##### Table of Contents



UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-K þ
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934For the Fiscal Year Ended December 31, 2004ORo
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934
 Commission File No. 0-20100 BELDEN & BLAKE CORPORATION  Ohio
(State or other jurisdiction of incorporation or organization)
    
    34-1686642
(I.R.S. Employer Identification Number)
 5200 Stoneham Road
North Canton, Ohio 44720
(Address of principal executive offices) (Zip Code) Registrants telephone number, including area code: (330) 499-1660 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes þ No o Indicate by check mark 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. þ Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule
12b-2 of the Act). Yes o No þ As of February 28, 2005, Belden & Blake Corporation had outstanding 1,500 shares of common
stock, without par value, which is its only class of stock. The common stock of Belden & Blake
Corporation is not traded on any exchange and, therefore, its aggregate market value and the value
of shares held by non-affiliates cannot be determined as of the last business day of the
registrants most recently completed second fiscal quarter. DOCUMENTS INCORPORATED BY REFERENCE: None.




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TABLE OF CONTENTS  PART IItems 1 and 2. BUSINESS AND PROPERTIESItem 3. LEGAL PROCEEDINGSItem 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSPART IIItem 5. MARKET FOR THE REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIESItem 6. SELECTED FINANCIAL DATAItem 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSItem 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKItem 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAItem 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREItem 9A. CONTROLS AND PROCEDURESItem 9B. OTHER INFORMATIONPART IIIItem 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTItem 11. EXECUTIVE COMPENSATIONItem 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERSItem 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONSItem 14. PRINCIPAL ACCOUNTANT FEES AND SERVICESPART IVItem 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULESSIGNATURESEX-10.19 Directors Fee for Outside DirectorsEX-10.20 Employee Agreement Between Belden and John SchwagerEX-10.21 Waiver of Rights to Payments and BenefitsEX-23 Consent of Independent AuditorsEX-31.1 302 CertificationEX-31.2 302 CertificationEX-32.1 906 CertificationEX-32.2 906 Certification    Table of Contents  References in this Annual report on Form 10-K to Belden & Blake, the Company, we,
ours, us or like terms refer to Belden & Blake Corporation and its subsidiaries. Forward-Looking Statements The information in this document includes forward-looking statements that are made pursuant to
the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements
preceded by, followed by or that otherwise include the statements should, believe, expect,
anticipate, intend, will, continue, estimate, plan, outlook, may, future,
projection, likely, possible, would, could and variations of these statements and similar
expressions are forward-looking statements as are any other statements relating to
developments, events, occurrences, results, efforts or impacts. These forward-looking statements are based on current
expectations and projections about future events. Forward-looking statements, and
the business prospects of Belden & Blake are subject to a number of risks and uncertainties which
may cause our actual results in future periods to differ materially from the forward-looking
statements contained herein. These risks and uncertainties include, but are not limited to, our
access to capital, the market demand for and prices of oil and natural gas, our oil and gas
production and costs of operation, results of our future drilling activities, the uncertainties of
reserve estimates, general economic conditions, new legislation or regulatory changes, changes in
accounting principles, policies or guidelines and environmental risks. These and other risks are
described on page 40 under the Heading Risk Factors and in our other filings with the Securities
and Exchange Commission (SEC). We undertake no obligation to publicly update or revise any
forward-looking statement, whether as a result of new information, future events, changes in
assumptions, or otherwise. 
 PART I 
 Items 1 and 2.BUSINESS AND PROPERTIES GENERAL Belden & Blake Corporation, an Ohio corporation, was formed on June 14, 1991 and is wholly
owned by Capital C Energy Operations, LP (Capital C), a Delaware limited partnership. Capital C
acquired us pursuant to a merger completed on July 7, 2004. Capital C is a controlled affiliate of
Carlyle/Riverstone Global Energy and Power Fund II, L.P. (Carlyle/Riverstone), a private equity
fund. The general partner of Carlyle/Riverstone is jointly controlled by Riverstone Holdings LLC
and The Carlyle Group. We are an independent energy company engaged in the exploitation, development, production,
operation and acquisition of oil and natural gas properties. Our operations are focused in the
Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale formation in the
Michigan Basin. We maintain our corporate offices at 5200 Stoneham Road, North Canton, Ohio 44720. Our
telephone number at that location is (330) 499-1660. SIGNIFICANT EVENTS Mergers and Acquisitions Acquisition by Carlyle/Riverstone Pursuant to an Agreement and Plan of Merger with Capital C, dated as of June 15, 2004 (the
Merger Agreement), a wholly owned subsidiary of Capital C merged with and into us (the Merger)
and we were the surviving corporation. The Merger was completed on July 7, 2004. 1




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Capital C is a Delaware limited partnership owned by an affiliate of Carlyle/Riverstone and
by Capital C Energy Partners, L.P. Carlyle/Riverstone is a private equity fund established by
Riverstone Holdings LLC and The Carlyle Group to make investments in the energy and power
industries globally. Capital C Energy Partners, L.P. is a privately owned partnership formed in
2002 to accumulate and manage a portfolio of onshore U.S. oil and gas
properties. Carlyle/Riverstone controls and owns the majority of
Capital C. In the Merger, each issued and outstanding share of our common stock was converted into the
right to receive cash. All outstanding amounts of indebtedness under our prior credit facility
were repaid. In connection with the Merger, pursuant to a consent solicitation and tender offer
previously announced by the Company, over 98% of our $225 million aggregate principal amount of
9-7/8% Senior Subordinated Notes (the 9-7/8% Notes) were tendered and repaid at the closing of the
Merger. As of September 30, 2004, all of the $225 million aggregate principal amount of the 9-7/8%
Notes had been paid. Merger with Subsidiaries Effective December 30, 2004, we merged with our wholly owned subsidiaries, The Canton Oil and
Gas Company (COG) and Ward Lake Drilling, Inc. (WLD), and we were the surviving corporation.
COG and WLD were the guarantor subsidiaries to our $192.5 million 8.75% Senior Secured Notes due
2012 described below. Senior Secured Notes due 2012 On July 7, 2004, we completed the sale of $192.5 million of our 8.75% Senior Secured Notes due
2012 (the Notes) in a private offering to qualified institutional buyers in reliance on Rule 144A
of the Securities Act of 1933, as amended (the Securities Act) and to non-U.S. persons under
Regulation S of the Securities Act. The net proceeds, along with proceeds from the Senior
Facilities as defined below, were used principally to repay $225 million of our 9-7/8% Senior
Subordinated Notes due 2007 (the 9-7/8% Notes) and to repay indebtedness outstanding under our
revolving credit facility. On December 23, 2004, we commenced an exchange offer which allowed the
holders of the unregistered Notes to exchange the unregistered Notes for new notes with materially
identical terms that had been registered under the Securities Act of 1933, as amended. The
exchange offer expired on February 4, 2005, and all of the unregistered Notes were exchanged for
registered Notes. The Senior Facilities In connection with the Merger, we entered into a new Senior Credit Agreement providing for a
$100 million term facility, a $30 million revolving facility (including letters of credit) and a
$40 million letter of credit facility (collectively, the Senior Facilities). Indebtedness under
the Senior Facilities constitutes our senior secured indebtedness and is secured by a
first-priority lien on a substantial majority of the aggregate value of our estimated proved
producing reserves on a present value (discounted at 10%) basis and substantially all of our other
real and personal property, each on a first-priority senior secured 2




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basis. The Notes constitute our senior secured indebtedness and are secured by a
second-priority lien on the same assets. The Hedges Also at the time of the Merger, we entered into long-term commodity hedges (the Hedges) with
J. Aron under a master agreement and related confirmations and documentation (collectively, the
Hedge Agreement) and, as required by the Senior Facilities and the indenture governing the Notes,
we will maintain such Hedges with J. Aron or its successor or permitted assigns. The letter of credit facility provides up to $40 million of credit support for our obligations
under the Hedge Agreement and other hedging transactions. Our obligations under the Hedge
Agreement are also secured by up to $15 million of letters of credit under the revolving facility.
To the extent our obligations exceed such letters of credit, such obligations under the Hedge
Agreement and other hedging transactions will be secured by a second-priority lien on the same
assets securing the Senior Facilities and the Notes. Dispositions Sale of Arrow Oilfield Service Company We sold the Michigan assets of Arrow Oilfield Service Company (Arrow) in May 2004. We sold
the Ohio and Pennsylvania assets of Arrow in June 2004. These transactions were classified as
discontinued operations. Historical information has been restated to remove Arrow from continuing
operations. Sale of Trenton Black River Assets On June 25, 2004, we completed the sale of substantially all of our interests, or rights to
our interests, in the Trenton Black River (TBR) assets in accordance with a letter agreement
dated June 14, 2004 with a third party. This transaction was classified as discontinued
operations. Historical information has been restated to remove the TBR properties from continuing
operations. DESCRIPTION OF BUSINESS Overview We are an independent energy company engaged in the exploitation, development, production,
operation and acquisition of oil and natural gas properties. Our operations are focused in the
Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale formation in the
Michigan Basin. In the fourth quarter of 2004, we achieved average net production from continuing operations
of approximately 47.5 Mmcfe (million cubic feet of natural gas equivalent) per day consisting of
41.0 Mmcf (million cubic feet) of natural gas and 1,077 Bbls (barrels) of oil per day. At December
31, 2004, we owned interests in 4,126 gross (3,197 net) productive oil and gas wells in Ohio,
Pennsylvania, New York and Michigan with estimated proved reserves totaling 285 Bcfe (billion cubic
feet of natural gas equivalent) consisting of 251 Bcf (billion cubic feet) of natural gas and 5.6
Mmbbl (million barrels) of oil. The estimated future net cash flows from these reserves had a
present value (discounted at 10%) before income taxes of approximately $510 million at December 31,
2004. The weighted average prices related to estimated proved reserves at December 31, 2004 were
$6.49 per Mcf (thousand cubic feet) for natural gas and $40.12 per Bbl for oil. At December 31, 2004, we operated approximately 3,652 wells, or 89% of our gross wells
representing approximately 98% of the value of our estimated proved developed reserves on a present
value (discounted at 10%) basis. We believe that operational control of our properties, coupled
with ownership of selected gathering assets, enables us to better control our operating costs and
capital expenditures and execute our field development plans. At December 31, 2004, we owned
leases on 712,267 gross (565,060 net) acres, including 272,697 gross (198,578 net) undeveloped
acres. We own and operate approximately 1,268 miles of natural gas gathering lines in Ohio,
Pennsylvania, New York and Michigan, which are connected directly to various intrastate and
interstate natural gas transmission systems. The interconnections with these pipelines afford us
marketing access to numerous gas markets, including those in the northeastern United States. The
proximity of our properties in the Appalachian and Michigan Basins to large commercial and
industrial natural gas markets has generally resulted in premium wellhead gas prices compared with
the New York Mercantile Exchange (NYMEX) price for gas delivered at the Henry Hub in Louisiana.
Monthly spot natural gas prices in our market areas are typically 15 to 60 cents higher per Mcf
than comparable NYMEX prices. 3




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Oil and Gas Reserves The following table sets forth our estimated proved oil and gas reserves as of December 31,
2002, 2003 and 2004 determined in accordance with the rules and regulations of the SEC. These
estimates of proved reserves were prepared by Wright & Company, Inc., independent petroleum
consultants. Estimated proved reserves are the estimated quantities of oil and 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. December 31,2002
    
    
    2003
    
    
    2004Estimated proved reservesGas (Bcf)
    
    
    335.5
    
    
    
    318.1
    
    
    
    251.3Oil (Mbbl)
    
    
    6,574
    
    
    
    6,176
    
    
    
    5,579Bcfe
    
    
    375.0
    
    
    
    355.1
    
    
    
    284.8
 See Note 17 to the Consolidated Financial Statements for more detailed information
regarding our oil and gas reserves. The present value of the estimated future net cash flows before income taxes from our
estimated proved reserves as of December 31, 2004, determined in accordance with the rules and
regulations of the SEC, was $510 million ($346 million after income taxes). Estimated future net
cash flows represent estimated future gross revenues from the production and sale of estimated
proved reserves, net of estimated costs (including production taxes, ad valorem taxes, operating
costs, development costs and additional capital investment). Estimated future net cash flows were
calculated on the basis of prices and costs estimated to be in effect at December 31, 2004 without
escalation, except where changes in prices were fixed and readily determinable under existing
contracts. The following table sets forth the weighted average prices, including fixed price contracts,
for oil and gas used in determining our estimated proved reserves. We do not include our natural
gas and crude oil hedging financial instruments, consisting of swaps and collars, in the
determination of our oil and gas reserves. December 31,2002
    
    
    2003
    
    
    2004Gas (per Mcf)
    
    $
    4.99
    
    
    $
    6.19
    
    
    $
    6.49Oil (per barrel)
    
    
    27.81
    
    
    
    29.78
    
    
    
    40.12
 At December 31, 2004, as specified by the SEC, the prices for oil and natural gas used in
this calculation were regional cash price quotes on the last day of the year except for volumes
subject to fixed price contracts. Consequently, these may not reflect the prices actually received
or expected to be received for oil and natural gas due to seasonal price fluctuations and other
varying market conditions. The prices shown above are weighted average prices for the total
reserves. 4




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Our estimated proved reserves as of December 31, 2004 were approximately 285 Bcfe compared
with estimated proved reserves from continuing operations as of December 31, 2003 of approximately
355 Bcfe. Estimated proved reserves as of December 31, 2004 decreased approximately 70 Bcfe from
December 31, 2003, as presented in the table below. Estimated
    
    
    Estimated
    
    
    TotalProved
    
    
    Proved
    
    
    EstimatedDeveloped
    
    
    Undeveloped
    
    
    Proved(Bcfe)Estimated proved reserves at 12/31/03 from
continuing operations
    
    
    230.7
    
    
    
    124.4
    
    
    
    355.1Extensions and discoveries
    
    
    0.2
    
    
    
    2.4
    
    
    
    2.6Purchase of reserves in place
    
    
    0.2
    
    
    
    1.1
    
    
    
    1.3Revisions of previous estimates:Changes in capital and operating costs
    
    
    (11.5
    )
    
    
    (6.0
    )
    
    
    (17.5
    )Commodity price changes
    
    
    2.5
    
    
    
    6.7
    
    
    
    9.2Engineering revisions
    
    
    0.1
    
    
    
    (21.3
    )
    
    
    (21.2
    )Surrendered and expired leases
    
    
    
    
    
    
    (7.4
    )
    
    
    (7.4
    )Reclassified to an unproved category
    
    
    
    
    
    
    (19.7
    )
    
    
    (19.7
    )Production 2004
    
    
    (17.6
    )
    
    
    
    
    
    
    (17.6
    )Drilling 2004
    
    
    16.3
    
    
    
    (16.3
    )
    
    
    Estimated proved reserves at 12/31/04
    
    
    220.9
    
    
    
    63.9
    
    
    
    284.8
 During 2004, the primary focus of our drilling program was on proved undeveloped
locations. The result of this program converted approximately 16.3 Bcfe of estimated proved
undeveloped reserves into estimated proved developed reserves. Production for 2004 was 17.6 Bcfe. Revisions of previous estimates accounted for a decrease of approximately 56.7 Bcfe. The
majority of this reduction was in the estimated proved undeveloped reserves category. Of this
decrease, approximately 21.2 Bcfe related to engineering revisions, which resulted from our
analysis of our drilling results in the past several years as compared to reserve estimates of
proved undeveloped well locations in our prior years reserve report. Additionally, as a result of
higher future development and operating costs, total estimated proved reserves were reduced by approximately 17.5 Bcfe. Increases in our estimated proved
reserves of 9.2 Bcfe resulted from increases in commodity prices at December 31, 2004 compared to
2003. Furthermore, approximately 19.7 Bcfe of estimated proved undeveloped reserves were
reclassified to an unproved category, as the locations were more than one direct offset spacing
unit from a productive well. During 2004, we performed a lease review of our proved undeveloped locations, which, due to
leases that have expired or that we have surrendered, resulted in a downward adjustment of
approximately 7.4 Bcfe to our estimated proved undeveloped reserves at December 31, 2004. Reserves estimates are based upon various assumptions, including assumptions required by the
SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. The process of estimating reserves is complex. This process
requires significant decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. Furthermore, different reserve
engineers may make different estimates of reserves and cash flow based on the same available data
and these differences may be significant. Therefore, these estimates are not precise. Actual
future production, oil and natural gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas 5




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reserves will most likely vary from
those estimated. In addition, we may adjust estimates of proved reserves to reflect production
history, results of exploration and development, prevailing oil and natural gas prices and other
factors, many of which are beyond our control. Appalachian Basin  Conventional Properties The Appalachian Basin is the oldest and geographically one of the largest oil and gas
producing regions in the United States. Although the Appalachian Basin has sedimentary formations
to depths of 15,000 feet or more, oil and natural gas has primarily been produced from shallow,
highly developed formations at depths of 1,000 to 6,500 feet. Our drilling completion rates and
those of others drilling in these shallow, highly developed formations historically have exceeded
90% with production generally lasting longer than 20 years. We currently own working interests in 2,782 gross (2,445 net) wells in the Appalachian Basin,
excluding our coalbed methane wells, which currently produce approximately 23.1 Mmcfe net per day.
Most of our production in the Appalachian Basin is derived from the shallow (1,000 to 6,500 feet)
Medina, Clinton and Clarendon formations, predominately in Pennsylvania and Ohio. During 2004, we drilled 27 gross (26.4 net) development Medina wells, 15 gross (15.0 net)
development Clarendon wells in Pennsylvania and 3 gross (3.0 net) Clinton wells in Ohio. We plan
to continue this development drilling program by drilling 40 gross (38.8 net) Medina wells, 35
gross (35.0 net) Clarendon wells and 20 gross (20.0 net) Clinton wells in 2005. Michigan Basin Properties The Michigan Basin has operational similarities to the Appalachian Basin, geographic proximity
to our operations in the Appalachian Basin and proximity to premium gas markets. We own working
interests in 1,184 gross (592 net) wells in the Michigan Basin which currently produce
approximately 19.2 Mmcfe net per day. Most of our production in the Michigan Basin is derived from the shallow (700 to 2,000 feet),
Antrim Shale formation. Completion rates for companies drilling to this formation have exceeded
90%, with production often lasting 20 years or more. Because the production rate from Antrim Shale
wells is relatively low, cost containment is a crucial aspect of our operations. Our operations in
the Michigan Basin are more capital intensive than our Appalachian Basin operations because of the
low natural reservoir pressures and the high initial water content of the Antrim Shale formation. During 2004, we drilled 38 gross (30.7 net) wells to the Antrim Shale formation. We plan to
drill 35 gross (33.2 net) wells in the Antrim Shale formation in 2005. Appalachian Basin  Coalbed Methane Properties We own working interests in 160 producing coalbed methane (CBM) wells in Pennsylvania and
own leases on approximately 69,000 gross (62,000 net) acres of undeveloped CBM properties. We own
a 100% working interest in all of our CBM wells. Current production from these wells is
approximately 2.9 Mmcf net per day. We drilled 18 CBM wells in 2004 and plan to drill an
additional 15 CBM wells in 2005. 6




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Oil and Gas Operations and Production Operations.We operate 89% of the wells in which we hold working interests. We maintain
production field offices in Ohio, Pennsylvania and Michigan. Through these offices, we review our
properties to determine what action can be taken to control operating costs and/or improve
production. We own and operate approximately 1,268 miles of natural gas gathering lines in Ohio,
Pennsylvania, New York and Michigan, which are connected directly to various intrastate and
interstate natural gas transmission systems. The interconnections with these pipelines afford us
marketing access to numerous gas markets. Production, Sales Prices and Costs.The following table sets forth certain information
regarding our net oil and natural gas production, revenues and unit expenses for the years
indicated, excluding discontinued operations. However, it does not exclude all dispositions of
properties that did not qualify as discontinued operations. See Note 5 to the Consolidated
Financial Statements. Year Ended December 31,2002
    
    
    2003
    
    
    2004ProductionGas (Mmcf)
    
    
    15,882
    
    
    
    14,834
    
    
    
    15,267Oil (Mbbl)
    
    
    522
    
    
    
    413
    
    
    
    381Total production (Mmcfe)
    
    
    19,012
    
    
    
    17,311
    
    
    
    17,553Average priceGas (per Mcf)
    
    $
    4.95
    
    
    $
    4.92
    
    
    $
    5.08Oil (per Bbl)
    
    
    22.72
    
    
    
    28.06
    
    
    
    34.42Mcfe
    
    
    4.76
    
    
    
    4.89
    
    
    
    5.16Average costs (per Mcfe)Production expense
    
    
    1.07
    
    
    
    1.16
    
    
    
    1.29Production taxes
    
    
    0.09
    
    
    
    0.14
    
    
    
    0.16Depletion
    
    
    0.87
    
    
    
    0.85
    
    
    
    1.36Operating margin (per Mcfe)
    
    
    3.60
    
    
    
    3.59
    
    
    
    3.71
 Mmcf - Million cubic feet
    
    Mmcfe - Million cubic feet equivalentMbbl - Thousand barrels
    
    Mcf - Thousand cubic feet
    
    Bbl - BarrelOperating margin (per Mcfe) - average price less production expense and production taxes
 Exploration and Development Our activities include development and exploratory drilling in both the low risk formations
and the less developed formations of the Appalachian and Michigan Basins. In 2004, we drilled 106 gross (96.9 net) wells to shallow, highly developed formations in our
operating area. The result of this drilling activity is shown in the
table on page 9. In 2005, we expect to spend approximately $36 million, including exploratory dry hole expense,
on development and exploratory drilling and other capital expenditures. We expect to drill
approximately 145 gross (142.0 net) wells. In 2005, we plan to spend substantially all of our
drilling capital expenditures on shallow, highly developed formations. We were a pioneer in CBM development and production in Pennsylvania, and we presently own a
100% working interest in 160 CBM gas wells in Indiana, Westmoreland and Fayette counties. CBM 7




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wells in this area range in depth from 1,200 to 1,500 feet and typically encounter three to six
unmined coal seams. With approximately 77,000 gross (69,000 net) CBM acres currently under lease
in
Pennsylvania, we believe the CBM may contribute significantly to our drilling portfolio. We plan
to drill 15 gross (15.0 net) CBM wells in 2005. The Antrim Shale formation, the principal shallow formation in the Michigan Basin, is
characterized by high formation water production in the early years of a wells productive life
with water production decreasing over time. Antrim Shale wells produce natural gas that typically
climbs to peak rates of 60 Mcf to 125 Mcf per day over a three to 12 month period as the producing
formation becomes less water saturated. Production generally holds flat for several months,
followed by initial annual decline rates of 10% to 25% that decrease over time to 5% or less. Average well
lives are 20 years or more. We plan to drill 35 gross (33.2 net) wells to the Antrim Shale
formation in 2005. In addition to our CBM and Antrim drilling, we also plan to drill 40 gross (38.8 net) wells to
the Medina formation, 35 gross (35.0 net) wells to the Clarendon formation in Pennsylvania and 20
gross (20.0 net) wells to the Clinton formation in Ohio during 2005. Certain typical characteristics of our drilling programs in the shallow, highly developed
formations we target are described below: Range of Average Drillingand Completion Costs perRange of Well Depths
    
    
    Well(in feet)
    
    
    (in thousands)Ohio:Clinton
    
    
    3,000
    
    
    
    -
    
    
    
    5,500
    
    
    $
    190
    
    
    
    -
    
    
    
    255Pennsylvania:Coalbed Methane
    
    
    1,100
    
    
    
    -
    
    
    
    1,700
    
    
    
    170
    
    
    
    -
    
    
    
    210Clarendon
    
    
    1,100
    
    
    
    -
    
    
    
    2,000
    
    
    
    75
    
    
    
    -
    
    
    
    95Medina
    
    
    5,000
    
    
    
    -
    
    
    
    6,300
    
    
    
    240
    
    
    
    -
    
    
    
    345Michigan:Antrim
    
    
    700
    
    
    
    -
    
    
    
    2,000
    
    
    
    180
    
    
    
    -
    
    
    
    270
 The Appalachian Basin has productive and potentially productive sedimentary formations to
depths of 15,000 feet or more, but the combination of long-lived production and high drilling
completion rates in the shallow formations has curbed the development of the deeper formations in
the basin. We have also tested the Niagaran Carbonate, Onondaga Limestone, Oriskany Sandstone and Knox
formations. In the future, we may allocate a portion of our drilling budget to drill wells in
these and other deeper or less developed formations. 8




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Drilling Results.The following table sets forth drilling results from continuing operations
with respect to wells drilled by us during the past three years: Development Wells
    
    
    Exploratory Wells2002
    
    
    2003
    
    
    2004
    
    
    2002
    
    
    2003(1)
    
    
    2004Productive:Gross
    
    
    91
    
    
    
    82
    
    
    
    100
    
    
    
    4
    
    
    
    
    
    
    
    Net
    
    
    66.4
    
    
    
    75.7
    
    
    
    92.1
    
    
    
    3.5
    
    
    
    
    
    
    
    Dry:Gross
    
    
    6
    
    
    
    
    
    
    
    1
    
    
    
    6
    
    
    
    5
    
    
    
    5Net
    
    
    3.9
    
    
    
    
    
    
    
    1.0
    
    
    
    3.1
    
    
    
    3.3
    
    
    
    3.8Wells in progress:Gross
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    1Net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.7
    
    
    
    
    
    
    
    1.0
   (1)
    
    Includes one well that was classified as a well in progress in 2002. Disposition of Assets We sold the Michigan assets of Arrow in May 2004. We sold the Ohio and Pennsylvania assets of
Arrow in June 2004. According to Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards No. (SFAS) 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, the disposition of Arrow was classified as discontinued operations. Historical
information has been restated to remove Arrow from continuing operations. On June 25, 2004, we completed the sale of substantially all of our interests, or rights to
our interests, in the TBR assets in accordance with a letter agreement dated June 14, 2004 with a
third party. According to SFAS 144, the disposition of this group of wells is classified as
discontinued operations. Historical information has been restated to remove the TBR properties
from continuing operations. We regularly review our oil and gas properties for potential disposition. Employees As of February 28, 2005, we had 180 full-time employees, including 153 oil and gas exploration
and production employees and 27 general and administrative employees. Our management and technical
staff in the categories above included six petroleum engineers, one geologist and one geophysicist. Competition The oil and gas industry is highly competitive. Competition is particularly intense with
respect to the acquisition of producing properties and undeveloped acreage and the sale of oil and
gas production. There is competition among oil and gas producers as well as with other industries
in supplying energy and fuel to end-users. Our competitors in oil and gas exploration, development and production include major
integrated oil and gas companies as well as numerous independent oil and gas companies, individual
proprietors, natural gas pipeline companies and their affiliates. Many of these competitors
possess and employ financial and personnel resources substantially in excess of those available to
us. Such competitors may be able to pay more for desirable prospects or producing properties and
to evaluate, bid for and purchase a 9




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greater number of properties or prospects than our financial or
personnel resources will permit. Our ability to add to our reserves in the future will depend on
the availability of capital, the ability to exploit
our current developed and undeveloped lease holdings and the ability to select and acquire suitable
producing properties and prospects for future exploration and development. Customers Each of the following customers accounted for 10% or more of our consolidated revenues during
2004: WPS Energy Services, National Fuel Gas and Exelon Energy. Regulation Regulation of Production.In all states in which we are engaged in oil and gas exploration
and production, our activities are subject to regulation. Such regulations may extend to requiring
drilling permits, spacing of wells, the prevention of waste and pollution, the conservation of oil
and natural gas and other matters. Such regulations may impose restrictions on the production of
oil and natural gas by limiting the number of wells or the location where wells may be drilled and
by reducing the rate of flow from individual wells below their actual capacity to produce, which
could adversely affect the amount or timing of our revenues from such wells. Moreover, future
changes in local, state or federal laws and regulations could adversely affect our operations and
financial condition. Federal Regulation of Sales and Transportation of Natural Gas.Historically, the
transportation and sale for resale of natural gas in interstate commerce has been regulated
pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and Federal Energy
Regulatory Commission (FERC) regulations. In the past, the federal government has regulated the
prices at which natural gas could be sold. Currently, sales by producers of natural gas can be
made at uncontrolled market prices. Congress could, however, reenact price controls in the future. Our sales of natural gas are affected by the availability, terms and cost of transportation.
The price and terms for access to pipeline transportation are subject to extensive federal and
state regulation. From 1985 to the present, several major regulatory changes have been implemented
by Congress and the FERC that affect the economics of natural gas production, transportation and
sales. In addition, the FERC is continually proposing and implementing new rules and regulations
affecting those segments of the natural gas industry, most notably interstate natural gas
transmission companies, that remain subject to the FERCs jurisdiction. These initiatives may also
affect the intrastate transportation of gas under certain circumstances. The stated purpose of
many of these regulatory changes is to promote competition among the various sectors of the natural
gas industry and these initiatives generally reflect more light-handed regulation. The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot
be predicted. In addition, many aspects of these regulatory developments have not become final but
are still pending judicial and FERC final decisions. We cannot predict what further action the
FERC will take on these matters. We do not believe, however, that we will be affected by any
action taken in a materially different way than other natural gas producers, gatherers and
marketers with which we compete. Federal Regulation of Sales and Transportation of Crude Oil.Our sales of crude oil and
condensate are not currently regulated and are made at market prices. In a number of instances,
however, the ability to transport and sell such products is dependent on pipelines whose rates,
terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act.
Certain regulations 10




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implemented by the FERC in recent years could result in an increase in the
cost of pipeline transportation service. We do not believe, however, that these regulations affect
us any differently than other producers. Environmental Regulations.Our oil and natural gas exploration, development, production and
pipeline operations are subject to stringent federal, state and local laws and regulations
governing the discharge of materials into the environment or otherwise relating to environmental
protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, also
referred to as the U.S. EPA, issue regulations to implement and enforce such laws, which often
require difficult and costly compliance measures that carry substantial administrative, civil and
criminal penalties or may result in injunctive relief if we fail to comply. These laws and
regulations may require the acquisition of a permit before drilling commences, restrict the types,
quantities and concentrations of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit construction or drilling
activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other
protected areas, require bonds to be posted for the anticipated costs of plugging and abandoning
wells, and can require remedial action to prevent pollution from former operations, such as
plugging abandoned wells or closing pits, and impose substantial liabilities for pollution
resulting from our operations. The regulatory burden on the oil and natural gas industry increases the cost of doing business
and consequently may affect our profitability. Changes in environmental laws and regulations occur
frequently, and any changes that result in more stringent and costly regulation could materially
adversely affect our operations and financial position, as well as those of the oil and gas
industry in general. While we have not yet experienced any material adverse effect from compliance
or non-compliance with these environmental requirements, there is no assurance that this trend will
continue in the future. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also
known as CERCLA or Superfund, and comparable state laws impose liability without regard to
fault or the legality of the original conduct, on certain classes of persons for the release of a
hazardous substance into the environment. These persons include the owner and/or operator of a
disposal site or sites where the release occurred and companies that disposed or arranged for the
disposal of the hazardous substances found at the site. Under CERCLA, such persons may be subject
to joint and several liability for the costs of cleaning up these hazardous substances for damages
to natural resources and for the costs of certain health studies. The Resource Conservation and Recovery Act, as amended, also known as RCRA, specifically
excludes from the definition of hazardous waste drilling fluids, produced waters, and other wastes
associated with the exploration, development, or production of crude oil, natural gas or geothermal
energy. However, these wastes that we may generate may be regulated by the EPA or state agencies
as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents,
laboratory wastes, and waste compressor oils, may be regulated as hazardous waste. Although the
costs of managing these wastes generated by us may be significant, we do not expect to experience
more burdensome costs than similarly situated companies involved in oil and gas exploration and
production. We currently own or lease, and have in the past owned or leased, numerous properties that for
many years have been used for the exploration and production of oil and gas. Hydrocarbons or other
wastes may have been disposed of or released on or under the properties owned or leased by us or on
or under other locations where such wastes have been taken for disposal. In addition, many of
these properties have been operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and the wastes disposed
thereon may be subject 11




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##### Table of Contents



to CERCLA, RCRA, and analogous state laws. Under such laws, we could be
required to remove or remediate previously disposed wastes or property contamination, or to perform
remedial plugging or pit closure operations to prevent future contamination. The federal Clean Air Act and analogous state laws restricts the emission of air pollutants
from many sources, including equipment we use such as compressors to transport natural gas in our
pipelines. New facilities may be required to obtain permits before work can begin, and existing
facilities may be required to incur costs in order to remain in compliance. Our operations involve discharges to surface waters of fluids associated with the production
of oil and gas. The federal Clean Water Act and analogous state laws impose restrictions and
strict controls regarding the discharge of these fluids from oil and gas operations into state
waters or waters of the United States prohibiting discharge, except in accord with the terms of a
permit issued by U.S. EPA or the state. We hold several permits for the discharge of ground water
that is produced in conjunction with our coalbed methane operations in Pennsylvania. These
operations can produce substantial amounts of water as a byproduct when extracting gas. Our
facilities in Michigan use injection wells to dispose of wastewater that is produced as a byproduct
of oil and gas production. These injection wells are subject to stringent regulation and
permitting requirements. At our oil and gas wells in Ohio and Pennsylvania, wastewater is
collected in aboveground tanks and collected by third-party contractors for disposal off-site. The
Clean Water Act also prohibits certain activity in wetlands unless authorized by a permit issued by
the U.S. Army Corps of Engineers. The U.S. EPA also has adopted regulations requiring certain oil
and gas exploration and production facilities to obtain permits for storm water discharges under
certain circumstances. Sanctions for failure to comply with Clean Water Act requirements include
administrative, civil and criminal penalties, as well as injunctive relief. The Oil Pollution Act of 1990, as amended, also known as the OPA, pertains to the prevention
of and response to spills or discharges of hazardous substances or oil into navigable water of the
United States. The OPA imposes strict, joint and several liability on responsible parties for oil
removal costs and a variety of public and private damages, including natural resource damages.
Regulations under the OPA and the Clean Water Act also require certain owners and operators of
facilities that store or otherwise handle oil, such as ours, to prepare and implement spill
prevention, control, and countermeasure, or SPCC, plans and spill response plans relating to
possible discharges of oil into surface waters. The SPCC regulations were amended in 2002 and some
plans may require revision by February 17, 2006 and implementation of any such revised plans by
August 18, 2006. We own and/or operate a substantial number of facilities that require SPCC plans
or comparable plans under state law, and we are currently evaluating the extent of compliance by
our facilities with SPCC regulations and comparable state requirements. We cannot assure you that
costs that may be necessary for compliance with these SPCC and comparable state requirements will
not be material. Producing Well Data As of December 31, 2004, we owned interests in 4,126 gross (3,197 net) producing oil and gas
wells and operated approximately 3,652 wells, including wells operated for third parties. By
operating a high percentage of our properties, we are able to control expenses, capital allocation
and the timing of development activities in the areas in which we operate. In the fourth quarter
of 2004, our net production was approximately 47.5 Mmcfe per day consisting of 41.0 Mmcf of natural
gas and 1,077 Bbls of oil per day. 12




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##### Table of Contents



The following table summarizes by state our productive wells at December 31, 2004: December 31, 2004Gas Wells
    
    
    Oil Wells
    
    
    TotalState
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetOhio
    
    
    871
    
    
    
    720
    
    
    
    829
    
    
    
    764
    
    
    
    1,700
    
    
    
    1,484Pennsylvania
    
    
    727
    
    
    
    617
    
    
    
    490
    
    
    
    489
    
    
    
    1,217
    
    
    
    1,106New York
    
    
    25
    
    
    
    15
    
    
    
    
    
    
    
    
    
    
    
    25
    
    
    
    15Michigan
    
    
    1,177
    
    
    
    588
    
    
    
    7
    
    
    
    4
    
    
    
    1,184
    
    
    
    5922,800
    
    
    
    1,940
    
    
    
    1,326
    
    
    
    1,257
    
    
    
    4,126
    
    
    
    3,197
 Acreage Data The following table summarizes by state our gross and net developed and undeveloped acreage at
December 31, 2004: December 31, 2004Developed Acreage
    
    

Undeveloped
Acreage
    
    
    Total AcreageState
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetOhio
    
    
    198,297
    
    
    
    178,494
    
    
    
    21,371
    
    
    
    19,618
    
    
    
    219,668
    
    
    
    198,112Pennsylvania
    
    
    185,602
    
    
    
    151,821
    
    
    
    133,573
    
    
    
    96,429
    
    
    
    319,175
    
    
    
    248,250New York
    
    
    6,706
    
    
    
    4,959
    
    
    
    49,516
    
    
    
    25,010
    
    
    
    56,222
    
    
    
    29,969Michigan
    
    
    47,807
    
    
    
    30,470
    
    
    
    41,338
    
    
    
    37,566
    
    
    
    89,145
    
    
    
    68,036Kentucky
    
    
    1,049
    

    
    
    629
    
    
    
    17,227
    
    
    
    10,336
    
    
    
    18,276
    
    
    
    10,965Indiana
    
    
    109
    
    
    
    109
    
    
    
    9,672
    
    
    
    9,619
    
    
    
    9,781
    
    
    
    9,728439,570
    
    
    
    366,482
    
    
    
    272,697
    
    
    
    198,578
    
    
    
    712,267
    
    
    
    565,060
 Developed acreage includes 235,104 gross (208,753 net) acres of undrilled acreage held by
production. 
 Item 3.LEGAL PROCEEDINGS In February 2000, four individuals filed a suit in Chautauqua County, New York on their own
behalf and on the behalf of others similarly situated, seeking damages for the alleged difference
between the amount of lease royalties actually paid and the amount of royalties that allegedly
should have been paid. Other natural gas producers in New York were served with similar complaints.
We believe the complaint is without merit and are defending the complaint vigorously. Although the
outcome is still uncertain, we believe the action will not have a material adverse effect on our
financial position, results of operations or cash flows. We no longer own the wells that are
subject to the suit. In April 2002, we were notified of a claim by an overriding royalty interest owner in Michigan
alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms
of several farmout agreements. On July 6, 2004, a suit was filed
in Otsego County, Michigan by affiliates of Merit Energy Company, the
successor in interest to these royalty interests, alleging substantially the same underpayments. We
believe there will be no material amount payable above and beyond the amount accrued as of December
31, 2004 13




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##### Table of Contents



and therefore, the result will have no material adverse effect on our financial position,
results of operation or cash flows. We were audited by the state of West Virginia for the years 1996 through 1998. The state
assessed taxes which we contested and filed a petition for reassessment. In February 2003, we were
notified by the State Tax Commissioner of West Virginia that our petition for reassessment had been
denied and taxes due, plus accrued interest, are now payable. We disagreed with the decision,
appealed, and received a favorable ruling. The state did not appeal the Circuit Court decision. We
received a
$324,000 refund of our appeal bond and expect to receive a refund of overpaid severance taxes of
approximately $100,000 plus interest. We are involved in several lawsuits arising in the ordinary course of business. We believe
that the result of such proceedings, individually or in the aggregate, will not have a material
adverse effect on our financial position, results of operations or cash flows. Environmental costs, if any, are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past operations and that have
no future economic benefits are expensed as incurred. Expenditures that extend the life of the
related property or reduce or prevent future environmental contamination are capitalized.
Liabilities related to environmental matters are only recorded when an environmental assessment
and/or remediation obligation is probable and the costs can be reasonably estimated. Such
liabilities are undiscounted unless the timing of cash payments for the liability are fixed or
reliably determinable. At December 31, 2004, no significant environmental remediation obligation
exists which is expected to have a material effect on our financial position, results of operations
or cash flows. 
 Item 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS On November 1, 2004, Capital C, our sole shareholder, approved by
written consent in lieu of a meeting, a resolution naming Michael Becci and James A. Winne III to
our Board of Directors and increasing our Boards membership from six to eight. The terms of our
other directors on such date, Gregory A. Beard, Michael B. Hoffman, Pierre F. Lapeyre Jr., and
David M. Leuschen, continued after such date. On November 29, 2004, Capital C approved by written consent in lieu of a meeting, a resolution
adopting Amended and Restated Regulations of the Corporation. On
December 16, 2004, Capital C approved by written consent in lieu of a meeting, a resolution
decreasing our Boards membership from eight to six. On February 14, 2005, Capital C approved by written consent in lieu of a meeting, a resolution
increasing our Boards membership from six to seven. 14




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##### Table of Contents



PART II 
  Item 5.
    MARKET FOR THE REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES There is no established public trading market for our equity securities. All of our equity securities at February 28, 2005, were held by Capital C. Dividends No dividends have been paid on our Common Stock. We currently have no intention to pay any
dividends on our Common Stock. Equity Compensation Plan Information: As of February 28, 2005, we do not have an equity compensation plan. 
 Item 6.SELECTED FINANCIAL DATA The Selected Financial Data should be read in conjunction with the Consolidated Financial
Statements at Item 15(a). SuccessorPredecessor Company
    
    
    
    CompanyFor the 183
    
    
    
    For the 183 DayDay Period
    
    
    
    Period fromfrom January
    
    
    
    July 2, 2004 toAs of or for the Years Ended December 31,
    
    
    1, 2004 to July
    
    
    
    December 31,(in thousands)
    
    2000(3)
    
    
    2001
    
    
    2002(2)
    
    

2003(1)
    
    
    1, 2004(2)
    
    
    
    2004Continuing Operations:Revenues
    
    $
    99,070
    
    
    $
    110,732
    
    
    $
    105,545
    
    
    $
    95,414
    
    
    $
    50,822
    
    
    
    $
    50,960Depreciation, depletion and amortization
    
    
    25,576
    
    
    
    25,132
    
    
    
    21,339
    
    
    
    18,098
    
    
    
    9,089
    
    
    
    
    17,527Impairment of oil and gas properties
    
    
    
    
    
    
    1,398
    
    
    
    
    
    
    
    896
    
    
    
    
    
    
    
    
    Income (loss) from continuing operations before
cumulative effect of change in accounting principle
    
    
    4,841
    
    
    
    7,200
    
    
    
    8,935
    
    
    
    5,960
    
    
    
    (17,034
    )
    
    
    
    890Balance sheet data:
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    As of 12/31/2004Working capital from continuing operations
    
    
    2,096
    
    
    
    11,529
    
    
    
    (7,521
    )
    
    
    (7,090
    )
    
    
    
    
    
    
    
    (3,206
    )Oil and gas properties and gathering systems, net
    
    
    211,065
    
    
    
    220,389
    
    
    
    211,776
    
    
    
    224,631
    
    
    
    
    
    
    
    
    502,102Total assets
    
    
    285,117
    
    
    
    305,349
    
    
    
    263,845
    
    
    
    285,311
    
    
    
    
    
    
    
    
    570,242Long-term liabilities, less current portion
    
    
    286,858
    
    
    
    284,745
    
    
    
    251,959
    
    
    
    276,611
    
    
    
    
    
    
    
    
    295,482Total shareholders (deficit) equity
    
    
    (48,313
    )
    
    
    (27,279
    )
    
    
    (44,645
    )
    
    
    (57,340
    )
    
    
    
    
    
    
    
    58,127
   (1)
    
    See Note 3 to the Consolidated Financial Statements. The cumulative effect of change in accounting principle, net of tax, was $2.4 million.(2)
    
    See Note 5 to the Consolidated Financial Statements for information on discontinued operations.(3)
    
    In March 2000, we sold Peake Energy, Inc., a wholly owned subsidiary, which owned oil and gas properties in West Virginia and Kentucky. 15




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Item 7.
    MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview We are an Ohio corporation wholly owned by Capital C Energy Operations, LP, a Delaware limited
partnership (Capital C). Capital C acquired us pursuant to a merger completed on July 7, 2004
(the Merger). Capital C is a controlled affiliate of Carlyle/Riverstone Global Energy and Power
Fund II, L.P., a private equity fund (Carlyle/Riverstone). The general partner of
Carlyle/Riverstone is jointly controlled by Riverstone Holdings LLC and The Carlyle Group. We are an independent energy company engaged in the exploitation, development, production,
operation and acquisition of oil and natural gas properties. Our operations are focused in the
Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale formation in the
Michigan Basin. At December 31, 2004, our total estimated proved reserves related to continuing operations
were 285 Bcfe. Natural gas comprised approximately 88% of our estimated proved reserves, and 78% of
our estimated proved reserves were classified as proved developed. Substantially all of our
reserves are located in shallow, highly developed formations with long-lived, stable production
profiles. At December 31, 2004 our conventional Appalachian properties accounted for 52% of our
estimated proved reserves, while the Michigan properties and our
Appalachian coalbed methane properties (CBM) accounted for 42%
and 6%, respectively. In connection with the acquisition by Capital C, our existing indebtedness was refinanced. The
principal elements of the refinancing including entering into the Senior Credit Agreement,
providing for a $100 million term facility, a $30 million revolving facility and a $40 million
letter of credit facility (collectively, the Senior Facilities), and our issuance of $192.5
million of 8.75% Senior Secured Notes due 2012 (the Notes). During the periods discussed, we earned revenue through the production and sale of oil and
natural gas and, to a lesser extent, from gas gathering and marketing. In 2004, we sold the assets
of Arrow Oilfield Services (Arrow) and substantially all of our interests, or rights to our
interests, in our Trenton Black River (TBR) operations. Both of these transactions were
classified as discontinued operations. Historical information has been restated to remove the TBR
properties and Arrow from continuing operations. Our financial results and cash flows can be significantly impacted as commodity prices
fluctuate in response to changing market conditions. We use derivative instruments on a significant
portion of our oil and natural gas production to reduce the volatility of oil and natural gas
prices and to protect cash flow available for our development drilling program. In connection with
the acquisition by Capital C, at the effective time of the Merger, we became a party to a long-term
hedging program (the Hedges) with J. Aron under a master agreement and related confirmations and
documentation (collectively, the Hedge Agreement) required by the Senior Facilities and the
indenture governing the Notes, we will maintain such Hedges with J. Aron or its successor permitted
assigns. We anticipate that the Hedges will cover approximately 69% of the expected production
through 2013 from our current estimated proved reserves and will range from 65% to 80% of such
expected production in any year. The average price realized for our natural gas increased $0.16 per Mcf to $5.08 per Mcf in
2004 compared to $4.92 per Mcf in 2003. The average price realized for our natural gas decreased
from $4.95 per Mcf in 2002 to $4.92 per Mcf in 2003. The monthly average settle for natural gas
trading on the New York Mercantile Exchange (NYMEX) increased from $3.22 per Mmbtu in 2002 to
$5.39 per Mmbtu in 2003 and to $6.14 per Mmbtu in 2004. Our selling price of natural gas is
generally higher than the 16




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NYMEX price due to the favorable regional basis received throughout our areas of operations
along with a favorable Btu (British thermal unit) content of our gas. The remainder of the
difference is due to fixed price contracts and our hedging activities during these periods. Our
average realized price for oil increased from $22.72 per Bbl in 2002 to $28.06 per Bbl in 2003 and
$34.42 per Bbl in 2004. CRITICAL ACCOUNTING POLICIES We prepare our consolidated financial statements in accordance with accounting principles
generally accepted in the United States (GAAP) and SEC guidance. See the Notes to Consolidated
Financial Statements included in Item 8. Financial Statements and Supplementary Data for a more
comprehensive discussion of our significant accounting policies. GAAP requires information in
financial statements about the accounting principles and methods used and the risks and
uncertainties inherent in significant estimates including choices between acceptable methods.
Following is a discussion of our most critical accounting policies: Successful Efforts Method of Accounting The accounting for and disclosure of oil and gas producing activities requires our management
to choose between GAAP alternatives and to make judgments about estimates of future uncertainties. We use the successful efforts method of accounting for oil and gas producing activities as
opposed to the alternate acceptable full cost method. Under the successful efforts method,
property acquisition and development costs and certain productive exploration costs are capitalized
while non-productive exploration costs, which include certain geological and geophysical costs,
exploratory dry hole costs and costs of carrying and retaining undeveloped properties, are expensed
as incurred. The geological and geophysical costs include costs for salaries and benefits of our
personnel in those areas and other third party costs. The costs of carrying and retaining
undeveloped properties include salaries and benefits of our land department personnel, delay rental
payments made on new and existing leases, ad valorem taxes on existing leases and the cost of
previously capitalized leases that are written off because the leases were dropped or expired.
Exploratory dry hole costs include the costs associated with drilling an exploratory well that has
been determined to be a dry hole. The major difference between the successful efforts method of accounting and the full cost
method is under the full cost method of accounting, such exploration costs and expenses are
capitalized as assets, pooled with the costs of successful wells and charged against the net income
(loss) of future periods as a component of depletion expense. Oil and Gas Reserves Our estimated proved developed and estimated proved undeveloped reserves are all located
within the Appalachian and Michigan Basins in the United States. There are many uncertainties
inherent in estimating proved reserve quantities and in projecting future production rates and the
timing of development expenditures. In addition, estimates of new discoveries are more imprecise
than those of properties with a production history. Accordingly, these estimates are expected to
change as future information becomes available. Material revisions of reserve estimates may occur
in the future, development and production of the oil and gas reserves may not occur in the periods
assumed and actual prices realized and actual costs incurred may vary significantly from
assumptions used. Estimated proved reserves represent estimated quantities of natural gas and oil
that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under economic and operating conditions existing at the time the
estimates were made. Estimated proved developed reserves are estimated proved reserves expected to
be recovered through wells and equipment 17




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in place and under operating methods being used at the time the estimates were made. The
accuracy of a reserve estimate is a function of:  --
    the quality and quantity of available data;--
    the interpretation of that data;--
    the accuracy of various mandated economic assumptions; and--
    the judgment of the persons preparing the estimate. Our estimated proved reserve information for the 2004 predecessor company period ended July 1,
2004, is based on our internal engineering estimates. Our estimated proved reserve information for
all other periods included in this Annual Report is based on estimates prepared by independent
petroleum consultants. Estimates prepared by others may be higher or lower than these estimates. Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets See the Successful Efforts Method of Accounting discussion above. Capitalized costs related
to estimated proved properties are depleted using the unit-of-production method. Depreciation,
depletion and amortization of proved oil and gas properties are calculated on the basis of
estimated recoverable reserve quantities. These estimates can change based on economic or other
factors. No gains or losses are recognized upon the disposition of oil and gas properties except
in extraordinary transactions. Sales proceeds are credited to the carrying value of the
properties. Maintenance and repairs are expensed, and expenditures which enhance the value of
properties are capitalized. Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These
costs are assessed periodically to determine whether their value has been impaired, and if
impairment is indicated, the costs are charged to expense. Gas gathering systems are stated at cost. Depreciation expense is computed using the
straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is
computed using the straight-line method over the useful lives of the assets ranging from 3 to 15
years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and
gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation
are removed from the accounts, and any resulting gain or loss is reflected in income for the
period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and
betterments are capitalized. Long-lived assets are reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount may not be recoverable. If the sum of the expected future
undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the
difference between the fair value and the carrying amount of the asset. Fair value is determined
based on managements outlook of future oil and natural gas prices and estimated future cash flows
to be generated by the assets, discounted at a market rate of interest. Impairment of unproved
properties is based on the estimated fair value of the property. Derivatives and Hedging Our financial results and cash flows can be significantly impacted as commodity prices
fluctuate widely in response to changing market conditions. Under the provisions of SFAS 133,
Accounting for Derivative Instruments and Hedging Activities, as amended, we recognize all
derivative financial instruments as either assets or liabilities at fair value. The changes in
fair value of derivative instruments 18




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not qualifying for designation as cash flow hedges that occur prior to maturity are initially
reported in expense in the consolidated statements of operations as derivative fair value (gain)
loss. All amounts recorded in this line item are ultimately reversed within the same line item and
included in oil and gas sales revenues over the respective contract terms. Changes in the fair
value of derivative instruments that are fair value hedges are offset against changes in the fair
value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes
in the fair value of derivative instruments that are cash flow hedges are recognized in other
comprehensive income (loss) until such time as the hedged items are recognized in net income
(loss). The relationship between the hedging instruments and hedged item must be highly effective in
achieving the offset of changes in fair values or cash flows attributable to the hedged risk both
at the inception of the contract and on an ongoing basis. We measure effectiveness at least on a
quarterly basis. Ongoing assessments of hedge effectiveness will include verifying and documenting
that the critical terms of the hedge and forecasted transaction do not change. Ineffective
portions of a derivative instruments change in fair value are immediately recognized in net income
(loss). If there is a discontinuance of a cash flow hedge because it is probable that the original
forecasted transaction will not occur, deferred gains or losses are recognized in earnings
immediately. From time to time we may enter into a combination of futures contracts, commodity derivatives
and fixed-price physical contracts to manage our exposure to natural gas or oil price volatility
and support our capital expenditure plans. Our derivative financial instruments primarily take the
form of swaps or collars. At December 31, 2004, our derivative contracts were comprised of natural
gas swaps and collars and crude oil swaps, which were placed with a major financial institution
that we believe is a minimal credit risk. Qualifying derivative financial instruments are
designated as cash flow hedges. We consider our natural gas swaps to be highly effective and expect there will be no
ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging
instruments and the hedged forecasted transactions are the same. We have not experienced
ineffectiveness on our natural gas swaps because we use NYMEX-based commodity derivative contracts
to hedge on the same basis as our natural gas production is sold (NYMEX-based sales contracts). We
have collar agreements that could not be redesignated as cash flow hedges because these collars
were not effective due to unrealized losses at the date of the Merger. These collars qualified and
were designated as cash flow hedges from their inception through the predecessor company period
ended July 1, 2004. Although these collars are not deemed to be effective hedges in accordance
with the provisions of SFAS 133, we have retained these instruments as protection against changes
in commodity prices and we will continue to record the mark-to-market adjustments on these natural
gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps are highly effective
and were designated as cash flow hedges. We have ineffectiveness on the crude oil swaps because
the oil is sold locally at a posted price which is different from the NYMEX price. Historically,
there has been a high correlation between the posted price and NYMEX. The changes in the fair
values of the natural gas collars and the ineffective portion of the crude oil swaps are recorded
as Derivative fair value gain or loss. Revenue Recognition Oil and gas production revenue is recognized as production and delivery take place. Oil and
gas marketing revenues are recognized when title passes. Asset Retirement Obligations On January 1, 2003, we adopted SFAS 143, Accounting for Asset Retirement Obligations. SFAS
143 amends SFAS 19, Financial Accounting and Reporting by Oil and Gas Producing 19




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Companies which requires us to recognize a liability for the fair value of our asset
retirement obligations associated with its tangible, long-lived assets. The majority of our asset
retirement obligations recorded relate to the plugging and abandonment (excluding salvage value) of
our oil and gas properties. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative
effect adjustment to record a $4.0 million increase in long-term asset retirement obligation
liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million
increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated
depreciation, depletion and amortization and a $1.4 million increase in deferred income tax
liabilities. The net effect of adoption was to record a gain of $2.4 million, net of tax, as a
cumulative effect of a change in accounting principle in our consolidated statement of operations
in the first quarter of 2003. Subsequent to the adoption of SFAS 143, there has been no significant current period activity
with respect to additional retirement obligations, settled obligations, accretion expense and
revisions of estimated cash flows. The asset retirement obligations increased as a result of
purchase accounting for the Merger, primarily due to a lower discount rate and revised estimates of
asset lives on certain oil and gas wells. The unaudited pro forma income from continuing
operations for the year ended December 31, 2002 was $4.3 million and has been prepared to give
effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002. Assuming
retroactive application of the change in accounting principle as of January 1, 2002, liabilities
would have increased approximately $6 million. At December 31, 2004, there were no assets legally restricted for purposes of settling asset
retirement obligations. A reconciliation of our liability for asset retirement obligations for the
year ended December 31, 2004 and 2003 is as follows (in thousands): Successor Company
    
    
    
    Predecessor CompanyFor The 183 DayPeriod From July 2, to
    
    
    
    For The 183 Day Period From
    
    
    Year endedDecember 31, 2004
    
    
    
    January 1, to July 1, 2004
    
    
    December 31, 2003Beginning asset retirement obligations
    
    $
    14,274
    
    
    
    $
    4,595
    
    
    $
    Cumulative effect adjustment
    
    
    
    
    
    
    
    
    
    
    
    4,387Liabilities incurred
    
    
    101
    
    
    
    
    9
    
    
    
    268Liabilities settled
    
    
    (85
    )
    
    
    
    (30
    )
    
    
    (471
    )Accretion expense
    
    
    633
    
    
    
    
    195
    
    
    
    344Revisions in estimated cash flows
    
    
    19
    
    
    
    
    24
    
    
    
    67Ending asset retirement obligations
    
    $
    14,942
    
    
    
    $
    4,793
    
    
    $
    4,595
 New Accounting Pronouncements In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities  An
Interpretation of Accounting Research Bulletin (ARB) 51.
FIN 46, as amended by FIN 46(R); in
December 2003, is an interpretation of ARB 51, Consolidated Financial Statements, and addresses
consolidation by business enterprises of variable interest entities (VIEs). The primary objective
of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities
over which control is achieved through means other than voting rights; such entities are known as
VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a
majority of the entitys expected losses if they occur, receive a majority of the entitys expected
residual returns if they occur, or both. An enterprise shall consider the rights and obligations
conveyed by its variable interests in 20




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making this determination. This guidance applied immediately
to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest
after that date. It applies in the first fiscal year or interim period beginning after December
15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February
1, 2003. The adoption of FIN 46 and FIN 46(R) did not have any effect on our financial statement
disclosures, financial position, results of operations or cash flows. In April 2003, the FASB issued SFAS 149, Amendment of Statement 133 on Derivative Instruments
and Hedging Activities. SFAS 149 is intended to result in more consistent reporting of contracts
as either freestanding derivative instruments subject to SFAS 133 in its entirety, or as hybrid
instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for
our financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149
did not have a material effect on our financial position, results of operations or cash flows. In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. SFAS
123(R) revises SFAS 123, Accounting for Stock-Based Compensation, and focuses on accounting for
share-based payments for services by employer to employee. SFAS 123(R) requires companies to
expense the fair value of employee stock options and other equity-based compensation at the grant
date. SFAS 123(R) does not require a certain type of valuation model and either a binomial or
Black-Scholes model may be used. The provisions of SFAS 123(R) are effective for financial
statements for fiscal periods ending after June 15, 2005. We did not have stock-based compensation
arrangements outstanding at December 31, 2004. The impact of adoption will depend on future
issuance of stock-based compensation arrangements. Our future cash flows will not be impacted by
the adoption of SFAS 123(R). See Note 2 to the Consolidated Financial Statements in Item 8 of this
Annual Report for the accounting policy description for Stock Based Compensation for further
information. 21




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Estimated Proved Reserves Evaluation Our estimated proved reserves as of December 31, 2004 were approximately 285 Bcfe compared
with estimated proved reserves from continuing operations as of December 31, 2003 of approximately
355 Bcfe. Wright & Company, Inc. (Wright), independent petroleum consultants, prepared reports
of our estimated proved reserves as of December 31, 2004 and 2003. Estimated proved reserves as of
December 31, 2004 decreased approximately 70 Bcfe from December 31, 2003, as presented in the table
below. Estimated
    
    
    Estimated Proved
    
    
    Total EstimatedProved Developed
    
    
    Undeveloped
    
    
    Proved(Bcfe)Estimated proved reserves at 12/31/03 from
continuing operations
    
    
    230.7
    
    
    
    124.4
    
    
    
    355.1Extensions and discoveries
    
    
    0.2
    
    
    
    2.4
    
    
    
    2.6Purchase of reserves in place
    
    
    0.2
    
    
    
    1.1
    
    
    
    1.3Revisions of previous estimates:Changes in capital and operating costs
    
    
    (11.5
    )
    
    
    (6.0
    )
    
    
    (17.5
    )Commodity price changes
    
    
    2.5
    
    
    
    6.7
    
    
    
    9.2Engineering revisions
    
    
    0.1
    
    
    
    (21.3
    )
    
    
    (21.2
    )Surrendered and expired leases
    
    
    
    
    
    
    (7.4
    )
    
    
    (7.4
    )Reclassified to an unproved category
    
    
    
    
    
    
    (19.7
    )
    
    
    (19.7
    )Production 2004
    
    
    (17.6
    )
    
    
    
    
    
    
    (17.6
    )Drilling 2004
    
    
    16.3
    
    
    
    (16.3
    )
    
    
    Estimated proved reserves at 12/31/04
    
    
    220.9
    
    
    
    63.9
    
    
    
    284.8
 During 2004, the primary focus of our drilling program was on proved undeveloped
locations. The result of this program converted approximately 16.3 Bcfe of estimated proved
undeveloped reserves into estimated proved developed reserves. Production for 2004 was 17.6 Bcfe. Revisions of previous estimates accounted for a decrease of approximately 56.7 Bcfe. The
majority of this reduction was in the estimated proved undeveloped reserves category. Of this
decrease, approximately 21.2 Bcfe related to engineering revisions which resulted from our analysis
of our drilling results in the past several years as compared to reserve estimates of proved
undeveloped well locations in our prior years reserve report. Additionally, as a result of higher
future development and operating costs, total estimated proved
reserves were reduced by approximately 17.5 Bcfe. Increases in our estimated proved
reserves of 9.2 Bcfe resulted from increases in commodity prices at December 31, 2004 compared to
2003. Furthermore, approximately 19.7 Bcfe of estimated proved undeveloped reserves were
reclassified to an unproved category, as the locations were more than one direct offset spacing
unit from a productive well. During 2004, we performed a lease review of our proved undeveloped locations, which, due to
leases that have expired or that we have surrendered, resulted in a downward adjustment of approximately 7.4 Bcfe to our
estimated proved undeveloped reserves at December 31, 2004. Reserves estimates are based upon various assumptions, including assumptions required by the
SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. The process of estimating reserves is complex. This process requires 22




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significant decisions and assumptions in the evaluation of available geological, geophysical,
engineering and economic data for each reservoir. Furthermore, different reserve engineers may
make different estimates of reserves and cash flow based on the same available data and these
differences may be significant. Therefore, these estimates are not precise. Actual future
production, oil and natural gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas reserves will most likely vary from
those estimated. In addition, we may adjust estimates of proved reserves to reflect production
history, results of exploration and development, prevailing oil and natural gas prices and other
factors, many of which are beyond our control. 23




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##### Table of Contents



Results of Operations As a result of the Merger, the results of operations for the periods subsequent to July 1,
2004 are not necessarily comparable to those prior to July 1, 2004. The following table combines
the predecessor company 183 day period ended July 1, 2004 with the successor company 183 day period
ended December 31, 2004 for purposes of the discussion of year-end results. The following table
sets forth financial data for the periods indicated. Dollars are stated in thousands and
percentages are stated as a percentage of total revenues. Year Ended December 31,2004
    
    
    2003
    
    
    2002RevenuesOil and gas sales
    
    $
    90,648
    
    
    
    89.1
    %
    
    $
    84,610
    
    
    
    88.7
    %
    
    $
    90,462
    
    
    
    85.7
    %Gas gathering and marketing
    
    
    9,980
    
    
    
    9.8
    
    
    
    10,538
    
    
    
    11.0
    
    
    
    13,526
    
    
    
    12.8Other
    
    
    1,154
    
    
    
    1.1
    
    
    
    266
    
    
    
    0.3
    
    
    
    1,557
    
    
    
    1.5101,782
    
    
    
    100.0
    
    
    
    95,414
    
    
    
    100.0
    
    
    
    105,545
    
    
    
    100.0ExpensesProduction expense
    
    
    22,585
    
    
    
    22.1
    
    
    
    20,017
    
    
    
    20.9
    
    
    
    20,247
    
    
    
    19.2Production taxes
    
    
    2,767
    
    
    
    2.7
    
    
    
    2,449
    
    
    
    2.6
    
    
    
    1,789
    
    
    
    1.7Gas gathering and marketing
    
    
    9,055
    
    
    
    8.9
    
    
    
    9,570
    
    
    
    10.0
    
    
    
    11,000
    
    
    
    10.4Exploration expense
    
    
    5,467
    
    
    
    5.4
    
    
    
    6,849
    
    
    
    7.2
    
    
    
    8,834
    
    
    
    8.4General and administrative expense
    
    
    5,151
    
    
    
    5.1
    
    
    
    4,559
    
    
    
    4.8
    
    
    
    4,557
    
    
    
    4.3Franchise, property and other taxes
    
    
    167
    
    
    
    0.2
    
    
    
    202
    
    
    
    0.2
    
    
    
    11
    
    
    
    Depreciation, depletion and amortization
    
    
    26,616
    
    
    
    26.2
    
    
    
    18,098
    
    
    
    19.0
    
    
    
    21,339
    
    
    
    20.2Impairment of oil and gas properties
    
    
    
    
    
    
    
    
    
    
    896
    
    
    
    0.9
    
    
    
    
    
    
    
    Accretion expense
    
    
    828
    
    
    
    0.8
    
    
    
    343
    
    
    
    0.4
    
    
    
    
    
    
    
    Derivative fair value (gain) loss
    
    
    1,209
    
    
    
    1.2
    
    
    
    (319
    )
    
    
    (0.3
    )
    
    
    
    
    
    
    Severance and other nonrecurring expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    923
    
    
    
    0.9Transaction expense
    
    
    26,001
    
    
    
    25.5
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    99,846
    
    
    
    98.1
    
    
    
    62,664
    
    
    
    65.7
    
    
    
    68,700
    
    
    
    65.1Operating income
    
    
    1,936
    
    
    
    1.9
    
    
    
    32,750
    
    
    
    34.3
    
    
    
    36,845
    
    
    
    34.9Other expenseLoss on sale of businesses
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    154
    
    
    
    0.1Interest expense
    
    
    24,061
    
    
    
    23.6
    
    
    
    23,580
    
    
    
    24.7
    
    
    
    22,506
    
    
    
    21.3(Loss) income from continuing operations
before income taxes and cumulative effect
of change in accounting principle
    
    
    (22,125
    )
    
    
    (21.7
    )
    
    
    9,170
    
    
    
    9.6
    
    
    
    14,185
    
    
    
    13.5(Benefit) provision for income taxes
    
    
    (5,981
    )
    
    
    (5.9
    )
    
    
    3,210
    
    
    
    3.4
    
    
    
    5,250
    
    
    
    5.0(Loss) income from continuing operations
before cumulative effect of change in
accounting principle
    
    
    (16,144
    )
    
    
    (15.8
    )
    
    
    5,960
    
    
    
    6.2
    
    
    
    8,935
    
    
    
    8.5Income (loss) from discontinued
operations, net of tax
    
    
    28,868
    
    
    
    28.4
    
    
    
    (10,681
    )
    
    
    (11.2
    )
    
    
    (6,470
    )
    
    
    (6.1
    )Income (loss) before cumulative effect of
change in accounting principle
    
    
    12,724
    
    
    
    12.6
    
    
    
    (4,721
    )
    
    
    (5.0
    )
    
    
    2,465
    
    
    
    2.4Cumulative effect of change in accounting
principle, net of tax
    
    
    
    
    
    
    
    
    
    
    2,397
    
    
    
    2.5
    
    
    
    
    
    
    
    Net income (loss)
    
    $
    12,724
    
    
    
    12.6
    %
    
    $
    (2,324
    )
    
    
    (2.5)
    %
    
    $
    2,465
    
    
    
    2.4
    %
 24




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The following Managements Discussion and Analysis is based on the results of operations
from continuing operations, unless otherwise noted. Accordingly, the discontinued operations have
been excluded. See Note 5 to the Consolidated Financial Statements. Production, Sales Prices and Costs The following table sets forth certain information regarding our net oil and natural gas
production, revenues and expenses for the years indicated. This table includes continuing
operations only. Year Ended December 31,2004
    
    
    2003
    
    
    2002ProductionGas (Mmcf)
    
    
    15,267
    
    
    
    14,834
    
    
    
    15,882Oil (Mbbl)
    
    
    381
    
    
    
    413
    
    
    
    522Total production (Mmcfe)
    
    
    17,553
    
    
    
    17,311
    
    
    
    19,012Average priceGas (per Mcf)
    
    $
    5.08
    
    
    $
    4.92
    
    
    $
    4.95Oil (per Bbl)
    
    
    34.42
    
    
    
    28.06
    
    
    
    22.72Mcfe
    
    
    5.16
    
    
    
    4.89
    
    
    
    4.76Average costs (per Mcfe)Production expense
    
    
    1.29
    
    
    
    1.16
    
    
    
    1.07Production taxes
    
    
    0.16
    
    
    
    0.14
    
    
    
    0.09Depletion
    
    
    1.36
    
    
    
    0.85
    
    
    
    0.87Operating margin (per Mcfe)
    
    
    3.71
    
    
    
    3.59
    
    
    
    3.60
 Mmcf  Million cubic feet
    
    Mmcfe  Million cubic feet equivalent
    
    Bbl  BarrelMbbl  Thousand barrels
    
    Mcf  Thousand cubic feetOperating margin (per Mcfe)  average price less production expense and production taxes
 2004 Compared to 2003 Revenues Net operating revenues increased from $95.1 million in 2003 to $100.6 million in 2004. The
increase was due to higher gas sales revenues of $4.5 million and higher oil sales revenues of $1.5
million partially offset by lower gas gathering and marketing revenues of $558,000. Gas volumes sold increased 433 Mmcf (3%) from 14.8 Bcf in 2003 to 15.3 Bcf in 2004 resulting
in an increase in gas sales revenues of approximately $2.1 million. Oil volumes sold decreased
approximately 32,000 Bbls (8%) from 413,000 Bbls in 2003 to 381,000 Bbls in 2004 resulting in a
decrease in oil sales revenues of approximately $890,000. The gas sales volume increase was
primarily due to the production from wells drilled in 2003 and 2004 and increased production as a
result of additional expenditures to stimulate production on declining wells partially offset by
normal production declines. The lower oil sales volumes are due to normal production declines. Our
drilling program primarily targets natural gas reserves. The average price realized for our natural gas increased $0.16 per Mcf to $5.08 per Mcf in
2004 compared to 2003, which increased gas sales revenues by approximately $2.4 million. As a
result of our hedging activities, gas sales revenues were decreased by $20.8 million ($1.36 per
Mcf) in 2004 and decreased by $10.3 million ($.69 per Mcf) in 2003. The average price realized for
our oil increased from 25




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$28.06 per Bbl in 2003 to $34.42 per Bbl in 2004, which increased oil sales
revenues by approximately $2.4 million. As a result of our hedging activities, oil sales revenues
were decreased by approximately $1.5 million ($3.96 per Bbl) in 2004. The operating margin from oil and gas sales on a per unit basis increased from $3.59 per Mcfe
in 2003 to $3.71 per Mcfe in 2004. The average price increased $0.27 per Mcfe which was partially
offset by an increase in production expense of $0.13 per Mcfe in 2004 compared to 2003.
Approximately $0.06 per Mcfe of the increase in production expense was due to recording the cost of
selling purchased oil inventory as a result of purchase accounting for the Merger. The decrease in gas gathering and marketing revenues was due to a $948,000 decrease in gas
marketing revenues partially offset by a $390,000 increase in gas gathering revenues. The lower
marketing revenues were primarily the result of decreased gas volumes from third party wells. The
increase in gas gathering revenues was primarily due to higher margins on a gathering system in
Pennsylvania. Costs and Expenses Production expense increased $2.6 million (13%) from $20.0 million in 2003 to $22.6 million in
2004 primarily due to an increase in labor resulting from continued well development activities, an
increased focus on production and compressor optimization, a general increase in fuel and power
costs and $462,000 of additional non-cash stock-based compensation expense recorded in the second
quarter of 2004 to reflect the increased value of our stock. Production expense was also increased
in the second half of 2004 due to recording approximately $975,000 in cost associated with the
selling of purchased oil inventory as a result of purchase accounting for the Merger. Oil inventory
was recorded at fair value of approximately $31.88 per Bbl as of July 1, 2004. The average
production cost increased from $1.16 per Mcfe in 2003 to $1.29 per Mcfe in 2004. The per unit
increase was primarily due to the higher costs discussed above partially offset by certain fixed
costs spread over greater volumes in 2004. Purchase accounting and the non-cash stock-based
compensation expense were responsible for $0.06 and $0.03 per Mcfe of the per unit increase,
respectively. Production taxes increased $318,000 from $2.4 million in 2003 to $2.8 million in 2004
primarily due to higher oil and gas prices in Michigan, where production taxes are based on a
percentage of revenues, excluding the effects of hedging. Average per unit production taxes
increased from $0.14 per Mcfe in 2003 to $0.16 per Mcfe in 2004 primarily due to the increase in
the selling price of natural gas in 2004, excluding the effects of hedging. Exploration expense decreased $1.3 million (20%) from $6.8 million in 2003 to $5.5 million in
2004 primarily due to decreases in expired lease expense, seismic expense and exploratory dry hole
expense partially offset by additional non-cash stock-based compensation expense recorded in the
second quarter of 2004. We have decreased exploration activity in order to focus our drilling
efforts on lower risk developmental drilling. However, we expect to continue to incur exploration
expense for costs related to our ongoing operations which are classified as exploration expense
under the successful efforts method of accounting. See Note 2 to the Consolidated Financial
Statements. General and administrative expense increased $592,000 (13%) from 2003 to 2004 primarily due to
management fees and reimbursements of $641,000 paid, respectively, to Capital C and Legend Natural Gas, LP (Legend) and $292,000 of additional non-cash stock-based compensation expense
recorded in the second quarter of 2004 to reflect the increased value of our stock. 26




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Depreciation, depletion and amortization increased by $8.5 million from $18.1 million in 2003
to $26.6 million in 2004. This increase was primarily due to an increase in depletion expense.
Depletion expense increased $9.0 million (61%) from
$14.6 million in 2003 to $23.6 million in 2004
due to higher gas volumes and a higher depletion rate per Mcfe. Depletion per Mcfe increased from
$0.85 per Mcfe in 2003 to $1.35 per Mcfe in 2004, primarily due to a higher cost basis resulting
from purchase accounting for the Merger in the last six months of 2004. Approximately $0.26 per
Mcfe of the increase in depletion per Mcfe was due to the $112.4 million deferred tax gross-up to
producing oil and gas properties. Derivative fair value gain/loss was a gain of $319,000 in 2003 compared to a loss of $1.2
million in 2004. The derivative fair value gain/loss reflects the changes in fair value of certain
derivative instruments that are not designated or do not qualify as cash flow hedges and $1.6
million related to the ineffective portion of crude oil swaps qualifying for hedge accounting which
was recorded in the third quarter of 2004. Transaction expenses of $26 million were recorded in the predecessor period. These expenses
include severance and retention payments made to employees, unamortized loan costs written off,
temporary financing facility costs, costs of the consent solicitation
process for our $225 million
Senior Subordinated Notes due 2007 (the 9-7/8% Notes) and buyer and seller investment banking fees, professional fees and other
transaction expenses. Interest expense increased $481,000 (2%) from $23.6 million in 2003 to $24.1 million in 2004.
This increase was due to an increase in average outstanding borrowings partially offset by lower
blended interest rates. Income tax expense decreased $9.2 million from $3.2 million in 2003 to a benefit of $6.0
million in 2004. The decrease was due to a decrease in income from continuing operations before
income taxes coupled with a lower effective tax rate in 2004. The effective tax rate was reduced
due to certain nondeductible transaction-related expenses recorded in the predecessor period. This
was partially offset by an increase in the tax rate from a benefit of $1.5 million recorded in the
successor period. This benefit was the result of a change in the effective state tax rate due to
the merger of two of our subsidiaries into Belden & Blake Corporation on December 30, 2004. Discontinued operations relating to the TBR and Arrow asset sales resulted in a gain, net of
tax, of $28.9 million in 2004 compared to a loss, net of tax, of $10.7 million in 2003. This was
primarily attributable to the $45.2 million ($28.0 million net of tax) net gain on the sales of the
TBR and Arrow recorded in the second quarter of 2004. 2003 Compared to 2002 Revenues Net operating revenues decreased from $104.0 million in 2002 to $95.1 million in 2003. The
decrease was due to lower gas sales revenues of $5.6 million, lower oil sales revenues of $266,000
and lower revenues from gas gathering and marketing of $3.0 million. Gas volumes sold decreased 1.1 Bcf (7%) from 15.9 Bcf in 2002 to 14.8 Bcf in 2003 resulting in
a decrease in gas sales revenues of approximately $5.2 million. Oil volumes sold decreased
approximately 109,000 Bbls (21%) from 522,000 Bbls in 2002 to 413,000 Bbls in 2003 resulting in a
decrease in oil sales revenues of approximately $2.5 million. The oil and gas volume decreases were
due to the sales of 202 wells in Ohio in the first quarter of 2002, 1,138 wells in Ohio in the
third quarter of 2002 and 135 wells in Pennsylvania in the fourth quarter of 2002 and the natural production decline of
the wells partially offset by production from wells drilled in 2002 and 2003. 27




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The average price realized for our natural gas decreased $0.03 per Mcf to $4.92 per Mcf in
2003 compared to 2002, which decreased gas sales revenues in 2003 by approximately $445,000. As a
result of our hedging activities, gas sales revenues were decreased by $10.3 million ($0.69 per
Mcf) in 2003 and increased by $21.6 million ($1.36 per Mcf) in 2002. The average price paid for our
oil increased from $22.72 per barrel in 2002 to $28.06 per barrel in 2003, which increased oil
sales revenues by approximately $2.2 million. The operating margin from oil and gas sales (oil and gas sales revenues less production
expense and production taxes) on a per unit basis decreased from $3.60 per Mcfe in 2002 to $3.59
per Mcfe in 2003. The decrease in gas gathering and marketing revenues was primarily the result of decreased gas
marketing activity, the termination of a gas marketing contract and lower margins on a gathering
system in Pennsylvania. Costs and Expenses Production expense decreased $230,000 from $20.2 million in 2002 to $20.0 million in 2003.
This decrease was primarily due to the sales of wells in Ohio and Pennsylvania during 2002,
partially offset by higher operating costs incurred as a result of colder temperatures and greater
amounts of snow during the first quarter of 2003 coupled with increased costs to stimulate
production on declining wells in the higher oil and natural gas price environment of 2003. These
efforts increased production volumes during 2003 but also had the effect of increasing the per unit
cost. The average production cost increased from $1.07 per Mcfe in 2002 to $1.16 per Mcfe in 2003.
The per unit increase was primarily due to the higher costs incurred during 2003 as discussed above
and certain fixed costs spread over fewer volumes in 2003. Production taxes increased $660,000 from $1.8 million in 2002 to $2.4 million in 2003
primarily due to higher oil and gas prices in Michigan, where production taxes are based on a
percentage of revenues, excluding the effects of hedging. Average per unit production taxes
increased 50% from $0.09 per Mcfe in 2002 to $0.14 per Mcfe in 2003 primarily due to a 56% increase
in the selling price of natural gas in 2003, excluding the effects of hedging. Exploration expense decreased $2.0 million from $8.8 million in 2002 to $6.8 million in 2003
due to a decrease in seismic costs of $1.1 million, a decrease of $252,000 in land leasing expense
and a decrease in employment and other compensation related expenses. Depreciation, depletion and amortization decreased by $3.2 million from $21.3 million in 2002
to $18.1 million in 2003. This decrease was primarily due to a $286,000 reduction in amortization
of loan costs, a $404,000 reduction in the amortization of nonconventional fuel source tax credits
and a decrease in depletion expense. Depletion expense decreased $2.0 million (12%) from $16.6
million in 2002 to $14.6 million in 2003 due to lower oil and gas volumes and a lower depletion
rate per Mcfe. Depletion per Mcfe decreased from $0.87 per Mcfe in 2002 to $0.85 per Mcfe in 2003,
primarily due to the effect of the adoption of SFAS 143. The basis used to calculate depletion
expense for oil and gas properties was increased by the fair value of the estimated future plugging
liability and decreased by the gross amount of the estimated salvage value of the well equipment. Impairment of oil and gas properties was $896,000 in 2003 due to impairment of acreage of
$475,000 in certain areas and an impairment of $421,000 in one of our smaller producing property
pools. The impairments reduced the propertys book value to its estimated fair value. 28




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Accretion expense was $343,000 in 2003 as a result of the adoption of SFAS 143 at the
beginning of 2003. Derivative fair value gain was $319,000 in 2003 related to certain derivative instruments that
are not designated as cash flow hedges. The gain reflects the changes in fair value of those
instruments. We recorded severance and other nonrecurring charges of $923,000 in 2002 which were primarily
related to employment reductions. In 2002, a total of 28 positions were eliminated when we combined
our Pennsylvania/ New York District with our Ohio District to form a new Appalachian District.
These actions were necessary to capitalize on operational and administrative efficiencies and bring
our employment level in line with current and anticipated future staffing. Interest expense increased $1.1 million (5%) from $22.5 million in 2002 to $23.6 million in
2003. This increase was due to an increase in average outstanding borrowings and higher blended
interest rates. Income tax expense decreased $2.1 million from $5.3 million in 2002 to $3.2 million in 2003.
The decrease in expense is due to a decrease in income from continuing operations and a lower
effective tax rate in 2003. Loss from discontinued operations increased from a net loss of $6.5 million in 2002 to a loss
of $10.7 million in 2003. Discontinued operations relate to the New York Medina wells sold in 2002
and the TBR and Arrow assets sold in the second quarter of 2004. The increase is primarily due to a
$7.9 million ($5.2 million net of tax benefit) increase in loss from the TBR assets as a result of
higher TBR exploration expense in 2003 and an impairment recorded on undeveloped TBR acreage in
2003. This increase was partially offset by a $1.2 million decrease in loss from the New York
Medina wells as a result of the $3.2 million ($1.8 million net of tax benefit) loss recorded on the
sale in 2002. Liquidity and Capital Resources Cash Flows We expect that our primary sources of cash in 2005 will be from funds generated from
operations and from borrowings under the Senior Facilities. Based on our current level of
operations, we believe our cash flow from operations, available cash and available borrowings under
our Senior Facilities, will be adequate to meet our future liquidity needs for the foreseeable
future. The primary sources of cash in the year ended December 31, 2004 were net proceeds from the
sale of our TBR and Arrow assets, funds generated from operations and from borrowings under our
credit facilities, and the proceeds from the issuance of the Notes. Funds used during this period
were primarily used for operations, exploration and development expenditures, interest expense,
Merger expenses and repayment of debt. Our liquidity and capital resources are closely related to
and dependent upon the current prices paid for our oil and natural gas. 29




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The following table summarizes the net cash flow for the periods presented: Year Ended December 31,2004
    
    
    2003
    
    
    Change(in millions)Cash flows provided by operating activities
    
    $
    44.3
    
    
    $
    26.2
    
    
    $
    18.1Cash flows from investing activities
    
    
    (27.1
    )
    
    
    (31.3
    )
    
    
    4.2Cash flows from financing activities
    
    
    (61.3
    )
    
    
    20.2
    
    
    
    (81.5
    )Changes in cash from discontinued operations
    
    
    61.1
    
    
    
    (15.4
    )
    
    
    76.5Net increase or decrease in cash and cash equivalents
    
    $
    17.0
    
    
    $
    (0.3
    )
    
    $
    17.3
 Our operating activities provided cash flows of $44.3 million during 2004 compared to
$26.2 million in 2003. The increase was primarily due to higher cash received for oil and gas
revenues (net of hedging) of $6.0 million and changes in certain working capital items of $11.0
million. Cash flows used in investing activities decreased $4.2 million in 2004 due to a decrease in
acquisitions of $4.8 million and a decrease in exploration expense of $1.4 million partially offset
by $2.6 million in lower asset sales in 2004 compared to 2003. Cash flows used in financing activities in 2004 were primarily due to the Merger and payments
on the predecessor company credit facility. During 2004, working capital from continuing operations increased $3.9 million from a deficit
of $7.1 million at December 31, 2003 to a deficit of $3.2 million at December 31, 2004. The
increase was primarily due to an increase in cash of $17.0 million, an increase in accounts
receivable of $4.4 million and an increase in deferred income tax assets of $3.7 million. This was
offset by an increase in accrued expenses of $10.7 million, an increase in the net current
liability for the fair value for derivatives of $8.5 million, a decrease in other current assets of
$1.3 million and an increase of $1.2 million for the current portion of long-term liabilities.
Accrued expenses increased primarily due to an increase of $6.9 million in accrued interest
expense. 30




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Capital Expenditures The table below sets forth our total capital expenditures for each of the years ending
December 31, 2004, 2003 and 2002. Year Ended December 31,2004
    
    
    2003
    
    
    2002(in millions)Total capital expendituresDrilling including exploratory dry hole expense
    
    $
    21
    
    
    $
    20
    
    
    $
    15Production enhancements and field improvements
    
    
    3
    
    
    
    3
    
    
    
    2Leasehold acreage
    
    
    1
    
    
    
    
    
    
    
    2Other capital expenditures
    
    
    
    
    
    
    1
    
    
    
    3Total
    
    $
    25
    
    
    $
    24
    
    
    $
    22
 During 2004, we spent approximately $25 million, including exploratory dry hole expense,
on our drilling and other capital expenditures related to continuing operations. In 2004, we
drilled 101 gross (93.1 net) development wells of which 100 gross (92.1 net) wells were
successfully completed as producers in the target formation and 1 gross (1.0 net) well was a dry
hole. We also drilled five gross (3.8 net) exploratory wells which were all dry holes. One
additional exploratory well drilled in 2004 is still being evaluated. We plan to spend approximately $36 million during 2005 on our drilling activities, including
exploratory dry hole expense, and other capital expenditures. We intend to finance our planned
capital expenditures through our cash on hand, available cash flow, borrowings under our revolving
credit facility and, to a lesser extent, the sale of non-strategic assets. At December 31, 2004,
and at February 28, 2005, we had approximately $13.8 million available under our revolving
facility. The level of our future cash flow will depend on a number of factors including the
demand for and price levels of oil and gas, the scope and success of our drilling activities and
our ability to acquire additional producing properties. There can be no assurance that the future
drilling of our proved undeveloped locations will provide adequate liquidity in the future. Financing and Credit Facilities Senior Secured Notes due 2012 We have $192.5 million of our Notes outstanding as of December 31, 2004. The Notes mature
July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year. The
Notes are secured on a second-priority lien on the same assets subject to the liens securing our
obligations under the Senior Facilities. The Notes are subject to redemption at our option at
specific redemption prices. July 15, 2008
    
    
    104.375
    %July 15, 2009
    
    
    102.188
    %July 15, 2010 and thereafter
    
    
    100.000
    %
 The Notes are governed by an indenture (the Indenture), which contains certain covenants
that limit our ability to incur additional indebtedness and issue stock, pay dividends, make
distributions, make 31




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investments, make certain other restricted payments, enter into certain transactions with
affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than
permitted liens and engage in mergers and consolidations. On December 23, 2004, we commenced an exchange offer, which allowed the holders of the
unregistered Notes to exchange the unregistered Notes for new notes with materially identical terms
that had been registered under the Securities Act of 1933, as amended. The exchange offer expired
on February 4, 2005, and all of the unregistered Notes were exchanged for registered Notes. The
Notes are not listed on any securities exchange. Senior Facilities At December 31, 2004, we had a $170 million senior credit facility comprised of: a seven year
$100 million term facility; a six year $30 million revolving facility for working capital
requirements and general corporate purposes, including the issuance of letters of credit; and a six
year $40 million letter of credit facility (the Senior Facilities) that may be used only to
provide credit support for our obligations under the Hedge Agreement and other hedging
transactions. The Senior Facilities are secured by a first-priority lien on certain of our assets.
At December 31, 2004, the interest rate under our base rate option was 7.0%. Under our three
month LIBOR option the rate was 5.24%. At December 31, 2004, we had $56.2 million of outstanding
letters of credit. At December 31, 2004, there was no outstanding balance under the revolving
credit agreement. Under the term facility the outstanding balance was $89.5 million. We had $13.8
million of borrowing capacity under our revolving credit facility available for general corporate
purposes. As of December 31, 2004, we were in compliance with all financial covenants and
requirements under the existing credit facilities. Term Facility The Term Facility consists of a $100 million term loan that was made on July 7, 2004. Proceeds
of the term loan were used to fund a portion of the consideration in the Merger, to refinance our
existing indebtedness, and to pay expenses associated with the transactions. All or a portion of the term loan will bear interest, at our option, either at the Base Rate
or at the Eurodollar Rate plus, in each case, a specified margin subject to adjustment. The Base
Rate is a rate calculated daily as the highest of (i) the annual rate of interest quoted in The
Wall Street Journal, Money Rates Section as the Prime Rate (currently defined as the base rate on
corporate loans posted by at least 75% of the nations thirty (30) largest banks), and (ii) the
federal funds effective rate plus 1/2 of 1%. Interest on any portion of the term loan bearing
interest based on the Base Rate is payable quarterly on January 1, April 1, July 1, and October 1
of each year. The
Eurodollar Rate is equal to the LIBOR as adjusted for certain
regulatory reserve costs. At our election, interest periods for that portion of the term loan
bearing interest at the Eurodollar Rate may be one, two, three and six months. Interest on any
portion of the term loan bearing interest based on the Eurodollar Rate is payable quarterly on
January 1, April 1, July 1, and October 1 of each year. Interest on overdue term loan amounts
accrues at a rate equal to the Base Rate plus the applicable margin plus 2.00%. The term loan amortizes quarterly at the rate of 0.25% of the outstanding amount of the term
loan per quarter during the first six years, with the balance payable in equal quarterly
installments during the seventh year. The term loan is required to be paid in full on July 7, 2011. We are entitled to
voluntarily prepay the term loan at any time, in whole or in part, without premium or penalty. 32




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We must make mandatory prepayments of the term loan utilizing funds derived from certain
proceeds as follows: (i) 100% of the net cash proceeds of the sale or disposition of our property
and assets and that of our subsidiaries (other than net cash proceeds of sales or dispositions of
inventory in the ordinary course of business and net cash proceeds less than a specified amount
that are reinvested in other assets useful in our business within 360 days); (ii) 100% of the net
cash proceeds of insurance paid on account of any loss by us or our subsidiaries of any property or
assets, other than net cash proceeds less than a specified amount that are reinvested in other
assets useful in our business or that of our subsidiaries (or used to replace damaged or destroyed
assets) within 360 days of receipt thereof; (iii) 50% of the net cash proceeds received from the
issuance of equity securities by us or our subsidiaries (other than issuances pursuant to employee
stock plans); (iv) 100% of the net cash proceeds received from the incurrence of indebtedness by us
or our subsidiaries (other than indebtedness otherwise permitted under the documentation for the
Senior Facilities), payable no later than the first business day following the date of receipt; and
(v) 100% (subject to reduction if certain financial performance measures are obtained) of excess
cash flow payable within 105 days of fiscal year end. Mandatory prepayments are applied to
scheduled amortization payments on the term loan on a pro rata basis. As a result of the amount of our calculation of excess cash flow, as defined in our credit
agreement, we elected to make a prepayment of $10 million on December 16, 2004. We have no
additional mandatory prepayment requirement for 2004, based on the calculation of excess cash flow. Revolving Facility The Revolving Facility is a $30 million revolving credit facility that may be used by us for
revolving loans and letters of credit including letters of credit to secure the Hedges and other
hedging transactions. Revolving loans may be borrowed anytime beginning July 7, 2004 and ending on
July 7, 2010. Proceeds of the revolving loan may be used for ongoing working capital requirements
and general corporate purposes and up to $15 million for the issuance of letters of credit (in
addition to the letters of credit provided under the letter of credit facility described below) to
provide credit support for our obligations under the Hedge Agreement and other hedging
transactions. An additional $5 million of letters of credit may be obtained during the term of the
Revolving Facility for general corporate purposes. All or a portion of the revolving loans will bear interest, at our option, either at the Base
Rate (as discussed above under Term Facility) plus a specified margin subject to adjustment or at
the Eurodollar Rate (as discussed above under Term Facility) plus a specified margin subject to
adjustment. Interest on any portion of the revolving loan bearing interest based on the Based Rate
is payable on March 31, June 30, September 30 and December 31 of each year. Interest on any
portion of the revolving loan bearing interest based on the Eurodollar Rate is payable at the end
of each interest period, and if an interest period is longer than three months, every three months
during the interest period. Interest on overdue revolving loan amounts accrues at a rate equal to
the Base Rate plus the applicable margin plus 2.00%. Letters of credit issued under the revolving facility accrue fees equal to a specified rate
per annum on the average daily maximum amount available to be drawn under such letters of credit.
Letter of credit fees are payable quarterly in arrears on January 1, April 1, July 1, and October 1
of each year. In addition, a fronting fee on the average daily maximum amount available to be
drawn under such letters of credit will be payable to the issuing bank for each letter of credit. We are required to pay a commitment fee equal to 0.50% per annum times the daily average
undrawn portion of the Revolving Facility (reduced by the amount of letters of credit issued and outstanding under the Revolving Facility) which shall accrue from July 7, 2004 and shall be payable
quarterly in arrears on January 1, April 1, July 1, and October 1 of each year. 33




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The revolving loan does not amortize. The revolving loan is required to be paid in full on
July 7, 2010. We are entitled to voluntarily prepay the revolving loan at any time, in whole or in
part, without premium or penalty. Any portion of the revolving loan that is prepaid may be
reborrowed. Once the term loan has been repaid in full, we must make mandatory prepayments of the
revolving loan on the same basis as described above in the discussion of the term loan. Letter of Credit Facility The Letter of Credit Facility provides for the issuance of up to $40 million of letters of
credit. Letters of credit under the Letter of Credit Facility may be obtained any time beginning on
July 7, 2004 and ending on July 7, 2010. These letters of credit may be used only to provide credit
support for our obligations under the Hedge Agreement and other hedging transactions. Letters of credit issued under the Letter of Credit Facility accrue fees equal to a specified
rate per annum on the average daily maximum amount available to be drawn under such letters of
credit. These letter of credit fees are payable quarterly in arrears on January 1, April 1, July 1,
and October 1 of each year. In addition, a fronting fee on the average daily maximum amount
available to be drawn under such letters of credit will be payable to the issuing bank for each
letter of credit. We are required to pay an annual commitment fee based upon the daily average undrawn portion
of the Letter of Credit Facility (reduced by the amount of letters of credit issued and outstanding
under the Letter of Credit Facility) which shall accrue from July 7, 2004 and shall be payable
quarterly in arrears on January 1, April 1, July 1, and October 1 of each year. Once the term loan and the revolving loan has been repaid in full, we must apply the amounts
that would otherwise be mandatory prepayments to cash collateralize our obligations to the lenders
under the letters of credit. Guarantees and Security Each of our existing and subsequently acquired domestic (and, to the extent no material
adverse tax consequences would result, foreign) subsidiaries (other than Immaterial Subsidiaries)
will guarantee all obligations under the Senior Facilities. The Senior Facilities, each guaranty and any interest rate hedging obligations that we or our
subsidiaries have entered into with a lender or our affiliates are secured by first-priority
security interests in certain of our assets and those of our subsidiaries, subject to permitted
liens. This security includes a first-priority security interest in all of our capital stock and
all capital stock of each of our domestic subsidiaries (other than Immaterial Subsidiaries) and all
intercompany debt. Our obligations under the Hedge Agreement, to the extent not secured by cash or letters of
credit, are secured by second-priority security interests in the assets securing the Senior
Facilities. The Notes are secured by second-priority security interests in the assets securing the
Senior Facilities and the Hedge Agreement. The priority of the security interests and related
creditor rights with respect to the Senior Facilities, the Hedge Agreement, and the Notes are
described in the intercreditor agreement. 34




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Covenants Our Senior Facilities contain customary affirmative and negative covenants for senior
financings of this kind including:  
    a minimum interest coverage covenant;
    a capital expenditures covenant;
    a maximum total first-priority senior leverage ratio covenant;
    a covenant imposing limitations on exploration and drilling capital expenditures (other
than in connection with estimated proved undeveloped reserves);
    a covenant imposing maximum total leverage to PV-10 of our total estimated proved reserves;
    a covenant imposing a limitation on our indebtedness;
    a covenant imposing limitations on liens; and
    a covenant imposing limitations on restricted payments. Events of Default Our Senior Facilities contain customary events of default including:  
    failure to make payments when due;
    defaults under the Hedge Agreement;
    defaults under other agreements or instruments of indebtedness;
    noncompliance with covenants;
    breaches of representations and warranties;
    bankruptcy;
    judgments in excess of a specified amount;
    ERISA defaults;
    impairment of security interests in collateral;
    invalidity of guarantees; and
    change of control. At the time of the Merger all outstanding amounts due under the then existing revolving credit
were repaid. 9 7/8% Senior Subordinated Notes As
of September 30, 2004, all of the $225 million aggregate principal amount of our 9-7/8%
Notes were tendered and all of the principal amount had been paid. From time to time the Company may enter into interest rate swaps to hedge the interest rate
exposure associated with the credit facility, whereby a portion of the Companys floating rate
exposure is exchanged for a fixed interest rate. There were no interest rate swaps in 2004, 2003
or 2002. At December 31, 2004, the aggregate long-term debt maturing in the next five years is as
follows: $1,005,000 (2005); $1,006,000 (2006); $1,007,000 (2007); $1,008,000 (2008) and
$278,071,000 (2009 and thereafter). Derivative Instruments The Hedges On July 7, 2004, we became a party to the Hedges with J. Aron pursuant to the Hedge Agreement.
We have agreed to maintain these Hedges with J. Aron or its successor or permitted assigns. We
anticipate that the Hedges will cover approximately 69% of the expected production through 2013
from our current estimated proved reserves and will range from 65% to 80% of such expected
production in any year. The Hedges primarily take the form of monthly settled fixed price swaps in respect of
the settlement prices for the market standard NYMEX futures contracts on crude oil and natural gas.
Under 35




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##### Table of Contents



such transactions, we pay NYMEX-based floating price per Mmbtu, in the case of Hedges on
natural gas, and we pay a NYMEX-based floating price per Bbl, in the case of Hedges on crude oil,
for each month during the term of the Hedges and receive a fixed price per Mmbtu or Bbl (as the
case may be) according to a monthly schedule of fixed prices that we established upon completion of
the Merger. The transactions will be settled on a net basis. The
notional amounts of the Hedges were designed to provide sufficient hedged cash flow to cover operating expenditures, general and
administrative expenses, interest expenses and the majority of capital expenditures needed to
develop proved reserves. We are required to cause the Hedge Agreement to remain in effect for so long as any portion of
the Senior Facilities or the Notes remains outstanding. The Hedges are documented under a standard
International Swap Dealers Association (ISDA) agreement with customized credit terms, designed to mitigate the liquidity pressures in a high
commodity price environment. The initial collateral requirements and ongoing margin requirements
(based on market movements) are satisfied by letters of credit issued under the Senior Facilities,
with an aggregate capitalization of $55 million. To support any exposure in excess of amounts
supported by the letters of credit, we have granted J. Aron a second lien on the same assets that
secure the Senior Facilities and the Notes and, to the extent our obligations exceed such letters
of credit, such obligations are secured by a second-priority lien on the same assets securing the
Senior Facilities and the Notes and are guaranteed by the same subsidiaries that guarantee the
Senior Facilities and the Notes on a second-priority senior secured basis. We may enter into crude
oil and natural gas hedges with parties other than J. Aron, which hedges may be secured by the
letters of credit issued under the Senior Facilities and by a second-priority lien on the same
assets securing the Senior Facilities and the Notes. To manage our exposure to natural gas or oil price volatility, we may partially hedge our
physical gas or oil sales prices by selling futures contracts on the NYMEX or by selling
NYMEX-based commodity derivative contracts which are placed with major financial institutions that
we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps,
collars or options. In March 2003, we entered into a collar for 4,320 Bbtu of our natural gas production in 2004
with a ceiling price of $5.80 per Mmbtu and a floor price of $4.00 per Mmbtu. We also sold a floor
at $3.00 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting
a maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per Mmbtu; 3) locking
in a price of $4.00 per Mmbtu if prices are between $3.00 and $4.00 per Mmbtu; and 4) receiving a
price of $1.00 per Mmbtu above the price if the price is $3.00 or less. All prices are based on
monthly NYMEX settle. Upon the Merger, these contracts were transferred to J. Aron and
re-established at a ceiling price of $5.75. These contracts were settled during 2004. In April 2003, we entered into a collar for 6,000 Bbtu of our natural gas production in 2005
with a ceiling price of $5.37 per Mmbtu and a floor price of $4.00 per Mmbtu. We also sold a floor
at $3.10 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting
a maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per Mmbtu; 3) locking
in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00 per Mmbtu; and 4) receiving a
price of $0.90 per Mmbtu above the price if the price is $3.10 or less. All prices are based on
monthly NYMEX settle. Upon the Merger, these contracts were transferred to J. Aron and
re-established at a ceiling price of $5.32. 36




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Our financial results and cash flows can be significantly impacted as commodity prices
fluctuate widely in response to changing market conditions. Accordingly, we may modify our fixed
price contract and financial hedging positions by entering into new transactions. The following
tables reflect the natural gas and crude oil volumes and the weighted average prices under
financial hedges (including settled hedges) at February 28, 2005: Natural Gas Swaps
    
    
    Natural Gas Collars
    
    
    Crude Oil SwapsNYMEX Price per
    
    
    
    
    
    
    NYMEX Price perBbtu
    
    
    Mmbtu
    
    
    Bbtu
    
    
    Mmbtu Floor/Cap (1)
    
    
    Estimated Mbbls
    
    
    NYMEX Price per BblQuarter EndingMarch 31, 2005
    
    
    1,500
    
    
    $
    3.81
    
    
    
    1,500
    
    
    $
    4.00 - 5.32
    
    
    
    68
    
    
    $
    34.76June 30, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    68
    
    
    
    34.18September 30, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    67
    
    
    
    33.72December 31, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    67
    
    
    
    33.316,000
    
    
    $
    3.73
    
    
    
    6,000
    
    
    $
    4.00 - 5.32
    
    
    
    270
    
    
    $
    34.00March 31, 2006
    
    
    2,829
    
    
    $
    6.14
    
    
    
    
    
    
    
    
    
    
    
    63
    
    
    $
    32.71June 30, 2006
    
    
    2,829
    
    
    
    5.24
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.35September 30, 2006
    
    
    2,829
    
    
    
    5.22
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.02December 31, 2006
    
    
    2,829
    
    
    
    5.39
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    31.7111,316
    
    
    $
    5.50
    
    
    
    
    
    
    
    
    
    
    
    249
    
    
    $
    32.20Year EndingDecember 31, 2007
    
    
    10,745
    
    
    $
    4.97
    
    
    
    
    
    
    
    
    
    
    
    227
    
    
    $
    30.91December 31, 2008
    
    
    10,126
    
    
    
    4.64
    
    
    
    
    
    
    
    
    
    
    
    208
    
    
    
    29.96December 31, 2009
    
    
    9,529
    
    
    
    4.43
    
    
    
    
    
    
    
    
    
    
    
    191
    
    
    
    29.34December 31, 2010
    
    
    8,938
    
    
    
    4.28
    
    
    
    
    
    
    
    
    
    
    
    175
    
    
    
    28.86December 31, 2011
    
    
    8,231
    
    
    
    4.19
    
    
    
    
    
    
    
    
    
    
    
    157
    
    
    
    28.77December 31, 2012
    
    
    7,005
    
    
    
    4.09
    
    
    
    
    
    
    
    
    
    
    
    138
    
    
    
    28.70December 31, 2013
    
    
    6,528
    
    
    
    4.04
    
    
    
    
    
    
    
    
    
    
    
    127
    
    
    
    28.70
 Mcf  Thousand cubic feet
    
    Mmbtu  Million British thermal units
    
    Bbl  barrelMmcf  Million cubic feet
    
    Bbtu  Billion British thermal units

    
    Mbbls  One thousand barrels
   (1)
 At December 31, 2004, the fair value of futures contracts covering 2005 through 2013 oil
and gas production represented an unrealized loss of $78.4 million. Commodity prices have changed
significantly since December 31, 2004 and, as a result, the fair value of our hedges as of March
23, 2005 was an unrealized loss of approximately $152.4 million. Inflation and Changes in Prices The average price realized for our natural gas decreased from $4.95 per Mcf in 2002 to $4.92
per Mcf in 2003, then increased to $5.08 in 2004. The average price realized for our oil increased
from $22.72 per Bbl in 2002 to $28.06 per Bbl in 2003 and increased to $34.42 per Bbl in 2004.
These prices reflect average prices for oil and gas sales of our continuing operations. The prices
include the effect of our oil and gas hedging activity. 37




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The price of oil and natural gas has a significant impact on our results of operations. Oil
and natural gas prices fluctuate based on market conditions and, accordingly, cannot be predicted.
Costs to drill, complete and service wells can fluctuate based on demand for these services which
is generally influenced by high or low commodity prices. Our costs and expenses may be subject to
inflationary pressures if oil and gas prices are favorable. A large portion of our natural gas is sold subject to market sensitive contracts. Natural gas
price risk is mitigated (hedged) by the utilization of over-the-counter NYMEX swaps, options or
collars. Natural gas price hedging decisions are made in the context of our strategic objectives,
taking into account the changing fundamentals of the natural gas marketplace. Contractual Obligations We have various commitments primarily related to leases for office space, vehicles, natural
gas compressors and computer equipment. We expect to fund these commitments with cash generated
from operations. The following table summarizes our contractual obligations at December 31, 2004. Payments Due by PeriodContractual Obligations atDecember 31, 2004
    
    Total
    
    
    Less than 1 Year
    
    

1 - 3 Years
    
    
    4 - 5 Years



    
    After 5 Years(in thousands)Long term debt
    
    $
    282,097
    
    
    $
    1,005
    
    
    $
    2,013
    
    
    $
    2,016
    
    
    $
    277,063Capital lease obligations
    
    
    200
    
    
    
    94
    
    
    
    104
    
    
    
    2
    
    
    
    Operating leases
    
    
    8,942
    
    
    
    3,453
    
    
    
    5,114
    
    
    
    375
    
    
    
    Total contractual cash obligations
    
    $
    291,239
    
    
    $
    4,552
    
    
    $
    7,231
    
    
    $
    2,393
    
    
    $
    277,063
 In addition to the items above, we have a severance plan and a change of control plan.
See Executive Compensation  Employment and Severance Agreements in Item 11 of this Annual
Report. We have entered into joint operating agreements, area of mutual interest agreements and
joint venture agreements with other companies. These agreements may include drilling commitments
or other obligations in the normal course of business. The following table summarizes our commercial commitments at December 31, 2004. Amount of Commitment Expiration Per PeriodCommercial Commitments at
    
    Total AmountsDecember 31, 2004
    
    Committed
    
    
    Less than 1 Year
    
    
    1 - 3 Years
    
    
    4 - 5 Years
    
    
    Over 5 years(in thousands)Standby Letters of Credit
    
    $
    56,200
    
    
    $
    56,200
    
    
    $
    
    
    
    $
    
    
    
    $
    Total Commercial Commitments
    
    $
    56,200
    
    
    $
    56,200
    
    
    $
    
    
    
    $
    
    
    
    $
    
 In the normal course of business, we have performance obligations which are supported by
surety bonds or letters of credit. These obligations are primarily site restoration and
dismantlement, royalty payments and exploration programs where governmental organizations require
such support. We also have letters of credit with our hedging counterparty. 38




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We have certain other commitments and uncertainties related to our normal operations,
including any obligation to plug wells. Off-Balance Sheet Arrangements We have no off-balance sheet arrangements. RISK FACTORS Our business activities are subject to significant hazards and risks, including those
described below. If any of these events should occur, our business, financial condition, liquidity
or results of operations could be materially adversely affected. Please also refer to the
cautionary note under Forward-Looking Statements on page 1 of this Annual Report. Risks Relating to Our Business Hedging transactions may limit our potential gains or expose us to loss. To manage our exposure to price risks in the marketing of our natural gas, we enter into
natural gas fixed-price physical delivery contracts as well as commodity price swap and collar
contracts from time to time with respect to a portion of our current or future production. In
connection with the Merger, we became a party to a long-term hedging program with J. Aron. We
anticipate the Hedges will cover approximately 69% of the expected production through 2013 from our
current estimated proved reserves. These transactions may limit our potential gains if natural gas
prices were to rise substantially over the prices specified in the Hedge Agreement. In addition,
such transactions may expose us to the risk of financial loss in certain circumstances, including
instances in which:  
    our production is less than expected;
    there is a narrowing of price differentials between delivery points for our
production and the delivery points assumed in the hedge arrangements;
    there is a failure of a hedge counterparty to perform under the Hedge Agreement or
other hedge transactions; or
    a sudden, unexpected event materially impacts natural gas and crude oil prices. Our operations require large amounts of capital that may not be recovered or raised. If our revenues were to decrease due to lower oil and natural gas prices, decreased production
or other reasons, and if we could not obtain capital through our credit facilities or otherwise,
our ability to execute our development plans, replace our reserves or maintain our production
levels could be greatly limited. Our current development plans will require us to make large
capital expenditures for the exploitation and development of our natural gas properties.
Historically, we have funded our capital expenditures through a combination of funds generated
internally from sales of production or properties, the issuance of equity, long-term debt financing
and short-term financing arrangements. We cannot assure you, however, that our business will
generate sufficient cash flow from operations or that future borrowings will be available to us
under our new Senior Facilities in an amount sufficient to enable us to pay our indebtedness,
including the Notes or to fund our other liquidity needs. We may need to refinance all or a
portion of our indebtedness, including the Notes on or before maturity. We cannot assure you that
we will be able to refinance any of our indebtedness, including our new Senior Facilities and the
Notes, 39




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on commercially reasonable terms or at all. Future cash flows and the availability of
financing will be subject to a number of variables, such as:  
    the success of our projects in the Appalachian and Michigan basins;
    our success in locating and producing new reserves;
    the level of production from existing wells; and
    prices of oil and natural gas. In addition, debt financing could lead to a diversion of cash flow to satisfy debt servicing
obligations and to restrictions on our operations. Oil and natural gas prices are volatile, and an extended decline in prices would hurt our
profitability and financial condition. While we will enter into long-term hedges covering most of our production in an effort to
mitigate the risk of a decline in prices for oil and gas, a substantial portion of our production
will remain unhedged. We expect that the markets for oil and gas will continue to be volatile.
Any substantial or extended decline in the price of oil or gas would negatively affect our
financial condition and results of operations. Our revenues, operating results, profitability,
future rate of growth and the carrying value of our oil and gas properties depend heavily on
prevailing market prices for oil and gas. A material decline could reduce our cash flow and
borrowing capacity, as well as the value and the amount of our natural gas reserves. Substantially
all of our proved reserves are natural gas. Therefore, we are more directly impacted by volatility
in the price of natural gas. Various factors beyond our control can affect prices of natural gas.
These factors include: North American supplies of oil and gas; political instability or armed
conflict in oil or gas producing regions; the price and level of foreign imports; worldwide
economic conditions; marketability of production; the level of consumer demand; the price,
availability and acceptance of alternative fuels; the availability of pipeline capacity; weather
conditions; and actions of federal, foreign, state, and local authorities. These external factors and the volatile nature of the energy markets make it difficult to
estimate future commodity prices. If oil and natural gas prices decrease or our drilling efforts are unsuccessful, we may be
required to write down the carrying value of our oil and natural gas properties. There is a risk that we will be required to write down the carrying value of our oil and gas
properties, which would reduce our earnings and stockholders equity. A write down could occur
when oil and gas prices are low or if we have substantial downward adjustments to our estimated
proved reserves, increases in our estimates of development costs or deterioration in our drilling
results. We account for our natural gas and crude oil exploration and development activities using the
successful efforts method of accounting. Under this method, costs of productive exploratory wells,
developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas
lease acquisition costs are also capitalized. Exploration costs, including personnel costs,
certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged
to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to
expense if and when the well is determined not to have found reserves in commercial quantities.
The capitalized costs of our oil and gas properties may not exceed the estimated future net cash
flows from our properties. If capitalized costs exceed future net revenues, we write down the
costs of the properties to our estimate of fair market value. Any such charge will not affect our
cash flow from operating activities, but it will reduce our earnings and stockholders equity. 40




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The application of the successful efforts method of accounting requires managerial judgment to
determine the proper classification of wells designated as developmental or exploratory, which will
ultimately determine the proper accounting treatment of the costs incurred. The results from a
drilling operation can take considerable time to analyze and the determination that commercial
reserves have been discovered requires both judgment and industry experience. Wells may be
completed that are assumed to be productive but may actually deliver oil and gas in quantities
insufficient to be economic, which may result in the abandonment of the wells at a later date.
Wells are drilled that have targeted geologic structures that are both developmental and
exploratory in nature and an allocation of costs is required to properly account for the results.
The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair
value of these costs with reference to drilling activity in a given area. We review our oil and gas properties for impairment whenever events and circumstances indicate
a decline in the recoverability of their carrying value. Once incurred, a write down of oil and
gas properties is not reversible at a later date even if gas or oil prices increase. Given the
complexities associated with oil and gas reserve estimates and the history of price volatility in
the oil and gas markets, events may arise that would require us to record an impairment of the
recorded book values associated with oil and gas properties. Information concerning our reserves and future net revenues is uncertain. This Annual Report and our SEC filings contain estimates of our estimated proved oil and
natural gas reserves and the estimated future net revenues from such reserves. Actual results will
most likely vary from amounts estimated, and any significant variance could have a material adverse
effect on our future results of operations. Reserve estimates are based upon various assumptions, including assumptions required by the
SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. The process of estimating reserves is complex. This process
requires significant decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. Furthermore, different reserve
engineers may make different estimates of reserves and cash flow based on the same available data
and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will
most likely vary from those estimated. Any significant variance could materially affect the
estimated quantities and present value of reserves disclosed by us. In addition, we may adjust
estimates of proved reserves to reflect production history, results of exploration and development,
prevailing oil and natural gas prices and other factors, many of which are beyond our control. At December 31, 2004, approximately 22% of our estimated proved reserves related to continuing
operations were proved undeveloped. Estimation of proved undeveloped reserves and proved developed
non-producing reserves is nearly always based on analogy to existing wells rather than the
performance data used to estimate producing reserves. Recovery of proved undeveloped reserves
requires significant capital expenditures and successful drilling operations. Production revenues
from estimated proved developed non-producing reserves will not be realized until some time in the
future. The reserve data assumes that we will make significant capital expenditures to develop our
reserves. Although we have prepared estimates of our reserves and the costs associated with these
reserves in accordance with industry standards, these estimated costs may not be accurate,
development may not occur as scheduled and actual results may not be as estimated. Analysts and investors should not construe the present value of future net reserves, or PV-10,
as the current market value of the estimated oil and natural gas reserves attributable to our
properties. We have based the estimated discounted future net cash flows from estimated proved
reserves on prices and 41




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costs as of the date of the estimate, in accordance with applicable regulations, whereas
actual future prices and costs may be materially higher or lower. Many factors will affect actual
future net cash flows, including:  
    the amount and timing of actual production;
    supply and demand for natural gas;
    curtailments or increases in consumption by natural gas purchasers; and
    changes in governmental regulations or taxation. The timing of the production of oil and natural gas and of the related expenses affect the
timing of actual future net cash flows from estimated proved reserves and, thus, their actual
present value. In addition, the 10% discount factor, which we are required to use to calculate
PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual
interest rates and risks to which our business or the oil and natural gas industry in general are
subject. Our exploitation and development drilling activities may not be successful. Our future drilling activities may not be successful, and we cannot assure you that our
overall drilling success rate or our drilling success rate for activity within a particular area
will not decline. In addition, the wells that we drill may not recover all or any portion of our
capital investment in the wells, infrastructure, or the underlying leaseholds. Unsuccessful
drilling activities could negatively affect our results of operations and financial condition. The
cost of drilling, completing and operating wells is often uncertain, and a number of factors can
delay or prevent drilling operations, including:  
    unexpected drilling conditions;
    pressure or irregularities in formations;
    equipment failures or accidents;
    ability to hire and train personnel for drilling and completion services;
    adverse weather conditions;
    compliance with governmental requirements; and
    shortages or delays in the availability of drilling rig services and the delivery of
equipment. In addition, we may not be able to obtain any options or lease rights in potential drilling
locations that we identify. There is no guarantee that the potential drilling locations that we
have identified will ever produce oil or natural gas. If our development drilling activities are not successful, we may not be able to replace or
grow our reserves. Our acquisition activities may not be successful. As part of our growth strategy, we may make additional acquisitions of businesses and
properties. However, suitable acquisition candidates may not be available on terms and conditions
we find acceptable, and acquisitions pose substantial risks to our business, financial condition
and results of operations. In pursuing acquisitions, we compete with other companies, many of
which have greater 42




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financial and other resources to acquire attractive companies and properties. Even if future
acquisitions are completed, the following are some of the risks associated with acquisitions:  
    some of the acquired businesses or properties may not produce revenues, earnings or
cash flow at anticipated levels;
    we may assume liabilities that were not disclosed or that exceed our estimates;
    we may be unable to integrate acquired businesses successfully and realize
anticipated economic, operational and other benefits in a timely manner, which could
result in substantial costs and delays or other operational, technical or financial
problems;
    acquisitions could disrupt our ongoing business, distract management, divert
resources and make it difficult to maintain our current business standards, controls
and procedures; and
    we may incur additional debt related to future acquisitions. If our acquisition activities are not successful, our ability to replace or grow our reserves
may be limited. We face strong competition in the oil and natural gas industry, and the resources of many of
our competitors are greater than ours. We operate in a highly competitive industry. We compete with major oil companies, independent
producers and institutional and individual investors, who are actively seeking oil and natural gas
properties throughout the world, along with the equipment, labor and materials required to operate
properties. Many of our competitors have financial and technological resources vastly exceeding
those available to us. Many oil and natural gas properties are sold in a competitive bidding
process in which we may lack technological information or expertise available to other bidders. We
cannot assure you that we will be successful in acquiring and developing profitable properties in
the face of this competition. Our operations are subject to the business and financial risk of oil and natural gas
exploration. The business of exploring for and, to a lesser extent, developing oil and natural gas
properties is an activity that involves a high degree of business and financial risk. Property
acquisition decisions generally are based on various assumptions and subjective judgments that are
speculative. It is impossible to predict accurately the ultimate production potential, if any, of
a particular property or well. Moreover, the successful completion of an oil or natural gas well
does not ensure a profit on investment. A variety of factors, both geological and market-related,
can cause a well to become uneconomic or marginally economic. Our business is subject to operating hazards that could result in substantial losses. The oil and natural gas business involves operating hazards such as well blowouts, craterings,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with
abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other
environmental hazards and risks, any of which could cause us a substantial loss. In addition, we
may be held liable for environmental damage caused by previous owners of property that we own or
lease. As a result, we may face substantial liabilities to third parties or governmental entities,
which could reduce or eliminate funds available for operation, development, production or
acquisitions or cause us to incur losses. An event that is not fully covered by insurance (for
example losses resulting from pollution and environmental risks, which are not fully insurable)
could have a material adverse effect on our financial condition and results of operations. 43




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We must comply with complex federal, state and local laws and regulations. Federal, state, and local authorities extensively regulate the oil and natural gas industry.
Noncompliance with these statutes and regulations may lead to substantial penalties, and the
overall regulatory burden on the industry increases the cost of doing business and, in turn,
decreases profitability. Regulations affect various aspects of oil and natural gas drilling and
production activities, including the pricing and marketing of oil and natural gas production, the
drilling of wells (through permit and bonding requirements), the positioning of wells, the
unitization or pooling of oil and natural gas properties, environmental matters, safety standards,
the sharing of markets, production limitations, plugging and abandonment, and restoration. These
laws and regulations are under constant review for amendment or expansion. We may incur substantial costs to comply with stringent environmental regulations. Our operations are subject to stringent and constantly changing environmental laws and
regulations adopted by federal, state, and local governmental authorities. We could be forced to
expend significant resources to comply with new laws or regulations, or changes to current
requirements. We will continue to be subject to uncertainty associated with new regulatory
interpretations and inconsistent interpretations between governmental environmental agencies. We
could face significant liabilities to the government and third parties for discharges of oil,
natural gas or other pollutants into the air, soil or water, and we could have to spend substantial
amounts on investigations, litigation and remediation, as well as our efforts to prevent future
spills. Moreover, our failure to comply with these laws and regulations may result in the
assessment of administrative, civil and criminal penalties, the imposition of investigatory and
remedial obligations and the issuance of injunctions that restrict or prohibit the performance of
operations. See Items 1 and 2  Business and Properties  Regulation. Our business depends on gathering and transportation facilities owned by others. The marketability of our natural gas production depends in part on the availability, proximity
and capacity of gathering and pipeline systems owned by third parties, and changes in our contracts
with these third parties could materially affect our operations. In addition, federal, state, and local regulation of oil and natural gas production and
transportation, tax and energy policies, changes in supply and demand, pipeline pressures, and
general economic conditions could adversely affect our ability to gather or transport our oil and
natural gas. Items 1 and 2  Business and Properties  Regulation. All of our common stock is owned by one controlling shareholder whose interests may differ
from those of the holders of our Notes. We are a wholly owned subsidiary of Capital C. As a result of this ownership, Capital C is
able to direct the election of our Board of Directors and therefore, direct our management and
policies. Capital C may unilaterally approve mergers and other fundamental corporate changes
involving us, which require shareholder approval. The interests of Capital C as shareholder may
differ from the interests of holders of our Notes. See Item 13  Certain Relationships and
Related Transactions. Our structure may present conflicts of interest. Carlyle/Riverstone controls our sole shareholder, Capital C. David M. Leuschen, Pierre F.
Lapeyre, Jr., Michael B. Hoffman and Gregory A. Beard are Managing Directors at Riverstone Holdings
LLC, which jointly controls the general partner of Carlyle/Riverstone with The Carlyle Group.
Carlyle/Riverstone currently has interests in three other oil and gas exploration and production
companies, Legend Natural Gas, LP, Legend Natural Gas II, LP (collectively, Legend) and Mariner
Energy, Inc., and may acquire interests in additional companies at any time. Messrs. Leuschen,
Lapeyre 44




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and Beard are directors of Legend and Mariner Energy, Inc. or its affiliates. In addition,
Messrs. Becci and Winne are directors, Executive Officers and limited partners of Legend. We can
give no assurance that conflicts of interest will not arise with respect to corporate
opportunities. Also, we can give no assurance that conflicts will not arise with respect to the
time and attention devoted to us by Messrs. Becci and Winne. Risks Relating to the Notes We may incur substantial additional debt, which could negatively impact our financial
condition, results of operations and business prospects and prevent us from fulfilling our
obligations under the Notes. After giving effect to the sale of the Notes and the borrowing under the Senior Facilities and
the application of the net proceeds therefrom and our entry into the Hedge Agreement, we had
approximately $348.6 million in outstanding debt and letters of credit issued. We are permitted to
incur additional debt, including debt that may share in the first-priority liens on the collateral
securing the Senior Facilities, the Hedges, and the Notes, provided we meet certain requirements in
the indenture governing the Notes, the Hedge Agreement and the new Senior Facilities. We will also
be permitted to incur additional debt that is secured by the collateral on an equal and ratable
basis with the Notes if we satisfy a secured leverage ratio test. Our ability to incur additional
debt in the future as either first-priority secured or second-priority secured and, in such event,
to enable the holders thereof to share in the collateral on either a priority basis to or a pari
passu basis with holders of the Notes may have the effect of diluting the value of the collateral
securing the Notes. In addition, our level of debt could have important consequences for our
operations, including:  
    making it more difficult for us to satisfy our obligations under the Notes or
other debt and, if we fail to comply with the requirements of any of our debt,
could result in an event of default;  
    requiring us to dedicate a substantial portion of our cash flow from operations
to required payments on debt, thereby reducing the availability of cash flow for
working capital, capital expenditures and other general business activities;  
    limiting our ability to obtain additional financing in the future for working
capital, capital expenditures and other general corporate activities; 45




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
    limiting our flexibility in planning for, or reacting to, changes in our
business and the industry in which we operate;  
    detracting from our ability to withstand successfully a downturn in our
business or the economy generally; and  
    placing us at a competitive disadvantage relative to other less leveraged
competitors. In addition, all amounts owing under the revolving and letter of credit components of the new
Senior Facilities will become due before any principal payments on the Notes are scheduled to
become due and such amounts may need to be refinanced. Furthermore, to the extent that we are
unable to repay the principal amount of the Notes at maturity out of cash on hand, we will need to
refinance the Notes, or repay the Notes with the proceeds of an equity offering, at or prior to
their maturity. There can be no assurance that we will be able to generate sufficient cash flow to
service our interest payment obligations under our indebtedness or that future borrowings or equity
financing will be available for the payment or refinancing of our indebtedness. To the extent that
we are not successful in negotiating renewals of our borrowings or in arranging new financing, we
may have to sell significant assets, which would have a material adverse effect on our business and
results of operations. Among the factors that will affect our ability to effect an offering of our
capital stock or refinance the Notes are financial market conditions and our value and performance
at the time of such offering or refinancing. There can be no assurance that any such offering or
refinancing can be successfully completed. All of these factors could have a material adverse effect on our business, financial
condition, results of operations, prospects and ability to satisfy our obligations under the Notes. The holders of the Notes may not be able to realize fully the value of the liens securing the
Notes. The Notes are secured by second-priority liens, on a parity basis with the liens securing the
Hedges, on certain of our assets and the assets of our subsidiary guarantors, subject to certain
permitted prior liens. The same assets have also been pledged to secure existing and future
first-priority secured debt. To the extent that any of these assets are released from the liens
securing the Senior Facilities and the Hedges, these assets will also be released from the liens
securing the Notes. The Notes will be effectively subordinated in right of payment to all of our
and our subsidiary guarantors existing and future first-priority secured debt to the extent of the
value of the assets securing that debt. The holders of the first-priority liens will receive all proceeds from the liquidation of the
collateral until all obligations secured by such liens are paid in full. Following payment of the
first-priority liens in full, the holders of the second-priority liens will receive all proceeds
from the liquidation of the collateral until all obligations secured by such liens are paid in
full. The amount to be received from a liquidation of the collateral will depend upon numerous
factors including market and economic conditions, the availability of buyers, the timing and manner
of sale and similar factors. There can be no assurance that the collateral can or will be
liquidated in a short period of time. No independent appraisals of any of the pledged property have
been prepared by or on behalf of us in connection with the issuance of Notes. Accordingly, we
cannot assure you that the proceeds of any sale of the pledged assets following an acceleration of
the maturity of the Notes would be sufficient to satisfy, or would not be substantially less than,
amounts due on the Notes after satisfying our obligations secured by the first-priority and other
second-priority liens. 46




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If the proceeds of any sale of the pledged assets were not sufficient to repay all amounts due
on the Notes, the holders of the Notes (to the extent the Notes were not repaid from the proceeds
of the sale of the pledged assets) would have only an unsecured claim against our remaining assets. The lien ranking and voting provisions set forth in the indenture and the collateral trust
agreement substantially limit the rights of the holders of the Notes with respect to the collateral
securing the Notes. The rights of the holders of the Notes with respect to the collateral securing the Notes are
substantially limited pursuant to the terms of the lien-ranking and voting provisions set forth in
the indenture and the collateral trust agreement. Under those provisions, at any time that
obligations that have the benefit of the first-priority liens are outstanding, any actions that may
be taken in respect of the collateral, including the ability to cause the commencement of
enforcement proceedings against the collateral and to control the conduct of such proceedings, and
the approval of amendments to, releases of collateral from the lien of, and waivers of past
defaults under, the security documents, will be at the direction of the holders of the obligations
secured by the first-priority liens. The trustee, on behalf of the holders of the Notes, does not
have the ability to control or direct such actions, even if the rights of the holders of the Notes
are adversely affected. Our creditors with first-priority liens may have interests that are
different from the interests of the holders of the Notes. Additional releases of collateral from
the second-priority lien securing the Notes may be permitted under some circumstances. The potential environmental liability of secured lenders may affect the value of the
collateral for the Notes. We have mortgaged real property as collateral for the Notes. Real property mortgaged as
security to a lender may be subject to both known and unknown environmental risks. As a holder of a
security interest in real property, under certain circumstances you could be held liable for the
environmental costs of remediating or preventing releases or threatened releases of hazardous
substances at the mortgaged property. Under the Comprehensive Environmental Response, Compensation
and Liability Act of 1980, a lender that participates in the management or operation of a mortgaged
property can be liable as an owner or operator for certain environmental costs. In addition, if the
mortgaged property were subject to material contamination, the value of the property could be
substantially reduced and the lender may choose not to foreclose. Your interest in the collateral may be adversely affected by the failure to perfect security
interests in certain collateral acquired in the future. The security interest in the collateral securing the Notes includes certain of our personal
property and real property and that of our subsidiaries, a pledge of certain stock and other equity
interests, intercompany notes and the proceeds of the foregoing, whether now owned or acquired or
arising in the future. Applicable law requires that certain property and rights acquired after the
grant of a general security interest can be perfected only at the time such property and rights are
acquired and identified. We cannot assure you that the collateral trustee will monitor, or that we
will inform the collateral trustee of, any future acquisition of property and rights that
constitute collateral, and that the necessary action will be taken to properly perfect the security
interest in such after-acquired collateral. Such failure may result in the loss of the security
interest therein or the priority of the security interest in favor of the Notes against third
parties. 47




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Your rights may be adversely affected by bankruptcy proceedings. An investment in the Notes, as in any type of security, involves certain insolvency and
bankruptcy considerations that investors should carefully consider. In the event we, or any of our
subsidiary guarantors, were to become a debtor subject to insolvency proceedings under the United
States Bankruptcy Code (Bankruptcy Code), it is likely delays in payment of the Notes and in
enforcing remedies under the Notes, any guarantee or the liens securing the Notes and the
guarantees would result. Provisions under the Bankruptcy Code or general principles of equity that
could result in the impairment of your rights include, but are not limited to, the automatic stay,
avoidance of preferential transfers by a trustee or debtor-in-possession, substantive
consolidation, limitations on collectibility of unmatured interest or attorney fees and forced
restructuring of the Notes. Under the Bankruptcy Code, a secured creditor such as the trustee or collateral agent is
prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of
security repossessed from such debtor, without bankruptcy court approval. Moreover, bankruptcy law
permits the debtor to continue to retain and to use collateral, and the proceeds, products, rents,
or profits of such collateral, even though the debtor is in default under the applicable debt
instruments, provided that the secured creditor is given adequate protection. The term adequate
protection is not defined under bankruptcy law and, because of the broad discretionary powers of a
bankruptcy court, it is impossible to predict how long payments under the Notes could be delayed
following commencement of a bankruptcy case, whether or when the trustee or collateral agent would
repossess or dispose of the collateral, or whether or to what
extent holders of the Notes would be compensated for any delay in payment or loss of value of
the collateral through the requirements of adequate protection. Furthermore, in the event the
bankruptcy court determines that the value of the collateral is not sufficient to repay all amounts
due on the Notes, the holders of the Notes would have undersecured claims. Federal bankruptcy
laws do not permit the payment or accrual of interest, costs, and attorneys fees for undersecured
claims during the debtors bankruptcy case. Furthermore, the undersecured portion of such claims
are unsecured claims and have a lower priority than secured claims in a bankruptcy and there is a
risk that the principal amount of such claims may not be repaid in full. Under the Bankruptcy Code, a trustee or debtor-in-possession may generally recover payments or
transfers of property of a debtor if such payment or transfer:  
    was to or for the benefit of a creditor;  
    was in payment of an antecedent debt owed before the transfer was made;  
    was made while the debtor was insolvent;  
    was within 90 days (or one year if the payment was to an insider of the debtor)
before the filing of the bankruptcy case; and  
    enabled the creditor to receive more than it would have received in a liquidation under
Chapter 7 of the Bankruptcy Code if the transfer had not been made and the creditor
received payment of the debt as provided in the Bankruptcy Code. By way of example, if payments were made on the Notes prior to the filing of a bankruptcy case
and a court subsequently determined that the value of the collateral pledged by the entity making
the payment was less than the debt owed, such payments could be subject to avoidance as a
preferential transfer. 48




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A financial failure by us could also result in impairment of payment of the Notes if a
bankruptcy court were to substantively consolidate us with our subsidiaries. If a bankruptcy
court substantively consolidated us with our subsidiaries, the assets of each entity would be
subject to the claims of creditors for all entities. Such a consolidation would expose the holders
of the Notes not only to the usual impairments arising from bankruptcy, but also to potential
dilution of the amount ultimately recoverable because of the larger creditor base. Forced restructuring of the Notes could occur through the cram-down provision of the
Bankruptcy Code. Under this provision, the Notes could be restructured over the objections of
holders of the Notes as to their general terms, primarily interest rate and maturity. Additionally,
the Notes could be bifurcated into secured debt and unsecured debt if a bankruptcy court were to
find that the debt owed by us exceeded the value of the collateral. If this were to occur, the
unsecured portion of the debt could be afforded different treatment than the secured portion of the
debt, including, but not limited to, the disallowance of the accrual of post-petition interest on
the Notes. In addition, the indenture provides that, in the event of a bankruptcy, the trustee and the
collateral trustee may not object to a number of important matters following the filing of a
bankruptcy petition so long as any first-priority lien debt is outstanding. After such a filing,
the value of your collateral could materially deteriorate and you would be unable to raise an
objection. The right of the holders of obligations secured by first-priority liens on the
collateral to foreclose upon and sell the collateral upon the occurrence of an event of default
also would be subject to limitations under applicable bankruptcy laws if we or any of our
subsidiaries become subject to a bankruptcy proceeding. Any future pledge of collateral might be avoidable in bankruptcy. Any future pledge of collateral in favor of the collateral trustee, including pursuant to
security documents delivered after the date of the indenture, might be avoidable by the pledgor (as
debtor-in-possession) or by its trustee in bankruptcy if certain events or circumstances exist or
occur, including, among others, if the pledgor is insolvent at the time of the pledge, the pledge
permits the holders of the Notes to receive a greater recovery than if the pledge had not been
given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following
the pledge, or, in certain circumstances, a longer period. We may not be able to repurchase the Notes upon a change of control. Upon the occurrence of certain change of control events, holders of the Notes may require us
to repurchase all or any part of their Notes. We may not have sufficient funds at the time of the
change of control to make the required repurchases of the Notes. Additionally, certain events that
would constitute a change of control (as defined in the indenture governing the Notes) would
constitute an event of default under our Senior Facilities that would, if it should occur, permit
the lenders to accelerate the debt outstanding under our Senior Facilities and that, in turn, would
cause an event of default under the indenture. The source of funds for any repurchase required as a result of any change of control will be
our available cash or cash generated from oil and natural gas operations or other sources,
including borrowings, sales of assets, sales of equity or funds provided by a new controlling
entity. 49




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We cannot assure you, however, that sufficient funds would be available at the time of any
change of control to make any required repurchases of the Notes tendered and to repay debt under
our senior secured credit facilities. Furthermore, using available cash to fund the potential
consequences of a change of control may impair our ability to obtain additional financing in the
future. Any future credit agreements or other agreements relating to debt to which we may become a
party will most likely contain similar restrictions and provisions. If the Notes receive an investment grade rating, many of the covenants in the indenture
governing the Notes will be suspended, thereby reducing some of the protections for holders of our
Notes in the indenture. If at any time the Notes receive investment grade ratings from both Standard & Poors Rating
Services and Moodys Investor Services, Inc., subject to certain additional conditions, many of the
covenants in the indenture governing the Notes applicable to us and to our restricted subsidiaries,
including the limitations on debt and restricted payments, will be suspended. While these covenants
will be reinstated if we fail to maintain investment grade ratings on the Notes or in the event of
a continuing default or event of default thereunder during the suspension period holders of our
Notes will not have the protection of these covenants and we will have greater flexibility to incur
indebtedness and make restricted payments. The terms of our Senior Facilities, as well as the Hedges and the indenture relating to the
Notes, restrict our current and future operations, particularly our ability to respond to industry
or economic changes or to take certain actions. Our Senior Facilities and the Hedge Agreement contain, and any future refinancing of our
Senior Facilities likely would contain, a number of restrictive covenants that impose significant
operating and financial restrictions on us. Our Senior Facilities and, to some extent, the Hedge
Agreement include covenants restricting, among other things, our ability to:  
    incur additional debt;  
    pay dividends and make investments, loans or advances;  
    incur capital expenditures;  
    create liens;  
    use the proceeds from sales of assets and capital stock;  
    enter into sale and leaseback transactions;  
    enter into transactions with affiliates;  
    transfer all or substantially all of our assets; and  
    enter into merger or consolidation transactions. Our Senior Facilities also include financial covenants, including requirements that we
maintain:  
    a minimum interest coverage ratio;  
    a maximum total leverage ratio; and  
    a maximum total first-priority senior leverage ratio to the PV-10 of our
estimated proved reserves. The indenture relating to the Notes also contains covenants including, among other things,
restrictions on our ability to: 50




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
    incur additional indebtedness;  
    pay dividends or make other distributions on stock, redeem stock or redeem
subordinated obligations;  
    make investments;  
    create liens or other encumbrances; and  
    sell or otherwise dispose of all or substantially all of our assets, or merge
or consolidate with another entity. A failure to comply with the covenants contained in our Senior Facilities or the indenture
could result in an event of default (or an event of default under the Hedge Agreement which would
result in an event of default under the Senior Facilities), which could materially and adversely
affect our operating results and our financial condition. In the event of any default under our
Senior Facilities or an event of default under the Hedge Agreement, the lenders under our Senior
Facilities, or the Hedge counterparty, respectively, could elect to declare all borrowings
outstanding or obligations thereunder, together with accrued and unpaid interest and fees, to be
due and payable, and to require us to apply all of our available cash to repay the obligations
owing to such entities, which would be an event of default under the Notes. In addition, our
existing debt and any new debt may impose financial restrictions and other covenants on us that may
be more restrictive than those applicable to the Notes. 51




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Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Among other risks, we are exposed to interest rate and commodity price risks. The interest rate risk relates to existing debt under our revolving credit facility as well as
any new debt financing needed to fund capital requirements. We may manage our interest rate risk
through the use of interest rate swaps to hedge the interest rate exposure associated with the
credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest
rate. A portion of our long-term debt consists of senior secured notes where the interest
component is fixed. We had no derivative financial instruments for managing interest rate risks in
place as of December 31, 2004, 2003 and 2002. If market interest rates for short-term borrowings
increased 1%, the increase in our annual interest expense would be approximately $895,000. This
sensitivity analysis is based on our financial structure at December 31, 2004. The commodity price risk relates to our natural gas and crude oil produced, held in storage
and marketed. Our financial results can be significantly impacted as commodity prices fluctuate
widely in response to changing market forces. From time to time we may enter into a combination of
futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure
to commodity price volatility. The fixed-price physical contracts generally have terms of a year
or more. We employ a policy of hedging gas production sold under NYMEX-based contracts by selling
NYMEX-based commodity derivative contracts which are placed with major financial institutions that
we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps
or options. If NYMEX gas prices decreased $0.50 per Mcf, our gas sales revenues would decrease by
$1.6 million, after considering the effects of the hedging contracts in place at December 31, 2004.
At December 31, 2004 we had hedges on a portion of our oil production from 2005 through 2013. If
the price of crude oil decreased $3.00 per Bbl, oil sales revenue for the year would decrease by
$300,000. We had net pre-tax losses on our hedging activities of $22.3 million in 2004 and $10.3
million in 2003. This sensitivity analysis is based on our 2004 oil and gas sales volumes and
assumes the NYMEX gas price would be above the ceiling in 2005 listed in the table on page 38. 
 Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Index to Consolidated Financial Statements and Schedules on page F-1 sets forth the
financial statements included in this Annual Report on Form 10-K and their location herein.
Schedules have been omitted as not required or not applicable because the information required to
be presented is included in the financial statements and related notes. 
 Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. 52




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Item 9A.CONTROLS AND PROCEDURES Our management, with the participation of our Chief Executive Officer and Chief Financial
Officer, has evaluated the effectiveness of our disclosure controls and procedures as of December
31, 2004. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer
concluded that our disclosure controls and procedures were effective as of December 31, 2004.
There were no changes in our internal control over financial reporting during the fourth quarter of
2004 that materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting. 
 Item 9B.OTHER INFORMATION Not applicable. 
 PART III 
 Item 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Our executive officers and directors and their respective positions and ages of as of March 5,
2005 were as follows: Name
    
    Age
    
    PositionJames A. Winne III
    
    
    53
    
    
    Chairman of the Board of Directors and Chief Executive OfficerMichael Becci
    
    
    48
    
    
    President, Chief Operating Officer and DirectorRobert W. Peshek
    
    
    50
    
    
    Senior Vice President and Chief Financial OfficerDavid M. Becker
    
    
    43
    
    
    Vice President and General Manager, Michigan Exploration
and Production DistrictDuane D. Clark
    
    
    49
    
    
    Vice President Legal Affairs/Gas MarketingPatricia A. Harcourt
    
    
    41
    
    
    Vice President AdministrationFrederick J. Stair
    
    
    45
    
    
    Vice President and Corporate ControllerGregory A. Beard
    
    
    33
    
    
    DirectorMichael B. Hoffman
    
    
    54
    
    
    DirectorPierre F. Lapeyre, Jr.
    
    
    42
    
    
    DirectorDavid M. Leuschen
    
    
    53
    
    
    DirectorMorris B. Sam Smith
    
    
    60
    
    
    Director
 All of our executive officers serve at the pleasure of our Board of Directors. None of our
executive officers is related to any other executive officer or director. The Board of Directors
consists of seven members, each of whom will hold office until our next annual shareholder meeting.
The business experience of each executive officer and director is summarized below. 53




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James A. Winne III.On December 16, 2004, Mr. Winne was appointed Chief Executive Officer and
Chairman of our Board of Directors. Prior to that he served as Senior Vice President since his
appointment on November 1, 2004. Mr. Winne has been a director since November 1, 2004. Mr. Winne
is President, Chief Executive Officer and a member of the Board of Supervisors of Legend Natural
Gas, LP and Legend Natural Gas II, LP, each a privately held oil and gas company located in
Houston, Texas and an affiliate of Carlyle/Riverstone (collectively, Legend). He has over 25
years of experience in the oil and gas industry. Prior to joining Legend in 2001, he served as
President and Chief Executive Officer of North Central Oil Corporation from 1993 to 2001. Mr.
Winne attended the University of Houston and is a Registered Land Professional. He serves on the
Board of Directors of Encore Acquisition Company, an oil and gas company and is currently chairman
of the Compensation Committee and a member of the Nominating and Corporate Governance Committee. Michael Becci.On December 16, 2004, Mr. Becci was appointed President and Chief Operating
Officer. Prior to that he served as Senior Vice President since his appointment on November 1,
2004. Mr. Becci has been a director since November 1, 2004. Mr. Becci is Vice President, Chief
Financial Officer and a member of the Board of Supervisors of Legend. Previously, he served as
Vice President, Chief Financial Officer and Director of North Central Oil Corporation from 1990 to
2001. He is a Certified Public Accountant with over 20 years of experience in the oil and gas
industry. Mr. Becci holds a Bachelor of Science degree in Business Administration from Valparaiso
University. Robert W. Peshek.Mr. Peshek has been our Senior Vice President since December of 2003.
Previously, he served as Vice President of Finance since 1997 and in 1999 was appointed Chief
Financial Officer. Prior to that, he served as Corporate Controller and Tax Manager from 1994 to
1997. Prior to joining our company, Mr. Peshek served as a Senior Manager of the Tax Department at
Ernst & Young LLP from 1981 to 1994. He is a Certified Public Accountant. Mr. Peshek holds a
Bachelor of Business Administration degree from Kent State University where he graduated with
honors. His professional affiliations include the American Institute of Certified Public
Accountants and the Ohio Society of Certified Public Accountants. Mr. Peshek is a member of the
Ohio Oil and Gas Association. David M. Becker.Mr. Becker has been our Vice President since May of 2000. He is also
General Manager of the Michigan Exploration and Production District since 1995. Mr. Becker joined
our company as a result of the acquisition of Ward Lake Energy, Inc., in February of 1995. He
worked for Ward Lake from 1988 to 1995, serving most recently as President and COO. Previously he
served as Facility Engineer for Shell Oil Company in New Orleans, Louisiana from 1984 to 1988. He
has 23 years of experience in the oil and gas industry. Mr. Becker received his Bachelor of
Science degree in Mechanical Engineering from Michigan Technical University. His professional
affiliations include the Michigan Oil and Gas Association and the American Petroleum Institute. Duane D. Clark.Mr. Clark has been our Vice President of Legal Affairs/ Gas Marketing since
April 2001. Previously, he served as Vice President of Gas Marketing. He joined us in 1995 as a
Gas Marketing Analyst. Prior to joining our company, Mr. Clark held various management positions
with Quaker State Corporation from 1978 to 1995. He has 26 years of experience in the oil and gas
industry. Mr. Clark received his Bachelor of Arts degree in Mathematics and Economics from Ohio
Wesleyan University. His professional affiliations include the Ohio Oil and Gas Association. Patricia A. Harcourt.Ms. Harcourt has been our Vice President of Administration since
January 2003. Previously she served as Director of Administration from 2001 to 2003 and Director
of Corporate Communications from 1994 to 2001. She joined us in 1988 as Investor Relations
Coordinator. Prior to joining us, Ms. Harcourt was employed by Austin Powder Company as Employee
Relations Administrator. She received her Bachelor of Arts degree in Communications from Bowling
Green State University. She has 17 years of experience in the oil and gas industry and is a member
of the Ohio Oil 54




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and Gas Association. Ms. Harcourt is also a member of the National Investor Relations
Institute and the Society for Human Resource Management. Frederick J. Stair.Mr. Stair has been our Vice President and Corporate Controller since
January 2003 and 1997, respectively. Prior to that date he served as Controller of the Exploration
and Production Division from 1991 to 1997. Mr. Stair joined us in 1981 and has 24 years of
accounting experience in the oil and gas industry. He graduated from the University of Akron where
he received a Bachelor of Science degree in Accounting. Mr. Stair is a member of the Council of
Petroleum Accountants Societies of Appalachia. Gregory A. Beard.In July 2004, Mr. Beard was elected to our Board of Directors. Mr. Beard
is a Managing Director with Riverstone Holdings, LLC and has been with the firm since 2000. Prior
to joining Riverstone, Mr. Beard was an Associate with Asen and Company, a privately held
investment firm, from 1997 to 2000, and was associated with a Nashville, Tennessee-based investment
firm from 1995 to 1997. Mr. Beard began his career as a Financial Analyst at Goldman Sachs in
1993. Mr. Beard currently serves as a director of Legend,
Capital C Energy, LLC, affiliates of Mariner Energy, Inc. and CDM Resource
Management, Ltd. Michael B. Hoffman.In July 2004, Mr. Hoffman was elected to the Board of Directors. Mr.
Hoffman is a Managing Director of Riverstone Holdings, LLC, and serves on the Managing Committee
responsible for all portfolio activities of Carlyle/Riverstone. Prior to joining Riverstone, Mr.
Hoffman was Senior Managing Director and Head of the Mergers & Acquisitions Advisory Group at The
Blackstone Group. He was also a member of Blackstones Management, Executive and Investment
Committees. Before joining Blackstone in 1989, Mr. Hoffman was the Partner in charge of the Merger
& Acquisitions Department of Smith Barney, Harris Upham & Co. Mr. Hoffman currently serves as a
director of Buckeye Pipe Line Company LLC, the general partner of Buckeye Partners, L.P., Capital C
Energy, LLC, Topaz Power Group, LLC, Microban International and Onconova Therapeutics. In
addition, Mr. Hoffman serves on the Board of Trustees of Lenox Hill Hospital and Manhattan Eye, Ear
and Throat Hospital. Pierre F. Lapeyre, Jr.In July 2004, Mr. Lapeyre was elected to our Board of Directors. Mr.
Lapeyre is a Founder and Managing Director of Riverstone Holdings, LLC and serves on the Managing
Committee responsible for all portfolio activities of Carlyle/Riverstone. Prior to founding
Riverstone in May 2000, Mr. Lapeyre served as a Managing Director of Goldman Sachs in its Global
Energy and Power Group since 1996. Mr. Lapeyre joined Goldman Sachs in 1986 and spent his 14-year
investment banking career focused on the energy and power sectors. Mr. Lapeyre currently serves on
the boards of Legend, Topaz Power Group, LLC, Seabulk International, Inc., CDM Resource Management,
Ltd., Capital C Energy, LLC, Mariner Energy, Inc., SemGroup, LP, Stallion Oilfield Services and
Frontier Holdings, Ltd. David M. Leuschen.In July 2004, Mr. Leuschen was elected to our Board of Directors. Mr.
Leuschen is a Founder and Managing Director of Riverstone Holdings, LLC and serves on the Managing
Committee responsible for all portfolio activities of Carlyle/Riverstone. Prior to founding
Riverstone in May 2000, Mr. Leuschen spent 22 years with Goldman Sachs. He joined the firm in
1977, established their Global Energy and Power Group in 1982, became a Partner in 1986, and
remained a Partner with the firm until leaving to found Riverstone in 2000. Mr. Leuschen currently
serves as a director of Seabulk International Inc., Frontier
Holdings, Ltd., Legend, Buckeye Pipe
Line Company LLC, the general partner of Buckeye Partners, L.P.,
Mariner Energy, Inc., Petroplus International N.V. and Mega
Energy LLC, as well as a number of other private industry-related businesses and nonprofit Boards
of Directors. He is also owner and President of Switchback Ranch LLC, an integrated cattle
ranching operation in the western United States. 55




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Morris B. Sam Smith.In February 2005, Mr. Smith was elected to our Board of Directors.
Mr. Smith was also designated a member and chairman of our Audit Committee. Mr. Smith retired from
Encore Acquisition Company, an independent oil and gas company, in December 2003 where he last held
the positions of Executive Vice President, Chief Financial Officer and Treasurer. Prior to joining
Encore, Mr. Smith worked for Union Pacific Resources, an independent oil and gas company, from 1996
until 2000 where he held the position of Vice President of Finance and Chief Financial Officer. He
received his Bachelor of Business Administration degree from McMurry University where he currently
serves as Chairman of the Board of Trustees. Mr. Smith also serves on the Board of Directors of
Cano Petroleum, Inc. and is the chairman of Canos audit committee. Audit Committee Messrs. Beard, Lapeyre and Smith serve on our Audit Committee. Mr. Smith is an audit
committee financial expert as defined in Item 401(h) of Regulation S-K. Mr. Smith is not
independent as defined by the New York Stock Exchanges listing standards because he was employed
as the Chief Financial Officer of Encore Acquisition Company at the same time Mr. Winne served on
Encore Acquisition Companys compensation committee. Code of Ethics We have adopted a Code of Ethics that applies to our Chief Executive Officer, Chief Financial
Officer, Chief Accounting Officer, Corporate Controller and any person performing similar
functions. It is available without charge upon oral or written request, by contacting: Belden & Blake Corporation
5200 Stoneham Road
North Canton, Ohio 44720
Attention: Duane Clark, Secretary
Telephone: (330) 499-1660 56




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Item 11.EXECUTIVE COMPENSATION The following table shows annual and long-term compensation for services in all capacities
during the fiscal years ended December 31, 2004, 2003 and 2002 of our Chief Executive Officers and
our other four most highly compensated executive officers. Summary Compensation Table Long-TermCompensationAnnual Compensation
    
    
    AwardsNo. of SharesOther Annual
    
    
    Underlying
    
    
    All OtherName and Principal Position
    
    Year
    
    
    Salary
    
    
    Bonus(6)
    
    
    Compensation
    
    
    Options/SARs
    
    
    Compensation(8)James A. Winne III(1)
    
    
    2004
    
    
    $
    44,576
    
    
    $
    59,260
    
    
    $
    
    
    
    
    
    
    
    $
    Chief Executive Officer and
Chairman of the BoardFrost W. Cochran(2)
    
    
    2004
    
    
    
    106,452
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    President and
Chief Executive OfficerJohn L. Schwager(3)
    
    
    2004
    
    
    
    217,052
    
    
    
    1,330,000
    (7)
    
    
    
    
    
    
    
    
    
    
    10,250President and
    
    
    2003
    
    
    
    349,327
    
    
    
    540,000
    (11)
    
    
    
    
    
    
    
    
    
    
    10,000Chief Executive Officer
    
    
    2002
    
    
    
    325,000
    
    
    
    573,750
    
    
    
    
    
    
    
    
    
    
    
    10,500Richard R. Hoffman(4)
    
    
    2004
    
    
    
    212,907
    
    
    
    549,600
    
    
    
    
    
    
    
    
    
    
    
    273,160
    (9)Senior Vice President of
    
    
    2003
    
    
    
    207,111
    
    
    
    52,075
    
    
    
    
    
    
    
    
    
    
    
    5,941Operations
    
    
    2002
    
    
    
    198,000
    
    
    
    39,600
    
    
    
    
    
    
    
    
    
    
    
    5,000Robert W. Peshek
    
    
    2004
    
    
    
    185,891
    
    
    
    549,600
    
    
    
    
    
    
    
    
    
    
    
    10,250Senior Vice President and
    
    
    2003
    
    
    
    178,924
    
    
    
    63,108
    
    
    
    
    
    
    
    
    
    
    
    10,000Chief Financial Officer
    
    
    2002
    
    
    
    168,308
    
    
    
    58,910
    
    
    
    
    
    
    
    
    
    
    
    9,187R. Mark Hackett(5)
    
    
    2004
    
    
    
    167,075
    
    
    
    549,600
    
    
    
    
    
    
    
    
    
    
    
    242,481
    (10)Senior Vice President of
Geoscience and EngineeringDavid M. Becker
    
    
    2004
    
    
    
    166,506
    
    
    
    366,308
    
    
    
    
    
    
    
    
    
    
    
    10,250Vice President of
    
    
    2003
    
    
    
    159,130
    
    
    
    30,741
    
    
    
    
    
    
    
    
    
    
    
    9,133Michigan Operations
    
    
    2002
    
    
    
    154,707
    
    
    
    23,200
    
    
    
    
    
    
    
    
    
    
    
    9,187
   (1)
    
    Paid in the form of reimbursements to Legend. See Item 13  Certain Relationships and
Related Transactions for more information. Mr. Winne became Senior Vice President and was
elected to our Board of Directors on November 1, 2004 and was subsequently appointed Chief
Executive Officer and Chairman of the Board on December 16, 2004.(2)
    
    Paid pursuant to a management services agreement with Capital C Energy Operations L.P.
See Item 13  Certain Relationships and Related Transactions for more information. Mr.
Cochran became Chief Executive Officer on July 7, 2004. He resigned from his position
effective on December 16, 2004.(3)
    
    Mr. Schwager was our Chief Executive Officer until July 7, 2004.(4)
    
    Mr. Hoffman resigned from his position effective February 11, 2005.(5)
    
    Mr. Hackett resigned from his position effective February 11, 2005.(6)
    
    Includes $549,600 paid under our Retention Plan dated February 12, 2004 for Messrs.
Hoffman, Peshek and Hackett and $366,308 paid to Mr. Becker. Performance bonus for 2004 for
Messrs. Becker and Peshek were not calculable. There is no formal executive plan and the
Board has not approved a bonus for 2004.(7)
    
    Represents a special retention bonus of $1,000,000 pursuant to a change in control
provision in Mr. Schwagers employment contract and an annual special retention bonus of
$330,000 paid to Mr. Schwager on June 30, 2004.(8)
    
    Represents contributions of cash and common stock to our 401(k) Profit Sharing Plan for
the account of the named executive officer, unless otherwise indicated.(9)
    
    Includes $266,884 related to a severance agreement entered into in connection with Mr.
Hoffmans resignation effective on February 11, 2005. Under the terms of the agreement we
will also pay Mr. Hoffmans COBRA premiums under our group health plan for the entire
period he is eligible for COBRA continuation coverage.(10)
    
    Includes $215,313 related to a severance agreement entered into in connection with Mr.
Hacketts resignation effective on February 11, 2005 and relocation expenses of $24,568.(11)
    
    This consists of an annual performance bonus of $210,000 and an annual retention bonus
of $330,000 paid to Mr. Schwager on June 30, 2003. For financial statement purposes we
accrued an additional retention bonus of $165,000 for the period July 1, 2003 through
December 31, 2003. 57




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##### Table of Contents



Aggregated Option/SAR Exercises in Last Fiscal Year
and Fiscal Year-End Option/SAR Values Number of Shares
    
    
    Value of UnexercisedShares
    
    
    
    
    
    
    Underlying Unexercised
    
    
    In-the-MoneyAcquired on
    
    
    Value
    
    
    Options/SARs at FY-End
    
    
    Options/SARs at FY-EndName
    
    Exercise
    
    
    Realized
    
    
    Exercisable
    
    
    Unexercisable
    
    
    Exercisable
    
    
    UnexercisableJohn L. Schwager
    
    
    54,353
    
    
    $
    107,596
    
    
    
    
    
    
    
    
    
    
    $
    
    
    
    $
    Richard R. Hoffman
    
    
    82,500
    
    
    
    685,575
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Robert W. Peshek
    
    
    71,250
    
    
    
    701,075
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    David M. Becker
    
    
    25,000
    
    
    
    259,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    R. Mark Hackett
    
    
    50,000
    
    
    
    415,500
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
 We
purchased the shares of our Common Stock underlying these options at the time of the
Merger. As of December 31, 2004, there were no options outstanding and all of the shares of our
Common Stock are owned by Capital C. Compensation of Directors With the exception of Mr. Smith, our outside directors are not compensated for their services.
We pay Mr. Smith $40,000 per year, an annual audit committee chairman fee of $5,000, a Board
meeting fee of $2,000 per meeting and a fee of $1,000 per committee meeting. Employment and Severance Agreements On February 18, 2005, we entered into a severance agreement with Richard R. Hoffman, former
Senior Vice President of Operations. Per the terms of the agreement, Mr. Hoffman received
severance pay in the amount of $266,884 and we will pay Mr. Hoffmans COBRA premiums under our
group health plan if Mr. Hoffman timely elects COBRA continuation coverage thereunder for the
entire period of time he is eligible for COBRA continuation coverage. This was agreed to in return
for a general release of claims against us, except with respect to his vested benefits under our
401(k) plan. On February 11, 2005, we entered into a severance agreement with R. Mark Hackett, former
Senior Vice President of Geoscience and Engineering. Per the terms of the agreement, Mr. Hackett
received severance pay in the amount of $215,313 in return for a general release of claims against
us, except with respect to his vested benefits under our 401(k) plan. On July 1, 2004, we entered into an amended and restated employment agreement with John L.
Schwager, former Chief Executive Officer. On July 7, 2004 Mr. Schwager executed and delivered a
letter pursuant to which he waived all rights under his employment agreement except for certain
specified rights, including the right to a Special Retention Bonus of $1,000,000, which we paid in
July 2004. Compensatory obligations under the agreement which we have not already fulfilled
include paying any additional amounts necessary to cover taxes
imposed by Section 4999 of the
Internal Revenue Code (if any) on the amounts paid by us pursuant to the agreement, and providing
medical benefits at our expense until July 7, 2006. After July 7, 2006, Mr. Schwager and his
spouse may continue to participate in our medical plan until they are of Medicare age to the extent
that they pay an amount equal to the applicable COBRA premiums to us. 58




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In February 2004, we entered into a retention plan effective until December 31, 2006, for
certain executive officers that provided for a retention bonus payable six months after a change of
control event (as defined in the plan). The purpose of the plan was to promote a stable management
team during the period preceding and immediately following a potential change of control event.
Under the plan, Messrs. Becker, Hackett, Hoffman and Peshek each received a retention bonus (as
defined in the plan). As a result of the Merger, the plan was terminated on January 6, 2005 after
retention payments were made to plan participants. Under our 1999 Severance Pay Plan, all employees whose employment is terminated by the Company
without cause (as defined therein) are eligible to receive severance benefits ranging from four
weeks to twenty-four months, depending on their years of service and position with the Company.
Under the Plan, Mr. Winne would be eligible to receive severance pay of four weeks. We have a 1999 Change in Control Protection Plan for Key Employees providing severance
benefits for such employees if, within two years following a change in control, in general, their
employment is terminated by us without cause (as defined therein) or if they resign in response
to a substantial reduction in duties, responsibilities, position, a reduction in compensation or a
material reduction in medical benefits or a change of more than 40 miles in the location of their
place of work as defined in the agreement. Such benefits range from twelve months to twenty-four
months, depending on their position with the Company. As a result of the Merger with Capital C,
Messrs. Becker and Peshek would be eligible to receive severance pay of 24 months under the Plan if
a qualifying termination occurs before July 7, 2006. Compensation Committee Interlocks and Insider Participation Prior to the Merger with Capital C, the Compensation and Organization Committee consisted of
two outside directors, William S. Price, III and Gareth Roberts. Prior to the Merger with Capital
C, none of our executive officers were a director or member of a compensation committee of any
entity of which a member of our Board of Directors was an executive officer. After the Merger with Capital C, we do not have a compensation committee. During 2004, the
following officers and employees (current and former) of the Company participated in our Boards
deliberations concerning executive officer compensation: Messrs. Schwager, Cochran, Winne and
Becci. Mr. Winne served as chairman of the compensation committee of Encore Acquisition Company where
Mr. Smith last held the positions of Executive Vice President, Chief Financial Officer and
Treasurer in December 2003. Mr. Winne is a member of the Board of Supervisors of Legend where Mr. Becci serves as Vice President and Chief Financial Officer. Mr. Becci
is a member of the Board of Supervisors of Legend where Mr. Winne serves as President and Chief
Executive Officer. See Item 13  Certain Relationships and Related Transactions for information regarding
our reimbursements to Legend of expenses incurred on our behalf. 59




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Item 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS The following table sets forth certain information as of February 28, 2005 regarding the
beneficial ownership of our common stock by each person who beneficially owns more than five
percent of our outstanding common stock, each director, the Chief Executive Officer and the four
other most highly compensated executive officers and by all of our directors and executive
officers, as a group: Percentage ofFive Percent Shareholders
    
    Number of Shares
    
    
    SharesCapital C Energy Operations, LP(1)
333 Clay Street, Suite 4960
Houston, Texas 77002
    
    
    1,500
    
    
    
    100.0
    %
   (1)
    
    Carlyle/Riverstone Global Energy and Power Fund II, L.P. controls Capital C Energy
Operations, L.P. and is therefore also deemed to be a beneficial owner of the 1,500 shares
(100%) of our Common Stock. The address of Carlyle/Riverstone is c/o The Carlyle Group,
1001 Pennsylvania Avenue, N.W., Suite 220 South, Washington, D.C.
20004. Equity Compensation Plan Information: As of February 28, 2005, we do not have an equity compensation plan. 60




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Item 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Carlyle
Riverstone controls and has a majority interest in Capital C, our sole
shareholder. Capital C received a fee from us of approximately $1.4 million in connection with the Merger.
We also reimbursed Capital C $61,323 for costs they incurred related to the Merger. We paid
Carlyle/Riverstone $492,277 for costs they incurred on our behalf, of which $471,790 was third
party legal fees related to the Merger. We were a party to a management services agreement with Capital C,
pursuant to which Frost W. Cochran, W. Mac Jensen and B. Dee Davis provided certain management and
advisory services to us for a quarterly fee of $250,000 plus reimbursement of expenses. These
services included general management supervision and oversight, in the capacity as officers of
Belden & Blake; financial advisory services; evaluation of potential acquisitions and other
business opportunities; and strategic consulting services. This agreement was terminated effective
December 20, 2004. The total amount paid pursuant to this agreement was approximately $526,136. David M. Leuschen, Pierre F.
Lapeyre, Jr., Michael B. Hoffman and Gregory A. Beard are Managing Directors at Riverstone Holdings
LLC, which jointly controls the general partner of Carlyle/Riverstone with The Carlyle Group.
Carlyle/Riverstone currently has interests in Legend and Mariner
Energy, Inc., which are also oil and gas exploration and production
companies, and may acquire
interests in additional companies at any time. Messrs. Leuschen, Lapeyre and Beard are directors
of Legend and Mariner Energy, Inc. or its affiliates. In addition, Messrs. Becci and Winne are
directors, Executive Officers and limited partners of Legend. Although the current operations of
Legend and Mariner are in different geographic regions than those of the Company, we can give no
assurance that conflicts of interest will not arise with respect to corporate opportunities. Also,
we can give no assurance that conflicts will not arise with respect to the time and attention
devoted to us by Messrs. Becci and Winne. Since November 1, 2004 we have reimbursed Legend for expenses incurred in connection with
services provided on our behalf. As of March 22, 2005, we have
paid to Legend a total of $246,212.
This consists of:  
    salary and bonus of $103,835 for James A. Winne III and reimbursement of Mr. Winnes
expenses related to Company activities of $11,067,
    salary and bonus of $104,131 for Michael Becci and reimbursement of Mr. Beccis expenses
related to Company activities of $16,526, and
    reimbursement of other Legend expenses related to Company activities of $10,653. Starting January 1, 2005, we have paid Messrs. Winne and Becci directly, as employees of the
Company, rather than reimbursing Legend. We will continue to reimburse Legend for any additional
expenses incurred on our behalf. 61




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Item 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES Ernst & Young served as our independent auditor for the year ended December 31, 2004.
Aggregate fees for professional services provided to us by Ernst & Young for the years ended
December 31, 2004 and 2003 were as follows: December 31,2004
    
    
    2003Audit fees
    
    $
    637,000
    
    
    $
    187,000Audit-related fees
    
    
    
    
    
    
    Tax fees
    
    
    110,000
    
    
    
    41,120All other fees
    
    
    2,663
    
    
    
    1,600$
    749,663
    
    
    $
    229,720
 Fees for audit services include fees associated with the annual audit, the review of our
Annual Report on Form 10-K and the reviews of our Quarterly Reports on Form 10-Q. In 2004, audit
services also included the audit of WLD, audit services in connection with the consent solicitation
of our 9-7/8% Notes and audit services in connection with the preparation of our Registration
Statement on Form S-4 related to our Notes and refinancing in connection with the Merger. Tax fees
included tax compliance and tax planning. All other fees include research materials. Audit Committee Pre-Approval Policies and Procedures The Audit Committee has adopted a policy that requires advance approval of all audit,
audit-related, and other services performed by the independent auditor or other public accounting
firms. The policy provides for pre-approval by the Audit Committee of specifically defined audit
and non-audit services. Unless the specific service has been previously pre-approved with respect
to that year, the Audit Committee must approve the permitted service before the independent auditor
or public accounting firm is engaged to perform it. The Audit Committee has delegated to the
Chairman of the Audit Committee authority to approve permitted services up to $75,000 per year
provided that the Chairman reports any decisions to the Committee at its next scheduled meeting.
All services of $75,000 or more are required to be approved by a majority of the Committee members. 
 PART IV 
 Item 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a) Documents filed as a part of this report: 1. Financial Statements The financial statements listed in the accompanying Index to Consolidated Financial Statements
and Schedules are filed as part of this Annual Report on Form 10-K. 2. Financial Statement Schedules No financial statement schedules are required to be filed as part of this Annual Report on
Form 10-K. 62




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##### Table of Contents



3. Exhibits No.
    
    Description2.1
    
    Agreement and Plan of Merger, dated as of June 15, 2004, by and among Capital C Energy
Operations, LP, Capital C Ohio, Inc. and Belden & Blake Corporation, incorporated by reference
to Exhibit 2.1 to Belden & Blake Corporations Form 8-K dated July 7, 2004 (as amended).3.1
    
    Amended and Restated Articles of Incorporation of Belden & Blake Corporation (fka Belden &
Blake Energy Corporation), incorporated by reference to Exhibit 3.1 to Belden & Blake
Corporations Form 8-K dated November 29, 2004.3.2
    
    Amended and Restated Code of Regulations of Belden & Blake Corporation, incorporated by
reference to Exhibit 3.2 to the Companys Registration Statement on Form S-4 (Registration No.
333-119194).4.1
    
    Indenture, dated as of July 7, 2004, by and among Belden & Blake Corporation, The Canton Oil
& Gas Company, Ward Lake Drilling, Inc. and BNY Midwest Trust Company, incorporated by
reference to Exhibit 4.2 to Belden & Blake Corporations Form 8-K dated July 7, 2004 (as
amended).10.1
    
    ISDA Master Agreement, dated as of June 30, 2004, between Capital C Ohio, Inc. and J. Aron &
Company, incorporated by reference to Exhibit 10.1 to Belden & Blake Corporations Form 8-K
dated July 7, 2004 (as amended).10.2
    
    Credit and Guaranty Agreement, dated as of July 7, 2004, among Belden & Blake Corporation,
The Canton Oil & Gas Company and Ward Lake Drilling, Inc., as Guarantors, various Lenders, and
Goldman Sachs Credit Partners L.P., as Sole Lead Arranger, Sole Bookrunner, Syndication Agent
and Administrative Agent, incorporated by reference to Exhibit 10.2 to Belden & Blake
Corporations Form 8-K dated July 7, 2004 (as amended).10.3
    
    Priority Lien Pledge and Security Agreement, dated as of July 7, 2004, between Belden & Blake
Corporation, The Canton Oil & Gas Company, Ward Lake Drilling, Inc. and Wells Fargo Bank,
N.A., as Collateral Trustee, incorporated by reference to Exhibit 10.3 to Belden & Blake
Corporations Form 8-K dated July 7, 2004 (as amended).10.4
    
    Parity Lien Pledge and Security Agreement, dated as of July 7, 2004, between Belden & Blake
Corporation, The Canton Oil & Gas Company, Ward Lake Drilling, Inc. and Wells Fargo Bank,
N.A., as Collateral Trustee, incorporated by reference to Exhibit 10.4 to Belden & Blake
Corporations Form 8-K dated July 7, 2004 (as amended).10.5
    
    Priority Lien Pledge Agreement, dated as of July 7, 2004, between Capital C Energy
Operations, LP and Wells Fargo Bank, N.A., as Collateral Trustee, incorporated by reference to
Exhibit 10.5 to Belden & Blake Corporations Form 8-K dated July 7, 2004 (as amended).10.6
    
    Parity Lien Pledge Agreement, dated as of July 7, 2004, between Capital C Energy Operations,
LP and Wells Fargo Bank, N.A., as Collateral Trustee, incorporated by
 63




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##### Table of Contents



No.
    
    Descriptionreference to Exhibit 10.6 to Belden & Blake Corporations Form 8-K dated July 7,
2004 (as amended).10.7
    
    Collateral Trust Agreement, dated as of July 7, 2004, among Belden & Blake Corporation, the
other Pledgors party from time to time thereto, Goldman Sachs Credit Partners L.P., as
Administrative Agent under the Credit Agreement, J. Aron & Company, as Hedge Counterparty
under the Hedge Agreement, BNY Midwest Trust Company, as Trustee under the Indenture, and
Wells Fargo Bank, N.A., as Collateral Trustee, incorporated by reference to Exhibit 10.7 to
Belden & Blake Corporations Form 8-K dated July 7, 2004 (as amended).10.8
    
    ISDA Master Agreement Waiver Letter, incorporated by reference to exhibit 10.1 to Belden &
Blake Corporations Form 8-K dated February 25, 2005.10.9
    
    Termination and Release Agreement, dated as of July 7, 2004, by and among Belden & Blake
Corporation, The Canton Oil & Gas Company, Ward Lake Drilling, Inc., Ableco Finance LLC and
Wells Fargo Foothill, Inc., incorporated by reference to Exhibit 10.10 to Belden & Blake
Corporations Form 8-K dated July 7, 2004 (as amended).10.10
    
    Belden & Blake Corporation Retention Plan, incorporated by reference to Exhibit 10.1 to
Belden & Blake Corporations Quarterly Report on Form 10-Q for the quarter ended March 31,
2004.10.11
    
    Change in Control Severance Pay Plan for Key Employees of Belden & Blake Corporation dated
August 12, 1999, incorporated by reference to Exhibit 10.7 to Belden & Blake Corporations
Annual Report on Form 10-K for the year ended December 31, 1999.10.12
    
    Amendment No. 1 of Belden & Blake Corporation 1999 Change in Control Protection Plan Key
Employees dated as of February 26, 2002, incorporated by reference to Exhibit 10.7 (a) to
Belden & Blake Corporations Annual Report on Form 10-K for the year ended December 31, 2002.10.13
    
    Amendment No. 2 of the Belden & Blake Corporation 1999 Change in Control Protection Plan for
Key Employees dated as of October 23, 2002, incorporated by reference to Exhibit 10.7(b) to
the Belden & Blake Corporations Annual Report on Form 10-K for the year ended December 31,
2002.10.14
    
    Severance Pay Plan for Employees of Belden & Blake Corporation dated August 12, 1999,
incorporated by reference to Exhibit 10.8 to Belden & Blake Corporations Annual Report on
Form 10-K for the year ended December 31, 1999.10.15
    
    Amendment 1 to the Belden & Blake Corporation 1999 Severance Pay Plan dated as of May 29,
2000, incorporated by reference to Exhibit 10.8 (a) to Belden & Blake Corporations Annual
Report on Form 10-K for the year ended December 31, 2002.10.16
    
    Amendment 2 to the Belden & Blake Corporation 1999 Severance Pay Plan dated as of September
12, 2002, incorporated by reference to Exhibit 10.8 (b) to the Belden & Blake Corporations
Annual Report on Form 10-K for the year ended December 31, 2002.
 64




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##### Table of Contents



No.
    
    Description10.17
    
    Severance Release Agreement dated February 11, 2005 by and between Belden & Blake
Corporation and R. Mark Hackett, incorporated by reference to Exhibit 10.1 to Belden & Blake
Corporations Form 8-K dated February 11, 2005.10.18
    
    Severance Release Agreement dated February 18, 2005 by and between Belden & Blake
Corporation and Richard R. Hoffman, incorporated by reference to Exhibit 10.1 to Belden &
Blake Corporations Form 8-K dated February 18, 2005.10.19*
    
    Directors Fees for Outside Directors effective February 14, 200510.20*
    
    Amended and restated employment agreement dated July 1, 2004 by and between Belden & Blake
Corporation and John L. Schwager.10.21*
    
    Waiver of certain rights to payments or benefits by and between Belden & Blake Corporation
and John L. Schwager.14.1
    
    Code of Ethics for Senior Financial Officers, incorporated by reference to Exhibit 14.1 to
Belden & Blake Corporations Annual Report on Form 10-K for the year ended December 31, 2003.23*
    
    Consent of Independent Registered Public Accounting Firm31.1*
    
    Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.31.2*
    
    Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.32.1*
    
    Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.32.2*
    
    Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
   *
    
    Filed herewith (c) Exhibits required by Item 601 of Regulation S-K Exhibits required to be filed by the Company pursuant to Item 601 of Regulation S-K are
contained in the Exhibits listed under Item 15(a)3. (d) Financial Statement Schedules required by Regulation S-X The items listed in the accompanying index to financial statements are filed as part of this
Annual Report on Form 10-K. 65




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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. BELDEN & BLAKE CORPORATIONMarch 30, 2005
    
    By:
    
    /s/ James A. Winne IIIDate
    
    James A. Winne III, Chief Executive Officer, Chairmanof the Board of Directors and Director
 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/ James A. Winne III
    
    Chief Executive Officer,
    
    March 30, 2005James A. Winne III
    
    Chairman of the Board of Directors
and Director
(Principal Executive Officer)
    
    Date/s/ Michael Becci
    
    President, Chief Operating
    
    March 30, 2005Michael Becci
    
    Officer and Director
    
    Date/s/ Robert W. Peshek
    
    Senior Vice President and
    
    March 30, 2005Robert W. Peshek
    
    Chief Financial Officer
(Principal Financial and
Accounting Officer)
    
    Date/s/ Gregory A. Beard
    
    Director
    
    March 30, 2005Gregory A. Beard
    
    
    
    Date/s/ Michael B. Hoffman
    
    Director
    
    March 30, 2005Michael B. Hoffman
    
    
    
    Date/s/ Pierre F. Lapeyre, Jr.
    
    Director
    
    March 30, 2005Pierre F. Lapeyre, Jr.
    
    
    
    Date/s/ David M. Leuschen
    
    Director
    
    March 30, 2005David M. Leuschen
    
    
    
    Date/s/ Morris B. Smith
    
    Director
    
    March 30, 2005Morris
B. Sam Smith
    
    
    
    Date
 66




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BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES Item 15(a) (1) and (2) CONSOLIDATED FINANCIAL STATEMENTS
    
    PageReport of Independent Registered Public Accounting Firm
    
    F-2Consolidated Balance Sheets as of December 31, 2004 (Successor Company)
and December 31, 2003 (Predecessor Company)
    
    F-3Consolidated Statements of Operations:183 day
period from July 2, 2004 to December 31, 2004 (Successor
Company)183 day period from January 1, 2004 to July 1, 2004 (Predecessor Company)
Years ended December 31, 2003 and 2002 (Predecessor Company)Years ended December 31, 2003 and 2002 (Predecessor Company)
    
    F-4Consolidated Statements of Shareholders Equity (Deficit):183 day period from July 2, 2004 to December 31, 2004 (Successor Company)183 day period from January 1, 2004 to July 1, 2004 (Predecessor Company)Years ended December 31, 2003 and 2002 (Predecessor Company)
    
    F-5Consolidated Statements of Cash Flows:183 day period from July 2, 2004 to December 31, 2004 (Successor Company)183 day period from January 1, 2004 to July 1, 2004 (Predecessor Company)Years ended December 31, 2003 and 2002 (Predecessor Company)
    
    F-6Notes to Consolidated Financial Statements
    
    F-7
 All financial statement schedules have been omitted since the required information is not present
in amounts sufficient to require submission of the schedule or because the information required is
included in the financial statements. F- 1




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##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholder and Board of Directors
Belden & Blake Corporation We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation
(Company) as of December 31, 2004 and 2003, and the related consolidated statements of
operations, shareholders equity (deficit), and cash flows for the one hundred eighty-three day
period ended December 31, 2004, the one hundred eighty-three day period ended July 1, 2004, and
each of the two years in the period ended December 31, 2003. These financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. We
were not engaged to perform an audit of the Companys internal control over financial reporting.
Our audit included consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Companys internal control over financial
reporting. Accordingly we express no such opinion. An audit also includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Belden & Blake Corporation at December
31, 2004 and 2003, and the consolidated results of their operations and their cash flows for the
one hundred eighty-three day period ended December 31, 2004, the one hundred eighty-three day
period ended July 1, 2004, and each of the two years in the period ended December 31, 2003, in
conformity with U.S. generally accepted accounting principles. As explained in Note 1 to the consolidated financial statements, in 2003 the Company adopted
Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. /s/ ERNST & YOUNG LLP Cleveland, Ohio
March 29, 2005 F- 2




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##### Table of Contents



BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data) Successor
    
    
    
    PredecessorDecember 31,2004
    
    
    
    2003ASSETSCurrent assetsCash and cash equivalents
    
    $
    18,407
    
    
    
    $
    1,428Accounts receivable, net
    
    
    18,667
    
    
    
    
    14,270Inventories
    
    
    518
    
    
    
    
    780Deferred income taxes
    
    
    10,558
    
    
    
    
    6,853Other current assets
    
    
    1,101
    
    
    
    
    2,353Fair value of derivatives
    
    
    
    
    
    
    
    319Assets of discontinued operations
    
    
    
    
    
    
    
    22,230Total current assets
    
    
    49,251
    
    
    
    
    48,233Property and equipment, at costOil and gas properties (successful efforts method)
    
    
    514,242
    
    
    
    
    452,167Gas gathering systems
    
    
    4,485
    
    
    
    
    15,264Land, buildings, machinery and equipment
    
    
    7,720
    
    
    
    
    13,173526,447
    
    
    
    
    480,604Less accumulated depreciation, depletion and amortization
    
    
    16,917
    
    
    
    
    250,162Property and equipment, net
    
    
    509,530
    
    
    
    
    230,442Fair value of derivatives
    
    
    
    
    
    
    
    755Other assets
    
    
    11,461
    
    
    
    
    5,881$
    570,242
    
    
    
    $
    285,311LIABILITIES AND SHAREHOLDERS EQUITY (DEFICIT)Current liabilitiesAccounts payable
    
    $
    3,796
    
    
    
    $
    4,873Accrued expenses
    
    
    23,445
    
    
    
    
    12,726Current portion of long-term liabilities
    
    
    1,964
    
    
    
    
    729Fair value of derivatives
    
    
    23,252
    
    
    
    
    14,765Liabilities of discontinued operations
    
    
    
    
    
    
    
    3,811Total current liabilities
    
    
    52,457
    
    
    
    
    36,904Long-term liabilitiesBank and other long-term debt
    
    
    88,592
    
    
    
    
    47,503Senior subordinated notes
    
    
    
    
    
    
    
    225,000Senior secured notes
    
    
    192,500
    
    
    
    
    Asset retirement obligations and other long-term liabilities
    
    
    14,390
    
    
    
    
    4,108295,482
    
    
    
    
    276,611Fair value of derivatives
    
    
    55,182
    
    
    
    
    9,723Deferred income taxes
    
    
    108,994
    
    
    
    
    19,413Shareholders equity (deficit)Common stock: Successor without par value; 1,500 shares authorized and issued
Predecessor $.10 stated value per share; authorized 58,000,000 shares;
issued 10,610,450 shares (which includes 214,593 treasury shares)
    
    
    
    
    
    
    
    1,040Paid in capital
    
    
    77,500
    
    
    
    
    107,633Retained earnings (deficit)
    
    
    890
    
    
    
    
    (150,656
    )Accumulated other comprehensive loss
    
    
    (20,263
    )
    
    
    
    (15,357
    )Total
shareholders equity (deficit)
    
    
    58,127
    
    
    
    
    (57,340
    )$
    570,242
    
    
    
    $
    285,311
 See accompanying notes. F- 3




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##### Table of Contents



BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands) Successor Company
    
    
    
    Predecessor CompanyFor the 183 Day Period
    
    
    
    For the 183 Day Periodfrom July 2, 2004 to
    
    
    
    from January 1, 2004 toDecember 31, 2004
    
    
    
    July 1, 2004
    
    
    Year ended December 31, 2003
    
    
    Year ended December 31, 2002RevenuesOil and gas sales
    
    $
    45,341
    
    
    
    $
    45,307
    
    
    $
    84,610
    
    
    $
    90,462Gas gathering and marketing
    
    
    4,923
    
    
    
    
    5,057
    
    
    
    10,538
    
    
    
    13,526Other
    
    
    696
    
    
    
    
    458
    
    
    
    266
    
    
    
    1,55750,960
    
    
    
    
    50,822
    
    
    
    95,414
    
    
    
    105,545ExpensesProduction expense
    
    
    11,634
    
    
    
    
    10,951
    
    
    
    20,017
    
    
    
    20,247Production taxes
    
    
    1,467
    
    
    
    
    1,300
    
    
    
    2,449
    
    
    
    1,789Gas gathering and marketing
    
    
    4,522
    
    
    
    
    4,533
    
    
    
    9,570
    
    
    
    11,000Exploration expense
    
    
    2,750
    
    
    
    
    2,717
    
    
    
    6,849
    
    
    
    8,834General and administrative expense
    
    
    2,651
    
    
    
    
    2,500
    
    
    
    4,559
    
    
    
    4,557Franchise, property and other taxes
    
    
    52
    
    
    
    
    115
    
    
    
    202
    
    
    
    11Depreciation, depletion and amortization
    
    
    17,527
    
    
    
    
    9,089
    
    
    
    18,098
    
    
    
    21,339Impairment of oil and gas properties
    
    
    
    
    
    
    
    
    
    
    
    896
    
    
    
    Accretion expense
    
    
    633
    
    
    
    
    195
    
    
    
    343
    
    
    
    Derivative fair value (gain) loss
    
    
    (829
    )
    
    
    
    2,038
    
    
    
    (319
    )
    
    
    Severance and other nonrecurring expense
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    923Transaction expense
    
    
    
    
    
    
    
    26,001
    
    
    
    
    
    
    
    40,407
    
    
    
    
    59,439
    
    
    
    62,664
    
    
    
    68,700Operating income (loss)
    
    
    10,553
    
    
    
    
    (8,617
    )
    
    
    32,750
    
    
    
    36,845Other expenseLoss on sale of businesses
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    154Interest expense
    
    
    11,877
    
    
    
    
    12,184
    
    
    
    23,580
    
    
    
    22,50611,877
    
    
    
    
    12,184
    
    
    
    23,580
    
    
    
    22,660(Loss) income from continuing operations before income taxes
and cumulative effect of change in accounting principle
    
    
    (1,324
    )
    
    
    
    (20,801
    )
    
    
    9,170
    
    
    
    14,185(Benefit) provision for income taxes
    
    
    (2,214
    )
    
    
    
    (3,767
    )
    
    
    3,210
    
    
    
    5,250Income (loss) from continuing operations before cumulative
effect of change in accounting principle
    
    
    890
    
    
    
    
    (17,034
    )
    
    
    5,960
    
    
    
    8,935Income (loss) from discontinued operations, net of tax
    
    
    
    
    
    
    
    28,868
    
    
    
    (10,681
    )
    
    
    (6,470
    )Income (loss) before cumulative effect of change in
accounting principle
    
    
    890
    
    
    
    
    11,834
    
    
    
    (4,721
    )
    
    
    2,465Cumulative effect of change in accounting principle,
net of tax
    
    
    
    
    
    
    
    
    
    
    
    2,397
    
    
    
    Net income (loss)
    
    $
    890
    
    
    
    $
    11,834
    
    
    $
    (2,324
    )
    
    $
    2,465
 See accompanying notes. F- 4




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##### Table of Contents



BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY (DEFICIT)
(in thousands) AccumulatedSuccessor Company
    
    
    Predecessor Company
    
    
    
    
    
    
    
    
    
    
    Other
    
    
    TotalCommon
    
    
    Common
    
    
    Common
    
    
    Common
    
    
    Paid in
    
    
    Equity
    
    
    Comprehensive
    
    
    EquityShares
    
    
    Stock
    
    
    Shares
    
    
    Stock
    
    
    Capital
    
    

(Deficit)
    
    
    Income
    
    
    (Deficit)Predecessor Company:January 1, 2002
    
    
    
    
    
    
    
    
    
    
    10,290
    
    
    $
    1,029
    
    
    $
    107,402
    
    
    $
    (150,797
    )
    
    $
    15,087
    
    
    $
    (27,279
    )Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,465
    
    
    
    
    
    
    
    2,465Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (5,518
    )
    
    
    (5,518
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (14,030
    )
    
    
    (14,030
    )Total comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (17,083
    )Stock options exercised
    
    
    
    
    
    
    
    
    
    
    65
    
    
    
    7
    
    
    
    (2
    )
    
    
    
    
    
    
    
    
    
    
    5Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    82
    
    
    
    
    
    
    
    
    
    
    
    82Repurchase of stock options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (29
    )
    
    
    
    
    
    
    
    
    
    
    (29
    )Tax benefit of repurchase of stock options
and stock options exercised
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    57
    
    
    
    
    
    
    
    
    
    
    
    57Treasury stock
    
    
    
    
    
    
    
    
    
    
    (59
    )
    
    
    (6
    )
    
    
    (392
    )
    
    
    
    
    
    
    
    
    
    
    (398
    )December 31, 2002
    
    
    
    
    
    
    
    
    
    
    10,296
    
    
    
    1,030
    
    
    
    107,118
    
    
    
    (148,332
    )
    
    
    (4,461
    )
    
    
    (44,645
    )Comprehensive (loss) income:Net loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,324
    )
    
    
    
    
    
    
    (2,324
    )Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (17,439
    )
    
    
    (17,439
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,543
    
    
    
    6,543Total comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (13,220
    )Stock options exercised
    
    
    
    
    
    
    
    
    
    
    120
    
    
    
    12
    
    
    
    108
    
    
    
    
    
    
    
    
    
    
    
    120Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    326
    
    
    
    
    
    
    
    
    
    
    
    326Repurchase of stock options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (48
    )
    
    
    
    
    
    
    
    
    
    
    (48
    )Tax benefit of repurchase of stock options
and stock options exercised
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    170
    
    
    
    
    
    
    
    
    
    
    
    170Treasury stock
    
    
    
    
    
    
    
    
    
    
    (20
    )
    
    
    (2
    )
    
    
    (41
    )
    
    
    
    
    
    
    
    
    
    
    (43
    )December 31, 2003
    
    
    
    
    
    
    
    
    
    
    10,396
    
    
    
    1,040
    
    
    
    107,633
    
    
    
    (150,656
    )
    
    
    (15,357
    )
    
    
    (57,340
    )Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    11,834
    
    
    
    
    
    
    
    11,834Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (11,180
    )
    
    
    (11,180
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,512
    
    
    
    5,512Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,166Stock options exercised
    
    
    
    
    
    
    
    
    
    
    65
    
    
    
    6
    
    
    
    105
    
    
    
    
    
    
    
    
    
    
    
    111Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,097
    
    
    
    
    
    
    
    
    
    
    
    1,097Repurchase of stock options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (283
    )
    
    
    
    
    
    
    
    
    
    
    (283
    )Tax benefit of repurchase of stock options
and stock options exercised
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    116
    
    
    
    
    
    
    
    
    
    
    
    116Treasury stock
    
    
    
    
    
    
    
    
    
    
    (6
    )
    
    
    (1
    )
    
    
    (28
    )
    
    
    
    
    
    
    
    
    
    
    (29
    )Redemption of common stock
    
    
    
    
    
    
    
    
    
    
    (10,455
    )
    
    
    (1,045
    )
    
    
    (108,640
    )
    
    
    138,822
    
    
    
    21,025
    
    
    
    50,162July 1, 2004
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    -Successor Company:Sale of common stock
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    77,500
    
    
    
    
    
    
    
    
    
    
    
    77,500Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    890
    
    
    
    
    
    
    
    890Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (28,919
    )
    
    
    (28,919
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    8,656
    
    
    
    8,656Total comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (19,373
    )December 31, 2004
    
    
    2
    
    
    $
    
    
    
    
    
    
    
    $
    
    
    
    $
    77,500
    
    
    $
    890
    
    
    $
    (20,263
    )
    
    $
    58,127
 See accompanying notes. F-5




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##### Table of Contents



BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) SuccessorCompany
    
    
    
    Predecessor CompanyFor the 183 Day
    
    
    
    For the 183 DayPeriod From July
    
    
    
    Period From
    
    
    Year ended
    
    
    Year ended2, to December
    
    
    
    January 1, to July
    
    
    December 31,
    
    
    December31, 2004
    
    
    
    1, 2004
    
    
    2003
    
    
    31, 2002Cash flows from operating activities:Income
(loss) from continuing operations
    
    $
    890
    
    
    
    $
    (17,034
    )
    
    $
    5,960
    
    
    $
    8,935Adjustments to reconcile income (loss) from continuing operations
to net cash provided by operating activities:Depreciation, depletion and amortization
    
    
    17,527
    
    
    
    
    9,089
    
    
    
    18,098
    
    
    
    21,339Impairment of oil and gas properties
    
    
    
    
    
    
    
    
    
    
    
    896
    
    
    
    Accretion
expense
    
    
    633
    
    
    
    
    195
    
    
    
    343
    
    
    
    Loss on sale of business
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    154Loss on disposal of property and equipment
    
    
    18
    
    
    
    
    375
    
    
    
    1,452
    
    
    
    198Net monetization of derivatives
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    22,185Amortization of derivatives and other noncash hedging activities
    
    
    (829
    )
    
    
    
    2,037
    
    
    
    (3,456
    )
    
    
    (19,241
    )Exploration expense
    
    
    2,750
    
    
    
    
    2,717
    
    
    
    6,849
    
    
    
    8,834Deferred income taxes
    
    
    (2,039
    )
    
    
    
    (2,666
    )
    
    
    3,210
    
    
    
    5,250Stock-based compensation
    
    
    
    
    
    
    
    1,097
    
    
    
    326
    
    
    
    82Debt extinguishment
    
    
    
    
    
    
    
    3,406
    
    
    
    
    
    
    
    Transaction expenses
    
    
    
    
    
    
    
    22,595
    
    
    
    
    
    
    
    Change in operating assets and liabilities, net of
effects of acquisition and disposition of businesses:Accounts receivable and other operating assets
    
    
    (304
    )
    
    
    
    (4,307
    )
    
    
    (3,997
    )
    
    
    (48
    )Inventories
    
    
    394
    
    
    
    
    79
    
    
    
    62
    
    
    
    459Accounts payable and accrued expenses
    
    
    4,234
    
    
    
    
    3,474
    
    
    
    (3,508
    )
    
    
    2,128Net cash provided by continuing operations
    
    
    23,274
    
    
    
    
    21,057
    
    
    
    26,235
    
    
    
    50,275Cash flows from investing activities:Acquisition of businesses, net of cash acquired
    
    
    
    
    
    
    
    
    
    
    
    (4,841
    )
    
    
    (1,223
    )Disposition of businesses, net of cash
    
    
    
    
    
    
    
    
    
    
    
    100
    
    
    
    12,390Proceeds from property and equipment disposals
    
    
    125
    
    
    
    
    247
    
    
    
    2,997
    
    
    
    1,927Exploration expense
    
    
    (2,750
    )
    
    
    
    (2,717
    )
    
    
    (6,849
    )
    
    
    (8,834
    )Additions to property and equipment
    
    
    (12,008
    )
    
    
    
    (11,228
    )
    
    
    (22,609
    )
    
    
    (19,243
    )(Increase)
decrease in other assets
    
    
    (35
    )
    
    
    
    1,218
    
    
    
    (120
    )
    
    
    (1,314
    )Net cash used in investing activities
    
    
    (14,668
    )
    
    
    
    (12,480
    )
    
    
    (31,322
    )
    
    
    (16,297
    )Cash flows from financing activities:Proceeds from senior secured notes
    
    
    
    
    
    
    
    192,500
    
    
    
    
    
    
    
    Proceeds from senior secured facility  term loan
    
    
    
    
    
    
    
    100,000
    
    
    
    
    
    
    
    Sale of common stock
    
    
    
    
    
    
    
    77,500
    
    
    
    
    
    
    
    Repayment of senior subordinated notes
    
    
    (1,040
    )
    
    
    
    (223,960
    )
    
    
    
    
    
    
    Payment to shareholders and optionholders
    
    
    
    
    
    
    
    (113,674
    )
    
    
    
    
    
    
    Transaction expenses
    
    
    
    
    
    
    
    (22,595
    )
    
    
    
    
    
    
    Debt issue costs
    
    
    
    
    
    
    
    (11,700
    )
    
    
    (250
    )
    
    
    (152
    )Repayment of senior secured facility  term loan
    
    
    (10,500
    )
    
    
    
    
    
    
    
    
    
    
    
    Proceeds from revolving line of credit
    
    
    
    
    
    
    
    146,636
    
    
    
    195,859
    
    
    
    151,158Repayment of long-term debt and other obligations
    
    
    (126
    )
    
    
    
    (194,187
    )
    
    
    (175,573
    )
    
    
    (184,003
    )Proceeds from stock options exercised
    
    
    
    
    
    
    
    111
    
    
    
    120
    
    
    
    5Repurchase of stock options
    
    
    
    
    
    
    
    (283
    )
    
    
    122
    
    
    
    (29
    )Purchase of treasury stock
    
    
    
    
    
    
    
    (29
    )
    
    
    (43
    )
    
    
    (398
    )Net cash (used in) provided by financing activities
    
    
    (11,666
    )
    
    
    
    (49,681
    )
    
    
    20,235
    
    
    
    (33,419
    )Net (decrease) increase in cash and equivalents from continuing operations
    
    
    (3,060
    )
    
    
    
    (41,104
    )
    
    
    15,148
    
    
    
    559Net increase (decrease) in cash and equivalents from discontinued operations
    
    
    
    
    
    
    
    61,143
    
    
    
    (15,435
    )
    
    
    (769
    )Cash and cash equivalents at beginning of period
    
    
    21,467
    
    
    
    
    1,428
    
    
    
    1,715
    
    
    
    1,925Cash and cash equivalents at end of period
    
    $
    18,407
    
    
    
    $
    21,467
    
    
    $
    1,428
    
    
    $
    1,715
 See accompanying notes. F-6




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##### Table of Contents



BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Merger Unless the context requires otherwise or unless otherwise noted, when we use the terms Belden
& Blake, we, us, our or the Company, we are referring to Belden & Blake Corporation and
its subsidiaries. On July 7, 2004, the Company, Capital C Energy Operations, LP, a Delaware
limited partnership (Capital C), and Capital C Ohio, Inc., an Ohio corporation and a wholly owned
subsidiary of Capital C (Merger Sub), completed a merger pursuant to which Merger Sub was merged
with and into the Company (the Merger), with the Company surviving the Merger as a wholly owned
subsidiary of Capital C. The Merger resulted in a change in control of the Company. The general
partner of Capital Cs general partner is Capital C Energy, LLC, an entity formed in April 2004 by
Carlyle/Riverstone Global Energy and Power Fund II, L.P. and Capital C Energy Partners, L.P.
Capital C Energy, LLC is headquartered in Houston, Texas. The Merger was completed on July 7, 2004 and for financial reporting purposes was accounted
for as a purchase effective July 1, 2004. The Merger resulted in a new basis of accounting
reflecting estimated fair values for assets and liabilities at that date. Accordingly, the
financial statements for the period subsequent to July 1, 2004 are presented on the Companys new
basis of accounting, while the results of operations for the periods ended July 1, 2004 and
December 31, 2003 reflect the historical results of the predecessor company. A vertical black line
is presented to separate the financial statements of the predecessor and successor companies. In the Merger, each issued and outstanding share of our common stock was converted into the
right to receive cash. All outstanding amounts of indebtedness under our prior credit facility
were repaid. In connection with the Merger, pursuant to a consent solicitation and tender offer
previously announced by the Company, over 98% of our $225 million aggregate principal amount of
9-7/8% Senior Subordinated Notes (the 9-7/8% Notes) were tendered and repaid at the closing of the
Merger. As of September 30, 2004, all of the $225 million aggregate principal amount of the 9-7/8%
Notes had been paid. Capital C obtained the funds necessary to consummate the Merger through (1) equity capital
contributions of $77.5 million by its partners, (2) our entry into a secured credit facility with
various lenders arranged through Goldman Sachs Credit Partners, L.P. with a $100 million term
facility maturing on July 7, 2011, a $30 million revolving facility maturing on July 7, 2010 and a
$40 million letter of credit facility, which amounts are secured by substantially all of the assets
of the Company (the Senior Facilities) and (3) a private placement of $192.5 million aggregate
principal amount of 8.75% Senior Secured Notes due 2012 (the Notes), which are secured by a
second-priority lien on the same assets. Pre-existing commodity hedges and ten-year commodity
hedges effected in connection with the Merger were also secured by a second-priority lien on the
same assets. F-7




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##### Table of Contents



The table below summarizes the allocation of the purchase price based on the acquisition date
fair values of the assets acquired and the liabilities assumed. The purchase price allocation is
preliminary because the determination of fair values of certain assets and liabilities as of the
acquisition date have not been completed. (in thousands)Net working capital
    
    $
    17,003Oil and gas properties
    
    
    501,705Other assets
    
    
    24,400Derivative liability
    
    
    (46,898
    )Other non-current liabilities
    
    
    (13,502
    )Net deferred income tax liabilities
    
    
    (112,573
    )Long-term debt
    
    
    (292,635
    )Net cash equity contribution
    
    $
    77,500
 In connection with the Merger we entered into commodity hedges on a substantial portion
of our future oil and gas production through the year 2013. See Note 6. Our management team remained after the Merger with the exception of the retirement of the
former Chief Executive Officer, John L. Schwager. Frost W. Cochran became our new President and
Chief Executive Officer and B. Dee Davis and W. Mac Jensen joined us as Senior Vice Presidents.
All of our former directors resigned and Frost W. Cochran, David M. Carmichael, Michael B. Hoffman,
Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A. Beard were elected to our Board of
Directors. On November 1, 2004, James A. Winne III and Michael Becci were elected to our Board of
Directors and were also named Senior Vice Presidents of the Company. On December 16, 2004, (i) the
Company accepted the resignations of Frost W. Cochran, President, Chief Executive Officer and
director, David M. Carmichael, Chairman of the Board of Directors and director, B. Dee Davis, Jr.,
Senior Vice President, and W. Mac Jensen, Senior Vice President, from all positions as officers
and, as applicable, directors of the Company and its subsidiaries, and (ii) the Companys Board of
Directors appointed James A. Winne III to serve as the new Chief Executive Officer and Chairman of
the Board of Directors of the Company, and Michael Becci to serve as the new President and Chief
Operating Officer of the Company. Following are unaudited pro forma results of operations as if the Merger occurred at the
beginning of 2003 (in thousands): Year ended December 31,2004
    
    
    2003Total revenues
    
    $
    101,782
    
    
    $
    95,414Loss from continuing operations
    
    
    (369
    )
    
    
    (3,414
    )
 The unaudited pro forma information presented above assumes the transaction-related
expenses were incurred prior to the period presented and does not purport to be indicative of the
results that actually would have been obtained if the merger had been consummated at the beginning
of 2003 and is not intended to be a projection of future results or trends. In connection with the
Merger, we entered into a management services agreement with Capital C, pursuant to which Frost W.
Cochran, B. Dee Davis and W. Mac Jensen, provided certain management and advisory services to us
for a quarterly fee of $250,000 plus reimbursement of expenses. These services included general
management supervision and oversight, in the capacity as officers of Belden & Blake; financial
advisory services; evaluation of potential
acquisitions and other business opportunities; and strategic consulting services. This agreement
was terminated effective December 20, 2004. F-8




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##### Table of Contents



Capital C received a fee from us of approximately $1.4 million in connection with the Merger. We incurred transaction costs associated with the Merger of $26.0 million. These costs were
expensed in the predecessor company period ended July 1, 2004. We also capitalized $11.7 million
of debt financing costs. The change in fair value of $2.4 million of certain hedges from July 1,
2004 to July 7, 2004 was recorded in Derivative fair value loss in the predecessor company period
ended July 1, 2004. Effective December 30, 2004, we merged with our wholly owned subsidiaries, The Canton Oil and
Gas Company (COG) and Ward Lake Drilling, Inc. (WLD), and we were the surviving corporation.
COG and WLD were the guarantor subsidiaries to our $192.5 million 8.75% Senior Secured Notes due
2012. (2) Business and Significant Accounting Policies Business We
operate in the oil and gas industry. Our principal business is the exploitation,
development, production, operation and acquisition of oil and gas properties. Sales of oil are
ultimately made to refineries. Sales of natural gas are ultimately made to gas utilities and
industrial consumers in Ohio, Michigan, Pennsylvania and New York. The price of oil and natural
gas has a significant impact on our working capital and results of operations. Principles of Consolidation and Financial Presentation The accompanying consolidated financial statements include the financial statements of the
Company and its subsidiaries. All significant intercompany accounts and transactions have been
eliminated in consolidation. Certain reclassifications have been made to conform to the
presentation in 2004. Use of Estimates in the Financial Statements The preparation of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the reported amounts.
Significant estimates used in the preparation of our financial statements which could be subject to
significant revision in the near term include estimated oil and gas reserves. Cash Equivalents For purposes of the statements of cash flows, cash equivalents are defined as all highly
liquid investments purchased with an initial maturity of three months or less. Concentrations of Credit Risk Credit limits, ongoing credit evaluation and account monitoring procedures are used to
minimize the risk of loss. Collateral is generally not required. Expected losses are provided for
currently and actual losses have been within managements expectations. Inventories Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural
gas inventories are stated at the lower of average cost or market. F-9




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##### Table of Contents



Property and Equipment We use the successful efforts method of accounting for our oil and gas properties. Under
this method, property acquisition and development costs and certain productive exploration costs
are capitalized while non-productive exploration costs, which include certain geological and
geophysical costs, exploratory dry holes and costs of carrying and retaining unpdeveloped
properties, are expensed as incurred. The geological and geophysical costs include costs for
salaries and benefits of our personnel in those areas and other third party costs. The costs of
carrying and retaining undeveloped properties include salaries and benefits of our land department
personnel, delay rental payments made on new and existing leases, ad valorem taxes on existing
leases and the cost of previously capitalized leases which are written off because the leases were
dropped or expired. Exploratory dry hole costs include the costs associated with drilling an
exploratory well that has been determined to be a dry hole. Capitalized costs related to proved
properties are depleted using the unit-of-production method. Depreciation, depletion and
amortization of proved oil and gas properties is calculated on the basis of estimated recoverable
reserve quantities. These estimates can change based on economic or other factors. No gains or
losses are recognized upon the disposition of oil and gas properties except in extraordinary
transactions such as the complete disposition of a geographical/geological pool. Sales proceeds
are credited to the carrying value of the properties. Maintenance and repairs are expensed, and
expenditures which enhance the value of properties are capitalized. Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These
costs are assessed periodically to determine whether their value has been impaired, and if
impairment is indicated, the costs are charged to expense. Impairments recorded in 2003 were
$475,000 which reduced the book value of unproved oil and gas properties to their estimated fair
value. No impairments were recorded in 2004 and 2002. Gas gathering systems are stated at cost. Depreciation expense is computed using the
straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is
computed using the straight-line method over the useful lives of the assets ranging from 3 to 15
years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and
gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation
are removed from the accounts, and any resulting gain or loss is reflected in income for the
period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and
betterments are capitalized. Long-lived assets are reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount may not be recoverable. If the sum of the expected future
undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the
difference between the fair value and the carrying amount of the asset. In performing the review
for long-lived asset recoverability during 2003, we recorded $421,000 of impairments which reduced
the book value of producing properties to their estimated fair value. Fair value was based on
estimated future cash flows to be generated by the assets, discounted at a market rate of interest.
No impairments were recorded in 2004 and 2002. Intangible Assets Under Statement of Financial Accounting Standards No. (SFAS) 142, Goodwill and Other
Intangible Assets which was issued in June 2001 by the Financial Accounting Standards Board
(FASB), goodwill and indefinite lived intangible assets are no longer amortized but are reviewed
for impairment annually or if certain impairment indicators arise. Separately identifiable
intangible assets that are not deemed to have an indefinite life will continue to be amortized over
their useful lives (but with no maximum life). We perform our annual impairment test on a
recurring basis on October 1st. F-10




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##### Table of Contents



At
December 31, 2004 and 2003, we had $10.9 million and
$3.9 million, respectively, of deferred debt issuance costs and no
unamortized goodwill. Deferred debt issuance costs are being amortized over their respective
terms. Amortization expense related to deferred debt issuance costs
was $1.4 million, $1.2 million and $1.5 million for
the years ended December 31, 2004, 2003 and 2002, respectively. At December 31, 2004, the amortization of deferred debt issuance costs in the next five
years is as follows: $1.6 million in each of the next five years
(2005 through 2009) and $2.9 million thereafter. Revenue Recognition Oil and gas production revenue is recognized as production and delivery take place. Oil and
gas marketing revenues are recognized when title passes. Income Taxes We use the asset and liability method of accounting for income taxes under SFAS 109,
Accounting for Income Taxes. Deferred income taxes are provided for temporary differences
between the carrying amounts of assets and liabilities for financial reporting purposes and the
amounts used for income tax purposes. Deferred income taxes also are recognized for operating
losses that are available to offset future taxable income and tax credits that are available to
offset future federal income taxes. A valuation allowance is established to reduce deferred tax
assets if it is more likely than not that the benefits will not be realized. Stock-Based Compensation On December 31, 2002, the FASB issued SFAS 148, Accounting for Stock Based
CompensationTransition and Disclosure. SFAS 148 amends SFAS 123, Accounting for Stock Based
Compensation by providing alternative methods of transition to SFAS 123s fair value method of
accounting for stock-based compensation. SFAS 148 also amends many of the disclosure requirements
of SFAS 123. We measure expense associated with stock-based compensation under the provisions of
Accounting Principles Board Opinion No. (APB) 25, Accounting for Stock Issued to Employees and
its related interpretations. Under APB 25, no compensation expense is required to be recognized
upon the issuance of stock options to key employees as the exercise price of the option is equal to
the market price of the underlying common stock at the date of grant. The fair value of our stock options was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted-average assumptions for the predecessor company
periods ended July 1, 2004, and December 31, 2003 and 2002, respectively: risk-free interest rates
of 3.6%, 3.7% and 4.1%; volatility factor of the expected market price of our common stock of near
zero; dividend yield of zero; and a weighted-average expected life of the option of seven years.
There were no stock options granted in the successor company period ended December 31, 2004. The Black-Scholes option valuation model was developed for use in estimating the fair value of
traded options which have no vesting restrictions and are fully transferable. In addition, option
valuation models require the input of highly subjective assumptions including the expected stock
price volatility. Because our stock options have characteristics significantly different from
those of traded options, and because changes in the subjective input assumptions can materially
affect the fair value estimate, in managements opinion, the existing models do not necessarily
provide a reliable single measure of the fair value of its stock options. For purposes of the pro forma disclosures required by SFAS 123, the estimated fair value of
the options is amortized to expense over the options vesting period. The changes in net income or
loss as if we had applied the fair value provisions of SFAS 123 for the predecessor company periods
ended July 1, 2004, and December 31, 2003 and 2002 were not material. There were no outstanding
stock options or activity in the successor company period ended December 31, 2004. F-11




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##### Table of Contents



The changes in share value and the vesting of shares are reported as adjustments to
compensation expense. The change in share value in the predecessor company periods ended July 1,
2004, and December 31, 2003 and 2002 resulted in an increase in compensation expense of $1.1
million, $325,000 and $82,000, respectively. Derivatives and Hedging On January 1, 2001, we adopted SFAS 133, Accounting for Derivative Instruments and Hedging
Activities which was issued in June 1998 by the FASB, as amended by SFAS 137, Accounting for
Derivative Instruments and Hedging Activities  Deferral of Effective Date of SFAS 133 and SFAS
138, Accounting for Certain Derivative Instruments and Certain Hedging Activities issued in June
1999 and June 2000, respectively. SFAS 133, as amended, was applied as the cumulative effect of an
accounting change effective January 1, 2001. As a result of the adoption of SFAS 133, we recognize all derivative financial instruments as
either assets or liabilities at fair value. Derivative instruments that are not hedges must be
adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the
fair value of derivative instruments that are fair value hedges are offset against changes in the
fair value of the hedged assets, liabilities, or firm commitments, through net income (loss).
Changes in the fair value of derivative instruments that are cash flow hedges are recognized in
other comprehensive income (loss) until such time as the hedged items are recognized in net income
(loss). Ineffective portions of a derivative instruments change in fair value are immediately
recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be
recognized as increases or decreases to oil and gas revenues during the same periods in which the
underlying forecasted transactions are recognized in net income (loss). If there is a
discontinuance of a cash flow hedge because it is probable that the original forecasted transaction
will not occur, deferred gains or losses are recognized in earnings immediately. See Note 6. The relationship between the hedging instruments and the hedged items must be highly effective
in achieving the offset of changes in fair values or cash flows attributable to the hedged risk,
both at the inception of the contract and on an ongoing basis. We measure effectiveness on changes
in the hedges intrinsic value. We consider these hedges to be highly effective and expect there
will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the
hedging instruments and the hedged forecasted transactions are the same. Ongoing assessments of
hedge effectiveness will include verifying and documenting that the critical terms of the hedge and
forecasted transaction do not change. We measure effectiveness at least on a quarterly basis. (3) New Accounting Pronouncements On January 1, 2003, we adopted SFAS 143, Accounting for Asset Retirement Obligations. SFAS
143 amends SFAS 19, Financial Accounting and Reporting by Oil and Gas Producing Companies which
requires us to recognize a liability for the fair value of its asset retirement obligations
associated with its tangible, long-lived assets. The majority of our asset retirement obligations
relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties. At
January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement
obligations. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment
to record a $4.0 million increase in long-term asset retirement obligation liabilities, a $621,000
increase in current asset retirement obligation liabilities, a $3.2 million increase in the
carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation,
depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net
effect of adoption was to record a gain of $2.4 million, net of tax, as a cumulative effect of a
change in accounting principle in our consolidated statement of operations in the first quarter of
2003. F-12




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Subsequent to the adoption of SFAS 143, there has been no significant current period activity
with respect to additional retirement obligations, settled obligations, accretion expense and
revisions of estimated cash flows. The asset retirement obligations increased as a result of
purchase accounting for the Merger, primarily due to a lower discount rate and revised estimates of
asset lives on certain oil and gas wells. The unaudited pro forma income from continuing
operations for the year ended December 31, 2002 was $4.3 million and was prepared to give effect to
the adoption of SFAS 143 as if it had been adopted on January 1, 2002. Assuming retroactive
application of the change in accounting principle as of January 1, 2002, liabilities would have
increased approximately $6 million. A reconciliation of our liability for plugging and abandonment costs for the year ended
December 31, 2004 and 2003 is as follows (in thousands): Successor
    
    
    
    PredecessorCompany
    
    
    
    CompanyFor The 183 Day
    
    
    
    For The 183 DayPeriod From July
    
    
    
    Period From
    
    
    Year ended2, to December 31,
    
    
    
    January 1, to July
    
    
    December 31,2004
    
    
    

1, 2004
    
    
    2003Beginning asset retirement obligations
    
    $
    14,274
    
    
    
    $
    4,595
    
    
    $
    Cumulative effect adjustment
    
    
    
    
    
    
    
    
    
    
    
    4,387Liabilities incurred
    
    
    101
    
    
    
    
    9
    
    
    
    268Liabilities settled
    
    
    (85
    )
    
    
    
    (30
    )
    
    
    (471
    )Accretion expense
    
    
    633
    
    
    
    
    195
    
    
    
    344Revisions in estimated cash flows
    
    
    19
    
    
    
    
    24
    
    
    
    67Ending asset retirement obligations
    
    $
    14,942
    
    
    
    $
    4,793
    
    
    $
    4,595
 In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities 
An Interpretation of Accounting Research Bulletin (ARB) 51. FIN 46, as amended by FIN 46(R) in
December 2003, is an interpretation of ARB 51, Consolidated Financial Statements, and addresses
consolidation by business enterprises of variable interest entities (VIEs). The primary objective
of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities
over which control is achieved through means other than voting rights; such entities are known as
VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable
interest that will absorb a majority of the entitys expected losses if they occur, receive a
majority of the entitys expected residual returns if they occur, or both. An enterprise shall
consider the rights and obligations conveyed by its variable interests in making this
determination. This guidance applied immediately to VIEs created after January 31, 2003, and to
VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal
year or interim period beginning after December 15, 2004. The adoption of FIN 46 and FIN 46(R) did
not have any effect on our financial statement disclosures, financial position, results of
operations or cash flows. In April 2003, the FASB issued SFAS 149, Amendment of Statement 133 on Derivative Instruments
and Hedging Activities. SFAS 149 is intended to result in more consistent reporting of contracts
as either freestanding derivative instruments subject to SFAS 133 in its entirety, or as hybrid
instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for
our financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149
did not have a material effect on our financial position, results of operations or cash flows. In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. SFAS
123(R) revises SFAS 123, Accounting for Stock-Based Compensation, and focuses on F-13




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accounting for share-based payments for services by employer to employee. The statement requires companies to
expense the fair value of employee stock options and other equity-based compensation at the grant
date. The statement does not require a certain type of valuation model and either a binomial or
Black-Scholes model may be used. The provisions of SFAS 123(R) are effective for financial
statements for fiscal periods ending after June 15, 2005. We did not have stock-based compensation
arrangements outstanding at December 31, 2004. The impact of adoption will depend on future
issuance of stock-based compensation arrangements. Our future cash flows will not be impacted by
the adoption of this standard. See Note 2 Stock Based Compensation for further information. (4) Acquisitions In February 2003, we purchased reserves in certain wells that we operate in Michigan for $3.8
million in cash. These properties were subject to a prior monetization transaction of the Section
29 tax credits which we entered into in 1996. We had the option to purchase these properties
beginning in 2003. We previously held a production payment on these properties including a 75%
reversionary interest in certain future production. We purchased those reserve volumes beyond our
currently held production payment along with the 25% reversionary interest not owned. The
estimated volumes acquired were 4.4 Bcf (billion cubic feet) of estimated proved developed
producing gas reserves. On July 11, 2002, we acquired net reserves totaling 4.2 Bcfe (billion cubic feet of natural
gas equivalent) for a cash payment of $1.2 million. We previously held a production payment on
these properties through December 31, 2002. (5) Dispositions and Discontinued Operations On June 25, 2004, we completed a sale of substantially all of our Trenton Black River (TBR)
assets to Fortuna Energy Inc., a wholly owned subsidiary of Talisman Energy Inc. The assets sold
included working interests in 16 wells, approximately 11 miles of natural gas gathering lines and
oil and gas leases on approximately 475,000 gross acres. The assets are located primarily in New
York, Pennsylvania, Ohio and West Virginia. The TBR assets accounted for approximately 5 Bcfe of
our estimated proved reserves as of December 31, 2003. The sale resulted in proceeds of approximately $68.2 million. The proceeds were used to pay
down our existing revolving credit facility. As a result of the disposition of the TBR
geographical/geological pools, we recorded a gain of approximately $46.6 million ($29.8 million net
of tax) in June 2004. According to SFAS 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, the disposition of this group of wells is classified as discontinued
operations. In April 2004, we decided to dispose of our Arrow Oilfield Service Company (Arrow) assets.
We sold the Michigan assets of Arrow in May 2004 and sold the Ohio and Pennsylvania assets of Arrow
in June 2004. The two Arrow asset sales resulted in proceeds of approximately $4.2 million. As a
result of the disposition of all of our Arrow assets, we recorded a loss of approximately $1.4
million ($864,000 net of tax) in the second quarter of 2004. According to SFAS 144, the
disposition of the Arrow assets is classified as discontinued operations. As a result of our decision to shift focus away from exploration and development activities in
the Knox formation in Ohio, we sold substantially all of our undeveloped Knox acreage in Ohio for
approximately $2.8 million in September 2003. The sale resulted in a loss of approximately
$150,000. On December 10, 2002, we sold 962 oil and natural gas wells in New York and Pennsylvania. The
sale included substantially all of our Medina formation wells in New York and a smaller number of
Pennsylvania Medina wells. The properties had approximately 23 Bcfe of total estimated proved
reserves. At the time of the sale, our net production from these wells was approximately 3.9 Mmcfe
(million cubic F-14




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##### Table of Contents



feet of natural gas equivalent) per day (4 Mcfe (thousand cubic feet of natural gas
equivalent) per day per well). We disposed of these properties due to the low production volume per
well and high cost characteristics. The wells sold had estimated proved developed reserves using
SEC pricing parameters of approximately 19.4 Bcfe and estimated proved undeveloped reserves of
approximately 3.6 Bcfe. The sale resulted in proceeds of approximately $16.2 million. On December 10, 2002, we
received $15.5 million in cash with the remaining amount of approximately $700,000 received in
February 2003. The proceeds were used to pay down our revolving credit facility. As a result of the
sale, we disposed of all of our properties producing from the New York Medina formation. As a
result of the disposition of the entire New York Medina geographical/geological pool, we recorded a
loss on sale of $3.2 million ($1.8 million net of tax) in 2002. According to SFAS 144, Accounting
for the Impairment or Disposal of Long-Lived Assets, the disposition of this group of wells is
classified as discontinued operations. We allocate interest expense to operating areas based on the proportionate share of net assets
of the area to the Companys consolidated net assets. The amounts of interest expense allocated to
income (loss) from discontinued operations for the years ended December 31, 2004, 2003 and 2002 was
$907,000, $2.0 million and $2.6 million, respectively. Revenues and (loss) income from discontinued operations are as follows (in thousands): Predecessor Company183 DayPeriod fromJanuary 1,2004 to July 1,
    
    
    Year ended December 31,2004
    
    
    2003
    
    
    2002Revenue from discontinued operations
    
    $
    7,294
    
    
    $
    13,698
    
    
    $
    17,620(Loss) income from operations of discontinued businesses
    
    $
    (43
    )
    
    $
    (16,368
    )
    
    $
    (7,024
    )(Benefit) provision for income taxes
    
    
    (17
    )
    
    
    (5,731
    )
    
    
    (2,386
    )(26
    )
    
    
    (10,637
    )
    
    
    (4,638
    )Income (loss) on sale of discontinued businesses
    
    
    45,223
    
    
    
    (69
    )
    
    
    (3,188
    )Income tax provision (benefit)
    
    
    16,329
    
    
    
    (25
    )
    
    
    (1,356
    )28,894
    
    
    
    (44
    )
    
    
    (1,832
    )Income (loss) from discontinued operations, net of tax
    
    $
    28,868
    
    
    $
    (10,681
    )
    
    $
    (6,470
    )
 F-15




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##### Table of Contents



Assets and liabilities of the discontinued operations are as follows (in thousands): December 31,2004
    
    
    2003AssetsCurrent assets
    
    $
    
    
    
    $
    3,407Net property and equipment
    
    
    
    
    
    
    16,141Other long term assets
    
    
    
    
    
    
    2,682Total assets
    
    $
    
    
    
    $
    22,230LiabilitiesCurrent liabilities
    
    $
    
    
    
    $
    3,290Other long term liabilities
    
    
    
    
    
    
    521Total liabilities
    
    
    
    
    
    
    3,811Net assets of discontinued operations
    
    $
    
    
    
    $
    18,419
 A transaction fee of $238,000 was paid in 2003 to Texas Pacific Group (TPG), a former
shareholder, in connection with the Knox asset sale. The fee was paid to TPG pursuant to a
Transaction Advisory Agreement entered into in 1997 between the Company and TPG. During 2002, we completed the sale of six natural gas compressors in Michigan to a compression
services company. The proceeds of approximately $2.0 million were used to pay down our revolving
credit facility. We also entered into an agreement to leaseback the compressors from the
compression services company, which will provide full compression services including maintenance
and repair on these and other compressors. Certain compressors were relocated to maximize
compression efficiency. A gain on the sale of $168,000 was deferred and will be amortized as
rental expense over the life of the lease. On August 1, 2002, we sold oil and gas properties consisting of 1,138 wells in Ohio that had
approximately 10 Bcfe of estimated proved reserves. At the time of the sale, our net production
from these wells was approximately 3.1 Mmcfe per day (3 Mcfe per day per well). We disposed of
these properties due to the low production volume per well and high operating costs per well. The
proceeds of approximately $8.0 million were used to pay down our revolving credit facility. (6) Derivatives and Hedging From time to time we may enter into a combination of futures contracts, commodity derivatives
and fixed-price physical contracts to manage our exposure to natural gas or oil price volatility
and support our capital expenditure plans. We employ a policy of hedging gas production sold under
New York Mercantile Exchange (NYMEX) based contracts by selling NYMEX-based commodity derivative
contracts which are placed with major financial institutions that we believe are minimal credit
risks. The contracts may take the form of futures contracts, swaps, collars or options. At
December 31, 2004, our derivative contracts consisted of natural gas swaps, collars and options.
Qualifying NYMEX-based derivative contracts were designated as cash flow hedges. The changes in
fair value of non-qualifying derivative contracts will be initially reported in expense in the
consolidated statements of operations as derivative fair value (gain) loss and will ultimately be
reversed within the same line item and included in oil and gas sales over the respective contract
terms. The fair value of derivative assets and liabilities represents the difference between hedged
prices and market prices on hedged volumes of natural gas as of December 31, 2004. During 2004, a
net loss on contract settlements of $22.6 million ($14.2 million after tax) was reclassified from
accumulated other F-16




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##### Table of Contents



comprehensive income to earnings and the fair value of open hedges increased by
$63.8 million ($40.1 million after tax). At December 31, 2004, the estimated net losses in
accumulated other comprehensive income that are expected to be reclassified into earnings within
the next 12 months are approximately $2.4 million. We have partially hedged our exposure to the
variability in future cash flows through December 2013. We are a party to a long-term hedging program through 2013 with J. Aron. The Hedges primarily
take the form of monthly settled fixed price swaps in respect of the settlement prices for the
market standard NYMEX futures contracts on natural gas and crude oil. We pay a NYMEX-based floating
price per Mmbtu, in the case of Hedges on natural gas, and pay a NYMEX-based floating price per Bbl
in the case of Hedges on crude oil for each month during the term of the Hedges and receive a fixed
price per Mmbtu or Bbl (as the case may be), according to a monthly schedule of fixed prices, which
were established upon the closing of the Merger. In addition to the monthly settled fixed prices
swaps, our current existing commodity hedge transactions for the remainder of 2004 and for 2005
were reestablished with J. Aron in connection with the Merger and now constitute part of the
Hedges. We consider our natural gas swaps to be highly effective and expect there will be no
ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging
instruments and the hedged forecasted transactions are the same. We have not experienced
ineffectiveness on our natural gas swaps because we use NYMEX-based commodity derivative contracts
to hedge on the same basis as our natural gas production is sold (NYMEX-based sales contracts). We
have collar agreements that could not be redesignated as cash flow hedges because these collars
were not effective due to unrealized losses at the date of the Merger. These collars qualified and
were designated as cash flow hedges from their inception through the predecessor company period
ended July 1, 2004. Although these collars are not deemed to be effective hedges in accordance
with the provisions of SFAS 133, we have retained these instruments as protection against changes
in commodity prices and we will continue to record the mark-to-market adjustments on these natural
gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps are highly effective
and were designated as cash flow hedges. We have ineffectiveness on the crude oil swaps because
the oil is sold locally at a posted price which is different from the NYMEX price. Historically,
there has been a high correlation between the posted price and NYMEX. The changes in the fair
values of the natural gas collars and the ineffective portion of the crude oil swaps are recorded
as Derivative fair value gain or loss. In March 2003, we entered into a collar for 4,320 Bbtu (billion British thermal units) of our
natural gas production in 2004 with a ceiling price of $5.80 per Mmbtu (million British thermal
units) and a floor price of $4.00 per Mmbtu. We also sold a floor at $3.00 per Mmbtu on this
volume of gas which was designated as a non-qualifying cash flow hedge under SFAS 133. This
aggregate structure has the effect of: 1) setting a maximum price of $5.80 per Mmbtu; 2) floating
at prices from $4.00 to $5.80 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are
between $3.00 and $4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if
the price is $3.00 or less. All prices are based on monthly NYMEX settle. Upon the Merger, these
contracts were transferred to J. Aron and re-established at a ceiling price of $5.75. In April 2003, we entered into a collar for 6,000 Bbtu of our natural gas production in 2005
with a ceiling price of $5.37 per Mmbtu and a floor price of $4.00 per Mmbtu. We also sold a floor
at $3.10 per Mmbtu on this volume of gas which was designated as a non-qualifying cash flow hedge
under SFAS 133. This aggregate structure has the effect of: 1) setting a maximum price of $5.37
per Mmbtu; 2) floating at prices from $4.00 to $5.37 per Mmbtu; 3) locking in a price of $4.00 per
Mmbtu if prices are
between $3.10 and $4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if
the price is $3.10 or less. All prices are based on monthly NYMEX settle. Upon the Merger, these
contracts were transferred to J. Aron and re-established at a ceiling price of $5.32. F-17




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##### Table of Contents



On January 17 and 18, 2002, we monetized 9,350 Bbtu (billion British thermal units) of our
2002 natural gas hedge position at a weighted average NYMEX price of $2.53 per Mmbtu (million
British thermal units) and 3,840 Bbtu of our 2003 natural gas hedge position at a NYMEX price of
$3.01 per Mmbtu. We received net proceeds of $22.7 million that are recognized as increases to
natural gas sales revenues during the same periods in which the underlying forecasted transactions
are recognized in net income (loss). In January 2002, we entered into a collar for 9,350 Bbtu of our natural gas production in 2002
with a ceiling price of $4.00 per Mmbtu and a floor price of $2.25 per Mmbtu which qualified and
was designated as a cash flow hedge under SFAS 133. We also sold a floor at $1.75 per Mmbtu on
this volume of gas which was designated as a non-qualifying cash flow hedge under SFAS 133. This aggregate structure has the effect of: 1) setting a maximum price of $4.00 per Mmbtu; 2)
floating at prices from $2.25 to $4.00 per Mmbtu; 3) locking in a price of $2.25 per Mmbtu if
prices are between $1.75 and $2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the
price if the price is $1.75 or less. All prices are based on monthly NYMEX settle. We paid $1.0
million for the options. We used the net proceeds of $21.7 million from the two transactions above
to pay down on our credit facility. The following table summarizes, as of December 31, 2003, our net deferred gains on terminated
natural gas hedges. Cash has been received and the deferred gains recorded in accumulated other
comprehensive income. The deferred gains have been recognized as increases to gas sales revenues
during the periods in which the underlying forecasted transactions were recognized in net income
(loss). First Quarter
    
    
    Second Quarter
    
    
    Third Quarter
    
    
    Fourth Quarter
    
    
    Total(in thousands)2003
    
    $
    723
    
    
    $
    865
    
    
    $
    771
    
    
    $
    585
    
    
    $
    2,944
 To manage our exposure to natural gas or oil price volatility, we may partially hedge our
physical gas or oil sales prices by selling futures contracts on the NYMEX or by selling NYMEX
based commodity derivative contracts which are placed with major financial institutions that we
believe are minimal credit risks. The contracts may take the form of futures contracts, swaps,
collars or options. Our financial results and cash flows can be significantly impacted as commodity prices
fluctuate widely in response to changing market conditions. Accordingly, we may modify our fixed
price contract and financial hedging positions by entering into new transactions. F-18




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##### Table of Contents



The following tables reflect the natural gas and crude oil volumes and the weighted average
prices under financial hedges (including settled hedges) at December 31, 2004: Natural Gas Swaps
    
    
    Natural Gas Collars
    
    
    Crude Oil SwapsNYMEX
    
    
    
    
    
    
    NYMEX PricePrice per
    
    
    
    
    
    
    per Mmbtu
    
    
    Estimated
    
    
    NYMEXBbtu
    
    
    Mmbtu
    
    
    Bbtu
    
    
    Floor/Cap (1)
    
    
    Mbbls
    
    
    Price per BblQuarter EndingMarch 31, 2005
    
    
    1,500
    
    
    $
    3.81
    
    
    
    1,500
    
    
    $
    4.00 - 5.32
    
    
    
    68
    
    
    $
    34.76June 30, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    68
    
    
    
    34.18September 30, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    67
    
    
    
    33.72December 31, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    67
    
    
    
    33.316,000
    
    
    $
    3.73
    
    
    
    6,000
    
    
    $
    4.00 - 5.32
    
    
    
    270
    
    
    $
    34.00March 31, 2006
    
    
    2,829
    
    
    $
    6.14
    
    
    
    
    
    
    
    
    
    
    
    63
    
    
    $
    32.71June 30, 2006
    
    
    2,829
    
    
    
    5.24
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.35September 30, 2006
    
    
    2,829
    
    
    
    5.22
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.02December 31, 2006
    
    
    2,829
    
    
    
    5.39
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    31.7111,316
    
    
    $
    5.50
    
    
    
    
    
    
    
    
    
    
    
    249
    
    
    $
    32.20Year EndingDecember 31, 2007
    
    
    10,745
    
    
    $
    4.97
    
    
    
    
    
    
    
    
    
    
    
    227
    
    
    $
    30.91December 31, 2008
    
    
    10,126
    
    
    
    4.64
    
    
    
    
    
    
    
    
    
    
    
    208
    
    
    
    29.96December 31, 2009
    
    
    9,529
    
    
    
    4.43
    
    
    
    
    
    
    
    
    
    
    
    191
    
    
    
    29.34December 31, 2010
    
    
    8,938
    
    
    
    4.28
    
    
    
    
    
    
    
    
    
    
    
    175
    
    
    
    28.86December 31, 2011
    
    
    8,231
    
    
    
    4.19
    
    
    
    
    
    
    
    
    
    
    
    157
    
    
    
    28.77December 31, 2012
    
    
    7,005
    
    
    
    4.09
    
    
    
    
    
    
    
    
    
    
    
    138
    
    
    
    28.70December 31, 2013
    
    
    6,528
    
    
    
    4.04
    
    
    
    
    
    
    
    
    
    
    
    127
    
    
    
    28.70
 Mcf  Thousand cubic feet
    
    Mmbtu  Million British thermal unitsBbtu  Billion British thermal units
   (1) The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005 assume
the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at less than
$3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90. (7) Severance and Other Nonrecurring Expense On October 10, 2002, we combined our Pennsylvania/New York District with our Ohio District to
form a new Appalachian District. A total of 28 positions were eliminated in the Ohio and
Pennsylvania/New York Districts and in the corporate office. These actions were necessary to
capitalize on operational and administrative efficiencies and bring our employment level in line
with anticipated future staffing. We recorded a nonrecurring charge of approximately $700,000 in
the fourth quarter of 2002 related to severance and other costs associated with these actions. F-19




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##### Table of Contents



(8) Details of Balance Sheets Successor
    
    
    
    PredecessorCompany
    
    
    
    CompanyDecember 31,2004
    
    
    
    2003(in thousands)Accounts receivableAccounts receivable
    
    $
    4,608
    
    
    
    $
    6,021Allowance for doubtful accounts
    
    
    (1,680
    )
    
    
    
    (1,485
    )Oil and gas production receivable
    
    
    15,694
    
    
    
    
    9,655Current portion of notes receivable
    
    
    45
    
    
    
    
    79$
    18,667
    
    
    
    $
    14,270InventoriesOil
    
    $
    348
    
    
    
    $
    459Natural gas
    
    
    86
    
    
    
    
    33Material, pipe and supplies
    
    
    84
    
    
    
    
    288$
    518
    
    
    
    $
    780Property and equipment, grossOil and gas propertiesProducing properties
    
    $
    483,526
    
    
    
    $
    438,057Non-producing properties
    
    
    30,357
    
    
    
    
    5,598Other
    
    
    359
    
    
    
    
    8,512$
    514,242
    
    
    
    $
    452,167Land, buildings, machinery and equipmentLand, buildings and improvements
    
    $
    5,287
    
    
    
    $
    4,700Machinery and equipment
    
    
    2,433
    
    
    
    
    8,473$
    7,720
    
    
    
    $
    13,173Accrued expensesAccrued interest expense
    
    $
    8,112
    
    
    
    $
    1,245Accrued other expenses
    
    
    4,147
    
    
    
    
    2,088Accrued drilling and completion costs
    
    
    1,488
    
    
    
    
    762Accrued income taxes
    
    
    484
    
    
    
    
    73Ad valorem and other taxes
    
    
    1,049
    
    
    
    
    1,517Compensation and related benefits
    
    
    1,989
    
    
    
    
    2,541Undistributed production revenue
    
    
    6,176
    
    
    
    
    4,500$
    23,445
    
    
    
    $
    12,726
 F-20




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##### Table of Contents



(9) Long-Term Debt Long-term debt consists of the following (in thousands): Successor
    
    
    
    PredecessorCompany
    
    
    
    CompanyDecember 31,2004
    
    
    
    2003Senior secured facility
    
    $
    89,500
    
    
    
    $
    Senior secured notes
    
    
    192,500
    
    
    
    
    Revolving credit facility
    
    
    
    
    
    
    
    47,406Senior subordinated notes
    
    
    
    
    
    
    
    225,000Other
    
    
    97
    
    
    
    
    102282,097
    
    
    
    
    272,508Less current portion
    
    
    1,005
    
    
    
    
    5Long-term debt
    
    $
    281,092
    
    
    
    $
    272,503
 Senior Secured Notes due 2012 We have $192.5 million of our Notes outstanding as of December 31, 2004. The Notes mature
July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year. The
Notes are secured on a second-priority lien on the same assets subject to the liens securing our
obligations under the Senior Facilities. The Notes are subject to redemption at our option at
specific redemption prices. July 15, 2008
    
    
    104.375
    %July 15, 2009
    
    
    102.188
    %July 15, 2010 and thereafter
    
    
    100.000
    %
 The Notes are governed by an indenture (the Indenture), which contains certain covenants
that limit our ability to incur additional indebtedness and issue stock, pay dividends, make
distributions, make investments, make certain other restricted payments, enter into certain
transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any
kind other than permitted liens and engage in mergers and consolidations. Senior Facilities At December 31, 2004, we had a $170 million senior credit facility comprised of: a seven year
$100 million term facility; a six year $30 million revolving facility for working capital
requirements and general corporate purposes, including the issuance of letters of credit; and a six
year $40 million letter of credit facility that may be used only to provide credit support for our
obligations under the Hedge Agreement and other hedging transactions. The Senior Facilities are
secured by a first-priority lien on certain of our assets. At December 31, 2004, the interest rate
under our base rate option was 7.0%. Under our three month LIBOR option the rate was 5.24%. At
December 31, 2004, we had $56.2 million of outstanding letters of credit. At December 31, 2004,
there was no outstanding balance under the revolving credit agreement. Under the term facility the
outstanding balance was $89.5 million. We had $13.8 million of borrowing capacity under our
revolving credit facility available for general corporate
purposes. As of December 31, 2004, we were in compliance with all financial covenants and
requirements under the existing credit facilities. F-21




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##### Table of Contents



Term Facility The term facility consists of a $100 million term loan that was made on July 7, 2004.
Proceeds of the term loan were used to fund a portion of the consideration in the Merger, to
refinance our existing indebtedness, and to pay expenses associated with the transactions. All or a portion of the term loan will bear interest, at our option, either at the Base Rate
or at the Eurodollar Rate plus, in each case, a specified margin subject to adjustment. The Base
Rate is a rate calculated daily as the highest of (i) the annual rate of interest quoted in The
Wall Street Journal, Money Rates Section as the Prime Rate (currently defined as the base rate on
corporate loans posted by at least 75% of the nations thirty (30) largest banks), and (ii) the
federal funds effective rate plus 1/2 of 1%. Interest on any portion of the term loan bearing
interest based on the Base Rate is payable quarterly on January 1, April 1, July 1, and October 1
of each year. The Eurodollar Rate is equal to the London Interbank Offered Rate as adjusted for certain
regulatory reserve costs. At our election, interest periods for that portion of the term loan
bearing interest at the Eurodollar Rate may be one, two, three and six months. Interest on any
portion of the term loan bearing interest based on the Eurodollar Rate is payable quarterly on
January 1, April 1, July 1, and October 1 of each year. Interest on overdue term loan amounts
accrues at a rate equal to the Base Rate plus the applicable margin plus 2.00%. The term loan amortizes quarterly at the rate of 0.25% of the outstanding amount of the term
loan during the first six years, with the balance payable in equal quarterly installments during
the seventh year. The term loan is required to be paid in full on July 7, 2011. We are entitled to
voluntarily prepay the term loan at any time, in whole or in part, without premium or penalty. We must make mandatory prepayments of the term loan utilizing funds derived from certain
proceeds as follows: (i) 100% of the net cash proceeds of the sale or disposition of our property
and assets and that of our subsidiaries (other than net cash proceeds of sales or dispositions of
inventory in the ordinary course of business and net cash proceeds less than a specified amount
that are reinvested in other assets useful in our business within 360 days); (ii) 100% of the net
cash proceeds of insurance paid on account of any loss by us or our subsidiaries of any property or
assets, other than net cash proceeds less than a specified amount that are reinvested in other
assets useful in our business or that of our subsidiaries (or used to replace damaged or destroyed
assets) within 360 days of receipt thereof; (iii) 50% of the net cash proceeds received from the
issuance of equity securities by us or our subsidiaries (other than issuances pursuant to employee
stock plans); (iv) 100% of the net cash proceeds received from the incurrence of indebtedness by us
or our subsidiaries (other than indebtedness otherwise permitted under the documentation for the
Senior Facilities), payable no later than the first business day following the date of receipt; and
(v) 100% (subject to reduction if certain financial performance measures are obtained) of excess
cash flow payable within 105 days of fiscal year end. Mandatory prepayments are applied to
scheduled amortization payments on the term loan on a pro rata basis. As a result of the amount of our calculation of excess cash flow, as defined in our credit
agreement, we elected to make a prepayment of $10 million on December 16, 2004. We have no
additional mandatory prepayment requirement for 2004, based on the calculation of excess cash flow. Revolving Facility The Revolving Facility is a $30 million revolving credit facility that may be used by us for
revolving loans and letters of credit including letters of credit to secure the Hedges and other
hedging transactions. Revolving loans may be borrowed anytime beginning July 7, 2004 and ending on July 7, F-22




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##### Table of Contents



2010. Proceeds of the revolving loan may be used for ongoing working capital requirements and
general corporate purposes and up to $15 million for the issuance of letters of credit (in addition
to the letters of credit provided under the letter of credit facility described below) to provide
credit support for our obligations under the Hedge Agreement and other hedging transactions. An
additional $5 million of letters of credit may be obtained during the term of the Revolving
Facility for general corporate purposes. All or a portion of the revolving loans will bear interest, at our option, either at the Base
Rate (as discussed above under Term Facility) plus a specified margin subject to adjustment or at
the Eurodollar Rate (as discussed above under Term Facility) plus a specified margin subject to
adjustment. Interest on any portion of the revolving loan bearing interest based on the Based Rate
is payable on March 31, June 30, September 30 and December 31 of each year. Interest on any
portion of the revolving loan bearing interest based on the Eurodollar Rate is payable at the end
of each interest period, and if an interest period is longer than three months, every three months
during the interest period. Interest on overdue revolving loan amounts accrues at a rate equal to
the Base Rate plus the applicable margin plus 2.00%. Letters of credit issued under the revolving facility accrue fees equal to a specified rate
per annum on the average daily maximum amount available to be drawn under such letters of credit.
Letter of credit fees are payable quarterly in arrears on January 1, April 1, July 1, and October 1
of each year. In addition, a fronting fee on the average daily maximum amount available to be
drawn under such letters of credit will be payable to the issuing bank for each letter of credit. We are required to pay a commitment fee equal to 0.50% per annum times the daily average
undrawn portion of the revolving facility (reduced by the amount of letters of credit issued and
outstanding under the revolving facility) which shall accrue from July 7, 2004 and shall be payable
quarterly in arrears on January 1, April 1, July 1, and October 1 of each year. The revolving loan does not amortize. The revolving loan is required to be paid in full on
July 7, 2010. We are entitled to voluntarily prepay the revolving loan at any time, in whole or in
part, without premium or penalty. Any portion of the revolving loan that is prepaid may be
reborrowed. Once the term loan has been repaid in full, we must make mandatory prepayments of the
revolving loan on the same basis as described above in the discussion of the term loan. Letter of Credit Facility The Letter of Credit Facility provides for the issuance of up to $40 million of letters of
credit. Letters of credit under the Letter of Credit Facility may be obtained any time beginning on
July 7, 2004 and ending on July 7, 2010. These letters of credit may be used only to provide credit
support for our obligations under the Hedge Agreement and other hedging transactions. Letters of credit issued under the Letter of Credit Facility accrue fees equal to a specified
rate per annum on the average daily maximum amount available to be drawn under such letters of
credit. These letter of credit fees are payable quarterly in arrears on January 1, April 1, July 1,
and October 1 of each year. In addition, a fronting fee on the average daily maximum amount
available to be drawn under such letters of credit will be payable to the issuing bank for each
letter of credit. We are required to pay an annual commitment fee based upon the daily average undrawn portion
of the Letter of Credit Facility (reduced by the amount of letters of credit issued and outstanding
under the Letter of Credit Facility) which shall accrue from July 7, 2004 and shall be payable
quarterly in arrears on January 1, April 1, July 1, and October 1 of each year. F-23




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##### Table of Contents



Once the term loan and the revolving loan has been repaid in full, we must apply the amounts
that would otherwise be mandatory prepayments to cash collateralize our obligations to the lenders
under the letters of credit. Guarantees and Security Each of our existing and subsequently acquired domestic (and, to the extent no material
adverse tax consequences would result, foreign) subsidiaries (other than Immaterial Subsidiaries)
will guarantee all obligations under the Senior Facilities. The Senior Facilities, each guaranty and any interest rate hedging obligations that we or our
subsidiaries have entered into with a lender or our affiliates are secured by first-priority
security interests in certain of our assets and those of our subsidiaries, subject to permitted
liens. This security includes a first-priority security interest in all of our capital stock and
all capital stock of each of our domestic subsidiaries (other than Immaterial Subsidiaries) and all
intercompany debt. Our obligations under the Hedge Agreement, to the extent not secured by cash or letters of
credit, are secured by second-priority security interests in the assets securing the Senior
Facilities. The Notes are secured by second-priority security interests in the assets securing the
Senior Facilities and the Hedge Agreement. The priority of the security interests and related
creditor rights with respect to the Senior Facilities, the Hedge Agreement, and the Notes are
described in the intercreditor agreement. Covenants Our Senior Facilities contain customary affirmative and negative covenants for senior
financings of this kind including:  
    a minimum interest coverage covenant;
    a capital expenditures covenant;
    a maximum total first-priority senior leverage ratio covenant;
    a covenant imposing limitations on exploration and drilling capital expenditures (other
than in connection with estimated proved undeveloped reserves);
    a covenant imposing maximum total leverage to PV-10 of our total estimated proved reserves;
    a covenant imposing a limitation on our indebtedness;
    a covenant imposing limitations on liens; and
    a covenant imposing limitations on restricted payments. Events of Default Our Senior Facilities contain customary events of default including:  
    failure to make payments when due;
    defaults under the Hedge Agreement;
    defaults under other agreements or instruments of indebtedness;
    noncompliance with covenants;
    breaches of representations and warranties;
    bankruptcy;
    judgments in excess of a specified amount;
    ERISA defaults;
    impairment of security interests in collateral; F-24




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##### Table of Contents




    invalidity of guarantees; and
    change of control. At the time of the Merger all outstanding amounts due under the then existing revolving credit
were repaid. As of September 30, 2004, all of the $225 million aggregate principal amount of
9-7/8% Senior Subordinated Notes due 2007 were tendered and all of the amount had been paid. From time to time the Company may enter into interest rate swaps to hedge the interest rate
exposure associated with the credit facility, whereby a portion of the Companys floating rate
exposure is exchanged for a fixed interest rate. There were no interest rate swaps in 2004, 2003
or 2002. At December 31, 2004, the aggregate long-term debt maturing in the next five years is as
follows: $1,005,000 (2005); $1,006,000 (2006); $1,007,000 (2007); $1,008,000 (2008) and
$278,071,000 (2009 and thereafter). Our term loan facility requires mandatory prepayments annually
based on the calculation of excess cash flow, as defined in the agreement. The future maturities
above assume no excess cash flow in each year.  (10)
    Leases The Company leases certain computer equipment, vehicles, natural gas compressors and office
space under noncancelable agreements with lease periods of one to five years. Rent expense
amounted to $1.7 million for the successor companys 183 day period ended December 31, 2004, and
$1.7 million, $2.9 million and $2.4 million for the predecessor companys 183 day period ended July
1, 2004 and the years ended December 31, 2003 and 2002, respectively. The Company also leases certain computer equipment accounted for as capital leases. Property
and equipment includes $273,000 and $506,000 of computer equipment under capital leases at December
31, 2004 and 2003, respectively. Accumulated depreciation for such equipment includes
approximately $60,000 and $298,000 at December 31, 2004 and 2003, respectively. Future minimum commitments under leasing arrangements at December 31, 2004 were as follows: Operating
    
    
    CapitalYear Ending December 31, 2004
    
    Leases
    
    
    Leases(in thousands)2005
    
    $
    3,453
    
    
    $
    962006
    
    
    2,976
    
    
    
    712007
    
    
    2,138
    
    
    
    362008
    
    
    333
    
    
    
    22009 and thereafter
    
    
    42
    
    
    
    Total minimum rental payments
    
    $
    8,942
    
    
    
    205Less amount representing interest
    
    
    
    
    
    
    5Present value of net minimum rental payments
    
    
    
    
    
    
    200Less current portion
    
    
    
    
    
    
    94Long-term capitalized lease obligations
    
    
    
    
    
    $
    106
  (11)
    Stock Option Plans We have a 1997 non-qualified stock option plan under which we are authorized to issue up to
1,824,195 shares of common stock to officers and employees. The exercise price of options may not
be F-25




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##### Table of Contents



less than the fair market value of a share of common stock on the date of grant. Options expire
on the tenth anniversary of the grant date unless cessation of employment causes earlier
termination. As of December 31, 2004, no options were outstanding under the plan. Stock option activity consisted of the following: WeightedAverageNumber of
    
    
    ExerciseShares
    
    
    PriceBalance at December 31, 2001
    
    
    781,606
    
    
    $
    0.97Granted
    
    
    35,000
    
    
    
    2.14Forfeitures
    
    
    (52,999
    )
    
    
    1.58Exercised or put
    
    
    (79,151
    )
    
    
    0.07Balance at December 31, 2002
    
    
    684,456
    
    
    
    1.09Granted
    
    
    77,500
    
    
    
    2.14Forfeitures
    
    
    (781
    )
    
    
    0.30Exercised or put
    
    
    (144,854
    )
    
    
    0.83Balance at December 31, 2003
    
    
    616,321
    
    
    
    1.29Granted
    
    
    17,500
    
    
    
    3.97Forfeitures
    
    
    (7,500
    )
    
    
    2.14Exercised or put
    
    
    (137,478
    )
    
    
    0.84Surrendered at Merger
    
    
    (488,843
    )
    
    
    1.49Balance at December 31, 2004
    
    
    Options exercisable at December 31, 2004
    
    
    
 The
weighted average fair value of options granted during 2004, 2003 and
2002 was $0.87, $0.49 and $0.52, respectively. F-26




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##### Table of Contents



(12) Taxes The provision (benefit) for income taxes on income from continuing operations before
cumulative effect of change in accounting principle includes the following (in thousands): SuccessorCompany
    
    
    
    Predecessor CompanyFor the 183Day Period
    
    
    
    For the 183from July 2,
    
    
    
    Day Period2004 to
    
    
    
    from JanuaryDecember 31,
    
    
    
    1, 2004 to July
    
    
    Year ended December 31,2004
    
    
    
    1, 2004
    
    
    2003
    
    
    2002CurrentFederal
    
    $
    (29
    )
    
    
    $
    (379
    )
    
    $
    
    
    
    $
    (190
    )State
    
    
    (146
    )
    
    
    
    (722
    )
    
    
    
    
    
    
    76(175
    )
    
    
    
    (1,101
    )
    
    
    
    
    
    
    (114
    )DeferredFederal
    
    
    482
    
    
    
    
    (3,185
    )
    
    
    3,111
    
    
    
    4,934State
    
    
    (2,521
    )
    
    
    
    519
    
    
    
    99
    
    
    
    430(2,039
    )
    
    
    
    (2,666
    )
    
    
    3,210
    
    
    
    5,364Total
    
    $
    (2,214
    )
    
    
    $
    (3,767
    )
    
    $
    3,210
    
    
    $
    5,250
 The effective tax rate for income from continuing operations before cumulative effect of
change in accounting principle differs from the U.S. federal statutory tax rate as follows: SuccessorCompany
    
    
    
    Predecessor CompanyFor the 183
    
    
    
    For the 183Day Period
    
    
    
    Day Periodfrom July 2,
    
    
    
    from2004 to
    
    
    
    January 1,December
    
    
    
    2004 to July
    
    
    Year ended December 31,31, 2004
    
    
    
    1, 2004
    
    
    2003
    
    
    2002Statutory federal income tax rate
    
    
    35.0
    %
    
    
    
    35.0
    %
    
    
    35.0
    %
    
    
    35.0
    %Increases (reductions) in taxes resulting from:State income taxes, net of federal tax benefit
    
    
    130.9
    
    
    
    
    0.6
    
    
    
    0.7
    
    
    
    2.3Transaction related expenses
    
    
    
    
    
    
    
    (17.5
    )
    
    
    
    
    
    
    Permanent differences
    
    
    1.2
    
    
    
    
    
    
    
    
    
    
    
    
    Other, net
    
    
    
    
    
    
    
    
    
    
    
    (0.7
    )
    
    
    (0.3
    )Effective income tax rate for the period
    
    
    167.1
    %
    
    
    
    18.1
    %
    
    
    35.0
    %
    
    
    37.0
    %
 Changes in the effective state tax rate due to changes in the state apportionment rates are
included in state income taxes, net of federal income tax benefit. On December 30, 2004, we merged
our two subsidiaries, COG and WLD, into Belden & Blake Corporation. As a result of the mergers our
effective tax rate on deferred taxes changed. As a result, we recorded a $1.5 million state tax
benefit in the successor period. F-27




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##### Table of Contents



Significant components of deferred income tax liabilities and assets are as follows (in
thousands): December 31,
    
    
    December 31,2004
    
    
    2003Deferred income tax liabilities:Property and equipment, net
    
    $
    157,539
    
    
    $
    48,459Other, net
    
    
    2,128
    
    
    
    Total deferred income tax liabilities
    
    
    159,667
    
    
    
    48,459Deferred income tax assets:Accrued expenses
    
    
    776
    
    
    
    1,224Asset retirement obligations
    
    
    5,607
    
    
    
    1,757Fair value of derivatives
    
    
    30,412
    
    
    
    8,254Net operating loss carryforwards
    
    
    23,865
    
    
    
    28,605Tax credit carryforwards
    
    
    1,412
    
    
    
    913Other, net
    
    
    550
    
    
    
    534Valuation allowance
    
    
    (1,391
    )
    
    
    (5,388
    )Total deferred income tax assets
    
    
    61,231
    
    
    
    35,899Net deferred income tax liability
    
    $
    98,436
    
    
    $
    12,560Long-term liability
    
    $
    108,994
    
    
    $
    19,413Current asset
    
    
    (10,558
    )
    
    
    (6,853
    )Net deferred income tax liability
    
    $
    98,436
    
    
    $
    12,560
 SFAS No. 109 requires a valuation allowance to be recorded when it is more likely than not
that some or all of the deferred tax assets will not be realized. The valuation allowance relates
principally to certain state net operating loss carryforwards which we estimate would expire before
they could be used. At December 31, 2004, we had approximately $46 million of net operating loss carryforwards
available for federal income tax reporting purposes. These net operating loss carryforwards, if
unused, will expire in 2019 through 2023. We also had state net
operating losses of $127 million
which expire between 2007 and 2023. The net operating losses are subject to annual limitations due
to IRC Section 382 as a result of the Merger in 2004. We do not believe the application of Section
382 hinders our ability to utilize the losses and, accordingly, no valuation allowance has been
recorded. We have alternative minimum tax credit carryforwards of approximately $1.4 million which
have no expiration date. We have approximately $1.0 million of statutory depletion carryforwards,
which have no expiration date. (13) Profit Sharing and Retirement Plans We have a non-qualified profit sharing arrangement under which we contribute discretionary
amounts determined by the compensation committee of our Board of Directors based on attainment of
performance targets. Amounts are allocated to substantially all employees based on relative
compensation. We expensed $428,000 for the successor companys 183 day period ended December 31,
2004, and $544,000, $1.3 million and $1.1 million for the predecessor companys 183 day period
ended July 1, 2004 and the years ended December 31, 2003 and 2002, respectively, for contributions
to the profit sharing plan and discretionary bonuses. All amounts were paid in cash. As of December 31, 2004, we have a qualified defined contribution plan (a 401(k) plan)
covering substantially all of the employees of the Company. Eligible employees may make voluntary
contributions which the Company matches $1.00 for every $1.00 contributed up to 4% of an employees
annual F-28




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##### Table of Contents



compensation and a $0.50 match for every $1.00 contributed up to the next 2% of compensation.
Retirement plan expense amounted to $121,000 for the successor companys 183 day period ended
December 31, 2004, and $237,000, $433,000 and $557,000 for the predecessor companys 183 day period
ended July 1, 2004 and the years ended December 31, 2003 and 2002, respectively. (14) Commitments and Contingencies In April 2002, we were notified of a claim by an overriding royalty interest owner in Michigan
alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms
of several farmout agreements. We believe there will be no material amount payable above and
beyond the amount accrued as of December 31, 2004 and therefore, the result will have no material
adverse effect on our financial position, results of operation or cash flows. We were audited by the state of West Virginia for the years 1996 through 1998. The state
assessed taxes which we contested and filed a petition for reassessment. In February 2003, we were
notified by the State Tax Commissioner of West Virginia that our petition for reassessment had been
denied and taxes due, plus accrued interest, are now payable. We disagreed with the decision,
appealed, and received a favorable ruling. The state did not appeal the Circuit Court decision. We
received a $324,000 refund of our appeal bond and expect to receive a refund of overpaid severance
taxes of approximately $100,000 plus interest. In February 2000, four individuals filed a suit in Chautauqua County, New York on their own
behalf and on the behalf of others similarly situated, seeking damages for the alleged difference
between the amount of lease royalties actually paid and the amount of royalties that allegedly
should have been paid. Other natural gas producers in New York were served with similar
complaints. We believe the complaint is without merit and are defending the complaint vigorously.
Although the outcome is still uncertain, we believe the action will not have a material adverse
effect on our financial position, results of operations or cash flows. We no longer own the wells
that were subject to the suit. We are involved in several lawsuits arising in the ordinary course of business. We believe
that the result of such proceedings, individually or in the aggregate, will not have a material
adverse effect on our financial position, results of operations or cash flows. Environmental costs, if any, are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past operations and that have
no future economic benefits are expensed as incurred. Expenditures that extend the life of the
related property or reduce or prevent future environmental contamination are capitalized.
Liabilities related to environmental matters are only recorded when an environmental assessment
and/or remediation obligation is probable and the costs can be reasonably estimated. Such
liabilities are undiscounted unless the timing of cash payments for the liability are fixed or
reliably determinable. At December 31, 2004, no significant environmental remediation obligation
exists which is expected to have a material effect on our financial position, results of operations
or cash flows. F-29




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##### Table of Contents



(15) Supplemental Disclosure of Cash Flow Information SuccessorCompany
    
    
    
    Predecessor Company183 Day
    
    
    
    183 DayPeriod from
    
    
    
    Period fromJuly 2, 2004
    
    
    
    January 1,to December
    
    
    
    2004 to July
    
    
    Year ended December 31,(in thousands)
    
    31, 2004
    
    
    
    1, 2004
    
    
    2003
    
    
    2002Cash paid during the period for:Interest
    
    $
    4,508
    
    
    
    $
    12,686
    
    
    $
    25,427
    
    
    $
    23,750Income taxes, net of refunds
    
    
    (25
    )
    
    
    
    
    
    
    
    172
    
    
    
    (221
    )Non-cash investing and financing activities:Acquisition of assets in exchange for long-term liabilities
    
    
    137
    
    
    
    
    
    
    
    
    136
    
    
    
    281Cumulative effect of change in accounting principle, net of tax
    
    
    
    
    
    
    
    
    
    
    
    2,397
    
    
    
    
 (16) Fair Value of Financial Instruments The fair value of the financial instruments disclosed herein is not representative of the
amount that could be realized or settled, nor does the fair value amount consider the tax
consequences, if any, of realization or settlement. The amounts in the financial statements for
cash equivalents, accounts receivable and notes receivable approximate fair value due to the short
maturities of these instruments. The recorded amounts of outstanding bank and other long-term debt
approximate fair value because interest rates are based on LIBOR or the prime rate or due to the
short maturities. The $192.5 million of our Senior Secured Notes due 2012 had an approximate fair
value of $196.8 million at December 31, 2004 based on quoted market prices. The $89.5 million
outstanding in our senior secured term loan had an approximate fair value of $90.7 million at
December 31, 2004 based on quoted market prices. From time to time we may enter into a combination of futures contracts, commodity derivatives
and fixed-price physical contracts to manage its exposure to natural gas or oil price volatility.
We employ a policy of hedging gas production sold under NYMEX-based contracts by selling
NYMEX-based commodity derivative contracts. Our NYMEX crude oil swaps are sold locally at posted
price which is different from the NYMEX price. Historically there has been a high correlation
between the posted price and NYMEX. The contracts may take the form of futures contracts, swaps,
collars or options which are placed with major financial institutions that we believe are minimal
credit risks. At December 31, 2004, our derivative contracts consisted of natural gas swaps,
collars and options and crude oil swaps. Qualifying derivative contracts are designated as cash
flow hedges. We incurred pre-tax losses on our hedging activities of $22.3 million in 2004 and
$10.3 million in 2003 and a pre-tax gain of $21.6 million in 2002. At December 31, 2004, the fair
value of futures contracts covering 2005 through 2013 oil and gas production represented an
unrealized loss of $78.4 million. F-30




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##### Table of Contents



(17) Supplementary Information on Oil and Gas Activities The following disclosures of costs incurred related to oil and gas activities from continuing
operations are presented in accordance with SFAS 69. SuccessorCompany
    
    
    
    Predecessor Company183 Day
    
    
    
    183 DayPeriod from
    
    
    
    Period fromJuly 2, 2004 to
    
    
    
    January 1,December 31,
    
    
    
    2004 to July 1,
    
    
    Year ended December 31,(in thousands)
    
    2004
    
    
    
    2004
    
    
    2003
    
    
    2002Acquisition costs:Proved properties
    
    $
    106
    
    
    
    $
    
    
    
    $
    3,923
    
    
    $
    1,724Unproved properties
    
    
    229
    
    
    
    
    286
    
    
    
    1,430
    
    
    
    1,643Developmental costs
    
    
    11,357
    
    
    
    
    9,688
    
    
    
    16,440
    
    
    
    16,237Exploratory costs
    
    
    2,750
    
    
    
    
    2,717
    
    
    
    6,849
    
    
    
    8,834Estimated asset retirement obligations incurred
    
    
    101
    
    
    
    
    9
    
    
    
    268
    
    
    
    
 Estimated Proved Oil and Gas Reserves (Unaudited) Our estimated proved developed and estimated proved undeveloped reserves are all located
within the United States. We caution that there are many uncertainties inherent in estimating
proved reserve quantities and in projecting future production rates and the timing of development
expenditures. In addition, estimates of new discoveries are more imprecise than those of
properties with a production history. Accordingly, these estimates are expected to change as
future information becomes available. Material revisions of reserve estimates may occur in the
future, development and production of the oil and gas reserves may not occur in the periods
assumed, and actual prices realized and actual costs incurred may vary significantly from those
used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that
geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future
years from known reservoirs under economic and operating conditions existing at the time the
estimates were made. Estimated proved developed reserves are estimated proved reserves expected to
be recovered through wells and equipment in place and under operating methods being used at the
time the estimates were made. The estimates of proved reserves as of December 31, 2004, 2003 and
2002 have been prepared by Wright & Company, Inc., independent petroleum consultants. The
estimated proved reserve information for the 2004 predecessor company 183 day period ended July 1,
2004, is based on our internal engineering estimates. F-31




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##### Table of Contents



The following table sets forth changes in estimated proved and estimated proved developed
reserves for the periods indicated: Successor Company
    
    
    
    Predecessor Company
    
    
    TotalOil
    
    
    Gas
    
    
    
    Oil
    
    
    Gas
    
    
    Oil
    
    
    Gas(Mbbl) (1)
    
    
    (Mmcf) (2)
    
    
    
    (Mbbl) (1)
    
    
    (Mmcf) (2)
    
    
    (Mbbl) (1)
    
    
    (Mmcf) (2)
    
    
    Mmcfe (3)December 31, 2001
    
    
    
    
    
    
    
    
    
    
    
    5,573
    
    
    
    312,800
    
    
    
    5,573
    
    
    
    312,800
    
    
    
    346,238Extensions and discoveries
    
    
    
    
    
    
    
    
    
    
    
    32
    
    
    
    2,382
    
    
    
    32
    
    
    
    2,382
    
    
    
    2,574Purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    13
    
    
    
    21,300
    
    
    
    13
    
    
    
    21,300
    
    
    
    21,378Sale of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    (729
    )
    
    
    (8,976
    )
    
    
    (729
    )
    
    
    (8,976
    )
    
    
    (13,350
    )Revisions of previous estimates
    
    
    
    
    
    
    
    
    
    
    
    2,206
    
    
    
    23,894
    
    
    
    2,206
    
    
    
    23,894
    
    
    
    37,130Production
    
    
    
    
    
    
    
    
    
    
    
    (521
    )
    
    
    (15,882
    )
    
    
    (521
    )
    
    
    (15,882
    )
    
    
    (19,008
    )December 31, 2002
    
    
    
    
    
    
    
    
    
    
    
    6,574
    
    
    
    335,518
    
    
    
    6,574
    
    
    
    335,518
    
    
    
    374,962Extensions and discoveries
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,437
    
    
    
    
    
    
    
    1,437
    
    
    
    1,437Purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    8,988
    
    
    
    
    
    
    
    8,988
    
    
    
    8,988Sale of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    (1
    )
    
    
    (41
    )
    
    
    (1
    )
    
    
    (41
    )
    
    
    (47
    )Revisions of previous estimates
    
    
    
    
    
    
    
    
    
    
    
    16
    
    
    
    (12,976
    )
    
    
    16
    
    
    
    (12,976
    )
    
    
    (12,880
    )Production
    
    
    
    
    
    
    
    
    
    
    
    (413
    )
    
    
    (14,837
    )
    
    
    (413
    )
    
    
    (14,837
    )
    
    
    (17,315
    )December 31, 2003
    
    
    
    
    
    
    
    
    
    
    
    6,176
    
    
    
    318,089
    
    
    
    6,176
    
    
    
    318,089
    
    
    
    355,145Extensions and discoveries
    
    
    51
    
    
    
    1,005
    
    
    
    
    
    
    
    
    1,245
    
    
    
    51
    
    
    
    2,250
    
    
    
    2,556Purchase of reserves in place
    
    
    
    
    
    
    1,319
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,319
    
    
    
    1,319Sale of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Capital C merger
    
    
    6,117
    
    
    
    320,637
    
    
    
    
    (6,117
    )
    
    
    (320,637
    )
    
    
    
    
    
    
    
    
    
    
    Revisions of previous estimates
    
    
    (397
    )
    
    
    (64,065
    )
    
    
    
    130
    
    
    
    9,000
    
    
    
    (267
    )
    
    
    (55,065
    )
    
    
    (56,667
    )Production
    
    
    (192
    )
    
    
    (7,570
    )
    
    
    
    (189
    )
    
    
    (7,697
    )
    
    
    (381
    )
    
    
    (15,267
    )
    
    
    (17,553
    )December 31, 2004
    
    
    5,579
    
    
    
    251,326
    
    
    
    
    
    
    
    
    
    
    
    
    5,579
    
    
    
    251,326
    
    
    
    284,800Proved developed reservesDecember 31, 2002
    
    
    
    
    
    
    
    
    
    
    
    4,103
    
    
    
    206,719
    
    
    
    4,103
    
    
    
    206,719
    
    
    
    231,337December 31, 2003
    
    
    
    
    
    
    
    
    
    
    
    3,809
    
    
    
    207,842
    
    
    
    3,809
    
    
    
    207,842
    
    
    
    230,696December 31, 2004
    
    
    3,448
    
    
    
    200,231
    
    
    
    
    
    
    
    
    
    
    
    
    3,448
    
    
    
    200,231
    
    
    
    220,919
   (1)
    
    Thousand barrels(2)
    
    Million cubic feet(3)
    
    Million cubic feet equivalent barrels are
converted to Mcfe based on one bbl of oil to six Mcf of natural gas
equivalent During 2004, the primary focus of our drilling program was on proved undeveloped locations.
The result of this program converted approximately 16.3 Bcfe of estimated proved undeveloped
reserves into estimated proved developed reserves. Production for 2004 was 17.6 Bcfe. Revisions of previous estimates accounted for a decrease of approximately 56.7 Bcfe. The
majority of this reduction was in the estimated proved undeveloped reserves category. Of this
decrease, approximately 21.2 Bcfe related to engineering revisions, which resulted from our
analysis of our drilling results in the past several years as compared to reserve estimates of
proved undeveloped well locations in our prior years reserve report. Additionally, as a result of
higher future development and operating costs, total estimated proved reserves were reduced
by approximately 17.5 Bcfe. Increases in our estimated proved
reserves of 9.2 Bcfe resulted from increases in commodity prices at December 31, 2004 compared to
2003. Furthermore, approximately 19.7 Bcfe of estimated proved undeveloped reserves were
reclassified to an unproved category, as the locations were more than one direct offset spacing
unit from a productive well. During 2004, we performed a lease review of our proved undeveloped locations, which, due to
leases that have expired or that we have surrendered, resulted in a downward adjustment of
approximately 7.4 Bcfe to our estimated proved undeveloped reserves at December 31, 2004. F-32




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##### Table of Contents



Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
(Unaudited) The following tables, which present a standardized measure of discounted future net cash flows
and changes therein relating to estimated proved oil and gas reserves, are presented pursuant to
SFAS No. 69. In computing this data, assumptions other than those required by the FASB could
produce different results. Accordingly, the data should not be construed as representative of the
fair market value of our estimated proved oil and gas reserves. The following assumptions have
been made:  -
    Future revenues were based on year-end oil and gas prices. Future
price changes were included only to the extent provided by existing
contractual agreements.-
    Production and development costs were computed using year-end costs
assuming no change in present economic conditions.-
    Future net cash flows were discounted at an annual rate of 10%.-
    Future income taxes were computed using the approximate statutory tax
rate and giving effect to available net operating losses, tax credits
and statutory depletion. The standardized measure of discounted future net cash flows relating to estimated proved oil
and gas reserves is presented below: SuccessorCompany
    
    
    
    Predecessor CompanyDecember 31,2004
    
    
    
    2003
    
    
    2002(in thousands)Estimated future cash inflows (outflows)Revenues from the sale of oil and gas
    
    $
    1,854,119
    
    
    
    $
    2,152,092
    
    
    $
    1,855,414Production costs
    
    
    (534,781
    )
    
    
    
    (470,604
    )
    
    
    (423,643
    )Development costs
    
    
    (126,750
    )
    
    
    
    (168,301
    )
    
    
    (167,295
    )Future net cash flows before income taxes
    
    
    1,192,588
    
    
    
    
    1,513,187
    
    
    
    1,264,476Future income taxes
    
    
    (397,606
    )
    
    
    
    (505,243
    )
    
    
    (412,193
    )Future net cash flows
    
    
    794,982
    
    
    
    
    1,007,944
    
    
    
    852,28310% timing discount
    
    
    (449,270
    )
    
    
    
    (608,767
    )
    
    
    (519,464
    )Standardized measure of discounted
future net cash flows
    
    $
    345,712
    
    
    
    $
    399,177
    
    
    $
    332,819
 At December 31, 2004, as specified by the SEC, the prices for oil and natural gas used in this
calculation were regional cash price quotes on the last day of the year except for volumes subject
to fixed price contracts. The weighted average prices for the total estimated proved reserves at
December 31, 2004 were $6.49 per Mcf of natural gas and $40.12 per barrel of oil. We do not
include our natural gas and crude oil hedging financial instruments, consisting of swaps and
collars, in the determination of our oil and gas reserves. F-33




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##### Table of Contents



The principal sources of changes in the standardized measure of future net cash flows are as
follows: SuccessorCompany
    
    
    
    Predecessor Company183 Day
    
    
    
    183 DayPeriod from
    
    
    
    Period fromJuly 2, 2004 to
    
    
    
    January 1,December 31,
    
    
    
    2004 to July 1,
    
    
    Year ended December 31,2004
    
    
    
    2004
    
    
    2003
    
    
    2002Beginning of year
    
    $
    372,686
    
    
    
    $
    399,177
    
    
    $
    332,819
    
    
    $
    170,152Sale of oil and gas, net of production costs
    
    
    (33,710
    )
    
    
    
    (34,019
    )
    
    
    (63,672
    )
    
    
    (70,367
    )Extensions and discoveries, less related estimated
future development and production costs
    
    
    2,671
    
    
    
    
    1,311
    
    
    
    1,867
    
    
    
    7,153Previously estimated development costs incurred
during the period
    
    
    9,634
    
    
    
    
    6,237
    
    
    
    25,095
    
    
    
    11,974Purchase of reserves in place less
estimated future production costs
    
    
    1,927
    
    
    
    
    
    
    
    
    10,193
    
    
    
    26,385Sale of reserves in place less
estimated future production costs
    
    
    
    
    
    
    
    
    
    
    
    (60
    )
    
    
    (6,227
    )Changes in estimated future development costs
    
    
    38,637
    
    
    
    
    (9,666
    )
    
    
    (26,714
    )
    
    
    (48,190
    )Revisions of previous quantity estimates
    
    
    (131,431
    )
    
    
    
    17,391
    
    
    
    (23,353
    )
    
    
    53,423Net changes in prices and production costs
    
    
    (5,961
    )
    
    
    
    (11,867
    )
    
    
    127,759
    
    
    
    239,368Change in income taxes
    
    
    32,981
    
    
    
    
    (21,141
    )
    
    
    (29,072
    )
    
    
    (105,414
    )Accretion of 10% timing discount
    
    
    28,483
    
    
    
    
    28,751
    
    
    
    47,959
    
    
    
    21,150Changes in production rates (timing) and other
    
    
    29,795
    
    
    
    
    (3,488
    )
    
    
    (3,644
    )
    
    
    33,412End of period
    
    $
    345,712
    
    
    
    $
    372,686
    
    
    $
    399,177
    
    
    $
    332,819
 (18) Industry Segment Financial Information We operate in one reportable segment, as an independent energy company engaged in producing
oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the
economic performance of producing oil and gas properties; and marketing and gathering natural gas
for delivery to intrastate and interstate gas transmission pipelines. Our operations are conducted
entirely in the United States. Major customers During 2004, we had three customers that each accounted for 10% or more of consolidated
revenues with sales of $19.9 million, $14.6 million and $12.6 million, respectively. During 2003,
we had three customers that each accounted for 10% or more of consolidated revenues with sales of
$19.8 million, $11.5 million and $10.8 million, respectively. One customer accounted for more than
10% of consolidated revenues during each of the year ended December 31, 2002, sales to which
amounted to $12.9 million. F-34




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##### Table of Contents



(19) Quarterly Results of Operations (Unaudited) The results of operations for the four quarters of 2004 and 2003 are shown below (in
thousands). Predecessor Company
    
    
    
    Successor Company92 Day
    
    
    
    91 DayPeriod from
    
    
    
    Period fromApril 1, 2004
    
    
    
    July 2, 2004to July 1,
    
    
    
    to SeptemberFirst
    
    
    2004
    
    
    
    30, 2004
    
    
    Fourth2004Operating revenues
    
    $
    24,945
    
    
    $
    25,419
    
    
    
    $
    23,847
    
    
    $
    26,417Gross profit
    
    
    10,682
    
    
    
    10,977
    
    
    
    
    5,659
    
    
    
    6,653Income (loss) from continuing operations before
cumulative effect of change in accounting principle
    
    
    2,366
    
    
    
    (19,400
    )
    
    
    
    (2,642
    )
    
    
    3,532(Loss) income from discontinued operations, net of tax
    
    
    (314
    )
    
    
    29,182
    
    
    
    
    
    
    
    
    Net income (loss)
    
    
    2,052
    
    
    
    9,782
    
    
    
    
    (2,642
    )
    
    
    3,532
 Predecessor CompanyFirst
    
    
    Second
    
    
    Third
    
    
    Fourth2003Operating revenues
    
    $
    22,678
    
    
    $
    23,494
    
    
    $
    23,966
    
    
    $
    25,010Gross profit
    
    
    8,404
    
    
    
    10,375
    
    
    
    10,289
    
    
    
    8,895Income from continuing operations before
cumulative effect of change in accounting principle
    
    
    719
    
    
    
    2,456
    
    
    
    1,935
    
    
    
    850Loss from discontinued operations, net of tax
    
    
    (349
    )
    
    
    (843
    )
    
    
    (3,576
    )
    
    
    (5,913
    )Net income (loss)
    
    
    2,768
    
    
    
    1,612
    
    
    
    (1,641
    )
    
    
    (5,063
    )
 Net
income in the 92 day period ended July 1, 2004 was reduced by
$3.4 million from amounts previously reported on Form 10-Q primarily
due to additional transaction expenses related to the Merger. The
loss from discontinued operations in the third and fourth quarters of
2003 increased as a result of certain exploratory dry hole expenses and
impairments reported during those quarters. F-35