent FERC
orders issued in individual pipeline restructuring proceedings has been the
subject of appeals, the results of which have generally been supportive of the
FERC's open-access policy. In 1996, the United States Court of Appeals for the
District of Columbia Circuit largely upheld Order No. 636. Because further
review of certain of these orders is still possible, and other appeals remain
pending, it is difficult to predict the ultimate impact of the orders on
Parallel and our gas marketing efforts. Generally, Order 636 has eliminated or
substantially reduced the interstate pipelines' traditional role as wholesalers
of gas, and has substantially increased competition and volatility in gas
markets. While significant regulatory uncertainty remains, Order 636 may
ultimately enhance our ability to market and transport our gas, although it may
also subject us to greater competition.
Sales of oil we produce are not regulated and are made at market
prices. The price we receive from the sale of oil is affected by the cost of
transporting the product to market. Effective January 1, 1995, FERC implemented
regulations establishing an indexing system for transportation rates for
interstate common carrier oil pipelines, which, generally, would index such
rates to inflation, subject to certain conditions and limitations. These
regulations could increase the cost of transporting oil by interstate pipelines,
although the most recent adjustment generally decreased rates. These regulations
have generally been approved on judicial review. We are unable to predict with
certainty what effect, if any, these regulations will have on us. The
regulations may, over time, tend to increase transportation costs or reduce
wellhead prices for oil.
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We are required to comply with various federal and state regulations
regarding plugging and abandonment of oil and gas wells.
Environmental Regulations
Various federal, state and local laws and regulations governing the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, health and safety, affect our operations and
costs. These laws and regulations sometimes:
. require prior governmental authorization for certain activities;
. limit or prohibit activities because of protected areas or
species;
. impose substantial liabilities for pollution related to our
operations or properties; and
. provide significant penalties for noncompliance.
In particular, our exploration and production operations, our
activities in connection with storing and transporting oil and other liquid
hydrocarbons, and our use of facilities for treating, processing or otherwise
handling hydrocarbons and related exploration and production wastes are subject
to stringent environmental regulations. As with the industry generally,
compliance with existing and anticipated regulations increases our overall cost
of business. While these regulations affect our capital expenditures and
earnings, we believe that they do not affect our competitive position in the
industry because our competitors are also affected by environmental regulatory
programs. Since environmental regulations have historically been subject to
frequent change, we cannot predict with certainty the future costs or other
future impacts of environmental regulations on our future operations. A
discharge of hydrocarbons or hazardous substances into the environment could
subject us to substantial expense, including the cost to comply with applicable
regulations that require a response to the discharge, such as claims by
neighboring landowners, regulatory agencies or other third parties for costs of:
. containment or cleanup;
. personal injury;
. property damage; and
. penalties assessed or other claims sought for natural resource
damages.
The following are examples of some environmental laws that potentially
impact our operations.
. Water. The Oil Pollution Act, or OPA, was enacted in 1990 and
amends provisions of the Federal Water Pollution Control Act of
1972 and other statutes as they pertain to prevention of and
response to major oil spills. The OPA
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subjects owners of facilities to strict, joint and potentially
unlimited liability for removal costs and certain other
consequences of an oil spill, where such spill is into navigable
waters, or along shorelines. In the event of an oil spill into
such waters, substantial liabilities could be imposed upon
Parallel. States in which Parallel operates have also enacted
similar laws. Regulations are currently being developed under the
OPA and similar state laws that may also impose additional
regulatory burdens on Parallel.
The FWPCA imposes restrictions and strict controls regarding the
discharge of produced waters, other oil and gas wastes, any form
of pollutant, and, in some instances, storm water runoff, into
waters of the United States. The FWPCA provides for civil,
criminal and administrative penalties for any unauthorized
discharges and, along with the OPA, imposes substantial potential
liability for the costs of removal, remediation or damages
resulting from an unauthorized discharge and, along with the OPA,
imposes substantial potential liability for the costs of removal,
remediation or damages resulting from an unauthorized discharge.
State laws for the control of water pollution also provide civil,
criminal and administrative penalties and liabilities in the case
of an unauthorized discharge into state waters. The cost of
compliance with the OPA and the FWPCA have not historically been
material to our operations, but there can be no assurance that
changes in federal, state or local water pollution control
programs will not materially adversely affect us in the future.
Although no assurances can be given, we believe that compliance
with existing permits and compliance with foreseeable new permit
requirements will not have a material adverse effect on our
financial condition or results of operations.
. Solid Waste. Parallel generates non-hazardous solid wastes that
fall under the requirements of the Federal Resource Conservation
and Recovery Act and comparable state statutes. The EPA and the
states in which we operate are considering the adoption of
stricter disposal standards for the type of non-hazardous waste
we generate. The Resource Conservation and Recovery Act also
govern the generation, management, and disposal of hazardous
wastes. At present, we are not required to comply with a
substantial portion of the Resource Conservation and Recovery Act
requirements because our operations generate minimal quantities
of hazardous wastes. However, it is anticipated that additional
wastes, which could include wastes currently generated during
operations, could in the future be designated as hazardous
wastes. Hazardous wastes are subject to more rigorous and costly
disposal and management requirements than are non-hazardous
wastes. Such changes in the regulations may result in Parallel
incurring additional capital expenditures or operating expenses.
. Superfund. The Comprehensive Environmental Response,
Compensation, and Liability Act, sometimes called CERCLA or
Superfund, imposes liability, without regard to fault or the
legality of the original act, on certain classes of persons in
connection with the release of a hazardous substance into the
environment. These persons include the current owner or operator
of any site where a release
-20-
historically occurred and companies that disposed or arranged for
the disposal of the hazardous substances found at the site.
CERCLA also authorizes the EPA and, in some instances, third
parties to act in response to threats to the public health or the
environment and to seek to recover from the responsible classes
of persons the costs they incur. In the course of our ordinary
operations, we may have managed substances that may fall within
CERCLA's definition of a hazardous substance. We may be jointly
and severally liable under CERCLA for all or part of the costs
required cleaning up sites where we disposed of or arranged for
the disposal of these substances. This potential liability
extends to properties that we owned or operated, as well as to
properties owned and operated by others at which disposal of
Parallel's hazardous substances occurred.
Parallel may also fall into the category of a current owner or
operator. We currently own or lease numerous properties that for many years have
been used for exploring and producing oil and gas. Although we believe we use
operating and disposal practices standard in the industry, hydrocarbons or other
wastes may have been disposed of or released by us on or under properties that
we have owned or leased. In addition, many of these properties have been
previously owned or operated by third parties who may have disposed of or
released hydrocarbons or other wastes at these properties. Under CERCLA, and
analogous state laws, we could be required to remove or remediate previously
disposed wastes, including wastes disposed of or released by prior owners or
operators, to clean up contaminated property, including contaminated
groundwater, or to perform remedial plugging operations to prevent future
contamination.
Risks Related to Our Business
The volatility of the oil and gas industry may have an adverse impact on our
operations.
Our revenues, cash flows and profitability are substantially dependent
upon prevailing prices for oil and gas. In recent years, oil and gas prices and,
therefore, the level of drilling, exploration, development and production, have
been extremely volatile. Any significant or extended decline in oil and/or gas
prices will have a material adverse effect on our business, financial condition
and results of operations and could impair access to future sources of capital.
Volatility in the oil and gas industry results from numerous factors over which
we have no control, including;
. the level of oil and natural gas prices, expectations about
future oil and natural gas prices and the ability of
international cartels to set and maintain production levels and
prices;
. the cost of exploring for, producing and transporting oil and
natural gas;
. the level and price of foreign oil and natural gas
transportation;
. available pipeline and other oil and natural gas transportation
capacity;
. weather conditions;
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. international political, military, regulatory and economic
conditions;
. the level of consumer demand;
. the price and the availability of alternative fuels;
. the effect of worldwide energy conservation measures; and
. the ability of oil and natural gas companies to raise capital.
Significant declines in oil and natural gas prices for an extended
period may:
. impair our financial condition, liquidity, ability to finance
planned capital expenditures and results of operations;
. reduce the amount of oil and natural gas that we can produce
economically;
. cause us to delay or postpone some of our capital projects;
. reduce our revenues, operating income and cash flow; and
. reduce the carrying value of our oil and natural gas properties.
No assurance can be given that current levels of oil and gas prices
will continue. We expect oil and gas prices, as well as the oil and gas industry
generally, to continue to be volatile.
We must replace oil and gas reserves that we produce. Failure to replace
reserves may negatively affect our business.
Our future performance depends in part upon our ability to find,
develop and acquire additional oil and gas reserves that are economically
recoverable. Our proved reserves decline as they are depleted and we must locate
and develop or acquire new oil and gas reserves to replace reserves being
depleted by production. No assurance can be given that we'll be able to find and
develop or acquire additional reserves on an economical basis. If we cannot
economically replace our reserves, our results of operations may be materially
adversely affected.
We are subject to uncertainties in reserve estimates and future net cash flows.
There is substantial uncertainty in estimating quantities of proved
reserves and projecting future production rates and the timing of development
expenditures. No one can measure underground accumulations of oil and gas in an
exact way. Accordingly, oil and gas reserve engineering requires subjective
estimations of those accumulations. Estimates of other engineers might differ
widely from those of our independent petroleum engineers, and our independent
petroleum engineers may make material changes to reserve estimates based on the
results of actual drilling, testing, and production. As a result, our reserve
estimates often differ from the
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quantities of oil and gas we ultimately recover. Also, we make certain
assumptions regarding future oil and natural gas prices, production levels, and
operating and development costs that may prove incorrect. Any significant
variance from these assumptions could greatly affect our estimates of reserves,
the economically recoverable quantities of oil and gas attributable to any
particular group of properties, the classifications of reserves based on risk of
recovery, and estimates of the future net cash flows. Some of our reserve
estimates are made without the benefit of a lengthy production history and are
calculated using volumetric analysis. Those estimates are less reliable than
estimates based on a lengthy production history. Volumetric analysis involves
estimating the volume of a reservoir based on the net feet of pay and an
estimation of the productive area.
The present value of future net cash flows from our proved reserves is
not necessarily the same as the current market value of our estimated oil and
gas reserves. We base the estimated discounted future net cash flows from our
proved reserves on prices and costs in effect on the day of estimate. However,
actual future net cash flows from our oil and gas properties also will be
affected by factors such as:
. actual prices we receive for oil and gas;
. the amount and timing of actual production;
. supply and demand of oil and gas;
. limits of increases in consumption by gas purchasers; and
. changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in
connection with the development and production of oil and gas properties will
affect the timing of actual future net cash flows from proved reserves, and thus
their actual present value. In addition, the 10% discount factor we use when
calculating discounted future net cash flows may not be the most appropriate
discount factor based on interest rates in effect from time to time and risks
associated with us or the oil and gas industry in general.
Competition in the oil and natural gas industry is intense, and many of our
competitors have greater financial, technological and other resources than we
do.
We operate in the highly competitive areas of oil and natural gas
acquisition, development, exploitation, exploration and production. The oil and
natural gas industry is characterized by rapid and significant technological
advancements and introductions of new products and services using new
technologies. We face intense competition from independent, technology-driven
companies as well as from both major and other independent oil and natural gas
companies in each of the following areas:
. seeking to acquire desirable producing properties or new leases
for future exploration;
-23-
. marketing our oil and natural gas production;
. integrating new technologies; and
. seeking to acquire the equipment and expertise necessary to
develop and operate our properties.
Many of our competitors have financial, technological and other
resources substantially greater than ours, and some of them are fully integrated
companies. These companies may be able to pay more for development prospects and
productive oil and natural gas properties and may be able to define, evaluate,
bid for and purchase a greater number of properties and prospects than our
financial or human resources permit. Further, these companies may enjoy
technological advantages and may be able to implement new technologies more
rapidly than we can. Our ability to develop and exploit our oil and natural gas
properties and to acquire additional properties in the future will depend upon
our ability to successfully conduct operations, implement advanced technologies,
evaluate and select suitable properties and consummate transactions in this
highly competitive environment.
We do not control all of our operations and development projects.
Substantially all of our business activities are conducted through
joint operating agreements under which we own partial interests in oil and gas
wells.
At December 31, 2003, we owned interests in 148 gross (110.9 net)
producing oil and gas wells for which we were the operator and 427 gross (194.9
net) producing oil and gas wells where we were not the operator.
If we do not operate wells in which we own an interest, we do not have
control over normal operating procedures, expenditures or future development of
underlying properties. The failure of an operator of our wells to adequately
perform operations, or an operator's breach of the applicable agreements, could
reduce our production and revenues. The success and timing of our drilling and
development activities on properties operated by others therefore depends upon a
number of factors outside of our control, including the operator's:
. timing and amount of capital expenditures;
. expertise and financial resources;
. inclusion of other participants in drilling wells; and
. use of technology.
-24-
Since we do not have a majority interest in most wells we do not
operate, we may not be in a position to remove the operator in the event of poor
performance.
Our business involves many operating risks, which may result in substantial
losses, and insurance may be unavailable or inadequate to protect us against
these risks.
Our operations are subject to hazards and risks inherent in drilling
for, producing and transporting oil and natural gas, such as:
. fires;
. natural disasters;
. explosions;
. pressure forcing oil or natural gas out of the wellbore at a
dangerous velocity coupled with the potential for fire or
explosion;
. weather;
. failure of oilfield drilling and service tools;
. changes in underground pressure in a formation that causes the
surface to collapse or crater;
. pipeline ruptures or cement failures;
. environmental hazards such as natural gas leaks, oil spills and
discharges of toxic gases; and
. availability of needed equipment at acceptable prices, including
steel tubular products.
Any of these risks can cause substantial losses resulting from:
. injury or loss of life;
. damage to and destruction of property, natural resources and
equipment;
. pollution and other environmental damage;
. regulatory investigations and penalties;
. suspension of our operations; and
-25-
. repair and remediation costs.
We do not insure against the loss of oil or natural gas reserves as a
result of operating hazards or insure against business interruption. Losses
could occur for uninsurable or uninsured risks, or in amounts in excess of
existing insurance coverage. The occurrence of an event that is not fully
covered by insurance could harm our financial condition and results of
operations.
The oil and gas industry is capital intensive.
The oil and gas industry is capital intensive. We make substantial
capital expenditures for the acquisition, exploration for and development of oil
and gas reserves.
Historically, we have financed capital expenditures primarily with cash
generated by operations, proceeds from bank borrowings and sales of our equity
securities. In addition, we may consider selling non-core assets to raise
additional operating capital. From time to time, we may also reduce our
ownership interests in 3-D seismic and other projects in order to reduce our
capital expenditure requirements, depending on our working capital needs.
Our cash flow from operations and access to capital is subject to a
number of variables, including:
. our proved reserves;
. the level of oil and gas we are able to produce from existing
wells;
. the prices at which oil and gas are sold; and
. our ability to acquire, locate and produce new reserves.
Any one of these variables can materially affect our ability to borrow
under our revolving credit facility.
If our revenues or the borrowing base under our revolving credit
facility decreases as a result of lower oil and gas prices, operating
difficulties, declines in reserves or for any other reason, we may have limited
ability to obtain the capital necessary to undertake or complete future drilling
projects. We may, from time to time, seek additional financing, either in the
form of increased bank borrowings, sales of debt or equity securities or other
forms of financing. There can be no assurance as to the availability or terms of
any additional financing.
There are risks in acquiring producing properties, including difficulties in
integrating acquired properties into our business, additional liabilities and
expenses associated with acquired properties, diversion of management attention,
increasing the scope, geographic diversity and complexity of our operations and
incurrence of additional debt.
Our business strategy includes growing our reserve base through
acquisitions. Our failure to integrate acquired businesses successfully into our
existing business, or the expense
-26-
incurred in consummating future acquisitions, could result in unanticipated
expenses and losses. In addition, we may assume cleanup or reclamation
obligations or other unanticipated liabilities in connection with these
acquisitions. The scope and cost of these obligations may ultimately be
materially greater than estimated at the time of the acquisition.
We are continually investigating opportunities for acquisitions. In
connection with future acquisitions, the process of integrating acquired
operations into our existing operations may result in unforeseen operating
difficulties and may require significant management attention and financial
resources that would otherwise be available for the ongoing development or
expansion of existing operations. Our ability to make future acquisitions may be
constrained by our ability to obtain additional financing.
Possible future acquisitions could result in our incurring additional
debt, contingent liabilities and expense, all of which could have a material
adverse effect on our financial condition and operating results.
The marketability of our natural gas production depends on facilities that we
typically do not own or control.
The marketability of our natural gas production depends in part upon
the availability, proximity and capacity of natural gas gathering systems,
pipelines and processing facilities. We generally deliver natural gas through
gas gathering systems and gas pipelines that we do not own. Our ability to
produce and market natural gas on a commercial basis could be harmed by any
significant change in the cost or availability of such systems and pipelines.
We are subject to many restrictions under our revolving credit facility.
As required by our revolving credit facility with our bank lenders, we
have pledged substantially all of our oil and natural gas properties as
collateral to secure the payment of our indebtedness. The revolving credit
facility restricts our ability to obtain additional financing, make investments,
lease equipment, sell assets and engage in business combinations. We are also
required to comply with certain financial covenants and ratios. The revolving
credit facility prohibits us from declaring or paying dividends on our common
stock, but we are permitted to pay dividends on our outstanding shares of 6%
convertible preferred stock if we are not in default under the revolving credit
facility. Although we are currently in compliance with these covenants, in the
past we have had to request waivers from our banks because of our non-compliance
with certain financial covenants and ratios. Our ability to comply with these
restrictions and covenants in the future is uncertain and will be affected by
the levels of cash flow from our operations and events or circumstances beyond
our control. Our failure to comply with any of the restrictions and covenants
under the revolving credit facility could result in a default under the
revolving credit facility, which could cause all of our existing indebtedness to
be immediately due and payable.
The revolving credit facility limits the amounts we can borrow to a
borrowing base amount, determined by the lenders, based upon projected revenues
from the oil and gas properties securing our loan. The lenders can adjust the
borrowing base and the borrowings
-27-
permitted to be outstanding under the revolving credit facility. Any increase in
the borrowing base requires the consent of all lenders. If all lenders do not
agree on an increase, then the borrowing base will be the lowest borrowing base
determined by each lender. Outstanding borrowings in excess of the borrowing
base must be repaid immediately, or we must pledge other oil and gas properties
as additional collateral. We do not currently have any substantial unpledged
properties and no assurance can be given that we would be able to make any
mandatory principal prepayments required under the revolving credit facility.
Our producing properties are geographically concentrated.
A substantial portion of our proved oil and natural gas reserves are
located in the Permian Basin of west Texas and eastern New Mexico. Specifically,
at December 31, 2003, approximately 84% of the discounted present value of our
proved reserves were located in the Permian Basin. As a result, we may be
disproportionately exposed to the impact of delays or interruptions of
production from these wells due to mechanical problems, damages to the current
producing reservoirs, significant governmental regulation, including any
curtailment of production, or interruption of transportation of oil or gas
produced from the wells.
Hedging activities create a risk of financial loss.
In order to manage our exposure to price risks in the marketing of our
oil and natural gas, we have in the past and expect to continue to enter into
oil and natural gas price risk management arrangements with respect to a portion
of our expected production. We use swap, floor, and collar hedging arrangements
that generally result in a fixed price or a range of minimum and maximum price
limits over a specified time period. Hedging contracts limit the benefits we
will realize if actual prices rise above the contract price. Our hedging
arrangements may expose us to the risk of financial loss in certain
circumstances. In a typical hedge transaction, the hedging party will have the
right to receive from the counterparty to the hedge, the excess of the fixed
price specified in the hedge over a floating price based on a market index,
multiplied by the quantity hedged. If the floating price exceeds the fixed
price, the hedging party is required to pay the counterparty this difference
multiplied by the quantity hedged. In this case, if we are the hedging party we
would be required to pay the difference regardless of whether we had sufficient
production to cover the quantities specified in the hedge. Significant
reductions in production at times when the floating price exceeds the fixed
price could require us to make payments under the hedge agreements even though
the payments are not offset by sales of production. Hedging will also prevent us
from receiving the full advantage of increases in oil or gas prices above the
fixed amount specified in the hedge. In addition, these transactions may expose
us to the risk of financial loss in certain circumstances, including instances
in which:
. production is less than expected;
. there is a widening of price differentials between delivery
points for our production and the delivery point assumed in the
arrangement;
. the counterparties to our future contracts fail to perform under
the contract; or
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. a sudden, unexpected event materially impacts oil or natural gas
prices.
In the past, some of our hedging contracts required us to deliver cash
collateral or other assurances of performance to the counterparties in the event
that our payment obligations exceeded certain levels. Future collateral
requirements are uncertain but will depend on arrangements with our
counterparties and highly volatile natural gas and oil prices.
We are subject to complex federal, state and local laws and regulations that
could adversely affect our business.
Extensive federal, state and local regulation of the oil and gas
industry significantly affects our operations. In particular, our oil and
natural gas exploration, development and production, are subject to stringent
environmental regulations. These regulations have increased the costs of
planning, designing, drilling, installing, operating and abandoning our oil and
natural gas wells and other related facilities. These regulations may become
more demanding in the future. Matters subject to regulation include:
. discharge permits for drilling operations;
. drilling bonds;
. spacing of wells;
. unitization and pooling of properties;
. environmental protection;
. reports concerning operations; and
. taxation.
Under these laws and regulations, we could be liable for:
. personal injuries;
. property damage;
. oil spills;
. discharge of hazardous materials;
. reclamation costs;
. remediation and clean-up costs; and
. other environmental damages.
-29-
Failure to comply with these laws and regulations also may result in
the suspension or termination of our operations and subject us to
administrative, civil and criminal penalties. Further, these laws and
regulations could change in ways that substantially increase our costs. Any of
these liabilities, penalties, suspensions, terminations or regulatory changes
could make it more expensive for us to conduct our business or cause us to limit
or curtail some of our operations.
Declining oil and gas prices may cause us to record ceiling test write-downs.
We use the full cost method of accounting to account for our oil and
gas operations. This means that we capitalize the costs to acquire, explore for
and develop oil and gas properties. Under full cost accounting rules, the
capitalized costs of oil and gas properties may not exceed a ceiling limit,
which is based on the present value of estimated future net revenues, net of
income tax effects, from proved reserves, discounted at 10%, plus the lower of
cost or fair market value of unproved properties. These rules generally require
pricing future oil and gas production at unescalated oil and gas prices in
effect at the end of each fiscal quarter, with effect given to cash flow hedge
positions. If capitalized costs of oil and gas properties, as adjusted for asset
retirement obligations, exceed the ceiling limit, we must charge the amount of
the excess against earnings. This is called a ceiling test write-down. This
non-cash impairment charge does not affect cash flow from operating activities,
but it does reduce stockholders' equity. Impairment charges cannot be restored
by subsequent increases in the prices of oil and gas.
The risk that we will be required to write down the carrying value of
our oil and gas properties increases when oil and gas prices decline. In
addition, write-downs may occur if we experience substantial downward
adjustments to our estimated proved reserves.
We did not recognize impairment in 2003. We cannot assure you that we
will not experience ceiling test write-downs in the future.
Terrorist activities may adversely affect our business.
Terrorist activities, including events similar to those of September
11, 2001, or armed conflict involving the United States may adversely affect our
business activities and financial condition. If events of this nature occur and
persist, the resulting political and social instability could adversely affect
prevailing oil and gas prices and cause a reduction in our revenues. In
addition, oil and natural gas production facilities, transportation systems and
storage facilities could be direct targets of terrorist attacks, and our
operations could be adversely impacted if infrastructure integral to our
operations is destroyed or damaged. Costs associated with insurance and other
security measure may increase as a result of these threats, and some insurance
coverage may become more difficult to obtain, if available at all.
-30-
Part of our business is seasonal in nature.
Weather conditions affect the demand for and price of oil and natural
gas and can also delay drilling activities, temporarily disrupting our overall
business plans. Demand for oil and natural gas is typically higher during winter
months than summer months. However, warm winters can also lead to downward price
trends. As a result, our results of operations may be adversely affected by
seasonal conditions.
We are highly dependent upon key personnel.
Our success is highly dependent upon the services, efforts and
abilities of key members of our management team. Our operations could be
materially and adversely affected if one or more of these individuals become
unavailable for any reason.
We do not have employment agreements or long term contractual
arrangements with any of our officers or other key employees. In periods of
improving market conditions, our ability to obtain and retain qualified
consultants on a timely basis may be adversely affected.
Our future growth and profitability will also be dependent upon our
ability to attract and retain other qualified management personnel and to
effectively manage our growth. There can be no assurance that we will be
successful in doing so.
Our Oil and Gas Operations Are Subject to Many Inherent Risks
Oil and gas drilling activities and production operations are highly
speculative and involve a high degree of risk. These operations are marked by
unprofitable efforts because of dry holes and wells that do not produce oil or
gas in sufficient quantities to return a profit. The success of our operations
depends, in part, upon the ability of our management and technical personnel.
The cost of drilling, completing and operating wells is often uncertain. There
is no assurance that our oil and gas drilling or acquisition activities will be
successful, that any production will be obtained, or that any such production,
if obtained, will be profitable.
Our operations are subject to all of the operating hazards and risks
normally incident to drilling for and producing oil and gas. These hazards and
risks include:
. encountering unusual or unexpected formations and pressures;
. explosions, blowouts and fires;
. pipe and tubular failures and casing collapses;
. environmental pollution; and
. personal injuries.
-31-
Any one of these potential hazards could result in accidents,
environmental damage, personal injury, property damage and other harm that could
result in substantial liabilities to us.
As is customary in the industry, we maintain insurance against some,
but not all, of these hazards. We maintain general liability insurance and
obtain insurance against blowouts on a well-by-well basis. We do not carry
insurance against pollution hazards. If we sustain an uninsured loss or
liability, our ability to operate could be materially adversely affected.
Our oil and gas operations are not subject to renegotiation of profits
or termination of contracts at the election of the federal government.
Restrictive debt covenants could limit our growth and our ability to finance our
operations, fund our capital needs, respond to changing conditions and engage in
other business activities that may be in our best interests.
Our revolving credit facility contains a number of significant
covenants that, among other things, restrict our ability to:
. dispose of assets;
. incur additional indebtedness;
. restrictions on all retained earnings and net income for payment
of dividends on our common stock;
. create liens on our assets;
. enter into specified investments or acquisitions;
. repurchase, redeem or retire our capital stock or other
securities;
. merge or consolidate, or transfer all or substantially all of our
assets and the assets of our subsidiaries;
. engage in specified transactions with subsidiaries and
affiliates; or
. engage in other specified corporate activities.
Also, our revolving credit facility requires us to maintain compliance
with specified financial ratios and satisfy certain financial condition tests.
Our ability to comply with these ratios and financial condition tests may be
affected by events beyond our control, and we cannot assure you that we will
meet these ratios and financial condition tests. These financial ratio
restrictions and financial condition tests could limit our ability to obtain
future financings, make needed capital expenditures, withstand a future downturn
in our business or the economy in general or otherwise conduct necessary
corporate activities. We may also be prevented from taking advantage of business
opportunities that arise because of the limitations that the restrictive
-32-
covenants under the revolving credit facility impose on us. A breach of any of
these covenants or our inability to comply with the required financial ratios or
financial condition tests could result in a default under the revolving credit
facility. A default, if not cured or waived, could result in acceleration of all
indebtedness outstanding under the revolving credit facility. The accelerated
debt would become immediately due and payable. If that should occur, we may not
be able to pay all such debt or to borrow sufficient funds to refinance it. Even
if new financing were then available, it may not be on terms that are acceptable
to us.
If we fail to meet our payment obligations under our revolving credit facility,
the lenders under such credit facility could foreclose on, and acquire control
of, substantially all of our assets.
The lenders under our revolving credit facility have liens on
substantially all of our assets. As a result of the liens held by our revolving
credit facility lenders, if we fail to meet our payment or other obligations
under the revolving credit facility, those lenders would be entitled to
foreclose on substantially all of our assets and liquidate those assets.
We do not pay dividends on our common stock.
We have never paid dividends on our common stock, and do not intend to
pay cash dividends on the common stock in the foreseeable future. Net income
from our operations, if any, will be used for the development of our business,
including capital expenditures, to retire debt and to pay dividends on our
outstanding shares of 6% convertible preferred stock. Any decision to pay
dividends on the common stock in the future will depend upon our profitability
at that time, the available cash and other factors. Our ability to pay dividends
on our common stock is further limited by the terms of our loan agreement and
the terms of our preferred stock.
Changes in control may be discouraged.
Our certificate of incorporation, our bylaws and the Delaware General
Corporation Law contain provisions that may discourage other persons from
initiating a tender offer or takeover attempt that a stockholder might consider
to be in the best interests of all stockholders, including takeover attempts
that might result in a premium to be paid over the market price of our stock.
On October 5, 2000, our Board of Directors adopted a stockholder rights
plan. The plan is designed to protect Parallel from unfair or coercive takeover
attempts and to prevent a potential acquirer from gaining control of Parallel
without fairly compensating all of the stockholders. The plan authorized 50,000
shares of $0.10 par Series A Preferred Stock Purchase Rights. A dividend of one
Right for each share of our outstanding common stock was distributed to
stockholders of record at the close of business on October 16, 2000. If a public
announcement is made that a person has acquired 15% or more of Parallel's common
stock or a tender or exchange offer is made for 15% of more of the common stock,
each Right entitles the holder to purchase from the company one one-thousandth
of a share of Series A Preferred Stock, at an exercise price of $26.00 per one
one-thousandth of a share, subject to adjustment. In addition, under certain
circumstances, the rights entitle the holders to buy Parallel's stock at a 50%
discount. See Note 9 to Financial Statements, on page F-24.
-33-
On November 25, 2003, our Board of Directors approved in principle the
adoption of an employee retention/severance plan that became effective January
1, 2004. Although specific details of the plan have not been determined and the
plan is not in final written form, we expect that the significant provisions of
the plan will provide for a one-time payment of all officers and employees of
Parallel upon the occurrence of a change of control. The aggregate payments of
all officers and employees will generally be 5% of an amount equal to the
positive difference between the amount by which our net asset value per share at
the time of the occurrence of a change of control exceeds the net asset value
per share as of January 1, 2004, compounded annually at a rate equal to the
annual industry average growth rate, plus 2%. Generally Parallel contemplates
that a "change of control" will include events such as a merger, reorganization,
liquidation or sale of substantially all of the asset of Parallel, or the
acquisition by a third party of 50% or more of our outstanding voting
securities.
We are authorized to issue 10.0 million shares of preferred stock,
957,000 shares of which were outstanding on March 1, 2004. Our Board of
Directors has total discretion in the issuance and the determination of the
rights and privileges of any shares of preferred stock which might be issued in
the future, which rights and privileges may be detrimental to the holders of the
common stock. It is not possible to state the actual effect of the authorization
and issuance of a new series of preferred stock upon the rights of holders of
the common stock and other series of preferred stock unless and until the Board
of Directors determines the attributes of any new series of preferred stock and
the specific rights of its holders. These effects might include:
. restrictions on dividends on common stock and other series of
preferred stock if dividends on any new series of preferred stock
have not been paid;
. dilution of the voting power of common stock and other series of
preferred stock to the extent that a new series of preferred
stock has voting rights, or to the extent that any new series of
preferred stock is convertible into common stock;
. dilution of the equity interest of common stock and other series
of preferred stock; and
. limitation on the right of holders of common stock and other
series of preferred stock to share in Parallel's assets upon
liquidation until satisfaction of any liquidation preference
attributable to any new series of preferred stock.
The issuance of preferred stock in the future could discourage, delay
or prevent a tender offer, proxy contest or other similar transaction involving
a potential change in control of Parallel that might be viewed favorably by
stockholders.
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- -------------------------------------------------------------------------------
ITEM 2. PROPERTIES
- -------------------------------------------------------------------------------
General
Our principal properties consist of developed and undeveloped oil and
gas leases and the reserves associated with these leases. Generally, developed
oil and gas leases remain in force so long as production is maintained.
Undeveloped oil and gas leaseholds are generally for a primary term of five or
ten years. In most cases, we can extend the term of our undeveloped leases by
paying delay rentals or by producing reserves that we discover under our leases.
Producing Wells and Acreage
We have presented the following table to provide you with a summary of
the producing oil and gas wells and the developed and undeveloped acreage in
which we owned an interest at December 31, 2003. We have not included in the
table acreage in which our interest is limited to options to acquire leasehold
interests, royalty or similar interests.
Producing Wells Acreage
----------------------------------------------- -----------------------------------------------
Oil(1) Gas Developed Undeveloped
----------------------- ---------------------- ----------------------- -----------------------
Gross Net(2) Gross Net(2) Gross Net(3) Gross Net(3)
----------- ----------- ---------- ---------- ---------- ----------- ----------- ----------
Texas 468 267.3 106 38.50 62,585 37,423 63,279 9,423
Nevada - - - - - - 3,326 3,326
New Mexico - - 1 0.06 - - 54,364 4,447
Utah - - - - - - 124,026 98,337
----------- ----------- ---------- ---------- ---------- ----------- ----------- ----------
Total 468 267.3 107 38.56 62,585 37,423 244,995 115,533
=========== =========== ========== ========== ========== =========== =========== ==========
- ---------------------
(1) Does not include 261 wells that are currently shut in or temporarily
abandoned.
(2) Net wells are computed by multiplying the number of gross wells by our
working interest in the gross wells.
(3) Net acres are computed by multiplying the number of gross acres by our
working interest in the gross acres.
At December 31, 2003, we owned interests in 148 gross (110.9 net)
producing oil and gas wells for which we were the operator and 427 gross (194.9
net) producing oil and gas wells where we were not the operator.
The operator of a well has significant control over its location and
the timing of its drilling. In addition, the operator receives fees from other
working interest owners as reimbursement for general and administrative expenses
for operating the wells.
Except for our oil and gas leases, we do not own any patents, licenses,
franchises or concessions which are significant to our oil and gas operations.
-35-
Title to Properties
As is customary in the oil and gas industry, we make only a cursory
review of title to undeveloped oil and gas leases at the time they are acquired.
These cursory title reviews, while consistent with industry practices, are
necessarily incomplete. We believe that it is not economically feasible to
review in depth every individual property we acquire, especially in the case of
producing property acquisitions covering a large number of leases. Ordinarily,
when we acquire producing properties, we focus our review efforts on properties
believed to have higher values and will sample the remainder. However, even an
in-depth review of all properties and records may not necessarily reveal
existing or potential defects nor will it permit a buyer to become sufficiently
familiar with the properties to assess fully their deficiencies and
capabilities. In the case of producing property acquisitions, inspections may
not always be performed on every well, and environmental problems, such as
ground water contamination, are not necessarily observable even when an
inspection is undertaken. In the case of undeveloped leases or prospects we
acquire, before any drilling commences, we will usually cause a more thorough
title search to be conducted, and any material defects in title that are found
as a result of the title search are generally remedied before drilling a well on
the lease commences. We believe that we have good title to our oil and gas
properties, some of which are subject to immaterial encumbrances, easements and
restrictions. The oil and gas properties we own are also typically subject to
royalty and other similar non-cost bearing interests customary in the industry.
We do not believe that any of these encumbrances or burdens will materially
affect our ownership or the use of our properties.
Oil and Gas Reserves
For the year ended December 31, 2003, our oil and gas reserves were
estimated by Cawley Gillespie & Associates, Inc., Fort Worth, Texas.
At December 31, 2003, our total estimated proved reserves were
approximately 12,100 MBbls of oil and 16.3 Bcf of gas, or 14,800 MBOEs.
-36-
The information in this table provides you with certain information
regarding the proved reserves as estimated by Cawley Gillespie & Associates,
Inc., at December 31, 2003.
Proved Proved
Developed Undeveloped Total
---------------- ----------------- -------------------
($ in thousands)
Oil (MBbls) 8,944 3,140 12,084
Gas (MMcf) 12,066 4,205 16,271
MBOE 10,955 3,841 14,796
Future Net Revenues (before income taxes) $ 216,595 $ 77,095 $ 293,690
Present Value of Future Net Revenues (before income taxes) $ 117,483 $ 30,306 $ 147,789
Estimates of our proved reserves and future net revenues are made using
sales prices and costs, estimated to be in effect as of the date of such reserve
estimates that are held constant throughout the life of the properties, except
to the extent a contract specifically provides for escalation. The average
realized prices for our reserves as of December 31, 2003 were $30.63 per Bbl of
oil and $5.45 per Mcf of natural gas.
For additional information concerning our estimated proved oil and gas
reserves, you should read Note 15 to the Financial Statements. See also Item 8 -
Financial Statements and Supplementary Data beginning on page 64 of this Annual
Report on Form 10-K.
The reserve data in this report represent estimates only. Reservoir
engineering is a subjective process. There are numerous uncertainties inherent
in estimating our oil and natural gas reserves and their estimated values. Many
factors are beyond our control. Estimating underground accumulations of oil and
natural gas cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment and the costs we actually incur in the
development of our reserves. As a result, estimates of different engineers often
vary. In addition, estimates of reserves are subject to revision by the results
of drilling, testing and production after the date of the estimates.
Consequently, reserve estimates are often different from the quantities of oil
and natural gas that are ultimately recovered. The meaningfulness of estimates
is highly dependent upon the accuracy of the assumptions upon which they were
based.
The volume of production from oil and natural gas properties declines
as reserves are produced and depleted. Unless we acquire properties containing
proved reserves or conduct successful drilling activities, our proved reserves
will decline as we produce our existing reserves. Our future oil and natural gas
production is highly dependent upon our level of success in acquiring or finding
additional reserves.
We do not have any gas or oil reserves outside the United States. Our
oil and gas reserves and production are not subject to any long term supply or
similar agreements with foreign governments or authorities.
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Our estimated reserves have not been filed with or included in reports
to any federal agency other than the SEC.
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ITEM 3. LEGAL PROCEEDINGS
- -------------------------------------------------------------------------------
At March 1, 2004, we were involved in one lawsuit incidental to our
business. We do not believe the ultimate outcome of this lawsuit will have a
material adverse effect on our financial position or results of operations and
we have not made an accrual for this item. We accrue for such items when a
liability is both probable and the amount can be reasonably estimated. We are
not aware of any other threatened litigation. We have not been a party to any
bankruptcy, receivership, reorganization, adjustment or similar proceeding.
- -------------------------------------------------------------------------------
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- -------------------------------------------------------------------------------
We did not submit any matter to a vote of our stockholders during the
fourth quarter of 2003.
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PART II
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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
- -------------------------------------------------------------------------------
Market Information
Our common stock trades on the Nasdaq National Market under the symbol
PLLL. The following table shows, for the periods indicated, the high and low
closing sales prices for the common stock as reported by Nasdaq.
Price Per Share
--------------------------
High Low
------------- ------------
2001
First Quarter $ 4.93 $ 3.50
Second Quarter $ 5.57 $ 4.20
Third Quarter $ 4.18 $ 2.95
Fourth Quarter $ 4.20 $ 2.77
2002
First Quarter $ 4.38 $ 3.08
Second Quarter $ 3.41 $ 2.60
Third Quarter $ 2.95 $ 2.15
Fourth Quarter $ 2.91 $ 2.03
2003
First Quarter $ 3.10 $ 2.51
Second Quarter $ 4.03 $ 2.40
Third Quarter $ 3.86 $ 3.15
Fourth Quarter $ 4.49 $ 3.19
The last sale price of our common stock on March 1, 2004 was $3.96 per
share, as reported on the Nasdaq National Market.
As of March 1, 2004, there were approximately 1,884 stockholders of
record.
Dividends
We have not paid, and do not intend to pay in the foreseeable future,
cash dividends on our common stock. The revolving credit facility we have with
our bank lenders prohibits the
-39-
payment of dividends on the common stock. Our 6% convertible preferred stock
also contains provisions that restrict us from paying dividends or making
distributions on our common stock if all dividends on the preferred stock have
not been paid in full. Any dividends on our preferred stock that are not
declared and paid will accumulate. All accumulated dividends must be paid in
full before dividends may be paid to holders of common stock. The credit
facility allows us to pay dividends on our outstanding shares of preferred stock
as long as we are not in default under the terms of the credit facility. The
holders of the preferred stock are entitled, as and when declared by the Board
of Directors, to receive an annual dividend of $.60 per share, payable
semi-annually on June 15 and December 15 of each year. See "Risks Related to Our
Business - We do not pay dividends on our common stock" on page 21 and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Capital Resources and Liquidity " on page 53.
Equity Compensation Plans
At December 31, 2003, a total of 2,705,650 shares of common stock were
authorized for issuance under our equity compensation plans. In the table below,
we describe certain information about these shares and the equity compensation
plans which provide for their authorization and issuance. You can find
additional information about our stock option plans beginning on page 78.
Equity Compensation Plan Information
- --------------------------------------------------------------------------------------------------------------
(a) (b) (c)
- --------------------------------------------------------------------------------------------------------------
Plan category Number of securities to Weighted-average Number of securities
be issued upon exercise exercise price of remaining available for
of outstanding options, outstanding future issuance under
warrants and rights options, warrants equity compensation
and rights plans (excluding
securities reflected in
column (a))
- --------------------------------------------------------------------------------------------------------------
Equity compensation
plans approved by 1,938,150 $ 3.53 192,500
security ho1ders
- --------------------------------------------------------------------------------------------------------------
Equity compensation
plans not approved by 575,000(1) $ 3.83 -
security holders
- --------------------------------------------------------------------------------------------------------------
Total 2,513,150 $ 3.60 192,500
- --------------------------------------------------------------------------------------------------------------
(1) These shares include an aggregate of 200,000 shares of common stock
underlying stock options granted in June, 2001 to non-officer employees
pursuant to Parallel's Employee Stock Option Plan; 275,000 shares of common
stock underlying a stock purchase warrant we issued to an investment
banking firm in November, 2001; and 100,000 shares of common stock
underlying a stock purchase warrant we issued to the same investment
banking firm in December, 2003.
-40-
Sale of Equity Securities
On December 23, 2003, we privately placed a total of 4.0 million shares
of common stock, $.01 par value per share, at a price of $3.25 per share. Gross
cash proceeds from the placement were $13.0 million. The shares of common stock
were sold to twenty accredited investors, including individuals, investment
funds and other privately held entities. The shares of common stock were issued
without registration under the Securities Act of 1933 in reliance on the
exemptions provided by Section 4(2) of the Securities Act and Rule 506 of
Regulation D under the Securities Act. Each purchaser acquired shares for
investment and not with a view to distribution and certificates evidencing the
shares bear restrictive legends. The net proceeds of the offering, approximately
$12.1 million, will be used for acquisition and development activities and for
general corporate purposes. Pending the use of proceeds, in January 2004, we
used the net proceeds to repay outstanding bank indebtedness under our revolving
credit facility.
Stonington Corporation acted as our placement agent and received a
placement fee in the amount of 6% of the gross proceeds, and warrants to
purchase 100,000 shares of common stock. The warrants are exercisable, in whole
or in part, at an exercise price equal to $3.98, the fair market value of the
common stock on the date of closing, and are exercisable at any time during the
four-year period commencing one year after the closing of the placement. The
warrants contain customary provisions providing for adjustment of the exercise
price and the number and type of securities issuable upon exercise of the
warrants if any one or more of certain specified events occur. The warrants
grant to the holder certain registration rights for the securities issuable upon
exercise of the warrants.
Repurchase of Equity Securities
Neither we nor any "affiliated purchaser" repurchased any of our equity
securities during the fourth quarter of the fiscal year ended December 31, 2003.
- -------------------------------------------------------------------------------
ITEM 6. SELECTED FINANCIAL DATA
- -------------------------------------------------------------------------------
In the table below, we provide you with selected historical financial
data. We have prepared this information using the audited financial statements
for the five-year period ended December 31, 2003. It is important that you read
this data along with our financial statements and related notes, and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" under Item 7 below. The selected financial data provided are not
necessarily indicative of our future results of operations or financial
performance.
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Year Ended December 31,
--------------------------------------------------------------
2003(1) 2002(2) 2001(3) 2000 1999(4)
------------ ----------- ----------- ------------ -----------
(in thousands, except per share and per unit data)
Consolidated Income Statements Data:
Operating revenues $ 33,855 $ 12,106 $ 17,840 $ 17,134 $ 8,974
Operating expenses $ 21,138 $ 11,250 $ 28,405 $ 9,530 $ 10,174
Income (loss) before cumulative effect of
change in accounting principle $ 7,664 $ 18,701 $ (4,708) $ 5,977 $ (2,450)
Net income (loss) $ 7,602 $ 18,701 $ (4,708) $ 5,977 $ (2,450)
Cumulative preferred stock dividend $ (580) $ (585) $ (585) $ (585) $ (585)
Net income (loss) available to common stockholders $ 7,022 $ 18,116 $ (5,292) $ 5,393 $ (3,035)
Net income (loss) per common share before cumulative effect
of change in accounting principle
Basic $ 0.33 $ 0.88 $ (0.26) $ 0.26 $ (0.16)
Diluted $ 0.31 $ 0.79 $ (0.26) $ 0.25 $ (0.16)
Weighted average common stock and common stock
equivalents outstanding
Basic 21,264 20,680 20,458 20,332 18,549
Diluted 24,175 23,549 20,458 23,465 18,549
Cash dividends - common stock $ - $ - $ - $ - $ -
Consolidated Balance Sheet Data:
Total assets $118,343 $102,351 $ 41,760 $ 46,456 $ 43,264
Total liabilities $ 57,111 $ 56,852 $ 15,446 $ 15,288 $ 17,464
Long-term debt, less current maturities $ 39,750 $ 45,604 $ 9,600 $ 11,624 $ 12,300
Total stockholders' equity $ 61,232 $ 45,499 $ 26,314 $ 31,168 $ 25,800
Consolidated Statement of Cash Flow Data:
Cash provided (used) by
Operating activities $ 19,465 $ 1,528 $ 13,383 $ 10,694 $ 3,406
Investing activities $(15,494) $(30,277) $(11,357) $ (5,846) $ (3,788)
Financing activities $ 1,595 $ 37,210 $ (676) $ (4,123) $ 455
Operating Data:
Product Sales
Oil (Bbls) 629 131 138 165 164
Gas (Mcf) 3,356 2,670 3,266 2,822 2,709
BOE 1,188 576 682 635 615
Average sales price
Oil (per Bbl) $ 29.11 $ 24.59 $ 24.80 $ 28.88 $ 17.32
Gas (per Mcf) $ 5.40 $ 3.33 $ 4.41 $ 4.38 $ 2.27
Proved reserves
Oil (Bbls) 12,084 10,271 916 974 1,008
Gas (Mcf) 16,271 15,633 13,947 15,686 17,284
Present value of proved oil and gas reserves discounted at 10%
(before estimated federal income taxes $147,789 $122,934 $ 17,074 $ 90,950 $ 25,499
Other Data:
Operating cash flow (5) $ 19,310 $ 5,225 $ 11,568 $ 11,718 $ 4,378
-42-
- ---------------
(1) Result includes $8.8 million and $3.3 million for operating revenue and
operating expenses, respectively, associated with our Fullerton properties
acquired December 2002.
(2) Results include a $31.0 million gain attributable to equity in income of
First Permian, L.P. See Note 6 to the Financial Statements. Results also
include noncash charges of $717,000 on the sale of Energen stock, $509,000
for the change in fair value of derivatives and $440,000 for the change in
fair market value of our crude oil swaps.
(3) Results include noncash charges of $2.2 million in the fiscal quarter ended
September 30, 2001 and $14.6 million in the fourth quarter ended December
31, 2001, in each case related to the impairment of oil and gas properties
incurred in 2001 and primarily a result of a decrease in year-end reserves
and lower oil and gas prices.
(4) Results include a non-cash charge of $1.7 million related to the impairment
of oil and gas properties incurred in the fourth quarter of 1999, primarily
a result of a decrease in year-end reserves.
(5) Defined as cash provided by operating activities before changes in
operating assets and liabilities. Because of the exclusion of changes in
assets and liabilities, this cash flow statistic is different from cash
provided (used) by operating activities, as is disclosed under generally
accepted accounting principles and is reconciled to operating cash flow as
follows:
2003 2002 2001 2000 1999
---------- -------- --------- --------- -------
(in thousands)
Cash provided (used) by operating activities $19,465 $1,528 $13,383 $10,694 $3,406
Changes in operating assets and liabilities (155) 3,697 (1,814) 1,024 972
--------- -------- --------- --------- -------
Operating cash flow $19,310 $5,225 $11,569 $11,718 $4,378
========= ======== ========= ========= =======
As compared to cash provided by operating activities, we believe operating
cash flow is a better liquidity indicator for oil and gas producers because
changes in assets and liabilities eliminates fluctuations related to the
timing of cash receipts and disbursements which can vary from
period-to-period because of conditions we cannot control.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
- -------------------------------------------------------------------------------
The following discussion is intended to assist you in understanding our
financial position and results of operations for each year in the three-year
period ended December 31, 2003. You should read the following discussion and
analysis in conjunction with our financial statements and the related notes.
The following discussion contains forward-looking statements. For a
description of limitations inherent in forward-looking statements, see
"Cautionary Statement Regarding Forward-Looking Statements" on page (ii).
Overview and Strategy
Our primary objective is to increase shareholder value of our common
stock through increasing reserves, production, cash flow and earnings. We are
shifting the balance of our investments from properties having high rates of
production in early years to properties with
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more consistent production over a longer term. We attempt to reduce our
financial risks by dedicating a smaller portion of our capital to high risk
projects, while reserving the majority of our available capital for exploitation
and development drilling opportunities. Obtaining positions in long-lived oil
and gas reserves will be given priority over properties that might provide more
cash flow in the early years of production, but which have shorter reserve
lives. We also attempt to further reduce risk by emphasizing acquisition
possibilities over high risk exploration projects.
During the latter part of 2002, we reduced our emphasis on high risk
exploration efforts and started focusing on established geologic trends where we
can utilize the engineering, operational, financial and technical expertise of
our entire staff. Although we anticipate participating in exploratory drilling
activities in the future, reducing financial, reservoir, drilling and geological
risks and diversifying our property portfolio are important criteria in the
execution of our business plan. In summary, our current business plan:
. focuses on projects having less geological risk;
. emphasizes exploitation and enhancement activities;
. focuses on acquiring producing properties; and
. expands the scope of operations by diversifying our exploratory
and development efforts, both in and outside of our current areas
of operation.
Although the direction of our exploration and development activities
has shifted from high risk exploratory activities to lower risk development
opportunities, we will continue our efforts, as we have in the past, to maintain
low general and administrative expenses relative to the size of our overall
operations, utilize advanced technologies, serve as operator in appropriate
circumstances, and reduce operating costs.
The extent to which we are able to implement and follow through with
our business plan will be influenced by:
. the prices we receive for the oil and gas we produce;
. the results of reprocessing and reinterpreting our 3-D seismic
data;
. the results of our drilling activities;
. the costs of obtaining high quality field services;
. our ability to find and consummate acquisition opportunities; and
. our ability to negotiate and enter into work to earn
arrangements, joint venture or other similar agreements on terms
acceptable to us.
-44-
Significant changes in the prices we receive for our oil and gas
drilling results, or the occurrence of unanticipated events beyond our control
may cause us to defer or deviate from our business plan, including the amounts
we have budgeted for our activities.
Operating Performance
Our operating performance is influenced by several factors, the most
significant of which are the prices we receive for our oil and gas and our
production volumes. The world price for oil has overall influence on the prices
that we receive for our oil production. The prices received for different grades
of oil are based upon the world price for oil, which is then adjusted based upon
the particular grade. Typically, light oil is sold at a premium, while heavy
grades of crude are discounted. Gas prices we receive are influenced by:
. seasonal demand;
. weather;
. hurricane conditions in the Gulf of Mexico;
. availability of pipeline transportation to end users;
. proximity of our wells to major transportation pipeline
infrastructures; and
. to a lesser extent, world oil prices.
Additional factors influencing our overall operating performance
include:
. production expenses;
. overhead requirements; and
. costs of capital.
Our oil and gas exploration, development and acquisition activities
require substantial and continuing capital expenditures. Historically, the
sources of financing to fund our capital expenditures have included:
. cash flow from operations;
. sales of our equity securities;
. bank borrowings; and
. industry joint ventures.
-45-
Depletion per BOE in 2003 was $6.83 versus $10.52 in 2002 and $9.13 in
2001. The decrease per BOE in 2003 was a result of lower cost reserves
associated with our acquisition of the Fullerton properties as of December,
2002.
Our oil and gas producing activities are accounted for using the full
cost method of accounting. Under this accounting method, we capitalize all costs
incurred in connection with the acquisition of oil and gas properties and the
exploration for and development of oil and gas reserves. See Note 3 to the
Financial Statements. These costs include lease acquisition costs, geological
and geophysical expenditures, costs of drilling productive and non-productive
wells, and overhead expenses directly related to land and property acquisition
and exploration and development activities. Proceeds from the disposition of oil
and gas properties are accounted for as a reduction in capitalized costs, with
no gain or loss recognized unless a disposition involves a material change in
reserves, in which case the gain or loss is recognized.
Depletion of the capitalized costs of oil and gas properties, including
estimated future development costs, is provided using the equivalent
unit-of-production method based upon estimates of proved oil and gas reserves
and production, which are converted to a common unit of measure based upon their
relative energy content. Unproved oil and gas properties are not amortized, but
are individually assessed for impairment. The cost of any impaired property is
transferred to the balance of oil and gas properties being depleted.
Results of Operations
Our business activities are characterized by frequent, and sometimes
significant, changes in our:
. reserve base;
. sources of production;
. product mix (gas versus oil volumes); and
. the prices we receive for our oil and gas production.
-46-
Year-to-year or other periodic comparisons of the results of our
operations can be difficult and may not fully and accurately describe our
condition. The following table shows selected operating data for each of the
three years ended December 31, 2003.
Year Ended December 31,
----------------------------------------------
2003 2002 2001
--------------- -------------- --------------
(in thousands except per unit data)
Production, Prices and Lifting Costs:
Oil (Bbls) 629 131 138
Natural gas (Mcf) 3,356 2,670 3,266
BOE 1,188 576 682
Oil price (per Bbl)(1) $ 29.11 $ 24.59 $ 24.80
Natural gas price (per Mcf)(1) $ 5.40 $ 3.33 $ 4.41
BOE price(1) $ 30.66 $ 21.03 $ 26.13
Average Production (lifting) Cost per BOE(2) $ 7.07 $ 5.00 $ 5.74
- -----------
(1) Average price received at the wellhead for our oil and natural gas.
(2) The increase in 2003 is attributable to increased lifting costs associated
with our waterflood projects.
Critical Accounting Policies and Practices
Full Cost and Impairment of Assets. We account for our oil and natural
gas exploration and development activities using the full cost method of
accounting. Under this method, all costs incurred in the acquisition,
exploration and development of oil and natural gas properties are capitalized.
Costs of non-producing properties, wells in process of being drilled and
significant development projects are excluded from depletion until such time as
the related project is developed and proved reserves are established or
impairment is determined. At the end of each quarter, the net capitalized costs
of our oil and natural gas properties, as adjusted for asset retirement
obligations, is limited to the lower of unamortized cost or a ceiling, based on
the present value of estimated future net revenues, net of income tax effects,
discounted at 10%, plus the lower of cost of fair market value of our unproved
properties. Revenues are measured at unescalated oil and gas prices at the end
of each quarter, with effect given to our cash flow hedge positions. If the net
capitalized costs of our oil and gas properties exceed the ceiling, we are
subject to a ceiling test write-down to the extent of the excess. A ceiling test
write-down is a non-cash charge to earnings. It reduces earnings and impacts
stockholders' equity in the period of occurrence and results in lower
depreciation, depletion and amortization expense in future periods.
The risk that we will be required to write down the carrying value of
oil and gas properties increases when oil and gas prices decline. If commodity
prices deteriorate, it is possible that we could incur an impairment in future
periods.
Depletion. Provision for depletion of oil and gas properties, under the
full cost method, is calculated using the unit of production method based upon
estimates of proved oil and gas reserves with oil and gas production being
converted to a common unit of measure based upon
-47-
their relative energy content. Investments in unproved properties and major
development projects are not amortized until proved reserves associated with the
projects can be determined or until impairment occurs. The cost of any impaired
property is transferred to the balance of oil and gas properties being depleted.
Proved Reserve Estimates. Our discounted present value of proved oil
and natural gas reserves is a major component of the ceiling calculation, and
represents the component that requires the most subjective judgments. Estimates
of reserves are forecasts based on engineering data, projected future rates of
production and the timing of future expenditures. The process of estimating oil
and natural gas reserves requires substantial judgment, resulting in imprecise
determinations, particularly for new discoveries. Different reserve engineers
may make different estimates of reserve quantities based on the same data. Our
reserve estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. However, there can be no assurance that more significant
revisions will not be necessary in the future. If future significant revisions
are necessary that reduce previously estimated reserve quantities, it could
result in a full cost ceiling writedown. In addition to the impact of these
estimates of proved reserves on calculation of the ceiling, estimates of proved
reserves are also a significant component of the calculation of depreciation,
depletion and amortization.
While the quantities of proved reserves require substantial judgment,
the associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. Accounting
principles generally accepted in the United States require that prices and costs
in effect as of the last day of the period are held constant indefinitely.
Accordingly, the resulting value is not indicative of the true fair value of the
reserves. Oil and natural gas prices have historically been cyclical and, on any
particular day at the end of a quarter, can be either substantially higher or
lower than prices we actually receive in the long-term, which are a barometer
for true fair value.
Use of Estimates. The preparation of financial statements in accordance
with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect reported
assets, liabilities, expenses, and some narrative disclosures. Hydrocarbon
reserves, future development costs and certain hydrocarbon production expense
are the most critical estimates to our financial statements.
Derivatives. The Financial Accounting Standards Board issued SFAS No.
133 and SFAS No. 138 requiring that all derivative instruments be recorded on
the balance sheet at their respective values. SFAS No. 133 and SFAS No. 138 are
effective for all fiscal quarters of all fiscal years beginning after June 30,
2000. We adopted SFAS No. 133 and SFAS No. 138 on January 1, 2001. For the
periods prior to January 1, 2003, derivative contracts were not designated as
hedges. Accordingly, the unrealized gains or losses were recorded in income. As
of January 1, 2003 we designated costless collars, oil and gas swaps, and
interest rate swaps as cash flow hedges. Accordingly, the effective portion of
the unrealized gain or loss on cash flow hedges is recorded in other
comprehensive income until the forecasted transaction occurs. We
-48-
continued to record the unrealized loss on put positions outstanding in income
during 2003. The purpose of our hedges is to provide a measure of stability in
our oil and gas prices and interest rate payments and to manage exposure to
commodity price and interest rate risk under existing sales contracts.
Overhead Reimbursement - Joint Operations. As compensation for
administration, supervision office services and warehousing cost, an operator
may charge drilling and producing overhead costs based upon rates negotiated in
the joint operating agreement.
Overhead reimbursements charged to working interest owners for
properties that we operate are treated as reductions in general and
administrative expense for producing overhead. For 2003, capital costs were
reduced by approximately $34,000 and general and administrative costs were
reduced by approximately $123,000 for drilling and producing overhead
reimbursements.
Prior to 2003, overhead was recorded as other income. The amounts
reimbursed to us for 2002 and 2001 were $20,000 and $24,000 respectively.
Years Ended December 31, 2003 and December 31, 2002
Oil and Gas Revenues. Our total oil and gas revenues for 2003 were
$33.9 million, an increase of $21.8 million, or approximately 180%, from $12.1
for 2002. The increase in revenues for 2003, compared to 2002, is related to a
106% increase in oil and gas production due to the Fullerton acquisition on
December 20, 2002, two additional productive wells drilled in 2003 in the Cook
Mountain along with a full year's production of the Murphy #1 and a 36% increase
in the average sales price per BOE including hedges. On an equivalent barrel
basis, 2003 production totaled 1.2 million BOE compared with 576,000 BOE in
2002, approximately a 612,000 BOE increase.
Lease Operating Expense. The increase in lease operating expense for
2003, compared with 2002, was primarily the result of increased lease operating
expense associated with the waterfloods on Fullerton and Diamond M properties.
Lease operating costs increased $4.4 million or 210%, to $6.5 million for the
twelve months ended December 31, 2003, from $2.1 million for the same period of
2002.
General and Administrative Costs. Overall general and administrative
expenses increased $2.2 million or approximately 102% to $4.3 million for the
year ended December 31, 2003. General and administrative expenses for the same
period of 2002 were $2.1 million. The increase in general and administrative
expenses was primarily due to additional personnel in conjunction with the
implementation of our new business plan in June 2002 and increased public
reporting costs. . General and administrative expense included in oil and gas
properties is $915,000 and $1.3 million for 2003 and 2002 respectively.
Depreciation Depletion and Amortization Expense. Depreciation,
depletion and amortization expenses for 2003 increased $2.2 million or
approximately 35% to $8.4 million as compared to $6.2 million in 2002. The
increase was primarily attributable to the 106% increase
-49-
in production volumes for the year ended December 31, 2003 and associated
depletable property base in connection with our property acquisitions.
Depreciation, depletion and amortization expenses did not increase at a
comparable rate to production volume increases because with the addition of the
Fullerton properties in late 2002, our depreciation, depletion and amortization
rate on a BOE basis decreased from $10.52 in 2002 to $6.83 in 2003.
Equity in Income of First Permian, L.P. As discussed in Note 3 to the
Financial Statements, First Permian, L.P. sold all of its oil and gas properties
on April 8, 2002. As the owner of a 30.675% interest in First Permian, we
received our prorata share of the net sales proceeds, or $5.5 million in cash
and 933,589 shares of common stock of Energen Corporation. Our pro rata share of
the net income and distributions for 2002 was $31.0 million.
Incentive Awards attributable to the sale of First Permian, L.P. The
Incentive Awards reflect bonus payments made to certain officers and employees
in 2002 as a result of First Permian's sale of all of its assets.
Loss on Marketable Securities. We recognized a loss in marketable
securities for the year ended December 31, 2002 in the amount of approximately
$717,000, which resulted from our sales of 933,589 shares, all of our investment
of Energen common stock. This loss represents the difference in Energen's stock
price of $27.40 per share at the time of the First Permian sale and our realized
net price of approximately $26.63 per share.
Change in Fair Value of Derivatives. We recognized a loss of
approximately $22,000 for the year ended December 31, 2003 compared to a loss of
$948,000 for the same period of 2002. The loss of $22,000 in 2003 was
attributable to the expiration of put options not designated as cash flow
hedges. The decrease from 2002 to 2003 is primarily due to our adopting cash
flow hedge accounting which allows us to record changes in fair value of
contracts designated as cash flow hedges through other comprehensive income
until realized. When realized, we reflect the gain or loss on commodity
derivatives designed as cash flow hedges in revenue and on interest rate
derivative designated as cash flow hedges in interest expense. See Note 5 to the
Financial Statements.
Gain (loss) in Ineffective Portion of Hedges. The gain on the
ineffective portion of our hedges was $191,000 for 2003. We did not use hedge
accounting for derivatives prior to 2003.
Dividend Income. Dividend income during 2002 was approximately $371,000
associated with our investment in and ownership of Energen common stock. All of
our investment in Energen stock was sold in 2002.
Interest Expense. Interest expense increased $1.4 million or 241% to
$2.0 million for the year ended December 31, 2003, from approximately $601,000
for the same period of 2002. This increase was due principally to increased bank
borrowings associated with our acquisitions, partially offset by a decrease in
the minimum interest rate under our revolving credit facility. The minimum
interest rate decreased from 4.75% to 4.50% in December 2002.
-50-
Income Tax Benefit (Expense) Deferred. For the period ended December
31, 2003, we recorded federal and state income tax expense of $3.9 million and a
credit of $900,000, which was a reduction of our estimate of State income tax
liability, respectively compared to an income tax expense of $8.8 million and
$932,000, respectively in 2002. See Note 8 to the Financial Statements.
Net Income. Our net income for 2003 was $7.6 million a decrease of
$11.1 million or approximately 59% compared to $18.7 million for 2002. The
decrease was principally due to the gain on sale of First Permian, L.P. and
dividend income from the Energen stock recognized in 2002. Other items
affecting net income include:
. a 106% increase in oil and gas production due to the Fullerton
acquisition and increased production at Cook Mountain along with
a 36% increase in sales price per BOE;
. a 210% increase in lease operating expense due to increased
production and operating costs associated with water flood
projects;
. a 102% increase in general and administrative costs due to a full
year of our business plan in place, which included increased
staffing needs and associated costs. We are also experiencing
increased public reporting costs due to expanded reporting
requirements and activity.
Years Ended December 31, 2002 and December 31, 2001
Oil and Gas Revenues. Our total oil and gas revenues for 2002 were
$12.1 million, a decrease of $5.7 million, or approximately 32%, from $17.8
million for 2001. The decrease in revenues for 2002, compared to 2001, is
related to a 20% decline in the average price we received for our oil and
natural gas production volumes, and a 16% decline in oil and natural gas
production volumes on a BOE basis. On an equivalent barrel basis, 2002
production totaled 576,000 BOE compared with 682,000 BOE in 2001. The decrease
in natural gas production was primarily due to production declines, which was
partially offset by our drilling activities in 2002.
Lease Operating Expense. The decrease in lease operating expenses for
2002, compared with 2001, was primarily the result of decreased production
volumes and, to a lesser extent, reduction in ad valorem taxes and other direct
operating expenses. Production costs decreased $656,000 or 24%, to $2.1 million
for the twelve months ended December 31, 2002, from $2.7 million for the same
period of 2001.
General and Administrative Costs. Overall general and administrative
expenses increased $807,000 or 60% to $2.2 million for the year ended December
31, 2002. General and administrative expenses for the same period of 2001 were
$1.3 million. The increase in general and administrative expenses was primarily
due to increased public reporting costs, increased costs associated with our new
office and increased staffing for six months ending 2002 associated with our new
business plan. General and administrative expense included in oil and gas
properties is $1.3 million and $782,000 for 2002 and 2001 respectively.
-51-
Depreciation Depletion and Amortization Expense. Depreciation,
depletion and amortization expenses for 2002 were slightly lower at $6.2
million, as compared to $6.3 million in 2001. The decline was attributable to an
increase in reserves as of December 31, 2002, which was partially offset by an
increase in net depletable property basis.
Impairment of Oil and Gas Properties. We recognized a noncash
impairment charge of $16.8 million in 2001 related to our oil and gas reserves
and unproved properties. The impairment of oil and gas assets was primarily the
result of significantly lower oil and natural gas prices on both proved and
unproved oil and gas properties. An impairment was not recognized in 2002.
Equity in Income of First Permian, L.P. As discussed in Note 6 to the
Financial Statements, First Permian, L.P. sold all of its oil and gas properties
on April 8, 2002. As the owner of a 30.675% interest in First Permian, we
received our prorata share of the net sales proceeds, or $5.5 million in cash
and 933,589 shares of common stock of Energen Corporation. Our pro rata share of
the net income and distributions for 2002 was $31.0 million.
Incentive Awards attributable to the sale of First Permian, L.P. The
Incentive Awards reflect bonus payments made to certain officers and employees
in 2002 as a result of First Permian's sale of all of its assets.
Loss on Marketable Securities. We recognized a loss in marketable
securities in the amount of approximately $717,000, which resulted from our
sales of 933,589 shares, all of our investment, of Energen common stock during
2002. This loss represents the difference in Energen's stock price of $27.40 per
share at the time of the First Permian sale and our realized net price of
approximately $26.63 per share.
Change in Fair Value of Derivatives. We also recognized a loss of
$948,000 which represented the decrease in fair value of our natural gas puts of
$508,000 and mark-to-market accounting for approximately $440,000. See Note 5 to
the Financial Statements.
Dividend Income. Dividend income during 2002 was $371,000 associated
with our investment in and ownership of Energen common stock.
Interest Expense. Interest expense decreased $201,000 or 25% to
$601,000 for the year ended December 31, 2002, from $802,000 for the same period
of 2001. This decrease was principally a result of a decrease in average
borrowings associated with the redeployment of cash from the sale of the Energen
stock and lower interest rates.
Income Tax Benefit (Expense) Deferred. For the period ended December
31, 2002, we recorded federal and state income tax expense of $8.7 million and
$932,000, respectively. See Note 8 to the Financial Statements.
Net Income (Loss). Our income, before preferred stock dividends, was
$18.7 million for the year ended December 31, 2002, compared with a loss of $4.7
million for the year ended
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December 31, 2001. In 2002, income of $29.7 million resulted entirely from the
sale of First Permian's oil and gas properties, net of incentive awards
attributable to First Permian's sale of its assets. Other items affecting net
income included:
. a 32% decrease in oil and gas revenues related to a decline in
volumes and average price received;
. decreased production costs of approximately 27% primarily related
to decreased production volumes and, to a lesser extent,
reductions in ad valorem taxes and other direct operating
expenses,
. increased general and administrative expenses of 60%, increased
public reporting costs, increased costs associated with our new
office and increased staffing needs associated with our new
business plan; and
. non-cash charges associated with the sale of Energen stock, fair
market value of our put options and mark to market of the crude
oil swaps.
Capital Resources and Liquidity
Our capital resources consist primarily of cash flows from our oil and
gas properties and bank borrowings supported by our oil and gas reserves. Our
level of earnings and cash flows depends on many factors, including the prices
we receive for oil and natural gas we produce.
Working capital increased 92% or $7.9 million as of December 31, 2003
compared with December 31, 2002. Current assets exceeded current liabilities by
$16.4 million at December 31, 2003. The working capital increase was primarily
due to the private placement of 4.0 million shares of common stock with gross
proceeds of $13.0 million and no current maturities on our revolving credit
facility and increased receivables associated with increased oil and gas volumes
and prices. See Note 9.
The following table summarizes our cash flows from operating, investing
and financing activities:
Year ended December 31,
----------------------------------------
2003 2002 2001
------------- ------------ -------------
(in thousands)
Operating activities $ 19,465 $ 1,528 $ 13,383
Investing activities $(15,494) $(30,277) $(11,357)
Financing activities $ 1,595 $ 37,210 $ (676)
Cash from operating activities in 2003 increased $17.9 million over
2002 largely due to increased operating income from the Fullerton acquisition,
increased production in the Cook Mountain Gas project and increased sales prices
in 2003. Investing and financing activities
-53-
decreased in 2003 compared to 2002 primarily as a result of the Fullerton
acquisition in 2002. These declines were partially offset by proceeds from the
First Permian asset sale also recorded in 2002.
Cash provided from operating activities declined $11.9 million in 2002
compared to 2001 primarily due to reduced production and product prices.
Investing and financing activities increased in 2002 compared to 2001 primarily
as a result of the Fullerton acquisition.
We incurred net property costs of $14.9 million for the period ended
December 31, 2003, primarily for our oil and gas property leasehold acquisition,
development, and enhancement activities. Also added to our property basis were
asset retirement costs of $1.5 million for the adoption of SFAS 143 (see Note
4). The property leasehold acquisition, development and enhancement activities
were financed by the utilization of cash flows provided by operations.
Based on our projected oil and gas revenues and related expenses and
available bank borrowings, we believe that we will have sufficient capital
resources to fund normal operations and capital requirements, interest expense
and principal reduction payments on bank debt, if required, and preferred stock
dividends. We continually review and consider alternative methods of financing.
Bank Borrowings
On December 20, 2002, Parallel and its subsidiary, Parallel, L.P.,
entered into a First Amended and Restated Credit Agreement with First American
Bank, SSB, Western National Bank and BNP Paribas. The credit facility provides
for revolving loans. This means that we can borrow, repay and reborrow funds
drawn under the credit facility. However, the aggregate amount that we can
borrow and have outstanding at any one time is subject to a borrowing base. The
borrowing base calculation is based primarily upon the estimated value of our
oil and gas reserves. Generally, we can borrow only up to the borrowing base in
effect from time to time. The borrowing base amount is redetermined by the banks
on or about April 1 and October 1 of each year or at other times required by the
banks or at our request. If, as a result of the banks' redetermination of the
borrowing base, the outstanding principal amount of our loan exceeds the
borrowing base, we must either provide additional collateral to the banks or
prepay the principal of the note in an amount equal to the excess. Except for
the principal payments that may be required because of our outstanding loans
being in excess of the borrowing base, interest only is payable monthly.
The credit agreement was amended in September 2003. The amendment
included:
. the deletion of the monthly commitment reduction, a provision
that would have required us to begin amortizing our loan
beginning August 31, 2003;
. the modification of certain financial ratio tests;
. an increase in our borrowing base to $50 million;
. changes in certain reporting requirements to the banks; and
-54-
. the revision of covenants in the credit agreement governing our
hedging activities.
The principal amount outstanding under the revolving credit facility
was $39.8 million at December 31, 2003. This facility bears interest at First
American Bank's base rate or the libor rate, at our election. Generally, First
American Bank's base rate is equal to the prime rate published in the Wall
Street Journal, but not less than 4.50%. The libor rate is generally equal to
the sum of (a) the rate designated as "British Bankers Association Interest
Settlement Rates" and offered on one, two, three or six month interest periods
for deposits of $1.0 million, and (b) a margin ranging from 2.25% to 2.75%,
depending upon the outstanding principal amount of the loans. The interest rate
we are required to pay, including the applicable margin, may never be less than
4.50%. If the principal amount outstanding is equal to or greater than 75% of
the borrowing base established by the banks, the margin is 2.75%. If the
principal amount outstanding is equal to or greater than 50%, but less than 75%
of the borrowing base, the margin is 2.50%. If the principal amount outstanding
is less than 50% of the borrowing base, the margin is 2.25%.
In the case of base rate loans, interest is payable on the last day of
each month. In the case of libor loans, interest is payable on the last day of
each applicable interest period.
If the total outstanding borrowings under the facility are less than
the borrowing base, an unused commitment fee is required to be paid to the bank
lenders. The amount of the fee is .25% of the daily average of the unadvanced
amount of the borrowing base. The fee is payable quarterly.
All outstanding principal under the revolving credit facility is due
and payable on December 20, 2006. The loan is secured by substantially all of
our oil and gas properties, including the properties Parallel, L.P. Parallel,
L.L.C., a subsidiary of Parallel Petroleum Corporation, guaranteed payment of
the loans.
We are highly dependent on bank borrowings to fund our exploration and
drilling activities. The borrowing base calculation is based upon the estimated
value of oil and gas reserves. If our borrowing base declines significantly, our
liquidity would be suddenly and materially limited.
If the borrowing base is increased, we are required to pay a fee of
..25% on the amount of any increase in the borrowing base.
Our obligations to the bank are secured by substantially all of our oil
and gas properties. Our bank borrowings have been incurred to finance our
property acquisition, 3-D seismic surveys, enhancement and drilling activities.
In addition to customary affirmative covenants, the credit agreement
contains various restrictive covenants and compliance requirements, including:
. maintaining certain financial ratios;
-55-
. limitations on incurring additional indebtedness;
. prohibiting the payment of dividends on our common stock;
. limitations on the disposition of assets; and
. prohibiting liens (other than in favor of the lenders) to exist
on any of our properties.
If we have borrowing capacity under our credit agreement, we intend to
borrow, repay and reborrow under the revolving credit facility from time to time
as necessary, subject to borrowing base limitations, to fund:
. interpretation and processing of 3-D seismic survey data;
. lease acquisitions and drilling activities;
. acquisitions of producing properties or companies owning
producing properties and;
. general corporate purposes.
Preferred Stock
At December 31, 2003 we had 959,500 shares of 6% convertible preferred
stock outstanding. The preferred stock:
. required us to pay dividends of $.60 per annum, semi-annually on
June 15 and December 15 of each year;
. is convertible into common stock at any time, at the option of
the holder, into 2.8751 shares of common stock at an initial
conversion price of $3.50 per share, subject to adjustment in
certain events;
. is redeemable at our option, in whole in part, for $10 per share,
plus accrued dividends;
. has no voting rights, except as required by applicable law, and
except that as long as any shares of preferred stock remain
outstanding, the holders of a majority of the outstanding shares
of the preferred stock may vote on any proposal to change any
provision of the preferred stock which materially and adversely
affects the rights, preferences or privileges of the preferred
stock;
. is senior to the common stock with respect to dividends and on
liquidation, dissolution or winding up of Parallel;
. has a liquidation value of $10 per share, plus accrued and unpaid
dividends.
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Commodity Price Risk Management Transactions
During 2001, we did not use derivative contracts. For the year ended
December 31, 2002, we used mark-to-market accounting for all our derivative
contracts. As of January 1, 2003 we designated the costless collars, oil and gas
swaps and interest rate swaps as cash flow hedges under the provisions of SFAS
133, as amended. We continued mark-to-market accounting for our put positions.
The purpose of our hedges is to provide a measure of stability in our oil and
gas prices and interest rate payments and to manage exposure to commodity price
and interest rate risk. Our objective is to lock in a range of oil and gas
prices and a fixed interest rate for certain notional amounts.
Under cash flow hedge accounting, the quarterly change in the fair
value of the commodity derivatives is recorded in stockholders' equity as other
comprehensive income (loss) and then transferred to revenue when the production
is sold. Ineffective portions of cash flow hedges (changes in realized prices
that do not match the changes in the hedge price) are recognized in other
expense as they occur. While the cash flow hedge contract is open, the
ineffective gain or loss many increase or decrease until settlement of the
contract.
Under cash flow hedge accounting for interest rate swaps, the quarterly
change in the fair value of the derivatives is recorded in stockholders' equity
as other comprehensive income (loss) and then transferred to interest expense
when the contract settles. Ineffective portions of cash flow hedges are
recognized in other expense as they occur.
We are exposed to credit risk in the event of nonperformance by the
counterparty in its derivative instruments. However, we periodically assess the
creditworthiness of the counterparty to mitigate this credit risk.
Certain of our commodity price risk management arrangements have
required us to deliver cash collateral or other assurances of performance to the
counterparties in the event that our payment obligations with respect to our
commodity price risk management transactions exceed certain levels.
For additional information about our price risk management
transactions, see Item 7A of this Annual Report on Form 10-K, beginning on page
62.
Future Capital Requirements
Our capital expenditure budget for 2004 is approximately $17.0 million
and is highly dependent on future oil and gas prices and the availability of
funding. These expenditures will be governed by the following factors:
. internally generated cash flows;
. availability of borrowing under our revolving credit facility;
-57-
. additional sources of financing; and
. future drilling successes.
In 2003, we have focused on drilling lower risk natural gas prospects
that could have a meaningful effect on our reserve base and cash flows. In
selected cases, we may elect to reduce our interest in higher risk, higher
impact projects. We may also sell certain non-core producing properties to raise
funds for capital expenditures.
Contractual Obligations, Commitments and Off-Balance Sheet Arrangements
We have contractual obligations and commitments that may affect our
financial position. However, based on our assessment of the provisions and
circumstances of our contractual obligation and commitments, we do not feel
there would be an adverse effect on our consolidated results of operations,
financial condition or liquidity.
The following table is a summary of significant contractual
obligations:
Obligation Due in Period
-----------------------------------------------------------------------------------------------
After 5
Contractual Cash Obligations 2004 2005 2006 2007 2008 years Total
- ---------------------------------- -------------- ------------- ------------ ------------- ------------- ----------- ------------
(in thousands)
Revolving Credit Facility (secured) $ - $ - $ 39,750 $ - $ - $ - $ 39,750
Office Lease (Dinero Plaza) 128 157 105 - - - 390
Preferred Stock Dividend 574 574 574 574 574 (2) 2,870
Other Long-term Liabilities(1) 503 38 66 66 30 998 1,701
Derivative Obligations 3,231 1,673 982 - - - 5,886
------- ------- -------- ------- -------- ------- --------
Total $ 4,436 $ 2,442 $ 41,477 $ 640 $ 604 $ 998 $ 50,597
======= ======= ======== ======= ======== ======= ========
- ------------
(1) Assets retirement obligations of oil and natural gas assets, excluding
salvage value.
(2) Payments of preferred dividends so long as preferred stock remains
outstanding and not converted.
Deferred taxes are not included in the table above. The utilization of
net operating loss carryforwards combined with our plans for development and
acquisitions may offset any major cash outflows. However, the ultimate timing of
the settlements cannot be precisely determined. Purchase obligations are not
included in the table because they are not considered material.
In addition to our principal payment obligations under the revolving
credit facility payment noted in the table above, we are subject to interest
payments on such indebtedness. See Note 7 to the Financial Statements.
-58-
We have no off-balance sheet financing arrangements or any
unconsolidated special purpose entities.
Outlook
The oil and gas industry is capital intensive. We make, and anticipate
that we will continue to make, substantial capital expenditures in the
exploration for, development and acquisition of oil and gas reserves.
Historically, our capital expenditures have been financed primarily with:
. internally generated cash from operations;
. proceeds from bank borrowings; and
. proceeds from sales of equity securities.
The continued availability of these capital sources depends upon a
number of variables, including:
. our proved reserves;
. the volumes of oil and gas we produce from existing wells;
. the prices at which we sell oil and gas; and
. our ability to acquire, locate and produce new reserves.
Each of these variables materially affects our borrowing capacity. We
may from time to time seek additional financing in the form of:
. increased bank borrowings;
. sales of Parallel's securities;
. sales of non-core properties; or
. other forms of financing.
We do not have agreements for any future financing and there can be no
assurance as to the availability or terms of any such financing.
-59-
Inflation
Inflation has not had a significant impact on our financial condition
or results of operations. We do not believe that inflation poses a material risk
to our business.
Recent Accounting Pronouncements
FIN No. 45, Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Other. FIN No. 45
requires that a liability be recorded in the guarantor's balance sheet upon
issuance of certain guarantees. Initial recognition and measurement of the
liability will be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. FIN No. 45 also requires disclosures about
guarantees in financial statements for interim or annual periods ending after
December 15, 2002. The adoption of FIN No. 45 did not have a material impact on
the Company's consolidated financial statements.
FIN No. 46, Consolidation of Variable Interest Entities. In December
2003, the FASB issued Interpretation No. 46R, Consolidation of Variable Interest
Entities" ("FIN 46"), which requires the consolidation of certain entities that
are determined to be variable interest entities ("VIE"). An entity is considered
to be a VIE when either (i) the entity lacks sufficient equity to carry on its
principal operations, (ii) the equity owners of the entity cannot make decisions
about the entity's activities or (iii) the entity's equity neither absorbs
losses or benefits from gains. The Company owns no interests in variable
interest entities, and therefore this new interpretation has not affected the
Company's consolidated financial statements.
In March 2003, the Financial Accounting Standards Board issued SFAS No.
148, Accounting for Stock-Based Compensation-Transition and Disclosure, which
amends SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 148
provides alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. As of
September 30, 2003, the Company adopted the Prospective method which applies
prospectively the fair value recognition method to all employee and director
awards granted, modified or settled after the beginning of the fiscal year in
which the fair value based method of accounting for stock-based compensation is
adopted. SFAS 148 also amends the disclosure requirements of SFAS No. 123 to
require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results.
In April, 2003, the Financial Accounting Standards Board issued SFAS
No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging
Activities, which clarifies financial accounting and reporting for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. The Statement is effective for
contracts entered into or modified after June 20, 2003. The adoption of SFAS 149
did not have a material impact on the Company's consolidated financial
statements.
In May, 2003, the Financial Accounting Standards Board issued SFAS No.
150
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"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity." This statement establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity. This statement was effective for financial
instruments entered into or modified after May 31, 2003, and otherwise was
effective at the beginning of the first interim period beginning after June 15,
2003. The adoption of SFAS 150 did not have a material impact on the Company's
consolidated financial statements.
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive
industries, including oil and gas companies. The issue is whether SFAS No. 142
requires registrants to classify the costs of mineral rights held under lease or
other contractual arrangements associated with extracting oil and gas as
intangible assets in the balance sheet, apart from other capitalized oil and gas
property costs, and provide specific footnote disclosures. Historically,
Parallel has included the costs of such mineral rights associated with
extracting oil and gas as a component of oil and gas properties. If it is
ultimately determined that SFAS No. 142 requires oil and gas companies to
classify costs of mineral rights held under lease or other contractual
arrangement associated with extracting oil and gas as a separate intangible
assets line item on the balance sheet, the Company would be required to
reclassify approximately $17.3 million at December 31, 2003 and $13.5 million at
December 31, 2002 out of Oil and Gas Properties and into a separate intangible
assets line item. Parallel's cash flows and results of operations would not be
affected since such intangible assets would continue to be depleted and assessed
for impairment in accordance with full cost accounting rules.
Effects of Derivative Instruments
For the year ended December 31, 2002, we used mark-to-market accounting
for all our derivative contracts. As of January 1, 2003 we designated the
costless collars, oil and gas swaps and interest rate swaps as cash flow hedges
under the provisions of SFAS 133, as amended. The adoption of cash flow hedge
accounting allows us to record changes in fair value of contracts designated as
cash flow hedges through other comprehensive income until realized. When
realized, we reflect the gain or loss on commodity derivatives designated as
cash flow hedges in revenue and on interest rate derivatives designated as cash
flow hedges in interest expense. We continued mark-to-market accounting for our
put positions. The purpose of our hedges is to provide a measure of stability in
our oil and gas prices and interest rate payments and to manage exposure to
commodity price and interest rate risk. Our objective is to lock in a range of
oil and gas prices and a fixed interest rate for certain notional amounts.
Under cash flow hedge accounting, the quarterly change in the fair
value of the derivatives is recorded in stockholders' equity as other
comprehensive income (loss) and then transferred to earnings when the production
is sold. Ineffective portions of cash flow hedges (changes in realized prices
that do not match the changes in the hedge price) are recognized in other
expense as they occur. While the cash flow hedge contract is open, the
ineffective gain or loss many increase or decrease until settlement of the
contract.
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We are exposed to credit risk in the event of nonperformance by the
counterparty in its derivative instruments. However, we periodically assess the
creditworthiness of the counterparty to mitigate this credit risk.
- -------------------------------------------------------------------------------
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- -------------------------------------------------------------------------------
The following quantitative and qualitative information is provided about market
risks and derivative instruments to which Parallel was a party at December 31,
2003, and from which Parallel may incur future earnings, gains or losses from
changes in market interest rates and oil and natural gas prices.
Interest Rate Sensitivity as of December 31, 2003
Our only financial instrument sensitive to changes in interest rates is
our bank debt. As the interest rate is variable and reflects current market
conditions, the carrying value approximates the fair value. The table below
shows principal cash flows and related weighted average interest rates by
expected maturity dates. Weighted average interest rates were determined using
weighted average interest paid and accrued in December, 2003. You should read
Note 7 to the Financial Statements for further discussion of our debt that is
sensitive to interest rates.
2004 2005 2006 2007 2008 Total
---------- ---------- ------------ ------------ ------------ -----------
(in thousands, except interest rates)
Variable rate debt $ - $ - $ 39,750 $ - $ - $ 39,750
Revolving Facility (secured) 4.50% 4.50% 4.50% - - -
Average interest rate
At December 31, 2003, we had bank loans in the amount of approximately
$39.7 million outstanding at an average interest rate of 4.50%. Borrowings under
our credit facility bear interest, at our election, at (i) the bank's base rate
or (ii) the libor rate, plus libor margin, but in no event less than 4.50%. As a
result, our annual interest cost in 2004 will fluctuate based on short-term
interest rates. As the interest rate is variable and is reflective of current
market conditions, the carrying value approximates the fair value.
Under our credit facility, we may elect an interest rate based upon the
agent lender's base lending rate, or the libor rate, plus a margin ranging from
2.25% to 2.75% per annum, depending on our borrowing base usage. The interest
rate we are required to pay, including the applicable margin, may never be less
than 4.50%.
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In January, 2003, we entered into a 45-month libor fixed interest rate
swap contract with BNP Paribas. We will receive fixed 90-day libor interest
rates for the 45-month period beginning March 31, 2003 through December 20,
2006.
A recap for the period of time, notional amounts, libor fixed interest
rates, expected margin rates and expected fixed interest rates for the contract
are as follows:
Libor Expected Expected
Period of Time Notional Amounts(1) Fixed Interest Rates(2) Margin Rates(3) Fixed Interest Rates(4)
- ---------------------------------- ----------------------- ------------------------ ------------------ ------------------------
Dec 31, 2003 thru Dec 31, 2004 $ 30,000,000 2.660% 2.500% 5.160%
Dec 31, 2004 thru Dec 31, 2005 $ 20,000,000 4.050% 2.250% 6.300%
Dec 31, 2005 thru Dec 20, 2006 $ 10,000,000 4.050% 2.250% 6.300%
- ----------------
(1) Based on the anticipated principal reductions under our credit facility.
(2) Parallel's swap contract with BNP Paribas.
(3) Based on the anticipated borrowing base usage under our credit facility.
(4) Total of the libor fixed interest rate plus the expected margin rate under
our credit facility.
Commodity Price Sensitivity as of December 31, 2003
Our major market risk exposure is in the pricing applicable to our oil
and natural gas production. Market risk refers to the risk of loss from adverse
changes in oil and natural gas prices. Realized pricing is primarily driven by
the prevailing domestic price for crude oil and spot prices applicable to the
region in which we produce natural gas. Historically, prices received for oil
and gas production have been volatile and unpredictable. We expect pricing
volatility to continue. Oil prices ranged from a low of $16.49 per barrel to a
high of $36.60 per barrel during 2003. Natural gas prices we received during
2003 ranged from a low of $1.98 per Mcf to a high of $10.28 per Mcf. A
significant decline in the prices of oil or natural gas could have a material
adverse effect on our financial condition and results of operations.
Put Options. On May 24, 2002 we purchased put floors on volumes of
100,000 Mcf per month for a total of 700,000 Mcf during the seven month period
from April 2003 through October 2003 at a floor price of $3.00 per Mcf for a
total consideration of $139,500. These derivatives are not held for trading
purposes.
A decrease in fair value of the put floors of approximately $22,000 was
recognized for the period ended December 31, 2003 in our consolidated statements
of operations.
Costless Collar. Collars are created by purchasing puts to establish a
floor price and then selling a call which establishes a maximum amount the
producer will receive for the oil or gas hedged. Calls are sold to offset or
reduce the premium paid for buying the put. We did not have any collars in place
during 2002. In 2003, we entered into several costless, seven-month
-63-
Houston ship channel gas collars. A majority of our natural gas production is
sold based on Houston ship channel prices. A recap for the period of time,
number of MMBtu's and gas prices is as follows:
Houston Ship Channel
gas prices
MMBtu of ---------------------------------
Period of Time Natural Gas Floor Cap
- --------------------------------------------- ------------- ------------ -------------------
January 1, 2004 thru March 31, 2004 273,000 $ 5.43 $ 6.58
April 1 2004 thru October 31, 2004 214,000 $ 4.40 $ 5.50
Swaps. Generally, swaps are an agreement to buy or sell a specified
commodity for delivery in the future, but at an agreed fixed price. Swap
transactions convert a floating price into a fixed price. For any particular
swap transaction, the counterparty is required to make a payment to the hedge
party if the reference price for any settlement period is less than the swap
price for such hedge, and the hedge party is required to make a payment to the
counterparty if the reference price for any settlement period is greater than
the swap price for such hedge.
In 2003, we entered into oil and gas swap contracts with BNP Paribas. A
recap for the period of time, number of MMBtu's, number of barrels, and swap
prices are as follows:
Barrels Houston Ship
of Nymex Oil MMBtu of Channel
Period of Time Oil Swap Price Natural Gas Gas Swap Price
- -------------------------------------------------- ------------- -------------- --------------- -------------------
January 1, 2004 thru December 31, 2004 439,200 $ 24.45 - $ -
April 1, 2004 thru December 31, 2004 - $ - 764,000 $ 4.692
January 1, 2005 thru December 31, 2005 365,000 $ 23.35 - $ -
January 1, 2005 thru March 31, 2005 - $ - 180,000 $ 4.705
January 1, 2006 thru December 20, 2006 265,500 $ 23.04 - $ -
- -------------------------------------------------------------------------------
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- -------------------------------------------------------------------------------
Parallel's financial statements and supplementary financial data are
included in this report beginning on page F-1.
-64-
- -------------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
- -------------------------------------------------------------------------------
Resignation of KPMG LLP
On December 4, 2003, we received written notice from KPMG LLP
confirming that the client-auditor relationship between Parallel and KPMG had
ceased as of December 2, 2003. KPMG resigned due to an independence issue
arising from retirement benefits paid to Ray M. Poage, a former partner of KPMG
who is also a director of Parallel. For the period from April 28, 2003 to
December 2, 2003, Mr. Poage received eight monthly retirement payments from
KPMG, each in the amount of $856.26.
KPMG's audit reports on our financial statements for the two fiscal
years ended December 31, 2001 and December 31, 2002 did not contain an adverse
opinion or disclaimer of opinion and were not qualified or modified as to audit
scope or accounting principles.
During the two fiscal years ended December 31, 2001 and December 31,
2002 and the period from January 1, 2003 through December 2, 2003, there were no
disagreements between Parallel and KPMG on any matter of accounting principles
or practices, financial statement disclosure, or auditing scope or procedure,
which, if not resolved to the satisfaction of KPMG would have caused it to make
reference to the subject matter of the disagreement in connection with its
report on the financial statements for that period, nor have there been any
reportable events as defined under Item 304(a)(1)(v) or regulation S-K during
such period.
We provided KPMG with a copy of our Current Report on Form 8-K, dated
December 2, 2003 and filed with the SEC on December 9, 2003, reporting KPMG's
resignation. We requested that KPMG furnish us with a letter addressed to the
Securities and Exchange Commission stating whether it agreed with the statements
we made in our Form 8-K Report and, if not, stating the respects in which it did
not agree. KPMG's letter, filed as an exhibit to the Form 8-K Report, expressed
agreement with our statements.
Engagement of BDO Seidman, LLP
Effective January 20, 2004, we engaged BDO Seidman, LLP as the
principal accountant to audit our financial statements. The decision to engage
BDO Seidman was recommended and approved by the Audit Committee of our Board of
Directors.
During the two fiscal years ended December 31, 2001 and December 31,
2002 and during any subsequent interim period, BDO Seidman was not engaged as
either the principal accountant to audit our financial statements or as an
independent accountant to audit a significant subsidiary and on whom the
principal accountant was expected to express reliance on its report. In
addition, during the two most recent fiscal years and during any subsequent
interim period prior to engaging BDO Seidman, neither we, nor anyone on our
behalf consulted BDO Seidman
-65-
regarding (a) either the application of accounting principles to a specified
transaction, either completed or proposed, or the type of audit opinion that
might be rendered on our financial statements, and no written report was
provided to us and no oral advice was provided to us by BDO Seidman which was
considered by us in reaching a decision as to the accounting, auditing or
financial reporting issues; and (b) there was no matter that was a subject of
disagreement as defined in paragraph 304(a)(1)(iv) of Regulation S-K, or a
reportable event, as described in paragraph 304(a)(1)(v) of Regulation S-K.
- -------------------------------------------------------------------------------
ITEM 9A. CONTROLS AND PROCEDURES
- -------------------------------------------------------------------------------
We use certain disclosure controls and procedures to help ensure that
information we are required to disclose in reports that we file with the SEC is
accumulated and communicated to our management and recorded, processed,
summarized and reported within the time periods specified by the SEC. As of the
end of the period covered by this Annual Report on Form 10-K, the effectiveness
of our disclosure controls and procedures (as defined in Rules 13a-15(e) and
15d-15(e) promulgated under the Securities Exchange Act of 1934) was evaluated
by Larry C. Oldham, our President and Chief Executive Officer (principal
executive officer), and Steven D. Foster, our Chief Financial Officer (principal
financial officer). Mr. Oldham and Mr. Foster have concluded that our disclosure
controls and procedures are effective, as of the end of the period covered by
this Annual Report on Form 10-K, for their intended purposes.
There were no changes in our internal controls over financial reporting
that occurred during our last fiscal quarter (the quarter ended December 31,
2003) that have materially affected, or are reasonably likely to materially
affect our internal controls over financial reporting.
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PART III
- -------------------------------------------------------------------------------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- -------------------------------------------------------------------------------
The Directors and executive officers of Parallel at March 1, 2004 are
as follows:
Director
Name Age Since Position with Company
- ---------------------------------------- ------------ ------------ -------------------------------------------------------
Thomas R. Cambridge(1) 68 1985 Chairman of the Board of Directors
Larry C. Oldham(1) 50 1979 Director, President and Chief Executive Officer
Dewayne E. Chitwood (2)(3)(4) 67 2000 Director
Martin B. Oring(1)(2)(3)(4) 58 2001 Director
Charles R. Pannill(2)(4) 78 1982 Director
Ray M. Poage(2)(3)(4) 56 2003 Director
Jeffrey G. Shrader(1)(2)(4) 53 2001 Director
Donald E. Tiffin 46 - Chief Operating Officer
Eric A. Bayley 55 - Vice President of Corporate Engineering
John S. Rutherford 44 - Vice President of Land and Administration
Steven D. Foster 48 - Chief Financial Officer
__________
(1) Member of Hedging and Acquisitions Committee
(2) Member of Compensation Committee
(3) Member of Audit Committee
(4) Member of Corporate Governance and Nominating Committee
Mr. Cambridge is an independent petroleum geologist engaged in the
exploration for, development and production of oil and natural gas. From 1970
until 1990, his activities were carried out primarily through Cambridge & Nail
Partnership. Since 1990, Mr. Cambridge's oil and gas activities have been
carried out through Cambridge Production, Inc. He received a Bachelors degree in
geology from the University of Nebraska in 1958 and a Master of Science degree
in geology from the University of Nebraska in 1960. Mr. Cambridge served as
Chief Executive Officer of Parallel from 1987 until January 1, 2004 when Mr.
Oldham became Chief Executive Officer.
Mr. Oldham is a founder of Parallel and has served as an officer and
Director since its formation in 1979. Mr. Oldham became President of Parallel in
October, 1994, and served as Executive Vice President before becoming President.
Effective January 1, 2004, Mr. Oldham replaced Mr. Cambridge as Chief Executive
Officer. Mr. Oldham received a Bachelor of Business Administration degree from
West Texas State University in 1975.
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Mr. Chitwood is president, chief executive officer and a manager of
Wes-Tex Holdings, LLC, the general partner of Wes-Tex Drilling Company, L.P., a
partnership engaged in oil and gas exploration and production. During the
five-year period preceding Mr. Chitwood's association with Wes-Tex in 1997, he
was an owner and founder of CBS Insurance L.P., a general insurance agency.
Mr. Oring is the owner of Wealth Preservation, LLC, a financial
counseling firm founded by Mr. Oring in January, 2001. From 1998 to December,
2000, Mr. Oring was Managing Director Executive Services of Prudential
Securities Incorporated, and from 1996 to 1998, Mr. Oring was Managing Director
Capital Markets of Prudential Securities Incorporated. From 1989 to 1996, Mr.
Oring was Manager of Capital Planning for The Chase Manhattan Corporation.
Mr. Pannill was employed by The Western Company of North America for
over thirty years until his retirement in February, 1982. During his employment
with The Western Company of North America, Mr. Pannill served in various
capacities, including those of an executive officer and director. He received a
Bachelor of Science degree in Geology from Texas A&M University in 1950.
Mr. Poage was employed by KPMG LLP from 1972 until June 2002 when he
retired. Mr. Poage's responsibilities included supervising and managing both
audit and tax professionals and providing services, primarily in the area of
taxation, to private and publicly held companies engaged in the oil and gas
industry. He is a Certified Financial Planner and member of the American
Institute of Certified Public Accountants and the Texas Society of Certified
Public Accountants. At March 1, 2004 Mr. Poage was Chairman of the Audit
Committee of the Board of Directors of Parallel.
Mr. Shrader has been a shareholder in the law firm of Sprouse Shrader
Smith, Amarillo, Texas, since January, 1993. He has also served as a director of
Hastings Entertainment, Inc. since 1992. At March 1, 2004 Mr. Shrader was
Chairman of the Compensation Committee of the Board of Directors of Parallel.
Mr. Tiffin served as Vice President of Business Development from June,
2002 until January 1, 2004 when he became Chief Operating Officer. From August,
1999 until May, 2002, Mr. Tiffin served as General Manager of First Permian,
L.P. and from July, 1993 to July, 1999, Mr. Tiffin was the Drilling and
Production Manager in the Midland, Texas office of Fina Oil and Chemical
Company. Mr. Tiffin graduated from the University of Oklahoma in 1979 with a
Bachelor of Science degree in Petroleum Engineering.
Mr. Bayley has been Vice President of Corporate Engineering since July,
2001. From October, 1993 until July, 2001, Mr. Bayley was employed by Parallel
as Manager of Engineering. From December, 1990 to October, 1993, Mr. Bayley was
an independent consulting engineer and devoted substantially all of his time to
Parallel. Mr. Bayley graduated from Texas A&M University in 1978 with a Bachelor
of Science degree in Petroleum Engineering. He graduated from the University of
Texas of the Permian Basin in 1984 with a Master's of Business Administration
degree.
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Mr. Rutherford has been Vice President of Land and Administration of
Parallel since July, 2001. From October 1993 until July, 2001, Mr. Rutherford
was employed as Manager of Land/Administration. From May, 1991 to October, 1993,
Mr. Rutherford served as a consultant to Parallel, devoting substantially all of
his time to Parallel's business. Mr. Rutherford graduated from Oral Roberts
University in 1982 with a degree in Education, and in 1986 he graduated from
Baylor University with a Master's degree in Business Administration.
Mr. Foster has been the Chief Financial Officer of Parallel since June,
2002. From November, 2000 to May, 2002, Mr. Foster was the Controller and
Assistant Secretary of First Permian, L.P. and from September, 1997 to November
2000, he was employed by Pioneer Natural Resources, USA in the capacities of
Director of Revenue Accounting and Manager of Joint Interest Accounting. Mr.
Foster graduated from Texas Tech University in 1977 with a Bachelor of Business
Administration degree in accounting. He is a certified public accountant.
Directors hold office until the annual meeting of stockholders
following their election or appointment and until their respective successors
have been duly elected or appointed.
Officers are appointed annually by the Board of Directors to serve at
the Board's discretion and until their respective successors in office are duly
appointed.
There are no family relationships between any of Parallel's directors
or officers.
Consulting Arrangements
As part of our overall business strategy, we continually monitor our
general and administrative expenses. Decisions regarding our general and
administrative expenses are made within parameters we believe to be compatible
with our size, the level of our activities and projected future activities. Our
goal is to keep general and administrative expenses at acceptable levels,
without impairing the quality of services and organizational structure necessary
for conducting our business. In this regard, we retain outside advisors and
consultants from time to time to provide technical and administrative support
services in the operation of our business.
Corporate Governance
Pursuant to the Delaware General Corporation Law and Parallel's bylaws,
our business, property and affairs are managed by or under the direction of the
Board of Directors. Members of the Board are kept informed of Parallel's
business through discussions with the Chief Executive Officer and other
officers, by reviewing materials provided to them and by participating in
meetings of the Board and its committees. We currently have seven members of the
Board. The Board has determined that all of the Directors, other than Mr.
Cambridge and Mr. Oldham, are "independent" for the purposes of NASD Rule
4200(a)(15). The Board based these determinations primarily on responses of the
Directors and executive officers to questions regarding employment and
compensation history, affiliations and family and other relationships and on
discussions among the Directors.
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The Board has four standing committees:
. The Audit Committee;
. The Corporate Governance and Nominating Committee;
. The Compensation Committee; and
. The Hedging and Acquisitions Committee.
Audit Committee
The Audit Committee reviews the results of the annual audit of our
financial statements and recommendations of the independent auditors with
respect to our accounting practices, policies and procedures. As prescribed by
our Audit Committee charter, the Audit Committee is also responsible for
overseeing management's conduct of our financial reporting process, our systems
of internal accounting and financial controls, and the independent audit of our
financial statements. The Audit Committee is directly responsible for the
appointment, compensation, retention and oversight of the work of the auditors.
The Audit Committee of the Board of Directors consists of three
directors, all of whom have no financial or personal ties to Parallel (other
than director compensation and equity ownership as described in this Annual
Report on Form 10-K) and meet the Nasdaq standards for independence. The Board
of Directors has determined that at least one member of the Audit Committee, Ray
M. Poage, meets the criteria of an "audit committee financial expert" as that
term is defined in Item 401(h) of Regulation S-K, and is independent for
purposes of Nasdaq listing standards and Section 10A (m)(3) of the Securities
Exchange Act of 1934, as amended. Mr. Poage's background and experience includes
service as a partner of KPMG LLP where Mr. Poage participated extensively in
accounting, auditing and tax matters related to the oil and natural gas
business. The Audit Committee operates pursuant to a charter, which was revised
in March 2004. The charter can be viewed in our website on
www.parallel-petro.com.
From May 2001 until April 2003, the Audit Committee was composed of Mr.
Oring (Chairman), Mr. Pannill and Mr. Shrader. Upon Mr. Poage's appointment to
the Board of Directors in April 2003, Mr. Pannill resigned from the Audit
Committee and Mr. Poage was appointed Chairman of the Audit Committee. Mr.
Shrader resigned from the Audit Committee in October 2003, because the law firm
with which Mr. Shrader is affiliated provided legal services to Parallel. Mr.
Chitwood was then appointed to serve on the Audit Committee in place of Mr.
Shrader. Since October 2003, the members of the Audit Committee have been and
continue to be Messrs. Poage (Chairman), Chitwood and Oring.
Corporate Governance and Nominating Committee
At its March 15, 2004 meeting, the Board formed a Corporate Governance
and Nominating Committee and adopted a charter for this new committee. The
functions of the Corporate Governance and Nominating Committee will include:
recommending to the Board of
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Directors nominees for election as directors of Parallel, and making
recommendations to the Board of Directors from time to time as to matters of
corporate governance. The members of the new Corporate Governance and Nominating
Committee are Dewayne E. Chitwood, Martin B. Oring, Charles R. Pannill, Ray M.
Poage and Jeffrey G. Shrader. The Corporate Governance and Nominating Committee
will operate under the charter setting out the functions and responsibilities of
this committee. A copy of the charter can be viewed in our website at
www.parallel-petro.com.
The committee will consider candidates for Director suggested by
stockholders. Stockholders wishing to suggest a candidate for Director should
write to any one of the members of the committee at his address shown under Item
12 of this Annual Report on Form 10-K. Suggestions should include:
. a statement that the writer is a stockholder and is proposing a
candidate for consideration by the committee;
. the name of and contact information for the candidate;
. a statement of the candidate's age, business and educational
experience;
. information sufficient to enable the committee to evaluate the
candidate;
. a statement detailing any relationship between the candidate and
any joint interest owners, customer, supplier or competitor of
Parallel;
. detailed information about any relationship or understanding
between the proposing stockholder and the candidate; and
. a statement that the candidate is willing to be considered and
willing to serve as a Director if nominated and elected.
Compensation Committee
The members of the Compensation Committee at March 1, 2004 were Dewayne
E. Chitwood, Martin B. Oring, Charles R. Pannill, Ray M. Poage and Jeffrey G.
Shrader. Mr. Shrader presently acts as the Chairman of the Compensation
Committee. The Compensation Committee's responsibilities include reviewing and
recommending to the Board the compensation and terms of benefit arrangements
with Parallel's officers, and the making of awards under such arrangements.
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Hedging and Acquisitions Committee
The Hedging and Acquisitions Committee presently consists of four
Directors, including Messrs. Oring, Shrader, Oldham and Cambridge. With respect
to hedging, the committee reviews, assists, and advises management on overall
risk management strategies and techniques. The committee strives to implement
prudent commodity and interest rate hedging arrangements, and monitors our
compliance with certain covenants in our revolving credit facility. The Hedging
and Acquisitions Committee also reviews with management oil and gas acquisition
opportunities, and consults with members of management to review plans and
strategies for pursing acquisitions.
Code of Ethics
On March 15, 2004, the Board also adopted a code of ethics as part of
our efforts to comply with the Sarbanes-Oxley Act of 2002 and rule changes made
by the Securities and Exchange Commission and Nasdaq. Our code of ethics applies
to all of our directors, officers and employees, including our chief executive
officer, chief financial officer and all other financial officers and
executives. You may review the code of ethics on our website at
www.parallel-petro.com. We have also filed a copy of our code of ethics with the
Securities and Exchange Commission as an exhibit to this Annual Report on Form
10-K. We will provide without charge to each person, upon written or oral
request, a copy of our code of ethics. Requests should be directed to:
Manager of Investor Relations
Parallel Petroleum Corporation
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Telephone: (432) 684-3727
Stockholder Communications with Directors
Parallel stockholders who want to communicate with any individual
Director can write to that Director at his address shown under Item 12 of this
Annual Report on Form 10-K.
Your letter should indicate that you are a Parallel stockholder.
Depending on the subject matter, the Director will:
. if you request, forward the communication to the other Directors;
. request that management handle the inquiry directly, for example
where it is a request for information about the company or it is
a stock-related matter; or
. not forward the communication to the other Directors or
management if it is primarily commercial in nature or if it
relates to an improper or irrelevant topic.
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Director Attendance at Annual Meetings
We typically schedule a Board meeting in conjunction with our annual
meeting of stockholders and expect that our Directors will attend, absent a
valid reason, such as illness or a schedule conflict. Last year, all seven of
the individuals then serving as Director attended our annual meeting of
stockholders.
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ITEM 11. EXECUTIVE COMPENSATION
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Summary of Annual Compensation
The table below shows a summary of the types and amounts of
compensation paid to Mr. Cambridge, our Chief Executive Officer for the last
three fiscal years, and the type and amounts of compensation paid to each of the
four most highly compensated executive officers, based on salary and bonus for
2003.
Compensation Table
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Long-Term Compensation
-----------------------------------
Annual Compensation Awards Payouts
--------------------------------------------------- ---------------------- ----------
Other Restricted Securities All
Annual Stock Underlying LTIP Other
Name and Salary Bonus Compensation Awards Options/ Payouts Compensation
Principal Position Year ($) ($)(1) ($) ($) SAR (#) ($) ($)
- --------------------------- -------- ------------- ------------- ------------ ----------- ----------- ---------- ------------
T. R. Cambridge 2003 $ 110,000 $ 25,000 $ - 0 0 0 0
Chairman of the Board and 2002 $ 106,284 $ 158,888 $ 450 0 0 0 0
Chief Executive Officer 2001 $ 91,362 $ 26,000 $ 900 0 100,000 0 0
L. C. Oldham 2003 $ 191,000 $ 61,391 $ 20,198 (2) 0 0 0 $ 14,064 (3)
President and Director 2002 $ 187,316 $ 555,674 $ 17,850 0 0 0 $ 11,113
2001 $ 170,392 $ 26,000 $ 17,922 0 200,000 0 $ 14,470
E. A. Bayley 2003 110,000 $ 23,391 $ 16,470 (4) 0 0 0 $ 6,600 (5)
Vice President 2002 $ 111,792 $ 172,178 $ 16,127 0 0 0 $ 6,303
2001 $ 96,155 $ 13,000 $ 15,705 0 50,000 0 $ 6,489
J. S. Rutherford 2003 $ 110,000 $ 23,391 $ 15,763 (6) 0 0 0 $ 6,600 (7)
Vice President 2002 $ 110,384 $ 410,352 $ 16,540 0 0 0 $ 6,488
2001 $ 103,411 $ 13,000 $ 15,028 0 50,000 0 $ 6,925
D. E. Tiffin 2003 $ 171,140 $ 44,391 $ 17,464 (8) 0 0 0 $ 10,268 (9)
Vice President 2002 $ 99,832 $ 47,421 $ 8,257 0 50,000 0 $ 5,990
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(1) The bonuses paid to Messrs. Cambridge, Oldham, Bayley and Rutherford during
2002 includes payments made to them under Incentive Award Agreements as a
result of the sale of First Permian's assets. Parallel entered into these
Incentive Award Agreements with Messrs. Cambridge, Oldham, Bayley,
Rutherford and four other employees in December 2001 to provide an
incentive to the participants and to reward outstanding efforts and
achievements by them when a material contribution to Parallel's success
resulted from an Award Event. An Award Event generally meant an acquisition
of First Permian, a sale of substantially all of First Permian's assets, or
Parallel's sale or other disposition of its 30.675% ownership interest in
First Permian. The agreements awarded Unit Equivalent Rights to the
recipients. A Unit Equivalent Right was essentially equivalent to a Common
Unit of common membership interest in First Permian. At March 1, 2002,
First
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Permian had outstanding 1,140,992 Common Units and 1,350,000 Preferred
Units. Parallel owned 350,000 Common Units of First Permian. The Unit
Equivalent Rights entitled the recipient to a one-time cash bonus. Payment
of the bonus was triggered by the occurrence of an Award Event. The amount
of a bonus payment was defined as the difference between $30.00 per Common
Unit and the price per Common Unit received by First Permian's holders of
Common Units in a transaction constituting an Award Event, multiplied by
the number of Unit Equivalent Rights granted to the recipient. To
illustrate, assuming the holders of First Permian's Common Units received
$100.00 per Common Unit from a sale of assets, a recipient of 1,000 Unit
Equivalent Rights would be entitled to receive a cash payment equal to
$70.00 ($100.00 minus $30.00) multiplied by 1,000, or $70,000. Under these
Incentive Award Agreements, 9,565 Unit Equivalent Rights were granted to
Mr. Oldham; 2,394 were granted to Mr. Cambridge; 2,869 to Mr. Bayley; and
7,173 to Mr. Rutherford. In April, 2002 an Award Event occurred when First
Permian sold all of its oil and gas properties to Energen Corporation.
Because shares of Energen Corporation's common stock were a component of
the total purchase price for First Permian's properties, the portion of the
bonus payments attributable to the Energen stock was based upon the price
at which we sold our shares of Energen stock. Under these agreements, Mr.
Cambridge received $132,480; Mr. Oldham - $529,266; Mr. Bayley - $158,770;
and Mr. Rutherford - $396,944. The Incentive Award Agreements automatically
terminated upon payment of the bonuses. Mr. Tiffin received a signing and
inducement bonus in the amount of $46,013 when he joined Parallel in June
2002.
(2) These amounts include insurance premiums for nondiscriminatory group life,
medical, disability and dental insurance as follows: $19,697 for 2003;
$17,647 for 2002; and $16,366 for 2001.
(3) For 2003, such amount includes $11,460 contributed by Parallel to Mr.
Oldham's individual retirement account maintained under Parallel's 408(k)
simplified employee pension plan/individual retirement account, and $2,604
for income tax preparation and planning. For 2002, such amount includes
$11,113 contributed by Parallel to Mr. Oldham's individual retirement
account maintained under Parallel's 408(k) simplified employee pension
plan/individual retirement account, and the reimbursement of $4,624 for
income tax preparation and planning. For 2001, such amount includes $11,482
contributed by Parallel to Mr. Oldham's retirement account and the
reimbursement to Mr. Oldham of $2,988 for income tax preparation and
planning.
(4) This amount includes insurance premiums for nondiscriminatory group life,
medical, disability and dental insurance as follows: $16,470 for 2003;
$15,150 for 2002; and $14,808 for 2001.
(5) This amount represents Parallel's contribution to Mr. Bayley's individual
retirement account maintained under the 408(k) simplified employee pension
plan/individual retirement account.
(6) This amount includes insurance premiums for nondiscriminatory group life,
medical, disability and dental insurance as follows: $15,763 for 2003;
$14,221 for 2002; and $13,155 for 2001.
(7) This amount represents Parallel's contribution to Mr. Rutherford's
individual retirement account maintained under the 408(k) simplified
employee premium plan/individual retirement account.
(8) This amount includes insurance premiums for nondiscriminatory group life,
medical, disability and dental insurance as follows: $16,964 for 2003; and
$8,150 for 2002.
(9) This amount represents Parallel's contribution to Mr. Tiffin's individual
retirement account maintained under the 408(k) simplified employee premium
plan/individual retirement account.
Stock Options
We use stock options as part of the overall compensation of directors,
officers and employees. However, we did not grant any stock options in 2003 to
any of the executive officers named in the Summary Compensation Table. Summary
descriptions of our stock option plans are included in this report so you can
review the types of options we have granted in the past and the significant
features of our stock options.
In the table below, we show certain information about the exercise of
stock options in 2003 and the value of unexercised stock options held by the
named executive officers at December 31, 2003.
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Aggregated Option/SAR Exercises in
Last Fiscal Year and Fiscal Year-End Option/SAR Values
Value of
Number of Securities Underlying Unexercised
Shares Acquired Value Unexercised Options at Fiscal in-the-Money Options
on Realized Year-End (#) at Fiscal Year-End ($)(2)
----------------------------------- --------------------------------------
Name Exercise ($)(1) Exercisable Unexercisable Exercisable Unexercisable
- -------------------- ------------------- ------------ ------------------ ---------------- ------------------ -----------------
T.R. Cambridge 0 0 300,000 0 190,000 (3) 0
L.C. Oldham 0 0 340,000 60,000 328,700 (4) 0 (4)
E. A. Bayley 0 0 205,000 0 156,730 (5) 0
J.S. Rutherford 0 0 158,750 0 120,230 (6) 0
D.E. Tiffin 0 0 25,000 25,000 54,250 54,250
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(1) The value realized is equal to the fair market value of a share of common
stock on the date of exercise, less the exercise price of the stock options
exercised.
(2) The value of unexercised in-the-money options is equal to the fair market
value of a share of common stock at fiscal year-end ($4.35 per share),
based on the last sale price of Parallel's common stock, less the exercise
price.
(3) At December 31, 2003, the exercise prices of exercisable options to
purchase a total of 100,000 shares of common stock held by Mr. Cambridge
exceeded $4.35, the fair market value of our common stock on that date.
(4) At December 31, 2003, the exercise prices of exercisable options to
purchase a total of 140,000 shares of common stock held by Mr. Oldham
exceeded $4.35, the fair market value of our common stock on that date. In
addition, an unexercisable stock option to purchase 60,000 shares of common
stock was held by Mr. Oldham at fiscal year-end, which also had an exercise
price greater than $4.35.
(5) At December 31, 2003, the exercise prices of exercisable options to
purchase a total of 100,000 shares of common stock held by Mr. Bayley
exceeded $4.35, the fair market value of our common stock on that date.
(6) At December 31, 2003, the exercise prices of exercisable options to
purchase a total of 93,750 shares of common stock held by Mr. Rutherford
exceeded $4.35, the fair market value of our common stock on that date.
Change of Control Arrangements
Stock Option Plans
Parallel's outstanding stock options and stock option plans contain
certain change of control provisions which are applicable to Parallel's
outstanding stock options, including the options held by our officers and
Directors. For purposes of our options, a change of control occurs if:
. Parallel is not the surviving entity in a merger or
consolidation;
. Parallel sells, leases or exchanges all or substantially all of
its assets;
. Parallel is to be dissolved and liquidated;
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. any person or group acquires beneficial ownership of more than
50% of Parallel's common stock; or
. in connection with a contested election of directors, the persons
who were directors of Parallel before the election cease to
constitute a majority of the Board of Directors.
If a change of control occurs, the Compensation Committee of the Board
of Directors can:
. accelerate the time at which options may be exercised;
. require optionees to surrender some or all of their options and
pay to each optionee the change of control value;
. make adjustments to the options to reflect the change of control;
or
. permit the holder of the option to purchase, instead of the
shares of common stock as to which the option is then
exercisable, the number and class of shares of stock or other
securities or property which the optionee would acquire under the
terms of the merger, consolidation or sale of assets and
dissolution if, immediately before the merger, consolidation or
sale of assets or dissolution, the optionee had been the holder
of record of the shares of common stock as to which the option is
then exercisable.
The change of control value is an amount equal to, whichever is
applicable:
. the per share price offered to Parallel's stockholders in a
merger, consolidation, sale of assets or dissolution transaction;
. the price per share offered to Parallel's stockholders in a
tender offer or exchange offer where a change of control takes
place; or
. if a change of control occurs, other than from a tender or
exchange offer, the fair market value per share of the shares
into which the options being surrendered are exercisable, as
determined by the Committee.
Change of Control Agreements
In June, 2001, Parallel entered into Change of Control Agreements with
Mr. Cambridge, Mr. Oldham, Mr. Bayley, Mr. Rutherford and four other employees.
The Compensation Committee determined not to renew these agreements and they
expired by their own terms in June 2003. The agreements provided that upon the
occurrence of a Change of Control, each person would be entitled to receive a
single lump sum cash payment in an amount equal to one year's salary. The
agreements also provided for continued participation in Parallel's medical,
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dental, disability and life insurance and retirement plans for a period of
twelve months after a Change of Control. A Change of Control would have occurred
if:
. any person became the beneficial owner of Parallel's voting
shares entitling that person to 20% or more of the voting power
of Parallel;
. the stockholders of Parallel approved a transaction providing for
(1) Parallel to be merged, consolidated or otherwise combined
with another person, (2) the sale of all or substantially all the
assets or stock of Parallel or (3) the liquidation or dissolution
of Parallel; or
. less than a majority of the members of the Board were continuing
directors. A continuing director meant a director of Parallel who
either (1) was a director of Parallel on June 1, 2001, the date
of the Change of Control Agreements or (2) was an individual
whose appointment, election, or nomination for election, as a
director of Parallel was approved by a vote of at least a
majority of the directors of Parallel then still in office who
were continuing directors (other than an individual whose initial
assumption of office was in connection with an actual or
threatened election contest relating to the election of the
directors of Parallel).
Compensation of Directors
In 2003, Parallel's nonemployee Directors each received $1,500 for
attending meetings of the Board of Directors. Nonemployee Directors who are
members of a Board committee also received the following fees:
. $750 per meeting for service on the Compensation Committee, with
the Chairman of the Compensation Committee being entitled to
receive an additional fee of $5,000 per year;
. $750 per meeting for service on the Audit Committee, with the
Chairman of the Audit Committee being entitled to receive an
additional fee of $10,000 per year and each other Audit Committee
member receiving $5,000 per year; and
. $750 per meeting for service on the Hedging and Acquisitions
Committee.
Under these arrangements, for 2003, Mr. Pannill received $35,000; Mr.
Chitwood - $30,000 Mr. Shrader - $56,500; Mr. Poage - $35,250; and Mr. Oring -
$52,750. All Directors are reimbursed for expenses incurred in connection with
attending meetings.
Directors who are not employees of Parallel are eligible to participate
in Parallel's 1997 Nonemployee Directors Stock Option Plan and the 2001
Nonemployee Directors Stock Option Plan. As previously reported, on April 28,
2003, Mr. Poage was granted a stock option to purchase 50,000 shares of common
stock at an exercise price of $2.61 per share, the fair market value of the
common stock on that date. The option becomes exercisable as to one-half of the
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shares on April 28, 2004 and the remaining one-half become exercisable on April
28, 2005. The option expires ten years from the grant date.
Stock Option Plans
1992 Stock Option Plan. In May, 1992, our stockholders approved and
adopted the 1992 Stock Option Plan. The 1992 Plan expired by its own terms on
March 1, 2002, but remains effective only for purposes of outstanding options.
The 1992 Plan provided for granting to key employees, including officers and
Directors who were also key employees of Parallel, and Directors who were not
employees, options to purchase up to an aggregate of 750,000 shares of common
stock. Options granted under the 1992 Plan to employees are either incentive
stock options or options which do not constitute incentive stock options.
Options granted to nonemployee Directors are not incentive stock options.
The 1992 Plan is administered by the Board's Compensation Committee,
none of whom were eligible to participate in the 1992 Plan, except to receive a
one-time option to purchase 25,000 shares at the time he or she became a
Director. The Compensation Committee selected the employees who were granted
options and established the number of shares issuable under each option and
other terms and conditions approved by the Compensation Committee. The purchase
price of common stock issued under each option is the fair market value of the
common stock at the time of grant.
The 1992 Plan provided for the granting of an option to purchase 25,000
shares of common stock to each individual who was a nonemployee Director of
Parallel on March 1, 1992 and to each individual who became a nonemployee
Director following March 1, 1992. Members of the Compensation Committee were not
eligible to participate in the 1992 Plan other than to receive a nonqualified
stock option to purchase 25,000 shares of common stock as described above.
An option may be granted in exchange for an individual's right and
option to purchase shares of common stock pursuant to the terms of a prior
option agreement. An agreement that grants an option in exchange for a prior
option must provide for the surrender and cancellation of the prior option. The
purchase price of common stock issued under an option granted in exchange for a
prior option is determined by the Compensation Committee and may be equal to the
price for which the optionee could have purchased common stock under the prior
option.
At March 1, 2002, 65,000 shares of common stock remained authorized for
issuance under the 1992 Plan. However, the 1992 Plan prohibited the grant of
options after March 1, 2002. Consequently, no additional options are available
for grant under the 1992 Plan.
At March 1, 2004, options to purchase a total of 358,750 shares of
common stock were outstanding under the 1992 Plan.
1997 Nonemployee Directors Stock Option Plan. The Parallel Petroleum
1997 Non-Employee Directors Stock Option Plan was approved by our stockholders
at the annual meeting of stockholders held in May, 1997. This plan provides for
granting to Directors who are not
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employees of Parallel options to purchase up to an aggregate of 500,000 shares
of common stock. Options granted under the plan will not be incentive stock
options within the meaning of the Internal Revenue Code.
This Plan is administered by the Compensation Committee of the Board of
Directors. The Compensation Committee has sole authority to select the
nonemployee Directors who are to be granted options; to establish the number of
shares which may be issued to nonemployee Directors under each option; and to
prescribe the terms and conditions of the options in accordance with the plan.
Under provisions of the plan, the option exercise price must be the fair market
value of the stock subject to the option on the grant date. Options are not
transferable other than by will or the laws of descent and distribution and are
not exercisable after ten years from the date of grant.
The purchase price of shares as to which an option is exercised must be
paid in full at the time of exercise in cash, by delivering to Parallel shares
of stock having a fair market value equal to the purchase price, or a
combination of cash or stock, as established by the Compensation Committee.
Options may not be granted under this plan after March 27, 2007. At
March 1, 2004, options to purchase a total of 320,000 shares of common stock
were outstanding under this plan.
At March 1, 2004, options to purchase 142,500 shares of common stock
were available for future grants under this plan.
1998 Stock Option Plan. In June, 1998, our stockholders adopted the
1998 Stock Option Plan. The 1998 Plan provides for the granting of options to
purchase up to 850,000 shares of common stock. Stock options granted under the
1998 Plan may be either incentive stock options or stock options which do not
constitute incentive stock options.
The 1998 Plan is administered by the Compensation Committee of the
Board of Directors. Members of the Compensation Committee are not eligible to
participate in the 1998 Plan. Only employees are eligible to receive options
under the 1998 Plan. The Compensation Committee selects the employees who are
granted options and establishes the number of shares issuable under each option.
Options granted to employees contain terms and conditions that are
approved by the Compensation Committee. The Compensation Committee is empowered
and authorized, but is not required, to provide for the exercise of options by
payment in cash or by delivering to Parallel shares of common stock having a
fair market value equal to the purchase price, or any combination of cash or
common stock. The purchase price of common stock issued under each option must
not be less than the fair market value of the common stock at the time of grant.
Options granted under the 1998 Plan are not transferable other than by will or
the laws of descent and distribution and are not exercisable after ten years
from the date of grant.
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Options may not be granted under the 1998 Plan after March 11, 2008. At
March 1, 2004, options to purchase a total of 809,400 shares of common stock
were outstanding under this plan.
At March 1, 2004, there were no available options to purchase shares of
common stock for future grant under the 1998 Stock Option Plan.
2001 Nonemployee Directors Stock Option Plan. The Parallel Petroleum
2001 Non-employee Directors Stock Option Plan was approved by our stockholders
at the annual meeting of stockholders held in June, 2001. This plan provides for
granting to Directors who are not employees of Parallel options to purchase up
to an aggregate of 500,000 shares of common stock. Options granted under the
plan will not be incentive stock options within the meaning of the Internal
Revenue Code.
This Plan is administered by the Compensation Committee of the Board of
Directors. The Compensation Committee has sole authority to select the
nonemployee Directors who are to be granted options; to establish the number of
shares which may be issued to nonemployee Directors under each option; and to
prescribe such terms and conditions as the Committee prescribes from time to
time in accordance with the plan. Under provisions of the plan, the option
exercise price must be the fair market value of the stock subject to the option
on the grant date. Options are not transferable other than by will or the laws
of descent and distribution and are not exercisable after ten years from the
date of grant.
The purchase price of shares as to which an option is exercised must be
paid in full at the time of exercise in cash, by delivering to Parallel shares
of stock having a fair market value equal to the purchase price, or a
combination of cash or stock, as established by the Compensation Committee.
Options may not be granted under this plan after May 2, 2011. At March
1, 2004, options to purchase 450,000 shares of common stock were outstanding
under this plan.
At March 1, 2004, there were available for future grant under this plan
options to purchase 50,000 shares of common stock.
Employee Stock Option Plan. In June, 2001, our Board of Directors
adopted the Parallel Petroleum Employee Stock Option Plan. This plan authorized
the grant of options to purchase up to 200,000 shares of common stock, or less
than 1.00% of our outstanding shares of common stock. Directors and officers are
not eligible to receive options under this plan. Only employees are eligible to
receive options. Stock options granted under this plan are not incentive stock
options.
This plan was implemented without stockholder approval.
The Employee Stock Option Plan is administered by the Compensation
Committee of the Board of Directors. The Compensation Committee selects the
employees who are granted options and establishes the number of shares issuable
under each option.
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Options granted to employees contain terms and conditions that are
approved by the Compensation Committee. The Compensation Committee is empowered
and authorized, but is not required, to provide for the exercise of options by
payment in cash or by delivering to Parallel shares of common stock having a
fair market value equal to the purchase price, or any combination of cash or
common stock. The purchase price of common stock issued under each option must
not be less than the fair market value of the common stock at the time of grant.
Options granted under this plan are not transferable other than by will or the
laws of descent and distribution.
The Employee Stock Option Plan will expire on June 20, 2011. Unless
some of the options that have been granted under the plan are forfeited and
again become available for future grant, no additional options may be granted
under this plan.
At March 1, 2004, options to purchase 200,000 shares of common stock
were outstanding under this plan.
Other Option Grants. The Board of Directors granted a nonqualified
stock option to Mr. Cambridge in October, 1993 under the general corporate
powers of Parallel, without stockholder approval. Upon recommendation of the
Board's Compensation Committee, the Board granted the option to Mr. Cambridge to
purchase 100,000 shares of common stock at an exercise price of $3.9375 per
share, the fair market value of the common stock on the grant date. The option
is not transferable, except by will or the laws of descent and distribution. The
option expired in October, 2003.
Retirement Plan
Parallel maintains under Section 408(k) of the Internal Revenue Code a
combination simplified employee pension and individual retirement account plan
for eligible employees. Generally, eligible employees include all employees who
are at least twenty-one years of age.
Contributions to employee SEP accounts may be made at the discretion of
Parallel, as authorized by the Compensation Committee of the Board of Directors.
The percentage of contributions may vary from time to time. However, the same
percentage contribution must be made for all participating employees. Parallel
is not required to make annual contributions to the SEP accounts. Under the
prototype simplified employee pension plan adopted by Parallel, all of the SEP
contributions must be made to SEP/IRAs maintained with the sponsor of the plan,
a national investment banking firm. All contributions to employees' accounts are
immediately 100% vested and become the property of each employee at the time of
contribution, including employer contributions, income-deferral contributions
and IRA contributions. Generally, earnings on contributions to an employee's
SEP/IRA account are not subject to federal income tax until withdrawn.
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In addition to receiving SEP contributions made by Parallel, employees
may make individual annual IRA contributions of up to the maximum of $12,000.
Maximum total contribution for Parallel and Parallel's employees can be no more
than $40,000. In addition to the annual salary deferral limit stated above,
employees who reach age 50 or older during a calendar year can elect to take
advantage of a catch-up salary deferral contribution; eligible participants can
increase their salary deferral by $2,000 for the year 2003. Each employee is
responsible for the investment of funds in his or her own SEP/IRA and can select
investments offered through the sponsor of the plan.
Distributions may be taken by employees at any time and must commence
by April 1st following the year in which the employee attains age 70 1/2.
Parallel presently makes matching contributions to employee accounts in
an amount equal to the contribution made by each employee, not to exceed,
however, 6% of each employee's salary during any calendar year. During 2003,
Parallel contributed an aggregate of $105,822 to the accounts of 23 employee
participants. Of this amount, $11,460 was allocated to Mr. Oldham's account;
$6,600 was allocated to Mr. Bayley's account; $6,600 was allocated to Mr.
Rutherford's account; $10,268 to Mr. Tiffin's account; and $6,360 to Mr.
Foster's account.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
- -------------------------------------------------------------------------------
This table shows information as of March 12, 2004 about the beneficial
ownership of common stock by: (1) each person known by us to own beneficially
more than five percent of our outstanding common stock; (2) the executive
officers named in the Summary Compensation Table in this report; (3) each
director of Parallel; and (4) all of Parallel's executive officers and directors
as a group.
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Name and Address Amount and Nature Percent
of of of
Beneficial Owner Beneficial Ownership(1) Class(2)
- --------------------------------------- ------------------------- ------------------------
Thomas R. Cambridge 1,057,045 (3) 4.14%
2201 Civic Circle, Suite 216
Amarillo, Texas 79109
Dewayne E. Chitwood 1,656,057 (4) 6.38%
400 Pine St., Suite 700
Abilene, Texas 79601
Larry C. Oldham 887,090 (5) 3.46%
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Martin B. Oring 190,666 (6) *
706 Cinnamon Lane
Franklin Lakes, New Jersey 07417
Charles R. Pannill 173,495 (7) *
3416 Acorn Run
Fort Worth, Texas 76019
Ray M. Poage 25,000 (8) *
4711 Meandering Way
Colleyville, Texas 76034
Jeffrey G. Shrader 100,000 (9) *
801 S. Filmore, Suite 600
Amarillo, Texas 79105
Eric A. Bayley 224,490 (10) *
1004 N. Big Spring, Suite 400
Midland, Texas 79701
John S. Rutherford 166,300 (11) *
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Donald E. Tiffin 35,415 (12) *
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Wes-Tex Drilling Company, L.P. 1,246,773 (13) 4.88%
519 First National Bank Building West
Abilene, Texas 79601
Crestview Capital Fund II, L.P. 1,323,000 5.24%
95 Revere Drive, Suite F
Northbrook, Illinois 60062
Julia Jones Matthews 1,942,856 (14) 7.36%
400 Pine, Suite 900
Abilene, Texas 79601
Dodge Jones Foundation 1,371,428 (15) 5.23%
400 Pine, Suite 900
Abilene, Texas 79601
All Executive Officers and Directors
as a Group (11 persons) 4,537,058 (16) 16.55%
- ------------------
*Less than one percent.
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(1) Unless otherwise indicated, all shares of common stock are held directly
with sole voting and investment powers.
(2) Securities not outstanding, but included in the beneficial ownership of
each such person, are deemed to be outstanding for the purpose of computing
the percentage of outstanding securities of the class owned by such person,
but are not deemed to be outstanding for the purpose of computing the
percentage of the class owned by any other person. Shares of common stock
that may be acquired within sixty days upon exercise of outstanding stock
options and warrants or upon conversion of preferred stock are deemed to be
outstanding.
(3) Includes 757,045 shares of common stock held indirectly through Cambridge
Collateral Services, Ltd., a limited partnership of which Mr. Cambridge and
his wife are the general partners. Also included are 300,000 shares of
common stock underlying presently exercisable stock options held by Mr.
Cambridge.
(4) Includes 932,488 shares of common stock held directly by Wes-Tex Drilling
Company, L.P., a limited partnership, and 314,285 shares of common stock
that may be acquired by Wes-Tex Drilling Company, L.P. upon conversion of
110,000 shares of preferred stock. In his capacity as president, chief
executive officer and a manager of Wes-Tex Holdings, LLC, the general
partner of Wes-Tex Drilling Company, L.P., Mr. Chitwood may be deemed to
have shared voting and investment powers with respect to such shares. See
note 13 below. Also included are 20,000 shares of common stock held by the
Estate of Myrle Greathouse (the "Estate"); 157,142 shares that may be
acquired by the Greathouse Charitable Remainder Trust (the "Trust") upon
conversion of 55,000 shares of preferred stock; and 157,142 shares of
common stock that may be acquired by the Greathouse Foundation (the
"Foundation") upon conversion of 55,000 shares of preferred stock. Mr.
Chitwood is the executor (but not a beneficiary) of the Estate, the trustee
(but not a beneficiary) of the Trust and the executive director and a
director of the Foundation. In these capacities, Mr. Chitwood may also be
deemed to have shared voting and investment powers with respect to the
shares of common stock beneficially owned by the Estate, the Trust and the
Foundation. However, Mr. Chitwood disclaims beneficial ownership of all
shares of common stock held by Wes-Tex Drilling Company, L.P., the Estate,
Trust and Foundation. Also included are 75,000 shares of common stock
underlying presently exercisable stock options held by Mr. Chitwood.
(5) Includes 200,000 shares of common stock held indirectly through Oldham
Properties, Ltd., a limited partnership of which Mr. Oldham is the general
partner and he and his wife are the limited partners. Also included are
350,000 shares of common stock underlying presently exercisable stock
options held by Mr. Oldham.
(6) Of the total number of shares shown, 24,000 shares are held directly by Mr.
Oring's wife; 75,000 shares may be acquired by Mr. Oring upon exercise of
stock options held by Mr. Oring; and 91,666 shares may be acquired upon
exercise of a stock purchase warrant.
(7) Includes 135,000 shares of common stock underlying presently exercisable
stock options. Also included are 1,300 shares held by Mr. Pannill as
custodian for the benefit of two minor grandchildren and as to which Mr.
Pannill disclaims beneficial ownership.
(8) All of such shares may be acquired upon exercise of presently exercisable
stock options.
(9) Includes 75,000 shares of common stock underlying presently exercisable
stock options.
(10) Includes 205,000 shares of common stock underlying presently exercisable
stock options. A total of 6,790 shares of common stock are held indirectly
by Mr. Bayley through individual retirement accounts and Parallel's 408(K)
Plan.
(11) Includes 158,750 shares of common stock underlying presently exercisable
stock options. Also included are 7,550 shares held indirectly by Mr.
Rutherford through his 408(k) Plan.
(12) Of the total number of shares shown 6,500 shares are held indirectly
through Mr. Tiffin's individual retirement account. Includes 25,000 shares
of common stock underlying presently exercisable stock options.
(13) Includes 314,285 shares of common stock that may be acquired upon
conversion of 110,000 shares of preferred stock. See note 4 above.
(14) Includes 400,000 shares of common stock owned directly by the Julia Jones
Matthews Family Trust and 171,428 shares of common stock that may be
acquired by the Trust upon conversion of 60,000 shares of preferred stock
held directly by the Trust. By virtue of her position as the President and
a Director of the Dodge Jones Foundation, Matthews has shared voting and
investment powers with respect to, and may also be deemed to be the
beneficial owner of, 971,428 shares of common stock that may be acquired by
the Dodge Jones Foundation upon conversion of 340,000 shares of preferred
stock held by it, and 400,000 shares of common stock that are owned
directly by the Dodge Jones Foundation. Matthews disclaims beneficial
ownership of all shares of common stock beneficially owned by the Dodge
Jones Foundation. See note 15.
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(15) Includes 971,428 shares that may be acquired upon conversion of 340,000
shares of preferred stock. The Dodge Jones Foundation has shared voting and
investment powers with respect to such shares of common stock. See note 14.
(16) Includes 1,579,416 shares of common stock underlying stock options that are
presently exercisable or that become exercisable within sixty days and
628,569 shares of common stock that may be acquired upon conversion of
220,000 shares of preferred stock.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires
Parallel's Directors and officers to file periodic reports with the SEC. These
reports show the Directors' and officers' ownership and the changes in
ownership, of Parallel's common stock and other equity securities. To our
knowledge, all Section 16(a) filing requirements were complied with during 2003,
except that Mr. Tiffin filed one Form 4 report two days late which reported his
purchase of 6,200 shares of Parallel's common stock.
- -------------------------------------------------------------------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- -------------------------------------------------------------------------------
Mr. Chitwood, a director of Parallel, has been the Chief Executive
Officer of Wes-Tex Drilling Company, L.P. since January 30, 2001. He was
appointed to Parallel's Board on December 19, 2000 to fill a vacancy created by
the death of a former director of Parallel. The former director was also the
sole owner of Wes-Tex Drilling Company, L.P. In 1994, the predecessor of Wes-Tex
Drilling Company, L.P. acquired an undivided working interest from Parallel in
an oil and gas prospect located in Howard County, Texas. Since then, Wes-Tex has
participated with us and other interest owners in the drilling and development
of this prospect. Wes-Tex has participated in these operations under standard
form operating agreements on the same or similar terms afforded by Parallel to
nonaffiliated third parties. We invoice all working interest owners, including
Wes-Tex, on a monthly basis, without interest, for their pro rata share of lease
acquisition, drilling and operating expenses. During 2003, we billed Wes-Tex
approximately $23,000 for its proportionate share of lease operating expenses
incurred on properties we operate. The largest amount owed to us by Wes-Tex at
any one time during 2003 for its share of lease operating expenses was
approximately $6,000. At December 31, 2003, Wes-Tex owed us approximately $3,800
for these expenses. During 2003, we disbursed approximately $74,000 to Wes-Tex
in payment of revenues attributable to Wes-Tex's pro rata share of the proceeds
from sales of oil and gas produced from properties in which Wes-Tex and Parallel
owned interests. Mr. Chitwood is not an owner of Wes-Tex and has no interest in
these transactions other than in his capacity as an officer of Wes-Tex.
During 2003, Cambridge Production, Inc., a corporation owned by Mr.
Cambridge, served as operator of 2 wells on oil and gas leases in which we
acquired a working interest in 1984. Generally, the operator of a well is
responsible for the day to day operations on the lease, overseeing production,
employing field personnel, maintaining production and other records, determining
the location and timing of drilling of wells, administering gas contracts, joint
interest billings, revenue distribution, making various regulatory filings,
reporting to working
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interest owners and other matters. During 2003, Cambridge Production billed us
approximately $51,000 for our pro rata share of lease operating expenses and
drilling and workover expenses all of which we paid in 2003. The largest amount
we owed Cambridge Production at any one time during 2003 was approximately
$20,000. At December 31, 2003, no amounts were owed by us to Cambridge
Production. Our pro rata share of oil and gas sales during 2003 from the wells
operated by Cambridge Production was $198,000. Cambridge Production's billings
to Parallel are made monthly on the same basis as all other working interest
owners in the wells.
Cambridge Production, Inc. maintains an office in Amarillo, Texas from
which Mr. Cambridge performs his duties and services as Chairman of the Board
and as geological consultant to Parallel. We reimburse Cambridge Production,
Inc. $3,000 per month for office and administrative expenses incurred on behalf
of Parallel. During 2003 we reimbursed Cambridge Production, Inc. a total of
$36,000.
We believe the transactions described above were made on terms no less
favorable than if we had entered into the transactions with an unrelated party.
- -------------------------------------------------------------------------------
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
- -------------------------------------------------------------------------------
KPMG LLP audited our financial statements for the year ended December
31, 2002 and for the prior eighteen years. However, as described under Item 9 of
this Annual Report on Form 10-K, KPMG resigned in December 2003. Prior to KPMG's
resignation, KPMG provided audit and tax services in 2003. In January 2004, we
engaged BDO Seidman, LLP as our independent auditors.
The audit committee had not, as of the time of filing this Annual
Report on Form 10-K with the Securities and Exchange Commission, adopted
policies and procedures for pre-approving audit or permissible non-audit
services performed by our independent auditors. Instead, the audit committee as
a whole has pre-approved all such services. In the future, our audit committee
may approve the services of our independent auditors pursuant to pre-approval
policies and procedures adopted by the Audit Committee, provided the policies
and procedures are detailed as to the particular service, the Audit Committee is
informed of each service, and such policies and procedures do not include
delegation of the Audit Committee's responsibilities to Parallel's management.
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The aggregate fees for professional services by BDO and KPMG in 2003
and 2002 were:
BDO KPMG
------------------ -----------------------------------
Types of Fees 2003 2003 2002
- ------------------------ ------------------ ----------------- -----------------
(dollars in thousands)
Audit fees $ 140 $ 120 $ 113
Audit-related fees - 61 2
Tax fees - 28 43
All other fees - - -
------------------ ----------------- -----------------
Total $ 140 $ 209 $ 158
================== ================= =================
In the above table, "audit fees" are fees we paid for professional
services for the audit of our financial statements included in Form 10-K and
review of financial statements included in Form 10-Qs, or for services that are
normally provided by the accountant in connection with statutory and regulatory
filings or engagements; "audit-related fees" are fees billed for assurance and
related services (such as due diligence services) that are reasonably related to
the performance of the audit or review of our financial statements; "tax fees"
are fees for tax compliance, advice and planning; and "all other fees" are fees
billed to Parallel for any services not included in the first three categories.
PART IV
- -------------------------------------------------------------------------------
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
- -------------------------------------------------------------------------------
(a) The following documents are filed as part of this report:
For a list of Financial Statements and Schedules, see "Index to
the Financial Statements" on page F-1, and incorporated herein by
reference.
(b) We filed the following Current Reports on Form 8-K during the
fiscal quarter ended December 31, 2003:
Form 8-K on October 29, 2003 pursuant to Item 7 (Financial
Statements and Exhibits), Item 9 (Regulation FD Disclosure) and
Item 12 (Results of Operations and Financial Condition)
announcing Parallel's results of operations and financial
condition for the third fiscal quarter ended September 30, 2003.
Form 8-K on December 9, 2003 pursuant to Item 4 (Changes in
Registrant's Certifying Accountant), announcing the resignation
of KPMG LLP.
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Form 8-K on December 24, 2003 pursuant to Item 5 (Other Events),
announcing the completion of Parallel's private placement of
common stock.
(c) Exhibits:
No. Description of Exhibit
- ----- -----------------------
3.1 Certificate of Incorporation of Registrant (Incorporated by reference to
Exhibit 3.1 to Form 10-K of the Registrant for the fiscal year ended
December 31, 1998)
3.2 Bylaws of Registrant (Incorporated by reference to Exhibit 3 to the
Registrant's Form 8-K, dated October 9, 2000, as filed with the
Securities and Exchange Commission on October 10, 2000)
4.1 Certificate of Designations, Preferences and Rights of Serial Preferred
Stock - 6% Convertible Preferred Stock (Incorporated by reference to
Exhibit 4.1 to Form 10-Q of the Registrant for the fiscal quarter ended
September 30, 1998)
4.2 Certificate of Designation, Preferences and Rights of Series A Preferred
Stock (Incorporated by reference to Exhibit 4.2 to Form 10-K of the
Registrant for the fiscal year ended December 31, 2000)
4.3 Rights Agreement, dated as of October 5, 2000, between the Registrant and
Computershare Trust Company, Inc., as Rights Agent (Incorporated by
reference to Exhibit 4.3 to Form 10-K of the Registrant for the fiscal
year ended December 31, 2000)
Executive Compensation Plans and Arrangements (Exhibit No.'s 10.1 through
10.9):
10.1 1983 Incentive Stock Option Plan (Incorporated by reference to Exhibit
10.2 to Form S-l of the Registrant (File No. 2-92397) as filed with the
Securities and Exchange Commission on July 26, 1984, as amended by
Amendments No. 1 and 2 on October 5, 1984, and October 25, 1984,
respectively)
10.2 1992 Stock Option Plan (Incorporated by reference to Exhibit 28.1 to Form
S-8 of the Registrant (File No. 33-57348) as filed with the Securities
and Exchange Commission on January 25, 1993)
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10.3 Stock Option Agreement between the Registrant and Thomas R. Cambridge
dated December 11, 1991 (Incorporated by reference to Exhibit 10.4 of
Form 10-K of the Registrant for the fiscal year ended December 31, 1992)
10.4 Stock Option Agreement between the Registrant and Thomas R. Cambridge
dated October 18, 1993 (Incorporated by reference to Exhibit 10.4(e) of
Form 10-K of the Registrant for the fiscal year ended December 31, 1993)
10.5 Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified
Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the
Registrant's Form 10-K for the fiscal year ended December 31, 1995)
10.6 Non-Employee Directors Stock Option Plan (Incorporated by reference to
Exhibit 10.6 of the Registrant's Form 10-K Report for the fiscal year
ended December 31, 1997)
10.7 1998 Stock Option Plan (Incorporated by reference to Exhibit 10.7 of Form
10-K of the Registrant for the fiscal year ended December 31, 1998)
10.8 Form of Incentive Award Agreements, dated December 12, 2001, between the
Registrant and Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and
John S. Rutherford granting 2,394 Unit Equivalent Rights to Mr.
Cambridge; 9,564 Unit Equivalent Rights to Mr. Oldham; 2,869 Unit
Equivalent Rights to Mr. Bayley; and 7,173 Unit Equivalent Rights to Mr.
Rutherford (Incorporated by reference to Exhibit 10.8 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2001)
10.9 Form of Change of Control Agreements, dated June 1, 2001, between the
Registrant and Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and
John S. Rutherford (Incorporated by reference to Exhibit 10.9 of Form
10-K of the Registrant for the fiscal year ended December 31, 2001)
10.10 Restated Loan Agreement, dated December 27, 1999, between the Registrant
and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.8 of
Form 10-K of the Registrant for the fiscal year ended December 31, 1999)
10.11 Loan Agreement, dated December 18, 2000, between the Registrant and Bank
United (Incorporated by reference to Exhibit 10.9 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2000)
10.12 Letter agreement, dated March 24, 1999, between the Registrant and Bank
One, Texas, N.A. (Incorporated by reference to Exhibit 10.9 of Form 10-K
of the Registrant for the fiscal year ended December 31, 1998)
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10.13 Certificate of Formation of First Permian, L.L.C. (Incorporated by
reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated June
30, 1999)
10.14 Limited Liability Company Agreement of First Permian, L.L.C.
(Incorporated by reference to Exhibit 10.2 of the Registrant's Form 8-K
Report dated June 30, 1999)
10.15 Merger Agreement, dated June 25, 1999 (Incorporated by reference to
Exhibit 10.3 of the Registrant's Form 8-K Report dated June 30, 1999)
10.16 Agreement and Plan of Merger of First Permian, L.L.C. and Nash Oil
Company, L.L.C. (Incorporated by reference to Exhibit 10.4 of the
Registrant's Form 8-K Report dated June 30, 1999)
10.17 Certificate of Merger of First Permian, L.L.C. and Nash Oil Company,
L.L.C. (Incorporated by reference to Exhibit 10.5 of the Registrant's
Form 8-K Report dated June 30, 1999)
10.18 Amended and Restated Limited Liability Company Agreement of First
Permian, L.L.C. dated as of May 31, 2000 (Incorporated by reference to
Exhibit 10.16 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2000)
10.19 Credit Agreement, dated June 30, 1999, by and among First Permian,
L.L.C., Parallel Petroleum Corporation, Baytech, Inc., and Bank One,
Texas, N.A. (Incorporated by reference to Exhibit 10.6 of the
Registrant's Form 8-K Report dated June 30, 1999)
10.20 Limited Guaranty, dated June 30, 1999, by and among First Permian,
L.L.C., parallel Petroleum Corporation and Bank One, Texas, N.A.
(Incorporated by reference to Exhibit 10.7 of the Registrant's Form 8-K
Report dated June 30, 1999)
10.21 Intercreditor Agreement, dated as of June 30, 1999, among First Permian,
L.L.C., Bank One, Texas, N.A., Tejon Exploration Company, and Mansefeldt
Investment Corporation (Incorporated by reference to Exhibit 10.8 of the
Registrant's Form 8-K Report dated June 30, 1999)
10.22 Subordinated Promissory Note, dated June 30, 1999, in the original
principal amount of $8.0 million made by First Permian, L.L.C. payable to
the order of Tejon Exploration Company (Incorporated by reference to
Exhibit 10.9 of the Registrant's Form 8-K Report dated June 30, 1999)
-90-
10.23 Subordinated Promissory Note, dated June 30, 1999, in the original
principal amount of $8.0 million made by First Permian, L.L.C. payable to
the order of Mansefeldt Investment Corporation (Incorporated by reference
to Exhibit 10.10 of the Registrant's Form 8-K Report dated June 30, 1999)
10.24 Second Restated Credit Agreement, dated October 25, 2000, among First
Permian, L.L.C., Bank One, Texas, N.A., and Bank One Capital Markets,
Inc. (Incorporated by reference to Exhibit 10.22 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2000)
10.25 Loan Agreement, dated as of January 25, 2002, between the Registrant and
First American Bank, SSB (Incorporated by reference to Exhibit 10.25 of
Form 10-K of the Registrant for the fiscal year ended December 31, 2001)
10.26 Purchase and Sale Agreement, dated as of November 27, 2002, among JMC
Exploration, Inc., Arkoma Star L.L.C., Parallel, L.P. and Texland
Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 of Form 8-K of
the Registrant, dated December 20, 2002)
10.27 First Amended and Restated Credit Agreement, dated December 20, 2002, by
and among Parallel Petroleum Corporation, Parallel, L.P., Parallel,
L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas
(Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant,
dated December 20, 2002)
10.28 Guaranty dated December 20, 2002, between Parallel, L.L.C. and First
American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3
of Form 8-K of the Registrant, dated December 20, 2002)
*14 Code of Ethics
*21 Subsidiaries
*23.1 Consent of KPMG LLP
*23.2 Consent of BDO Seidman, LLP
*23.3 Consent of Cawley Gillespie & Associates, Inc. Independent Petroleum
Engineers
*31.1 Certification of Principal Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley
Act of 2002
*31.2 Certification of Principal Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley
Act of 2002
-91-
*32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of
2002.
*32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of
2002.
- ---------------
* Filed herewith.
-92-
PARALLEL PETROLEUM CORPORATION
Index to the Financial Statements
Page
Independent Auditors' Report - BDO Seidman, LLP F-2
Independent Auditors' Report - KPMG LLP F-3
Financial Statements:
Consolidated Balance Sheets at December 31, 2003 and 2002 F-4
Consolidated Statements of Operations for the years
ended December 31, 2003, 2002, and 2001 F-5
Consolidated Statements of Stockholders' Equity for the years
ended December 31, 2003, 2002, and 2001 F-6
Consolidated Statements of Cash Flows for the years
ended December 31, 2003, 2002, and 2001 F-7
Consolidated Statements of Comprehensive Income (Loss)
for the years ended December 31, 2003, 2002, and 2001 F-8
Notes to Consolidated Financial Statements F-9
All schedules are omitted, as the required information is inapplicable or the
information is presented in the consolidated financial statements or related
notes.
F-1
The Board of Directors and Stockholders
Parallel Petroleum Corporation:
We have audited the accompanying consolidated balance sheet of Parallel
Petroleum Corporation and subsidiaries (the Company) as of December 31, 2003,
and the related consolidated statements of operations, stockholders' equity,
cash flows and comprehensive income (loss) for the year then ended. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Parallel Petroleum
Corporation and subsidiaries as of December 31, 2003, and the results of their
operations and their cash flows for the year then ended, in conformity with
accounting principles generally accepted in the United States of America.
As discussed in Note 4 to the financial statements, effective January 1, 2003,
the Company changed its method for accounting for asset retirement obligations.
As discussed in Note 1(g), to the financial statements, effective January 1,
2003 the Company changed its method of accounting for stock based employee
compensation.
/s/ BDO Seidman, LLP
Houston, Texas
March 5, 2004
F-2
The Board of Directors and Stockholders
Parallel Petroleum Corporation:
We have audited the accompanying consolidated balance sheet of Parallel
Petroleum Corporation and subsidiaries (the Company) as of December 31, 2002,
and the related consolidated statements of operations, stockholders' equity,
cash flows and comprehensive income (loss) for each of the years in the two-year
period ended December 31, 2002. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Parallel Petroleum
Corporation and subsidiaries as of December 31, 2002, and the results of their
operations and their cash flows for each of the years in the two-year period
ended December 31, 2002, in conformity with accounting principles generally
accepted in the United States of America.
/s/ KPMG LLP
Midland, Texas
March 14, 2003
F-3
PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
December 31, 2003 and 2002
(dollars in thousands)
Assets
2003 2002
-------------- --------------
Current assets:
Cash and cash equivalents $ 17,378 $ 11,812
Accounts receivable:
Oil and gas 4,610 3,071
Others, net of allowance for doubtful account of $9 and $13 316 236
Affiliate - 2
-------------- --------------
4,926 3,309
Income tax receivable - 833
Other assets 210 79
Fair value of derivative instruments - 22
Deferred tax asset 1,098 -
-------------- --------------
Total current assets 23,612 16,055
-------------- --------------
Property and equipment, at cost:
Oil and gas properties, full cost method 162,621 146,680
Other 1,414 1,083
-------------- --------------
164,035 147,763
Less accumulated depreciation and depletion (70,070) (62,075)
-------------- --------------
Net property and equipment 93,965 85,688
-------------- --------------
Other assets, net of accumulated amortization of $182 and $79 766 608
-------------- --------------
$ 118,343 $ 102,351
============== ==============
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable and accrued liabilities $ 3,965 $ 3,034
Current maturities of long-term debt - 4,146
Derivative obligations 3,231 336
-------------- --------------
Total current liabilities 7,196 7,516
-------------- --------------
Long-term debt, excluding current maturities 39,750 45,604
Asset retirement obligation 1,701 -
Derivative obligations 2,655 104
Deferred tax liability 5,809 3,628
-------------- --------------
Total long-term liabilties 49,915 49,336
-------------- --------------
Commitments and contingencies
Stockholders' equity:
Series A preferred stock -- par value $0.10 per share, authorized 50,000 shares - -
Preferred stock -- $0.60 cumulative convertible preferred stock -- par value of $0.10 per share,
(aggregate liquidation preference of $10) authorized 10,000,000 shares, issued
and outstanding 959,500 and 974,500 96 97
Common stock -- par value $0.01 per share, authorized 60,000,000
shares, issued and outstanding 25,216,863 and 21,143,406 253 211
Additional paid-in capital 47,544 35,153
Retained earnings 17,060 10,038
Accumulated comprehensive loss (3,721) -
-------------- --------------
Total stockholders' equity 61,232 45,499
-------------- --------------
$ 118,343 $ 102,351
============== ==============
See accompanying Notes to Consolidated Financial Statements.
F-4
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Operations
Years ended December 31, 2003, 2002, 2001
(dollars in thousands, except per share data)
2003 2002 2001
--------------- ---------------- --------------
Oil and gas revenues $ 33,855 $ 12,106 $ 17,840
-------- -------- --------
Cost and expenses:
Lease operating expense 6,458 2,081 2,737
Production taxes 1,946 796 1,184
General and administrative 4,344 2,153 1,346
Depreciation and depletion 8,390 6,220 6,318
Impairment of oil and gas properties - - 16,820
------- -------- --------
Total costs and expenses 21,138 11,250 28,405
------- -------- --------
Operating income (loss) 12,717 856 (10,565)
------- -------- --------
Other income (expense), net:
Equity in income of First Permian, L.P. - 31,044 840
Incentive awards attributable to the sale of First Permian, L.P. - (1,382) -
Loss on sale of marketable securities - (717) -
Change in fair market value of derivatives (22) (948) -
Gain (loss) on ineffective portion of hedges 191 - -
Interest and other income 116 93 237
Dividend income - 371 -
Interest expense (2,048) (601) (802)
Other expense (259) (332) (529)
------- -------- --------
Total other income (expense), net (2,022) 27,528 (254)
------- -------- --------
Income (loss) before income taxes 10,695 28,384 (10,819)
Income tax benefit (expense), deferred (3,031) (9,683) 6,111
------- -------- --------
Income (loss) before cumulative effect of change in accounting principle 7,664 18,701 (4,708)
Cumulative effect on prior years of a change in accounting principle,
net of tax of $32 (62) - -
------- -------- --------
Net income (loss) 7,602 18,701 (4,708)
------- -------- --------
Cumulative preferred stock dividend (580) (585) (585)
------- -------- --------
Net income (loss) available to common stockholders $ 7,022 $ 18,116 $ (5,293)
======= ======== ========
Net income (loss) per common share:
Basic - before cumulative effect of a change in accounting principle $ 0.33 $ 0.88 $ (0.26)
Cumulative effect of a change in accounting principle, net of tax - - -
------- -------- --------
Basic - after cumulative effect of a change in accounting principle $ 0.33 $ 0.88 $ (0.26)
======= ======== ========
Diluted - before cumulative effect of a change in accounting principle $ 0.31 $ 0.79 $ (0.26)
Cumulative effect of a change in accounting principle, net of tax - - -
------- -------- --------
Diluted - after cumulative effect of a change in accounting principle $ 0.31 $ 0.79 $ (0.26)
======= ======== ========
See accompanying Notes to Consolidated Financial Statements.
F-5
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Stockholders' Equity
Years ended December 31, 2003, 2002 and 2001
(amounts in thousands)
Preferred stock Common stock
------------------ ------------------ Additional Accumulated Total
Number of Number of paid-in Retained Comprehensive stockholders'
shares Amount shares Amount capital earnings (deficit) Loss equity
--------- -------- --------- -------- ---------- ----------------- -------------- -------------
Balance,
January 1, 2001 975 $ 97 20,332 $ 203 $ 34,238 $ (3,370) $ - $ 31,168
Options issued - - - - 99 - - 99
Options exercised,
including income tax
benefit of $123 - - 332 4 359 - - 363
Net loss - - - - - (4,708) - (4,708)
Dividends on preferred stock
($0.60 per share) - - - - (585) - - (585)
-------- -------- ------- -------- -------- -------- -------- --------
Balance
December 31, 2001 975 97 20,664 207 34,111 (8,078) - 26,337
Common stock issued as
part of asset purchase - - 454 5 995 - - 1,000
Options exercised,
including income tax
benefit of $16 - - 25 - 46 - - 46
Net income - - - - - 18,701 - 18,701
Dividends on preferred stock
($0.60 per share) - - - - - (585) - (585)
-------- -------- -------- ------- ------- -------- ------- -------
Balance,
December 31, 2002 975 97 21,143 212 35,152 10,038 - 45,499
Common stock issued - - 4,000 40 12,080 - - 12,120
Preferred stock converted (15) (1) 43 1 - - - -
Warrants issued - - - - 157 - - 157
Options exercised,
including income tax
benefit of $19 - - 31 - 57 - - 57
Stock option expense - - - - 98 - - 98
Decrease in value of cash
flow hedges - - - - - - (3,721) (3,721)
Net income - - - - - 7,602 - 7,602
Dividends on preferred stock - - - - - - - -
($0.60 per share) - - - - - (580) - (580)
-------- -------- -------- -------- -------- -------- -------- ---------
Balance
December 31, 2003 960 $ 96 25,217 $ 253 $ 47,544 $ 17,060 $ (3,721) $ 61,232
======== ======= ======== ======== ======== ======== ======== ========
See accompanying Notes to Consolidated Financial Statements.
F-6
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Cash Flows
Years ended December 31, 2003, 2002 and 2001
(in thousands)
2003 2002 2001
------------ ----------- ------------
Cash flows from operating activities:
Net income (loss) $ 7,602 $ 18,701 $ (4,708)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and depletion 8,390 6,220 6,318
Accretion of asset retirement obligation 139 - -
Equity in income of First Permian, L.P. - (31,044) (840)
Loss on sale of marketable securities - 717 -
Deferred income taxes 3,031 9,683 (6,111)
Change in fair value of derivative instruments 22 508 -
(Gain) loss on ineffective portion of hedges (191) 440 -
Stock option expense 98 - -
Loss on disposal of equipment - - (9)
Impairment of oil and gas properties - - 16,820
Stock-based financial advisory services 157 - 99
Cumulative effect on prior years of a change in accounting principle, net of tax 62 - -
Changes in assets and liabilities:
Other, net 139 (549) 25
(Increase) decrease in receivables (783) (1,608) 2,696
Increase in prepaid expenses (132) (621) (180)
Increase (decrease) in accounts payable and accrued liabilities 931 (388) (727)
Purchase of derivative instruments - (531) -
----------- --------- ---------
Net cash provided by operating activities 19,465 1,528 13,383
----------- --------- ---------
Cash flows from investing activities:
Additions to oil and gas property (14,930) (61,240) (13,126)
Proceeds from disposition of oil and gas property 64 693 1,965
Proceeds from disposition of Energen Stock - 24,863 -
Additions to other property and equipment (331) (531) (211)
Proceeds from disposition of other property and equipment - - 15
Distribution received from investment of First Permian, LLC - 5,938 -
Investment in limited Partnership (297) - -
----------- --------- ---------
Net cash used in investing activities (15,494) (30,277) (11,357)
----------- --------- ---------
Cash flows from financing activities:
Borrowings from bank line of credit 3,174 53,436 2,000
Payments on bank line of credit (13,174) (15,686) (2,428)
Proceeds from exercise of options and warrants 55 45 337
Proceeds (net) from private placement 12,120 - -
Payment of preferred stock dividend (580) (585) (585)
----------- --------- ---------
Cash provided by (used in) financing activities 1,595 37,210 (676)
----------- --------- ---------
Net increase in cash and cash equivalents 5,566 8,461 1,350
Cash and cash equivalents at beginning of year 11,812 3,351 2,001
----------- --------- ---------
Cash and cash equivalents at end of year $ 17,378 $ 11,812 $ 3,351
=========== ========= =========
Non-cash financing and investing activities:
Oil and gas properties asset retirement obligation $ 1,075 $ - $ -
(Non-cash) proceeds from sale of investment of First Permian, L.P. $ - $ (25,580) $ -
Accrued preferred stock dividend $ - $ 24 $ 24
Issuance of stock for purchase of oil and gas property $ - $ 1,000 $ -
See accompanying Notes to Consolidated Financial Statements.
F-7
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Comprehensive Income (Loss)
Years ended December 31, 2003, 2002 and 2001
(dollars in thousands)
2003 2002 2001
------------ ------------- ------------
Net income (loss) $ 7,602 $ 18,701 $ (4,708)
Other comprehensive loss:
Unrealized losses on derivatives (8,336) - -
Reclassification adjustment for losses on derivatives included in net income 2,699 - -
-------- -------- --------
Change in fair value of derivatives (5,637) - -
Income tax benefit 1,916 - -
-------- -------- --------
Total other comprehensive loss (3,721) - -
-------- -------- --------
Total comprehensive incomes (loss) $ 3,881 $ 18,701 $ (4,708)
======== ======== ========
See accompanying notes to Consolidated Financial Statements
F-8
PARALLEL PETROLEUM CORPORATION
Notes to Consolidated Financial Statements
December 31, 2003, 2002 and 2001
(1) Organization, Business and Summary of Significant Accounting Policies
(a) Nature of Operations
Parallel Petroleum Corporation (the Company), a Delaware
corporation, is primarily engaged in the acquisition of, and the
exploration for, development, production and sale of, crude oil
and natural gas. The Company's business activities are carried out
primarily in Texas. The Company's activities are focused in the
onshore Gulf Coast area of south Texas, East Texas and in the
Permian Basin of West Texas and New Mexico.
(b) Basis of Consolidation
The Company's financial statements present the consolidated
results of Parallel Petroleum Corporation, and its wholly owned
subsidiaries, Parallel L.P. and Parallel, L.L.C. All significant
inter-company account balances and transactions have been
eliminated.
(c) Concentration of Credit Risk and Geographic Area
Financial instruments that potentially expose the Company to
concentrations of credit risk consist primarily of unsecured
accounts receivable from unaffiliated working interest owners and
crude oil and natural gas purchasers. A substantial portion of our
oil and natural gas reserves are located in the Permian Basin and
we may be disproportionally exposed to the impact of delays or
interruptions of production from these wells due to mechanical
problems, damages to the current producing reservoirs, significant
governmental regulation, including any curtailment of production
or interruption of transportation of oil or gas produced from the
wells.
(d) Property and Equipment
Oil and gas properties:
The Company uses the full cost method of accounting for its oil
and gas producing activities. Accordingly, all costs associated
with acquisition, exploration, and development of oil and gas
reserves, including directly related overhead costs, are
capitalized.
Management and service fees received for contractual arrangements,
if any, are treated as reimbursement of costs, offsetting the
costs incurred to provide those services.
Depletion is provided using the unit-of-production method based
upon estimates of proved oil and gas reserves with oil and gas
production being converted to a common unit of measure based upon
their relative energy content. Investments in unproved properties
and major development projects are not amortized until proved
reserves associated with the projects can be determined or until
impairment occurs. If the results of an assessment indicate that
the properties are impaired, the amount of the impairment is added
to the capitalized costs to be amortized.
If the net investment in oil and gas properties in a cost center,
as adjusted for asset retirement obligations, exceeds an amount
equal to the sum of (1) the standardized measure of discounted
future net cash flows from proved reserves (see Note 15) and (2)
the lower of cost or fair market value of properties in process of
development and unexplored acreage, the excess is charged to
expense as additional depletion. The standardized measure is
calculated using a 10% discount rate and is based
F-9
on unescalated prices in effect at year-end with effect given to
the Company's cash flow hedge positions. For 2001, the Company
recognized an impairment of approximately $16.8 million. There was
no impairment recorded for 2003 and 2002.
Sales of proved and unproved properties are accounted for as
adjustments of capitalized costs with no gain or loss recognized,
unless such adjustments would significantly alter the relationship
between capitalized costs and proved oil and gas reserves, in
which case the gain or loss is recognized in income. Abandonments
of properties are accounted for as adjustments of capitalized
costs subject to amortization.
Other:
Maintenance and repairs are charged to operations; renewals and
betterments are capitalized to the appropriate property and
equipment accounts.
Upon retirement or disposition of assets other than oil and gas
properties, the cost and related accumulated depreciation are
removed from the accounts with the resulting gains or losses, if
any, recognized in income. Depreciation of other property and
equipment is computed using the straight-line method based on the
estimated useful lives of the property and equipment.
(d) Income Taxes
The Company accounts for federal income taxes using the liability
method. Under the liability method, deferred tax assets and
liabilities are recognized for the future tax consequences
attributable to differences between financial statement carrying
amounts of existing assets and liabilities and their respective
tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years
in which those temporary differences are expected to be recovered
or settled. Under the liability method, the effect on previously
recorded deferred tax assets and liabilities resulting from a
change in tax rates is recognized in earnings in the period in
which the change is enacted.
(e) Investments
Investments in affiliated companies with a 20% to 50% ownership
interest are accounted for on the equity basis and, accordingly,
net income includes the Company's share of their income or loss.
(f) Gas Balancing
Deferred income associated with gas balancing is accounted for on
the entitlements method and represents amounts received for gas
sold under gas balancing arrangements in excess of the Company's
interest in properties covered by such agreements. The Company
currently has no significant amounts outstanding under gas
balancing arrangements.
(g) Stock-Based Compensation
Prior to 2003, Parallel accounted for stock-based compensation
utilizing the intrinsic value method prescribed by Accounting
Principles Board Opinion No. 25 "Accounting for Stock Issued to
Employees" ("APB 25") and related interpretations. In September,
2003, Parallel adopted the provisions of Statement of Financial
Accounting Standards No. 148, Accounting for Stock-Based
F-10
Compensation - Transition and Disclosure, an amendment to SFAS No.
123, whereby certain transitional alternatives are available for a
voluntary change to the fair value based method of accounting for
stock-based employee compensation. Parallel uses the prospective
method which applies prospectively the fair value recognition
method to all employee and director awards granted, modified or
settled after the beginning of the fiscal year in which the fair
value based method of accounting for stock-based compensation is
adopted. The potential impact of using the fair value method, on a
pro forma basis, is presented in the table that follows. As
Parallel adopted the fair value recognition provisions of SFAS No.
123 prospectively for all employee awards granted, modified or
settled after January 1, 2003, the charge for stock-based
compensation included in the determination of income in 2003 and
2002 is less than that which would have been recognized if the
fair value method had been applied to all awards since the
original effective date of SFAS No. 123.
In 2003, Parallel recognized compensation expense of $98,000
associated with its stock option grants. The total number of
options granted during 2003 was 180,000.
The following table illustrates the effect on net income and
earnings per share as if the fair value based method had been
applied to all outstanding and unvested awards in each period. The
fair value of each grant is estimated on the date of grant using
the Black-Scholes option-pricing model.
Year Ended December 31,
-------------------------------------------------
2003 2002 2001
---------------- ---------------- ----------------
(in thousands, except per share data)
Net income (loss) as reported $ 7,602 $ 18,701 $ (4,708)
Add:
Expense recorded in 2003 98 - -
Deduct:
Total stock-based employee compensation expense
determined under fair value method for all awards,
net of related tax effects (587) (757) (239)
------- ------- --------
Pro forma net income (loss) $ 7,113 $ 17,944 $ (4,947)
======= ======== ========
Earnings per share:
Basic -- as reported $ 0.33 $ 0.88 $ (0.26)
======= ======== ========
Basic -- pro forma $ 0.33 $ 0.87 $ (0.26)
======= ======== ========
Diluted -- as reported $ 0.31 $ 0.79 $ (0.26)
======= ======== ========
Diluted -- pro forma $ 0.29 $ 0.74 $ (0.26)
======= ======== ========
(h) Environmental Expenditures
The Company is subject to extensive Federal, state and local
environmental laws and regulations. These laws regulate the
discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the
disposal or release of petroleum or chemical substances at various
sites. Environmental expenditures are expensed or capitalized
depending on
F-11
their future economic benefit. Expenditures that relate to an
existing condition caused by past operations and that have no
future economic benefits are expensed.
Liabilities for expenditures of a noncapital nature are recorded
when environmental assessment and/or remediation is probable, and
the costs can be reasonably estimated. Such liabilities are
generally undiscounted unless the timing of cash payments for the
liability or component are fixed or reliably determinable.
(i) Earnings (loss) Per Share
Basic earnings (loss) per share excludes any dilutive effects of
option, warrants and convertible securities and is computed by
dividing income (loss) available to common stockholders by the
weighted average number of common shares outstanding for the
period. Diluted earnings (loss) per share are computed similar to
basic earnings per share, however diluted earnings per share
reflects the assumed conversion of all potentially dilutive
securities.
The following table provides the computation of basic and diluted
earnings (loss) per share for the year ended December 31:
2003 2002 2001
------------- ------------- --------------
(in thousands except per share data)
Basic EPS Computation:
Numerator-
Net income (loss) before cumulative effect of a change in accounting principle $ 7,664 $ 18,701 $ (4,708)
Cumulative effect of a change in accounting principle, net of tax (62) - -
-------- -------- --------
7,602 18,701 (4,708)
Preferred stock dividend (580) (585) (585)
-------- --------- ---------
Net income (loss) available to common stockholders $ 7,022 $ 18,116 $ (5,293)
======== ========= =========
Denominator-
Weighted average common shares outstanding 21,264 20,680 20,458
======== ========= =========
Basic EPS:
Net income before cumulative effect of a change in accounting principle $ 0.33 $ 0.88 $ (0.26)
Cumulative effect of a change in accounting principle, net of tax - - -
-------- --------- ---------
Basic net earnings (loss) per share $ 0.33 $ 0.88 $ (0.26)
======== ========= =========
Diluted EPS Computation:
Numerator-
Net income (loss) before cumulative effect of a change in accounting principle $ 7,664 $ 18,701 $ (4,708)
Cumulative effect of a change in accounting principle, net of tax (62) - -
-------- --------- ---------
7,602 18,701 (4,708)
Preferred stock dividend - - (585)
-------- --------- ---------
Net income (loss) available to common stockholders $ 7,602 $ 18,701 $ (5,293)
======== ========= =========
Denominator -
Weighted average common shares outstanding 21,264 20,680 20,458
Employee stock options 150 85 -
Warrants 20 - -
Preferred stock 2,741 2,784 -
-------- --------- ---------
Weighted average common shares for diluted earnings per share assuming conversion 24,175 23,549 20,458
======== ========= =========
Diluted EPS:
Net income (loss) before cumulative effect of a change in accounting principle $ 0.31 $ 0.79 $ (0.26)
Cumulative effect of a change in accounting principle, net of tax - - -
-------- --------- ---------
Diluted net earnings (loss) per share $ 0.31 $ 0.79 $ (0.26)
======== ========= =========
F-12
Some stock options and the convertible preferred stock outstanding
during 2003, 2002 and 2001 were not included in the computation of
diluted net earnings (loss) per share because either (i) the stock
options' exercise price was greater than the average market price
of common stock of the Company, (ii) the effect of the assumed
conversion of the Company's preferred stock to common stock would
be antidilutive, or (iii) the Company had a net loss from
continuing operations and, therefore, the effect would be
antidilutive.
(j) Use of Estimates in the Preparation of Financial Statements
Preparation of the accompanying financial statements in conformity
with accounting principles generally accepted in the United States
of America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and
expenses during the reporting period. The oil and gas reserve
estimates, and the related future net cash flows derived from
those reserves, are used in the determination of depletion expense
and the full-cost ceiling test and are inherently imprecise.
Actual results could differ from those estimates.
(k) Cash Equivalents
For purposes of the statements of cash flows, the Company
considers all demand deposits, money market accounts and
certificates of deposit purchased with an original maturity of
three months or less to be cash equivalents.
(l) Reclassifications
Certain reclassifications have been made to 2002 amounts to
conform to the 2003 presentation.
(m) Derivative Financial Instruments
Derivative financial instruments, utilized to manage or reduce
commodity price risk related to the Company's production and
interest rate risk related to the Company's long-term debt, are
accounted for under the provisions of SFAS No. 133, "Accounting
for Derivative Instruments and for Hedging Activities", and
related interpretations. Under this statement, all derivatives are
carried on the balance sheet at fair value. If the derivative is
designated as a fair value hedge, the changes in the fair value of
the derivative and of the hedged item attributable to the hedged
risk are recognized in earnings. If the derivative is designated
as a cash flow hedge, the effective portions of changes in the
fair value of the derivative are recorded in other comprehensive
income ("OCI") and are recognized in the statement of operations
when the hedged item affects earnings. If the derivative is not
designated as a hedge, changes in the fair value are recognized in
other expense. Ineffective portions of changes in the fair value
of cash flow hedges are recognized in other expense.
(n) Revenue Recognition
Oil and natural gas revenues are recorded using the sales method,
whereby the Company recognizes oil and natural gas revenue based
on the amount of oil and gas sold to purchasers.
F-13
The following summarizes our revenue for each of the three years
ended December 31 by product sold.
2003 2002 2001
------------ ------------ ------------
(in thousands)
Oil revenue $ 18,300 $ 3,217 $ 3,429
Oil hedge (1,659) - -
Gas revenue 18,121 8,889 14,411
Gas hedge (907) - -
-------- ------- --------
$ 33,855 $ 12,106 $ 17,840
======== ======== ========
(o) Recent Accounting Pronouncements
FIN No. 45, Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Other. FIN No. 45 requires that a liability be recorded in the
guarantor's balance sheet upon issuance of certain guarantees.
Initial recognition and measurement of the liability will be
applied on a prospective basis to guarantees issued or modified
after December 31, 2002. FIN No. 45 also requires disclosures
about guarantees in financial statements for interim or annual
periods ending after December 15, 2002. The adoption had no impact
on the Company's consolidated financial statements.
FIN No. 46, Consolidation of Variable Interest Entities. In
December 2003, the FASB issued Interpretation No. 46R, which
requires the consolidation of certain entities that are determined
to be variable interest entities ("VIE"). An entity is considered
to be a VIE when either (i) the entity lacks sufficient equity to
carry on its principal operations, (ii) the equity owners of the
entity cannot make decisions about the entity's activities or
(iii) the entity's equity neither absorbs losses or benefits from
gains. The Company owns no interests in variable interest
entities, and therefore this new interpretation has not affected
the Company's consolidated financial statements.
In April, 2003, the Financial Accounting Standards Board issued
SFAS No. 149, Amendment of Statement 133 on Derivative Instruments
and Hedging Activities, which clarifies financial accounting and
reporting for derivative instruments, including certain derivative
instruments embedded in other contracts and for hedging activities
under SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities. The Statement is effective for contracts
entered into or modified after June 20, 2003. The adoption of SFAS
149 did not have a material impact on the Company's consolidated
financial statements.
In May, 2003, the Financial Accounting Standards Board issued SFAS
No. 150 "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity." This statement
establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both
liabilities and equity. This statement was effective for financial
instruments entered into or modified after May 31, 2003, and
otherwise was effective at the beginning of the first
F-14
interim period beginning after June 15, 2003. The adoption of SFAS
150 did not have a material impact on the Company's consolidated
financial statements.
A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and SFAS No. 142 to companies in the
extractive industries, including oil and gas companies. The issue
is whether SFAS No. 142 requires registrants to classify the costs
of mineral rights held under lease or other contractual
arrangements associated with extracting oil and gas as intangible
assets in the balance sheet, apart from other capitalized oil and
gas property costs, and provide specific footnote disclosures.
Historically, Parallel has included the costs of such mineral
rights associated with extracting oil and gas as a component of
oil and gas properties. If it is ultimately determined that SFAS
No. 142 requires oil and gas companies to classify costs of
mineral rights held under lease or other contractual arrangement
associated with extracting oil and gas as a separate intangible
assets line item on the balance sheet, the Company would be
required to reclassify approximately $17.3 million at December 31,
2003 and $13.5 million at December 31, 2002 out of Oil and Gas
Properties and into a separate intangible assets line item.
Parallel's cash flows and results of operations would not be
affected since such intangible assets would continue to be
depleted and assessed for impairment in accordance with full cost
accounting rules.
(2) Fair Value of Financial Instruments
The carrying amount of cash, accounts receivable, accounts payable, and
accrued liabilities approximates fair value because of the short maturity
of these instruments.
The carrying amount of long-term debt approximates fair value because the
Company's current borrowing rate is based on a variable market rate of
interest.
(3) Oil and Gas Properties
The following table reflects capitalized costs related to the oil and gas
properties as of December 31:
2003 2002
------------------ -------------------
(in thousands)
Proved properties $ 160,287 $ 144,787
Unproved properties, not subject to depletion 2,334 1,893
---------- ---------
162,621 146,680
Accumulated depletion (69,726) (61,614)
---------- ---------
$ 92,895 $ 85,066
========= =========
Certain directly identifiable internal costs of property acquisition,
exploration, and development activities are capitalized. Such costs
capitalized in 2003, 2002 and 2001 totaled $915,000, $1.3 million and
$782,000, respectively.
Depletion per equivalent unit of production (BOE) was $6.83, $10.52 and
$9.13 for 2003, 2002, and 2001, respectively.
F-15
The following table reflects costs incurred in oil and gas property
acquisition, exploration, and development activities for each of the
years in the three year period ended December 31:
2003 2002 2001
-------------- --------------- --------------
(in thousands)
Proved property acquisition costs $ 2,209 $ 48,044 $ 27
Unproved property acquisitions costs 3,831 2,295 3,420
Exploration 3,240 1,291 6,821
Development 5,650 9,308 1,203
------- -------- --------
$14,930 $ 60,938 $ 11,471
======= ======== ========
On December 20, 2002, we purchased, through our subsidiary, Parallel,
L.P., a majority non-operated interest in producing oil and gas
properties located in the Fullerton Field of Andrews County, Texas in the
Permian Basin of west Texas. The total purchase price for our interest in
the Fullerton properties was $46.0 million.
(4) Asset Retirement Obligation
On January 1, 2003 the Company adopted Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations "SFAS
143". SFAS 143 requires companies to recognize a liability for the
present value of all legal obligations associated with the retirement of
tangible long-lived assets and to capitalize an equal amount as part of
the cost of the related oil and gas properties.
The adoption of this statement required the Company to record a non-cash
expense, net of tax, of approximately $62,000 as a cumulative effect of
change in accounting principle in the first quarter of 2003, as well as a
non-current liability of approximately $1.7 million and an addition to
oil and gas properties of approximately $1.5 million. The following table
summarizes the Company's asset retirement obligation transactions as if
SFAS No. 143 had been applied during all periods presented.
2003 2002 2001
----------------- ------------- ------------
(in thousands)
Pro Forma
--------------------------
Beginning asset retirement obligation $ 1,469 $ 897 $ 793
Additions related to new properties 345 498 39
Deletions related to property disposals (252) - -
Accretion expense 139 74 65
------- ------- -------
Ending asset retirement obligation $ 1,701 $ 1,469 $ 897
======= ======= =======
Applying the provisions of SFAS No. 143 reduced 2003 income before
cumulative effect of changes in accounting principle by $139,000
($92,000, or $0.00 per share, net of income taxes).
F-16
The table below reflects, on a pro forma basis, the net income (loss) and
net income (loss) per share amounts as if the provisions of SFAS No. 143
had been applied during all the periods presented. Year 2003 is presented
to show the effect on net income had the provisions of SFAS No. 143 been
adopted at the beginning of 2001.
2003 2002 2001
--------------- ---------------- ---------------
(dollars in thousands except per share data)
Net income (loss), as reported $ 7,602 $ 18,701 $ (4,708)
Accretion of asset retirement obligation, net of tax - (39) (13)
Cumulative effect of change in
accounting principle, net of tax 62 - -
-------- -------- --------
Pro forma net income (loss) $ 7,664 $ 18,662 $ (4,721)
======== ========= =========
Basic net income (loss) per share, as reported $ 0.33 $ 0.88 $ (0.26)
======== ========= =========
Basic net income (loss) per share, pro forma $ 0.34 $ 0.88 $ (0.26)
======== ========= =========
Diluted net income (loss) per share, as reported $ 0.31 $ 0.79 $ (0.26)
======== ========= =========
Diluted net income (loss) per share, pro forma $ 0.32 $ 0.79 $ (0.26)
======== ========= =========
(5) Derivative Instruments
In 2002, the Company began entering into derivative contracts to provide
a measure of stability in the Company's oil and gas revenues and interest
rate payments and to manage exposure to commodity price and interest rate
risk. The Company's objective is to lock in a range of oil and gas prices
and a fixed interest rate for certain notional amounts. For the year
ended December 31, 2002, the Company did not designate derivative
contracts as hedges. Accordingly, unrealized gains or losses on these
contracts were recorded through income. As of January 1, 2003 the Company
designated its interest rate swaps, costless collars and the commodity
swaps as cash flow hedges (see below). The effective portion of the
unrealized gain or loss on cash flow hedges is recorded in other
comprehensive income until the forecasted transaction occurs. The Company
continued to record the unrealized gains or losses on put contracts to
income. During the terms of a cash flow hedge, the effective portion of
the quarterly change in the fair value of the derivatives is recorded in
stockholders' equity as other comprehensive income (loss) and then
transferred to oil and gas revenues when the production is sold and
interest expense when the interest payment is made. Ineffective portions
of hedges (changes in realized prices that do not match the changes in
the hedge price) are recognized in other expense as they occur. While the
hedge contract is open, the ineffective gain or loss may increase or
decrease until settlement of the contract.
As of December 31, 2003, the Company had recorded unrealized losses of
$5.9 ($3.7 million, net of tax) related to its derivative instruments,
which represented the estimated aggregate fair values of the Company's
open derivative contracts as of that date. These unrealized losses are
presented on the Consolidated Balance Sheet as a current liability of
$3.2 million and long-term liabilities of $2.7 million. During the twelve
month period ending December 31, 2004 the Company expects approximately
$2.1 million, net of tax, to be transferred out of other comprehensive
income (loss) and charged to earnings.
F-17-
The Company is exposed to credit risk in the event of nonperformance by
BNP Paribas in its derivative instruments. However, the Company
periodically assesses its credit worthiness to mitigate this credit risk.
Interest Rate Sensitivity
Swaps. In January, 2003, the Company entered into a 45-month libor fixed
interest rate swap contract with BNP Paribas. The Company will receive a
fixed interest rate, as noted in the table below, for the 45-month period
beginning March 31, 2003 through December 20, 2006. Prior to January
2003, the Company did not hedge its interest rate risk.
In 2002, the decrease in fair value of the swaps of $440,000 was
recognized in the Consolidated Statements of Operations.
Under the Company's revolving credit facility, the Company may elect an
interest rate based upon the agent lender's base lending rate, or the
libor rate, plus a margin ranging from 2.25% to 2.75% per annum,
depending on the Company's borrowing base usage. The interest rate the
Company is required to pay, including the applicable margin, may never be
less than 4.50%.
A recap for the period of time, notional amounts, libor fixed interest
rates, expected margin rates and expected fixed interest rates for the
contract are as follows:
Libor Expected Expected
Period of Time Notional Amounts(1) Fixed Interest Rates(2) Margin Rates(3) Fixed Interest Rates(4)
------------------------------- ----------------------- ------------------------ ------------------ ------------------------
Dec 31, 2003 thru Dec 31, 2004 $ 30,000,000 2.660% 2.500% 5.160%
Dec 31, 2004 thru Dec 31, 2005 $ 20,000,000 4.050% 2.250% 6.300%
Dec 31, 2005 thru Dec 20, 2006 $ 10,000,000 4.050% 2.250% 6.300%
---------------------
(1) Based on the anticipated principal reductions under the Company's
credit facility.
(2) The Company's swap contract with BNP Paribas.
(3) Based on the anticipated borrowing base usage under the Company's
credit facility.
(4) Total of the libor fixed interest rate plus the expected margin rate
under the Company's credit facility. The Company's credit agreement
requires the interest rate to not be below 4.50%.
Commodity Price Sensitivity
Puts. On May 24, 2002 the Company purchased put floors on volumes of
100,000 Mcf per month for a total of 700,000 Mcf during the seven month
period from April, 2003 through October, 2003 at a floor price of $3.00
per Mcf for a total consideration of approximately $139,500. These
derivatives were not held for trading purposes.
A decrease in fair value of the put floors of $22,000 and $508,000 was
recognized in the Consolidated Statements of Operations for the years
ended 2003 and 2002, respectively.
Costless Collars. Collars are created by purchasing puts to establish a
floor price and then selling a call which establishes a maximum amount
the producer will receive for the oil or gas hedged. Calls are sold to
offset the premium paid for buying the put. In 2003, the Company entered
into several costless, seven-month Houston ship channel gas collars. A
majority of the Company's natural gas production is sold based
F-18
on Houston ship channel prices. A recap for the period of time, number of
MMBtu's and average gas prices is as follows:
Houston Ship Channel
gas prices
MMBtu of ---------------------------------
Period of Time Natural Gas Floor Cap
--------------------------------------------- ------------- ------------ -------------------
January 1, 2004 thru March 31, 2004 273,000 $ 5.43 $ 6.58
April 1 2004 thru October 31, 2004 214,000 $ 4.40 $ 5.50
Swaps. Generally, swaps are an agreement to buy or sell a specified
commodity for delivery in the future, but at an agreed fixed price. Swap
transactions convert a floating price into a fixed price. For any
particular swap transaction, the counterparty is required to make a
payment to the hedge party if the reference price for any settlement
period is less than the swap price for such hedge, and the hedge party is
required to make a payment to the counterparty if the reference price for
any settlement period is greater than the swap price for such hedge.
In 2003, the Company entered into additional oil and gas swap contracts
with BNP Paribas. A recap for the period of time, number of MMBtu's,
number of barrels, and swap prices are as follows:
Barrels Houston Ship
of Nymex Oil MMBtu of Channel
Period of Time Oil Swap Price Natural Gas Gas Swap Price
- -------------------------------------------------- ------------- -------------- --------------- -------------------
January 1, 2004 thru December 31, 2004 439,200 $ 24.45 - $ -
April 1, 2004 thru December 31, 2004 - $ - 764,000 $ 4.692
January 1, 2005 thru December 31, 2005 365,000 $ 23.35 - $ -
January 1, 2005 thru March 31, 2005 - $ - 180,000 $ 4.705
January 1, 2006 thru December 20, 2006 265,500 $ 23.04 - $ -
(6) Equity Investment and Business Acquisition
During 2003, the Company invested $290,000 in a partnership to construct
a pipeline on its leaseholds in the Barnett Shale area, which is recorded
in other long term assets in the accompanying consolidated balance sheet.
The total commitment of the Company is approximately $350,000, resulting
in a 28% interest in the partnership, which mirrors the Company's working
interest in the leaseholds in the area. The Company intends to develop
those leaseholds and utilize the pipeline to transport the resulting
production to market. The partnership is currently acquiring the
necessary easements and permits for the pipeline. Upon successful
completion of the acquisition of the easements, construction of the
pipeline and development of the leasehold will commence. The partnership
had no operations in 2003.
F-19
On March 7, 2002, First Permian entered into an Agreement of Sale and
Purchase with Energen Resources Corporation, a wholly owned subsidiary of
Energen Corporation (Energen), to sell all of First Permian's oil and gas
properties for a gross consideration of $120.0 million in cash and 3.0
million shares in Energen stock approximating $70.0 million in value.
Energen is a publicly traded company listed on the NYSE. The transaction
closed on April 8, 2002. As a 30.675% interest owner in First Permian,
the Company received its prorata share of the net proceeds, $5.5 million
in cash and 933,589 shares of Energen common stock. All shares of Energen
stock were sold prior to December 31, 2002 for $24.9 million; resulting
in the total proceeds from the sale of First Permian in the amount of
$30.4 million.
On December 20, 2002 the Company purchased through the Company's
subsidiary, Parallel, L.P., a majority of non-operated interest in
producing oil and gas properties located in the Fullerton Field of
Andrews County, Texas in the Permian Basin of west Texas. The total
purchase price for the Company's interest in the Fullerton properties was
$46.0 million.
The following table presents unaudited pro forma operating results as if
the purchase was effective on January 1, 2002.
Pro forma
----------------------------------------------
2002 2001
---------------------- ----------------------
(in thousands, except per share data)
Revenues $ 22,236 $ 27,474
Operating income $ 7,292 $ (4,552)
Net income available to common stockholders $ 22,364 $ (1,325)
Net income per common share:
Basic $ 1.09 $ (0.06)
Diluted $ 0.97 $ (0.06)
The pro forma results have been prepared for comparative purposes only.
The pro forma results do not purport to present actual results that would
have been achieved or to be indicative of future results.
(7) Long-Term Debt
Long-term debt consists of the following at December 31:
2003 2002
--------------- -----------------
(in thousands)
Revolving Facility note payable to banks, at the agent bank's base lending rate
(4.5% at December 31, 2003) $ 39,750 $ 49,750
Less: current maturities - 4,146
--------------- -----------------
$ 39,750 $ 45,604
=============== =================
On July 19, 2002, the Company entered into a loan agreement ("the
Facility") to refinance its outstanding indebtedness. Under the facility,
the Company may borrow the lesser of $100.0 million or the "borrowing
base" then in effect. The borrowing base calculation is based upon the
estimated value of the Company's oil and gas reserves. The credit
agreement was amended in September, 2003. The amendment included the
F-20
deletion of the monthly commitment reduction, a provision that would have
had the Company begin amortizing its loan beginning August 31, 2003; the
modification of certain financial ratio tests; changes in certain
reporting requirements to the banks; and the revision of covenants in the
credit agreement governing the Company's hedging activities.
The borrowing base at December 31, 2003 was $50.0 million. All borrowings
are collateralized by the Company's oil and gas reserves. The total
outstanding principal amount of the Company's bank indebtedness at
December 31, 2003 and 2002 was $39.8 million and $49.8 million,
respectively, excluding $250,000 for Letters of Credit. The borrowing
base is subject to redetermination semi-annually, on or about April 1 and
October 1 or at times required by the banks or at the Company's request.
All indebtedness matures December 20, 2006.
Unpaid principal balances under the Facility bear interest at the
election of the Company at a rate equal to (i) the bank's base lending
rate, or (ii) the libor rate plus a libor margin of 2.25% to 2.75%.
However, the interest rate may never be less than 4.50%. Interest is due
and payable on the day which the related libor interest period ends. The
Company is required to pay a commitment fee of .25% times the daily
average of the unadvanced amount of the commitment.
The loan agreement includes various restrictive covenants and compliance
requirements. Among these covenants and restrictions are:
. dispose of assets;
. incur additional indebtedness;
. restrictions on all the retained earnings and net income for
payment of dividends on the Company's common stock;
. create liens on our assets;
. enter into specified investments or acquisitions;
. repurchase, redeem or retire our capital stock or other
securities;
. merge or consolidate, or transfer all or substantially all
of our assets and the assets of our subsidiaries;
. engage in specified transactions with subsidiaries and
affiliates; or
. engage in other specified corporate activities.
As of December 31, 2003 the Company was in compliance with all covenants.
F-21
(8) Income Taxes
The Company's income tax provision is attributable to the following items:
Years ended December 31,
---------------------------------------
2003 2002 2001
------------ ------------- ------------
(dollars in thousands)
Income before cumulative effect of change
in accounting principle $ 3,031 $ 9,683 $ (6,111)
Cumulative effect of change in accounting principle (32) - -
Losses on derivatives recognized in other
comprehensive income (1,916) - -
------- ------- --------
Total income tax provision $ 1,083 $ 9,683 $ (6,111)
======= ======= ========
Federal income tax expense (benefit) applicable to income before
cumulative effect of change in accounting principle differs from the
amount computed at the Federal statutory rate as follows:
Year ended December 31,
---------------------------------------------
2003 2002 2001
-------------- --------------- --------------
(in thousands)
Income tax expense (benefit) at statutory rate $ 3,700 $ 9,651 $ (3,678)
Change in valuation allowance for deferred tax assets - - (2,063)
Statutory depletion (96) (360) (389)
State tax, net of federal benefit(1) (594) 370 -
Nondeductible expenses and other 21 22 19
------- ------- --------
Income tax expense (benefit) $ 3,031 $ 9,683 $ (6,111)
======= ======= ========
- ---------------
(1) The state tax benefit resulted from the Company reducing its estimate of
State income tax liability.
F-22
The tax effect of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at
December 31 are as follows:
2003 2002
-------- ---------
(in thousands)
Current:
Deferred tax assets:
Losses on derivatives recognized in other comprehensive income $ 1,098 $ -
======== =======
Noncurrent:
Deferred tax assets:
Net operating loss carryforwards, state and federal $ 3,104 $ 4,264
Statutory depletion carryforwards 1,724 1,418
Alternative minimum tax credit carryforward 118 118
Equity investment in First Permian, LLC 16 59
Allowance for accounts receivable - 5
Losses on derivatives recognized in other comprehensive income 818 -
Other 169 163
-------- -------
Total noncurrent deferred tax assets 5,949 6,027
-------- -------
Deferred tax liabilities:
Property and equipment, principally due to differences in
basis, expensing of intangible drilling costs for tax
purposes and depletion (11,758) (9,655)
-------- -------
Total deferred tax liabilities (11,758) (9,655)
-------- -------
Net noncurrent deferred income tax liability $ (5,809) $ (3,628)
======== ========
As of December 31, 2003, the Company had net operating loss carryforwards
for regular tax and alternative minimum taxable income (AMT) purposes
available to reduce future taxable income. These carryforwards expire as
follows:
Net operating AMT
loss operating loss
----------------- -----------------
(in thousands)
2019 $ 4,510 $ 4,869
2021 4,576 4,498
2022 44 44
------- -------
$ 9,130 $ 9,411
======= =======
As of December 31, 2003, the Company had approximately $118,000 of
alternative minimum tax (credit carryover that does not expire.
F-23
(9) Equity Transactions
Preferred Stock
As of December 31, 2003 the Company had outstanding 959,500 shares of 6%
Convertible Preferred Stock, $0.10 par value per share. Cumulative annual
dividends of $0.60 per share are payable semi-annually on June 15 and
December 15 of each year. Each share of Convertible Preferred Stock may
be converted, at the option of the holder, into 2.8571 shares of common
stock at an initial conversion price of $3.50 per share, subject to
adjustment in certain events. The Convertible Preferred Stock has a
liquidation preference of $10 per share and has no voting rights, except
as required by law. The Company may redeem the preferred stock, in whole
or part, for $10 per share plus accrued and unpaid dividends.
On October 5, 2000, the Company authorized 50,000 shares of $0.10 par
Series A Preferred Stock. These shares will be issued upon the exercise
of the Company's Preferred Stock Purchase Rights. Subject to the rights
of the holders of any series of preferred stock ranking prior and
superior to the Series A preferred stock with respect to dividends, the
holders of shares of the Series A Preferred Stock shall be entitled to
receive, when, and if declared by the board of directors, quarterly
dividends payable in cash on the first day of July, October, January and
April, in each year, commencing on the first quarterly dividend payment
Date after the first issuance of a fraction of a share of Series A
Preferred Stock. Each share of Series A Preferred Stock shall entitle the
holder to one one-thousandth of a vote on all matters submitted to a vote
of the stockholders of the Company.
Sale of Equity Securities
On December 23, 2003, the Company privately placed a total of 4.0 million
shares of common stock, $.01 par value per share, at a price of $3.25 per
share. Gross cash proceeds from the placement were $13.0 million, and net
proceeds were $12.1 million. The shares were subsequently registered for
resale under the Securities Act of 1933, as amended.
(10) Stock Options, Warrants and Rights
At the election of the board of directors, the Company awards both
incentive stock options and nonqualified stock options to selected key
employees and officers. The options are awarded at an exercise price
equal to the closing price of the Company's common stock on the date of
grant. These options vest over a period of two to ten years with a
ten-year exercise period. As of December 31, 2003, options expire
beginning in the current year and extending through 2013. Options to
purchase a total of 192,500 shares of common stock remain available for
grant.
Under FAS 123, the fair value of each stock option grant is estimated on
the date of grant using the Black-Scholes option pricing model with the
following weighted average assumptions used for grants in 2003 and 2002.
2003 2002 2001
------------ ------------ ------------
Risk-free interest rate 3.7% 2.5% 4.49%
Expected life 8 years 8 years 8 years
Expected volatility 45.3% 45.2% 56.0%
F-24
A summary of the Company's employee stock options as of December 31,
2003, 2002 and 2001, and changes during the years ended on those dates is
presented below:
Year ended Year ended Year ended
December 31, 2003 December 31, 2002 December 31, 2001
--------------------------- -------------------------- ---------------------------
Number of Weighted Number of Weighted Number of Weighted
shares average price shares average price shares average price
------------ ------------- ------------ ------------- ------------ -------------
Stock options:
Outstanding at beginning of year 2,338,750 $ 2.71 2,103,750 $ 3.74 1,951,750 $ 3.13
Options granted 180,000 2.96 345,000 2.54 700,000 4.87
Options exercised (30,600) (1.82) (25,000) (1.82) (325,500) (1.03)
Options cancelled (100,000) (4.97)
Options expired (250,000) (3.94) (85,000) (1.75) (222,500) 3.80
------------ ---------- ----------
Outstanding at end of year 2,138,150 $ 3.65 2,338,750 $ 2.71 2,103,750 $ 3.74
============ =========== ========== ========== ========== ==========
Exercisable at end of year 1,785,650 $ 3.85 1,656,250 $ 2.82 1,451,250 $ 3.54
============ =========== ========== ========== ========== ==========
Weighted average fair value of
options granted during the year $ 1.64 $ 1.66 $ 3.18
The following table summarizes information about the Company's employee
stock options outstanding at December 31, 2003:
Options outstanding Options exercisable
---------------------------------------------- -----------------------------
Number Weighted Number
Outstanding at average Weighted exercisable at Weighted
Range of December 31, remaining average December 31, average
exercise prices 2003 contractual life exercise price 2003 exercise price
---------------- --------------- ----------------- -------------- -------------- --------------
$1.81 - $3.94 1,149,400 8 years $ 2.69 796,900 $ 2.66
$4.09 - $5.50 988,750 6 years $ 4.81 988,750 $ 4.81
--------------- --------------
2,138,150 1,785,650
=============== ==============
(a) Stock Warrants
The Company has outstanding at December 31, 2003 and 2002, 300,000
warrants which were issued as part of the Company's initial public
offering in 1980. Each warrant allows the holder to buy one share of
common stock for $6.00. The warrants are exercisable for a 30 day period
commencing on the date a registration statement covering exercise is
declared effective. The warrants contain antidilution provisions and in
the event of liquidation, dissolution, or winding up of the Company, the
holders are not entitled to participate in the assets of the Company.
The Company also has outstanding at December 31, 2003 and 2002; an
additional 275,000 warrants issued as partial payment for services
rendered for financial and investment advice in 2001. The warrants have
an exercise price equal to the average of the last bid and asked price of
the Company's common stock on the
F-25
effective date of the issuance of the warrants and have a term of five
years from date of issuance and a vesting period of one year. The
exercise price for the warrants is $2.95. The expense related to these
warrants in the amount of $99,000 was recorded in other expenses in 2001
and is based on the estimated fair value on the date of grant using the
Black-Scholes option pricing model.
The Company has outstanding at December 31, 2003, 100,000 warrants which
were issued as partial payment for services rendered for financial and
investment advice for the Company's private placement offering in
December, 2003. The warrants have an exercise price equal to the average
of the last bid and last asked price of the Company's common stock on the
effective date of the issuance of the warrants and have a term of five
years from date of issuance and a vesting period of one year. The
exercise price for the warrants is $3.98. The fair value related to these
warrants in the amount of $157,000 was recorded in other expenses in 2003
and is based on the estimated fair value on the date of grant using the
Black-Scholes option pricing model.
(b) Stock Rights
On October 5, 2000, the board of directors declared a dividend of one
Right for each outstanding share of the Company's common stock. If a
public announcement that a person has acquired 15% or more of the
Company's common stock or a tender offer or exchange offer is made for
15% or more of the common stock, each Right will entitle the holder to
purchase from the Company one one-thousandth of a share of Series A
Preferred Stock, par value $0.10 per share, at an exercise price of
$26.00 per one one-thousandth of a share, subject to adjustment.
Initially, the Rights attach to all common stock certificates
representing shares then outstanding, and no separate rights certificates
will be distributed. The Rights separate from the common stock upon the
earlier of (1) ten business days following a public announcement that a
person or group of affiliated or associated persons has acquired or
obtained the right to acquire, beneficial ownership of 15% or more of the
outstanding shares of common stock or (2) ten business days (or such
later date as the board of directors shall determine) following the
commencement of a tender or exchange offer that would result in a person
or group beneficially owning 15% or more of such outstanding shares of
common stock. The date the Rights separate is referred to as the
"distribution date".
Under certain circumstances the rights entitle the holders to buy the
Company's stock at a 50% discount. In the event that (1) the Company is
the surviving corporation in a merger or other business combination with
an entity that owns 15% or more of the Company's outstanding stock; (2)
any person shall acquire beneficial ownership of 15% of the Company's
outstanding stock; or (3) there is any type of recapitalization of the
Company that results in an increase by more than 1% the proportionate
share of equity securities of the Company owned by a person who owns 15%
or more of the Company's outstanding stock, each right holder will have
the option to buy for the purchase price common stock of the Company
having a value equal to two times the purchase price of the right.
Under certain circumstances the rights entitle the holders to buy shares
of the acquirer's common stock at a 50% discount. In the event that, at
any time after a person has acquired 15% or more of the Company's common
stock, (1) the Company enters into a merger or other business combination
transaction in which the Company is not the surviving corporation; (2)
the Company is the surviving corporation in a transaction in which all or
part of the common stock is exchanged for cash, property or securities of
any other person; or (3) more than 50% of the assets, cash flow or
earning power of the Company is sold, each right holder will have the
option to buy for the purchase price stock of the acquiring company
having a value equal to two times the purchase price of the right.
F-26
The Rights are not exercisable until the distribution date and will
expire at the close of business on October 5, 2010, unless earlier
redeemed by the Company for $0.001 per right.
(11) Related Party Transactions
An entity in which Thomas R. Cambridge, the Chairman of the Board, is the
owner acted as the Company's agent in performing the routine day to day
operations on 2 wells. In 2003, 2002 and 2001 the Company was billed
approximately $51,000, $85,000 and $115,000 respectively, for the
Company's pro rata share of lease operating and drilling expenses and
received $198,000, $187,000 and $319,000 in 2003, 2002, and 2001
respectively, in oil and gas revenues related to these wells. These 2
wells were acquired in 1984.
Dewayne E. Chitwood, a Director of the Company, also serves as director
of an entity which owns 110,000 shares of preferred stock of the Company.
In addition, a Foundation, where Mr. Chitwood is the chairman of the
board of directors of the Foundation, and a Trust, where he is trustee,
owns a total of 55,000 shares each of preferred stock of the Company. All
of the shares of preferred stock of the Company were purchased in 1998 at
a price of $10 per share on the same terms as all other unaffiliated
purchasers.
An entity, in which Mr. Chitwood is an officer of the managing general
partner, owned interests in certain wells that are operated by the
Company. During 2003, 2002 and 2001 the Company charged approximately
$23,000 and $34,000 and $264,000 respectively, for lease operating
expenses and paid $74,000, $69,000 and $176,000 respectively, in oil and
gas revenues related to these wells.
In 2001, Martin B. Oring, a Director of the Company, acquired an interest
in a portion of the warrants awarded to the Company's investment advisor
(see note 10(a)) whereby the director acted as a consultant for the
investment advisor. The fair value of the warrants was estimated on the
date of grant to be $33,000 using the Black-Scholes Option Pricing model.
(12) Statements of Cash Flows
No Federal income taxes were paid in 2003, 2002 and 2001.
The Company made interest payments of approximately $2.0 million,
$601,000 and $802,000 in 2003, 2002 and 2001, respectively.
At December 31, 2003 and 2002, there were $600,000 and $301,000,
respectively, of property additions accrued in accounts payable.
F-27
(13) Major Customers
The following purchasers accounted for 10% or more of the Company's oil
and gas sales for the years ended December 31:
2003 2002 2001
--------------- -------------- ---------------
Company A 30% 31% 38%
Company B - 16% 23%
Company C - 10% 25%
Company D 33% - -
(14) Commitments and Contingencies
At December 31, 2003, the Company was involved in one lawsuit incidental
to the Company's business. The Company accrues for such items when a
liability is both probable and the amount can be reasonably estimated.
The Company does not believe the ultimate outcome of this lawsuit will
have a material adverse effect on the Company's financial position or
results of operations, therefore no amount has been accrued. The Company
is not aware of any threatened litigation. The Company has not been a
party to any bankruptcy, receivership, reorganization, adjustment or
similar proceeding.
The Company established a simplified employee pension plan "SEP" covering
all salaried employees of the Company. The employees voluntarily
contribute a portion of their eligible compensation, not to exceed
$12,000, to the plan. In addition to the annual salary deferral limit
stated above, employees who reach age 50 or older during a calendar year
can elect to take advantage of a catch-up salary deferral contribution;
eligible participants can increase their salary deferral by $2,000 for
the year 2003. The Company may make discretionary contributions to the
plan; however, total contributions cannot exceed $40,000 per employee.
During 2003, 2002 and 2001, the Company contributed an aggregate of
approximately $106,000, $56,000, and $40,000, respectively, to the Plan.
On November 25, 2003, the Company's Board of Directors approved in
principle the adoption of an employee retention/severance plan that would
be effective January 1, 2004. Although specific details of the plan have
not been determined and the plan is not in final written form, the
Company expects that the significant provisions of the plan will provide
for a one-time payment of all officers and employees of the Company upon
the occurrence of a change of control. The aggregate payments of all
officers and employees will generally be 5% of an amount equal to the
positive difference between the amount by which the Company's net asset
value per share at the time of the occurrence of a change of control
exceeds the net asset value per share as of January 1, 2004, compounded
annually at a rate equal to the annual industry average growth rate, plus
2.00%. Generally the Company contemplates that a "change of control" will
include events such as a merger, reorganization, liquidation or sale of
substantially all of the asset of the Company, or the acquisition by a
third party of 50% or more of our outstanding voting securities.
The Company leases office space under a non-cancelable operating lease
expiring in 2006. Future annual payments under this operating lease are
$128,000, $157,000 and $105,000 for the years ended December 31, 2004,
2005 and 2006, respectively. Rental expense under our current and former
lease totaled $130,000, $84,000 and $54,000 for the years ended December
31, 2003, 2002 and 2001, respectively.
F-28
(15) Supplemental Oil and Gas Reserve Data (Unaudited)
The Company has presented the reserve estimates utilizing an oil price of
$30.63, $29.21 and $18.98 per Bbl and a gas price of $5.45, $4.40 and
$2.72 per Mcf as of December 31, 2003, 2002 and 2001, respectively.
Information for oil is presented in barrels (BBL) and for gas in
thousands of cubic feet (MCF).
The estimates of the Company's proved natural gas reserves and related
future net cash flows that are presented in the following tables are
based upon estimates made by independent petroleum engineering
consultants.
The Company's reserve information was prepared as of December 31, 2003,
2002 and 2001. The Company cautions that there are many inherent
uncertainties in estimating proved reserve quantities, projecting future
production rates, and timing of development expenditures. Accordingly,
these estimates are likely to change as future information becomes
available. Proved oil and gas reserves are the estimated quantities of
crude oil and natural gas 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 reserves are those reserves expected to be recovered
through existing wells, with existing equipment and operating methods.
A summary of changes in reserve balances is presented below:
Total proved Proved developed
-------------------------- --------------------------
BBL MCF BBL MCF
------------ ------------- ------------ -------------
(in thousands)
Reserves as of December 31, 2000 974 15,686 572 11,576
Sales of reserves in place (1) - (1) -
Extensions and discoveries 78 1,737 78 1,737
Revisions of previous estimates 4 (210) (20) (473)
Production (139) (3,266) (139) (3,266)
------------ ------------- ------------ -------------
Reserves as of December 31, 2001 916 13,947 490 9,574
Purchase of reserves in place 9,119 1,931 7,513 1,609
Sales of reserves in place - - - -
Extensions and discoveries 323 2,048 323 2,048
Revisions of previous estimates 43 376 67 640
Production (130) (2,669) (130) (2,669)
------------ ------------- ------------ -------------
Reserves as of December 31, 2002 10,271 15,633 8,263 11,202
Extensions and discoveries 1,412 1,811 283 1,811
Revisions of previous estimates 1,030 2,183 1,027 2,409
Production (629) (3,356) (629) (3,356)
------------ ------------- ------------ -------------
Reserves as of December 31, 2003 12,084 16,271 8,944 12,066
============ ============= ============ =============
The following is a standardized measure of the discounted net future cash
flows and changes applicable to proved oil and gas reserves required by
SFAS No. 69. The future cash flows are based on estimated oil and
F-29
gas reserves utilizing prices and costs in effect as of year end,
discounted at 10% per year and assuming continuation of existing economic
conditions.
During 2003, the average sales price received by the Company for its oil
was approximately $29.11 (unhedged) per Bbl, as compared to $24.59 in
2002, while the average sales price for the Company's gas was
approximately $5.40 (unhedged) per Mcf in 2003, as compared to $3.33 per
Mcf in 2002.
The standardized measure of discounted future net cash flows, in
management's opinion, should be examined with caution. The basis for this
table is the reserve studies prepared by independent petroleum
consultants, which contain imprecise estimates of quantities and rates of
production of reserves. Revisions of previous year estimates can have a
significant impact on these results. Also, exploration costs in one year
may lead to significant discoveries in later years and may significantly
change previous estimates of proved reserves and their valuation.
Therefore, the standardized measure of discounted future net cash flow is
not necessarily indicative of the fair value of the Company's proved oil
and gas properties.
F-30
Future income tax expense was computed by applying statutory rates less
the effects of tax credits for each period presented to the difference
between pre-tax net cash flows relating to the Company's proved reserves
and the tax basis of proved properties and available net operating loss
and percentage depletion carryovers.
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
(in thousands)
December 31,
---------------------------------------------
2003 2002 2001
-------------- --------------- --------------
Future cash inflows $ 458,723 $ 368,835 $ 47,648
Future costs:
Production (149,548) (103,924) (17,353)
Development (15,485) (9,440) (4,874)
--------- --------- --------
Future net cash flows before income taxes 293,690 255,471 25,421
Future income taxes (66,757) (58,622) (34)
--------- --------- --------
Future net cash flows 226,933 196,850 25,387
10% annual discount for estimated timing of cash flows (110,667) (97,233) (8,312)
--------- --------- --------
Standardized measure of discounted future net cash flows $ 116,266 $ 99,616 $ 17,075
========= ========= ========
Changes in Standardized Measure of
Discounted Future Net Cash Flows From Proved Reserves
(in thousands)
December 31,
-----------------------------------------
2003 2002 2001
------------- ------------- -------------
Increase (decrease):
Sales of minerals in place $ - $ - $ (4)
Purchases of minerals in place - 85,075 -
Extensions and discoveries and improved recovery,
net of future production and development costs 9,556 10,790 3,831
Accretion of discount 12,293 1,707 9,095
Net change in sales prices net of production costs 10,832 16,619 (68,367)
Changes in estimated future development costs (6,948) (512) 5
Revisions of quantity estimates 13,520 1,218 (172)
Net change in income taxes (8,204) (23,318) 9,662
Sales, net of production costs (25,451) (9,170) (13,919)
Changes of production rates (timing) and other 11,052 132 (4,344)
--------- -------- --------
Net increase (decrease) 16,650 82,541 (64,213)
Standardized measure of discounted future net cash flows:
Beginning of year 99,616 17,075 81,288
--------- -------- --------
End of year $ 116,266 $ 99,616 $ 17,075
========= ======== ========
F-31
(16) Selected Quarterly Financial Results (Unaudited)
Quarter
----------------------------------------------------
First Second Third Fourth
------------ ------------ ------------- ------------
(in thousands, except per share data)
2003
Oil and gas revenues $ 8,493 $ 8,532 $ 8,732 $ 8,098
Total costs and expenses 4,323 5,143 5,329 6,343
------- ------- -------- -------
Operating income 4,170 3,389 3,403 1,755
------- ------- -------- -------
Income before cumulative effect of change
in accounting principle 2,313 2,671 1,695 985
Cumulative effect of change in accounting
principle, net of tax (62) - - -
------- ------- -------- -------
Net income $ 2,251 $ 2,671 $ 1,695 $ 985
======= ======= ======== =======
Net income after preferred stock dividend $ 2,105 $ 2,525 $ 1,549 $ 843
======= ======= ======== =======
Net income per share:
Basic:
Income before cumulative effect of change
in accounting principle $ 0.10 $ 0.12 $ 0.07 $ 0.04
Cumulative effect of change in accounting
principle, net of tax - - - -
------- ------- ------- -------
Net income per common share $ 0.10 $ 0.12 $ 0.07 $ 0.04
======= ======= ======= =======
Diluted:
Income before cumulative effect of change
in accounting principle $ 0.09 $ 0.11 $ 0.07 $ 0.04
Cumulative effect of change in accounting
principle, net of tax - - - -
------- ------- -------- -------
Net income per common share $ 0.09 $ 0.11 $ 0.07 $ 0.04
======= ======= ======== =======
During the fourth quarter of 2003, the Company reduced its estimate of State income tax liability by $907,000.
2002
Oil and gas revenues $ 1,971 $ 2,809 $ 2,710 $ 4,616
Total costs and expenses 2,254 4,029 2,319 4,030
Net income (769) 19,662 (398) 206
Net income (loss) after preferred stock dividend (915) 19,515 (544) 60
Net income per common share - basic $ (0.04) $ 0.94 $ (0.03) $ 0.02
Net income per common share - diluted $ (0.04) $ 0.84 $ (0.03) $ 0.01
2002 results include a gain of $31.1 million in the second quarter related to the sale of First Permian assets.
F-32
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.
PARALLEL PETROLEUM CORPORATION
March 22, 2004 By: /s/ Larry C. Oldham
--------------------------
Larry C. Oldham,
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
/s/ Thomas R. Cambridge Chairman of the Board of Directors March 22, 2004
- ------------------------
Thomas R. Cambridge
/s/ Larry C. Oldham President and Chief Executive Officer March 22, 2004
- ------------------------ (Principal Executive Officer)
/s/ Steven D. Foster Chief Financial Officer March 22, 2004
- ------------------------ (Principal Financial and
Steven D. Foster Accounting Officer)
/s/ Dewayne E. Chitwood Director March 22, 2004
- ------------------------
Dewayne E. Chitwood
/s/ Martin B. Oring Director March 22, 2004
- ------------------------
Martin B. Oring
/s/ Charles R. Pannill Director March 22, 2004
- ------------------------
Charles R. Pannill
/s/ Ray M. Poage Director March 22, 2004
- ------------------------
Ray M. Poage
/s/ Jeffrey G. Shrader Director March 22, 2004
- ------------------------
Jeffrey G. Shrader
S-1
INDEX TO EXHIBITS
Exhibit
No. Description of Exhibit
- ------- ----------------------
3.1 Certificate of Incorporation of Registrant (Incorporated by reference to
Exhibit 3.1 to Form 10-K of the Registrant for the fiscal year ended
December 31, 1998)
3.2 Bylaws of Registrant (Incorporated by reference to Exhibit 3 to the
Registrant's Form 8-K, dated October 9, 2000, as filed with the
Securities and Exchange Commission on October 10, 2000)
4.1 Certificate of Designations, Preferences and Rights of Serial Preferred
Stock - 6% Convertible Preferred Stock (Incorporated by reference to
Exhibit 4.1 to Form 10-Q of the Registrant for the fiscal quarter ended
September 30, 1998)
4.2 Certificate of Designation, Preferences and Rights of Series A Preferred
Stock (Incorporated by reference to Exhibit 4.2 to Form 10-K of the
Registrant for the fiscal year ended December 31, 2000)
4.3 Rights Agreement, dated as of October 5, 2000, between the Registrant and
Computershare Trust Company, Inc., as Rights Agent (Incorporated by
reference to Exhibit 4.3 to Form 10-K of the Registrant for the fiscal
year ended December 31, 2000)
Executive Compensation Plans and Arrangements (Exhibit No.'s 10.1 through
10.9):
10.1 1983 Incentive Stock Option Plan (Incorporated by reference to Exhibit
10.2 to Form S-l of the Registrant (File No. 2-92397) as filed with the
Securities and Exchange Commission on July 26, 1984, as amended by
Amendments No. 1 and 2 on October 5, 1984, and October 25, 1984,
respectively)
10.2 1992 Stock Option Plan (Incorporated by reference to Exhibit 28.1 to Form
S-8 of the Registrant (File No. 33-57348) as filed with the Securities
and Exchange Commission on January 25, 1993)
10.3 Stock Option Agreement between the Registrant and Thomas R. Cambridge
dated December 11, 1991 (Incorporated by reference to Exhibit 10.4 of
Form 10-K of the Registrant for the fiscal year ended December 31, 1992)
10.4 Stock Option Agreement between the Registrant and Thomas R. Cambridge
dated October 18, 1993 (Incorporated by reference to Exhibit 10.4(e) of
Form 10-K of the Registrant for the fiscal year ended December 31, 1993)
10.5 Merrill Lynch, Pierce, Fenner & Smith Incorporated Prototype Simplified
Employee Pension Plan (Incorporated by reference to Exhibit 10.6 of the
Registrant's Form 10-K for the fiscal year ended December 31, 1995)
10.6 Non-Employee Directors Stock Option Plan (Incorporated by reference to
Exhibit 10.6 of the Registrant's Form 10-K Report for the fiscal year
ended December 31, 1997)
1
Exhibit
No. Description of Exhibit
- ------- ----------------------
10.7 1998 Stock Option Plan (Incorporated by reference to Exhibit 10.7 of Form
10-K of the Registrant for the fiscal year ended December 31, 1998)
10.8 Form of Incentive Award Agreements, dated December 12, 2001, between the
Registrant and Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and
John S. Rutherford granting 2,394 Unit Equivalent Rights to Mr.
Cambridge; 9,564 Unit Equivalent Rights to Mr. Oldham; 2,869 Unit
Equivalent Rights to Mr. Bayley; and 7,173 Unit Equivalent Rights to Mr.
Rutherford (Incorporated by reference to Exhibit 10.8 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2001)
10.9 Form of Change of Control Agreements, dated June 1, 2001, between the
Registrant and Thomas R. Cambridge, Larry C. Oldham, Eric A. Bayley and
John S. Rutherford (Incorporated by reference to Exhibit 10.9 of Form
10-K of the Registrant for the fiscal year ended December 31, 2001)
10.10 Restated Loan Agreement, dated December 27, 1999, between the Registrant
and Bank One, Texas, N.A. (Incorporated by reference to Exhibit 10.8 of
Form 10-K of the Registrant for the fiscal year ended December 31, 1999)
10.11 Loan Agreement, dated December 18, 2000, between the Registrant and Bank
United (Incorporated by reference to Exhibit 10.9 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2000)
10.12 Letter agreement, dated March 24, 1999, between the Registrant and Bank
One, Texas, N.A. (Incorporated by reference to Exhibit 10.9 of Form 10-K
of the Registrant for the fiscal year ended December 31, 1998)
10.13 Certificate of Formation of First Permian, L.L.C. (Incorporated by
reference to Exhibit 10.1 of the Registrant's Form 8-K Report dated June
30, 1999)
10.14 Limited Liability Company Agreement of First Permian, L.L.C.
(Incorporated by reference to Exhibit 10.2 of the Registrant's Form 8-K
Report dated June 30, 1999)
10.15 Merger Agreement, dated June 25, 1999 (Incorporated by reference to
Exhibit 10.3 of the Registrant's Form 8-K Report dated June 30, 1999)
10.16 Agreement and Plan of Merger of First Permian, L.L.C. and Nash Oil
Company, L.L.C. (Incorporated by reference to Exhibit 10.4 of the
Registrant's Form 8-K Report dated June 30, 1999)
10.17 Certificate of Merger of First Permian, L.L.C. and Nash Oil Company,
L.L.C. (Incorporated by reference to Exhibit 10.5 of the Registrant's
Form 8-K Report dated June 30, 1999)
10.18 Amended and Restated Limited Liability Company Agreement of First
Permian, L.L.C. dated as of May 31, 2000 (Incorporated by reference to
Exhibit 10.16 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2000)
2
Exhibit
No. Description of Exhibit
- ------- ----------------------
10.19 Credit Agreement, dated June 30, 1999, by and among First Permian,
L.L.C., Parallel Petroleum Corporation, Baytech, Inc., and Bank One,
Texas, N.A. (Incorporated by reference to Exhibit 10.6 of the
Registrant's Form 8-K Report dated June 30, 1999)
10.20 Limited Guaranty, dated June 30, 1999, by and among First Permian,
L.L.C., parallel Petroleum Corporation and Bank One, Texas, N.A.
(Incorporated by reference to Exhibit 10.7 of the Registrant's Form 8-K
Report dated June 30, 1999)
10.21 Intercreditor Agreement, dated as of June 30, 1999, among First Permian,
L.L.C., Bank One, Texas, N.A., Tejon Exploration Company, and Mansefeldt
Investment Corporation (Incorporated by reference to Exhibit 10.8 of the
Registrant's Form 8-K Report dated June 30, 1999)
10.22 Subordinated Promissory Note, dated June 30, 1999, in the original
principal amount of $8.0 million made by First Permian, L.L.C. payable to
the order of Tejon Exploration Company (Incorporated by reference to
Exhibit 10.9 of the Registrant's Form 8-K Report dated June 30, 1999)
10.23 Subordinated Promissory Note, dated June 30, 1999, in the original
principal amount of $8.0 million made by First Permian, L.L.C. payable to
the order of Mansefeldt Investment Corporation (Incorporated by reference
to Exhibit 10.10 of the Registrant's Form 8-K Report dated June 30, 1999)
10.24 Second Restated Credit Agreement, dated October 25, 2000, among First
Permian, L.L.C., Bank One, Texas, N.A., and Bank One Capital Markets,
Inc. (Incorporated by reference to Exhibit 10.22 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2000)
10.25 Loan Agreement, dated as of January 25, 2002, between the Registrant and
First American Bank, SSB (Incorporated by reference to Exhibit 10.25 of
Form 10-K of the Registrant for the fiscal year ended December 31, 2001)
10.26 Purchase and Sale Agreement, dated as of November 27, 2002, among JMC
Exploration, Inc., Arkoma Star L.L.C., Parallel, L.P. and Texland
Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 of Form 8-K of
the Registrant, dated December 20, 2002)
10.27 First Amended and Restated Credit Agreement, dated December 20, 2002, by
and among Parallel Petroleum Corporation, Parallel, L.P., Parallel,
L.L.C., First American Bank, SSB, Western National Bank and BNP Paribas
(Incorporated by reference to Exhibit 10.2 of Form 8-K of the Registrant,
dated December 20, 2002)
10.28 Guaranty dated December 20, 2002, between Parallel, L.L.C. and First
American Bank, SSB, as Agent (Incorporated by reference to Exhibit 10.3
of Form 8-K of the Registrant, dated December 20, 2002)
*14 Code of Ethics
*21 Subsidiaries
3
Exhibit
No. Description of Exhibit
- ------- ----------------------
*23.1 Consent of KPMG LLP
*23.2 Consent of BDO Seidman, LLP
*23.3 Consent of Cawley Gillespie & Associates, Inc. Independent Petroleum
Engineers
*31.1 Certification of Principal Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley
Act of 2002
*31.2 Certification of Principal Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 302 of the Sarbanes - Oxley
Act of 2002
*32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of
2002.
*32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of
2002.
_______________
* Filed herewith.
4