-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, OJIx0vmuZn+0TU1lgPRJgk3uPv0gi092K4gxYBC9Hzg2smZ5L9F2y/8Mbz5NB1Xp MUbuWCM0lGC2G6GEX6lkSw== 0001362310-09-005172.txt : 20090410 0001362310-09-005172.hdr.sgml : 20090410 20090410144432 ACCESSION NUMBER: 0001362310-09-005172 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20081231 FILED AS OF DATE: 20090410 DATE AS OF CHANGE: 20090410 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BELDEN & BLAKE CORP /OH/ CENTRAL INDEX KEY: 0000880114 STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381] IRS NUMBER: 341686642 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-20100 FILM NUMBER: 09744995 BUSINESS ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 BUSINESS PHONE: 3304991660 MAIL ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 FORMER COMPANY: FORMER CONFORMED NAME: BELDEN & BLAKE ENERGY CORP /OH DATE OF NAME CHANGE: 19920427 10-K 1 c83251e10vk.htm 10-K 10-K
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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 1934
For the Fiscal Year Ended December 31, 2008
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No. 0-20100
BELDEN & BLAKE CORPORATION
(Exact name of registrant as specified in its charter)
     
Ohio   34-1686642
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification Number)
1001 Fannin Street, Suite 800
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (713) 659-3500
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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes þ No o
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 a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer” and “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o   Accelerated filer o   Non-accelerated filer þ   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
As of February 28, 2009, Belden & Blake Corporation had outstanding 1,534 shares of common stock, no 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.
 
 

 

 

TABLE OF CONTENTS

PART I
Items 1 and 2. BUSINESS AND PROPERTIES
Item 1A. RISK FACTORS
Item 1B. UNRESOLVED STAFF COMMENTS
Item 3. LEGAL PROCEEDINGS
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
Item 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Item 6. SELECTED FINANCIAL DATA
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Item 9A. CONTROLS AND PROCEDURES
Item 9B. OTHER INFORMATION
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE
Item 11. EXECUTIVE COMPENSATION
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
SIGNATURES
Item 15(a) (1) and (2)
EXHIBIT INDEX
Exhibit 10.9
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

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DOCUMENTS INCORPORATED BY REFERENCE:
None.
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,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “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, including the financial and capital market crisis, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described on page 15 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.

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS
Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Btu. A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one-pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Developed acres. Acres spaced or assigned to productive wells.
Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive in another reservoir, or to extend a known reservoir.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMBbl. One million barrels.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Natural gas liquids. The hydrocarbon liquids contained within natural gas.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NYMEX. The New York Mercantile Exchange.
Oil. Crude oil and condensate.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

 

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Proved reserves. Proved oil and natural gas reserves, as defined by the Securities and Exchange Commission (the “SEC”) in Article 4-10(a)(2) of Regulation S-X, are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions. Comprehensive SEC oil and natural gas reserve definitions can be found on the SEC’s website at www.sec.gov/about.forms/regs-x.pdf.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of produceable oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Standardized measure. Standardized measure is the present value of estimated future net revenues (after income taxes) to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as certain general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.
Successful well. A well capable of producing oil and/or natural gas in commercial quantities.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover. Operations on a producing well to restore or increase production.

 

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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. On August 16, 2005, Capital C was acquired by institutional funds managed by EnerVest, Ltd. (“EnerVest”).
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 1001 Fannin Street, Suite 800, Houston, Texas 77002-6707. Our telephone number at that location is (713) 659-3500.
SIGNIFICANT EVENTS
Acquisition by Institutional Funds Managed by EnerVest, Ltd.
On August 16, 2005, the former partners of our direct parent, Capital C, completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest, a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”). The Transaction resulted in a change in control of our company (“Change in Control”).
On July 7, 2004, we, 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 the Merger Sub was merged with and into the Company (the “Merger”), with our company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of our company. The general partner of Capital C was controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P until the Transaction on August 16, 2005.
Credit Agreement
In 2005, we amended and restated our then existing credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.

 

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Effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement. The agreement was entered into to provide for certain waivers and modifications to the debt terms and covenants. This amendment was a direct result of the determination as of December 31, 2008, that the Company, would not maintain compliance with certain financial covenants during 2009 and 2010. Accordingly, on April 9, 2009, our bank group waived the leverage ratio for the quarters ended March 31, 2009 and June 30, 2009 and amended the Amended Credit Agreement to increase the maximum leverage ratio to 5.375 : 1.0 through December 31, 2009, 5.25 : 1.0 at March 31, 2010 and 5.0 : 1.0 at June 30, 2010. The bank group also waived the interest coverage ratio as of June 30, 2009 and amended the Amended Credit Agreement to reduce our minimum interest coverage ratio to 2.0 : 1.0 through March 31, 2010 and 2.25 : 1.0 at June 30, 2010. Additionally, Capital C, our parent, has committed to the Company to provide financial support. Taking into consideration the amended financial covenants and the financial support from Capital C, the Company, as of April 9, 2009, has projected that it would maintain compliance with such amended covenants through 2009 and 2010.
Additionally, the amendment provided that the borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 1.75% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.25% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The agreement was also amended for the following:
  •   Set the Borrowing Base at $100 million.
  •   Set the Borrowing Base redetermination dates to March 15th and September 15th each year.
  •   Prohibit payment of dividends to our shareholder.
  •   Prohibit Senior Secured Note repurchases by the Company.
  •   Prohibit principal or cash interest payments on the Capital C Subordinated Note.
  •   Prohibit borrowings to fund restructuring of the hedge agreements.
  •   Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.
  •   Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.
  •   Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.
At December 31, 2008, we were in compliance with our covenants under the Amended Credit Agreement. Our leverage ratio was 4.25 : 1.0 and the interest coverage ratio was 2.72 : 1.0.
On August 3, 2007, our bank group waived the covenant compliance requirement as of June 30, 2007 and amended the Amended Credit Agreement to increase the maximum leverage ratio from 4.0 : 1.0 to 4.25 : 1.0 for the quarters ending on September 30, 2007 and December 31, 2007. If we had not received this waiver, we would not have complied with our leverage ratio covenant as it would have been 4.07 : 1.0 as of June 30, 2007. On March 24, 2008, our bank group waived the covenant compliance requirement as of December 31, 2007 and amended the Amended Credit Agreement to further increase the maximum leverage ratio to 4.5 : 1.0 through December 31, 2008. If we had not received this waiver and amendment, we would not have complied with our leverage ratio covenant as it would have been 4.38 : 1.0 as of December 31, 2007.
In connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note (“Subordinated Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. The Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. Interest payments on the Subordinated Note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the Subordinated Note by borrowing additional amounts against the Subordinated Note. The interest payments in 2006, the first quarter of 2007 and the first three quarters of 2008 were paid in cash. Interest payments for the last three quarters of 2007 and the fourth quarter of 2008 were made by additional borrowings against the Subordinated Note. The Subordinated Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. Pursuant to the Fourth Amendment to our credit agreement, cash payments for principal or interest on the Subordinated Note are prohibited. The Subordinated Note is subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, a long-term hedging program (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) and notes issued under our Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).
Impairment of goodwill
We recorded a goodwill impairment charge of $90.1 million in the fourth quarter of 2008 due to the significant decline in oil and gas prices. See further discussion in “Critical Accounting Policies and Estimates,” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 9, “Goodwill.”

 

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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 2008, we achieved average net production of approximately 41.8 MMcfe per day consisting of 36.0 MMcf of natural gas and 956 Bbls of oil per day. At December 31, 2008, we owned interests in 4,550 gross (3,608 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with estimated proved reserves totaling 223 Bcfe consisting of 200 Bcf of natural gas and 3.8 MMbbl of oil. The estimated future net cash flows from these reserves had a present value (discounted at 10%) after income taxes of approximately $253 million at December 31, 2008. The weighted average prices related to estimated proved reserves at December 31, 2008 were $6.38 per Mcf for natural gas and $41.00 per Bbl for oil.
We entered into an operating agreement with EnerVest Operating, L.L.C. (“EnerVest Operating”). Under this operating agreement, EnerVest Operating acts as operator of the oil and gas wells, the related gathering systems and production facilities where our interest entitles us to control the appointment of the operator. As operator, EnerVest Operating manages the drilling and completion of wells and the day to day operating and maintenance activities for our assets. At December 31, 2008, Enervest Operating operated approximately 4,006 wells, or 88% of our gross wells representing approximately 97% of the value of our estimated proved developed reserves on a present value (discounted at 10%) basis. At December 31, 2008, we owned leases on 639,724 gross (562,068 net) acres, including 409,268 gross (381,165 net) undeveloped acres.
We own approximately 1,660 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 NYMEX price for gas delivered at the Henry Hub in Louisiana. During 2008, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.45 and $0.08, respectively, higher than the average NYMEX monthly settle price for 2008.

 

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Oil and Gas Reserves
The following table sets forth our estimated proved oil and gas reserves as of December 31, 2006, 2007 and 2008 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,  
    2008     2007     2006  
Estimated proved reserves
                        
Gas (Bcf)
     199.8       227.2       233.0  
Oil (Mbbl)
     3,833       5,149       5,181  
Bcfe
     222.8       258.1       264.1  
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 after income taxes from our estimated proved reserves as of December 31, 2008, determined in accordance with the rules and regulations of the SEC, was $253 million. 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, additional capital investment and income taxes). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 2008 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 derivative financial instruments, consisting of natural gas and crude oil swaps and natural gas basis differential swaps, in the determination of our oil and gas reserves.
                         
    December 31,  
    2008     2007     2006  
Gas (per Mcf)
   $ 6.38     $ 7.54     $ 5.91  
Oil (per Bbl)
     41.00       92.77       57.21  
At December 31, 2008, 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 prices 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.
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 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.

 

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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 have historically exceeded 90%, with production generally lasting longer than 20 years.
We currently own working interests in 3,118 gross (2,800 net) wells in the Appalachian Basin, excluding our coalbed methane wells, which currently produce approximately 21.3 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 2008, we drilled 22 gross (21.8 net) development wells in the Medina Formation in Pennsylvania, 38 gross (38.0 net) development wells in the Clarendon Formation in Pennsylvania, 1 gross (1.0 net) Onondaga development well in Pennsylvania, 6 gross (3.1 net) Clinton development wells in Ohio and 5 gross (5.0 net) Utica Shale development wells in Ohio. We also drilled 3 gross (3.0 net) exploratory dry holes in 2008. Due to a change in market conditions, the anticipated 2009 focus will be primarily in the following three areas: Knox exploration in Ohio, operational reworks and enhancement projects, and Marcellus recompletions and new drilling in Pennsylvania. We will continue to evaluate our development drilling opportunities in our traditional areas such as the Medina and Clarendon formations in Pennsylvania and the Clinton Formation in Ohio as market conditions improve.
Michigan Basin Properties
The Michigan Basin has operational similarities to the Appalachian Basin, including geographic proximity to natural gas markets, which has generally resulted in premium wellhead prices as compared to NYMEX prices. We own working interests in 1,227 gross (603 net) wells in the Michigan Basin which currently produce approximately 16.5 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 2008, we drilled 24 gross (11.6 net) wells to the Antrim Shale Formation. We plan to drill 10 gross (5.6 net) wells in the Antrim Shale Formation in 2009. We also drilled 2 gross and (1.9 net) exploratory dry holes in 2008.
Appalachian Basin — Coalbed Methane Properties
We own a 100% working interest in 205 producing coalbed methane (“CBM”) wells in Pennsylvania and own leases on approximately 63,185 gross (61,078 net) acres, including approximately 53,017 gross (52,708 net) undeveloped CBM acres. Current production from these wells is approximately 2.9 MMcf net per day. We drilled 3 CBM wells in 2008 and have no plans to drill additional CBM wells in 2009.
Oil and Gas Operations and Production
Operations. EnerVest Operating operates 88% of the wells in which we hold working interests. They maintain production field offices in Ohio, Pennsylvania and Michigan. Through these offices, EnerVest Operating reviews our properties to determine what action can be taken to control operating costs and/or improve production.
We own approximately 1,660 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.

 

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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. The average prices shown in the table include the effects of our qualified effective hedging activities. See Note 5 to the Consolidated Financial Statements.
                         
    Year Ended December 31,  
    2008     2007     2006  
 
                        
Production
                        
Gas (MMcf)
     13,217       13,357       14,104  
Oil (Mbbl)
     334       348       373  
Total production (MMcfe)
     15,221       15,446       16,340  
 
Average price (1)
                        
Gas (per Mcf)
   $ 8.62     $ 6.81     $ 8.77  
Oil (per Bbl)
     94.40       67.42       62.78  
Per Mcfe
     9.55       7.41       9.00  
 
Average costs (per Mcfe)
                        
Production expense
   $ 1.73     $ 1.59     $ 1.45  
Production taxes
     0.20       0.15       0.15  
Depletion
     2.31       2.31       2.30  
     
(1)   The average prices presented above include non-cash amounts related to our derivatives as a result of purchase accounting for the Merger and the Transaction. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average prices:
                         
    Year Ended December 31,  
    2008     2007     2006  
Gas (per Mcf)
   $ 9.31     $ 7.34     $ 7.22  
Oil (per Bbl)
     94.40       67.42       62.78  
Per Mcfe
     10.15       7.87       7.67  
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 2008, we spent approximately $28.3 million on development and exploratory drilling and other capital expenditures including exploratory dry hole costs. We drilled 98 gross (83.5 net) development wells to shallow, highly developed formations in our operating area. The results of this drilling activity are shown in the table on page 10. We also drilled 5 gross and (4.9 net) exploratory dry holes on 2008.
In 2009, we expect to spend approximately $15 million on development and exploratory drilling and other capital expenditures. Due to a change in market conditions for oil and natural gas, the anticipated 2009 focus primarily will be in the following three areas: Knox exploration in Ohio, operational reworks and enhancement projects and Marcellus recompletions and new drilling in Pennsylvania. We will continue to evaluate our development drilling opportunities in our traditional areas such as the Antrim play in Michigan, the Medina and Clarendon plays in Pennsylvania and the Clinton play in Ohio.
We were a pioneer in CBM development and production in Pennsylvania, and we presently own a 100% working interest in 205 CBM gas wells in Indiana, Westmoreland and Fayette counties. CBM wells in this area range in depth from 1,200 to 1,500 feet and typically encounter three to six unmined coal seams. We have approximately 63,185 CBM acres currently under lease in Pennsylvania. We currently have no plans to drill CBM wells in 2009.

 

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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.
Typical characteristics of our drilling programs in the shallow, highly developed formations we target are described below:
         
        Range of Average
        Drilling and
        Completion Costs per
    Range of Well Depths   Well
    (in feet)   (in thousands)
Ohio:
        
Clinton
   3,500–5,750   $360–420
Pennsylvania:
        
Coalbed Methane
   1,000–1,600   210–320
Clarendon
   1,100–2,100   120–150
Medina
   5,300–6,200   370–400
Michigan:
        
Antrim
   1,300–2,100   310–370
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, Knox, Utica Shale, Marcellus Shale and Trenton Black River 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.
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 Wells  
    2006     2007     2008     2006(1)     2007     2008  
Productive:
                                                
Gross
     177       96       98       —       —       —  
Net
     170.3       92.0       83.5       —       —       —  
Dry:
                                                
Gross
     2       —       —       1       —       5  
Net
     2.0       —       —       0.5       —       4.9  
Wells in progress:
                                                
Gross
     —       —       —       —       —       —  
Net
     —       —       —       —       —       —  
     
(1)   Includes one well (dry hole) that was classified as a well in progress in 2005.

 

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Disposition of Assets
On March 31, 2006, we sold our interests in 13 Oriskany wells and the associated gas gathering system for approximately $3.3 million, which approximated the net carrying value of such assets.
In March of 2008, we sold a 50-70% option interest in certain deep rights on approximately 201,000 net acres in Ohio and Pennsylvania for $3.0 million.
Employees
As of February 28, 2009, we had no employees. On March 15, 2006, we entered into a joint operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. All of our operating, administrative and technical services are provided by employees of EnerVest or other third parties.
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 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.
Principal Customers
Each of the following customers accounted for 10% or more of our consolidated revenues during 2008: Integrys Energy, National Fuel Resources, Inc. and American Refining Group, Inc. If we were to lose any one of these oil or natural gas purchasers, the loss could temporarily cease production and sale of our oil or natural gas production from the wells subject to contracts with that purchaser. We believe, however, that we would be able promptly to replace the purchaser. We do not believe any of our customers are credit risks.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect our carrying value of the properties.

 

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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 future 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 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 address 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 noncompliance with these environmental requirements, there is no assurance that this trend will continue in the future.

 

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Under the federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws, liability generally is joint and several for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRP”), include current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous Substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRP the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, we have generated and will generate wastes that fall within CERCLA’s definition of Hazardous Substances. We may also be an owner or operator of facilities on which Hazardous Substances have been released. We may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been released and for natural resource damages, as a past or present owner or operator or as an arranger. To our knowledge, we have not been named a PRP under CERCLA nor have any prior owners or operators of our properties been named as PRP’s related to their ownership or operation of such property.
Although oil and gas wastes generally are exempt from regulation as hazardous wastes (“Hazardous Wastes”) under the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, it is possible some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. The U.S. EPA and various state agencies have limited the disposal options for certain wastes, including hazardous wastes and is considering adopting stricter disposal standards for non-hazardous wastes. 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 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. Federal and state laws generally require new and modified sources of air pollutants to obtain permits prior to commencing construction, which may require, among other things, stringent, technical controls. Other federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement agencies can bring actions for failure to strictly comply with air pollution regulations or permits and generally enforce compliance through administrative, civil or criminal enforcement actions, resulting in fines, injunctive relief and imprisonment.
More stringent laws and regulations relating to climate change and greenhouse gases (GHGs) may be adopted in the future and could cause us to incur material expenses in complying with them. The U.S. Congress last session considered climate change-related legislation to regulate GHG emissions that could affect our operations and our regulatory costs, as well as the value of oil and natural gas generally. Although that legislation did not pass, expectations are that Congress will continue to consider some type of climate change legislation and that U.S. EPA may consider climate change-related regulatory initiatives. As a result, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential federal and state initiatives may result in so-called cap-and-trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. These regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce.

 

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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, a term broadly defined, 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, including permit 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 waters of the United States. The OPA imposes strict, joint and several liability on liable responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. 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. Our SPCC plans have been updated to comply with the current regulations. We continue to monitor rapid changes in rules and requirements at both the federal and state level regarding spill prevention. We cannot assure you that costs that may be necessary for compliance with these SPCC and comparable state requirements will not be material.
The federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes impose requirements related to disclosure and organization of certain information related to hazardous materials. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes may require us to organize and/or disclose information about hazardous materials used or produced in our operations.
Producing Well Data
As of December 31, 2008, we owned interests in 4,550 gross (3,608 net) producing oil and gas wells of which approximately 4,006 wells were operated by EnerVest Operating. In the fourth quarter of 2008, our net production was approximately 41.8 MMcfe per day consisting of 36.0 MMcf of natural gas and 956 Bbls of oil per day.
The following table summarizes by state our productive wells at December 31, 2008:
                                                 
    December 31, 2008  
    Gas Wells     Oil Wells     Total  
State   Gross     Net     Gross     Net     Gross     Net  
Ohio
     1,048       893       677       609       1,725       1,502  
 
                                                
Pennsylvania
     1,476       1,392       104       104       1,580       1,496  
 
                                                
New York
     18       7       —       —       18       7  
 
                                                
Michigan
     1,210       601       17       2       1,227       603  
 
                                    
 
                                                
 
     3,752       2,893       798       715       4,550       3,608  
 
                                    

 

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Acreage Data
The following table summarizes by state our gross and net developed and undeveloped acreage at December 31, 2008:
                                                 
    December 31, 2008  
    Developed Acreage     Undeveloped Acreage     Total Acreage  
State   Gross     Net     Gross     Net     Gross     Net  
Ohio
     112,644       64,701       115,151       115,072       227,795       179,773  
 
                                                
Pennsylvania
     50,642       49,907       251,227       226,981       301,869       276,888  
 
                                                
New York
     2,828       2,241       26,805       26,226       29,633       28,467  
 
                                                
Michigan
     64,302       64,014       14,752       11,553       79,054       75,567  
 
                                                
Indiana
     40       40       1,333       1,333       1,373       1,373  
 
                                    
 
                                                
 
     230,456       180,903       409,268       381,165       639,724       562,068  
 
                                    
In prior filings developed acreage included undrilled acreage held by production. Beginning with fiscal year 2008, undrilled acreage held by production is included in undeveloped acreage.
Item 1A. 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. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us. 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 2009 through 2013 production 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 which risk has increased with the current economic and financial crisis; or
  •   a sudden, unexpected event materially impacts natural gas and crude oil prices.
While we believe J. Aron to be a strong and creditworthy counterparty, current disruptions occurring in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

 

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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 Amended Credit Agreement in an amount sufficient to enable us to pay our indebtedness, including the Senior Secured Notes or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the Senior Secured Notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our Amended Credit Agreement and the Senior Secured Notes, on commercially reasonable terms or at all, especially given the current economic and financial market crisis. 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.
We depend upon access to the credit markets to fund our growth strategy. Currently, the credit markets are experiencing an unprecedented disruption which, if it continues for an extended period of time, will adversely affect our growth strategy.
U.S. and international financial and credit markets are experiencing unprecedented volatility and disruption. The current disruption in the financial and credit markets has made it unlikely that we could successfully issue common stock, debt securities or secure a loan to fund our growth in the near future. In addition, the current markets for bank credit facilities are unfavorable to borrowers. If the disruption in the financial markets continues for a substantial period of time, our ability to fund growth may be adversely affected.
Oil and natural gas prices are volatile, and an extended decline in prices would hurt our profitability and financial condition.
While we have entered 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 portion of our production remains 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. If gas prices decreased $1.00 per Mcf, our gas sales revenues would decrease by approximately $13.2 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $3.3 million. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $1.00 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas by approximately $4.4 million after considering the effects of the derivative contracts in place as of December 31, 2008. This sensitivity analysis is based on our 2008 oil and gas sales volumes. A material decline could reduce our cash flow and borrowing capacity, as well as the value and the amount of our natural gas reserves. Approximately 90% of our proved reserves are natural gas. Therefore, we are more directly impacted by volatility in the price of natural gas. For example, as of December 31, 2008, a 10% reduction in the price of oil and natural gas would have reduced our future net cash flow from proved reserves by $29 million. 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, including the current economic and capital market crisis; 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.

 

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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.
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. In 2008, we recorded an impairment to our oil and natural gas properties of $3.9 million.
Information concerning our reserves and future net revenues is uncertain.
This Annual Report and our other 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, 2008, approximately 11% of our estimated proved reserves 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.

 

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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 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.
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.

 

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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 insure 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.
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. See “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 Senior Secured 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 Senior Secured Notes. See “Item 13 — Certain Relationships and Related Transactions.”

 

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Our structure may present conflicts of interest.
Our sole shareholder, Capital C, is owned by institutional funds managed by EnerVest. Messrs. Houser and Vanderhider are executive officers of EnerVest. EnerVest manages other funds that own interests in oil and gas properties in our area of operations. Mr. Mariani is an executive officer of EnerVest Operating, an affiliate of EnerVest. EnerVest Operating controls the operations of our wells and the wells owned by other EnerVest managed funds. 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. Houser, Vanderhider and Mariani.
The terms of our Amended Credit Agreement, as well as the J. Aron Swap and the indenture relating to the Senior Secured Notes, restrict our current and future operations, particularly our ability to respond to industry or economic changes or to take certain actions.
Effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement. The agreement was entered into to provide for certain waivers and modifications to the debt terms and covenants. This amendment was a direct result of the determination as of December 31, 2008, that the Company, would not maintain compliance with certain financial covenants during 2009 and 2010. Accordingly, on April 9, 2009, our bank group waived the leverage ratio for the quarters ended March 31, 2009 and June 30, 2009 and amended the Amended Credit Agreement to increase the maximum leverage ratio to 5.375 : 1.0 through December 31, 2009, 5.25 : 1.0 at March 31, 2010 and 5.0 : 1.0 at June 30, 2010. The bank group also waived the interest coverage ratio as of June 30, 2009 and amended the Amended Credit Agreement to reduce our minimum interest coverage ratio to 2.0 : 1.0 through March 31, 2010 and 2.25 : 1.0 at June 30, 2010. Additionally, Capital C, our parent, has committed to the Company to provide financial support. Taking into consideration the amended financial covenants and the financial support from Capital C, the Company, as of April 9, 2009, has projected that it would maintain compliance with such amended covenants through 2009 and 2010.
Additionally, the amendment provided that the borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 1.75% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.25% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The agreement was also amended for the following:
  •   Set the Borrowing Base at $100 million.
  •   Set the Borrowing Base redetermination dates to March 15th and September 15th each year.
  •   Prohibit payment of dividends to our shareholder.
  •   Prohibit Senior Secured Note repurchases by the Company.
  •   Prohibit principal or cash interest payments on the Capital C Subordinated Note.
  •   Prohibit borrowings to fund restructuring of the hedge agreements.
  •   Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.
  •   Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.
  •   Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.
At December 31, 2008, we were in compliance with our covenants under the Amended Credit Agreement. Our leverage ratio was 4.25 : 1.0 and the interest coverage ratio was 2.72 : 1.0.
In addition, our existing debt agreements and any new debt agreements may impose financial restrictions and other covenants on us that may be more restrictive than those applicable to the Senior Secured Notes.
Our Amended Credit Agreement and the Hedge Agreement contain, and any future refinancing of our Amended Credit Agreement likely would contain, a number of restrictive covenants that impose significant operating and financial restrictions on us. Our Amended Credit Agreement 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.

 

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Our Amended Credit Agreement also include financial covenants, including requirements that we maintain:
  •   a minimum interest coverage ratio;
  •   a maximum total leverage ratio; and
  •   a minimum current ratio.
The indenture relating to the Senior Secured Notes also contains covenants including, among other things, restrictions on our ability to:
  •   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.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3. LEGAL PROCEEDINGS
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.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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 March 5, 2009, were held by Capital C.
Dividends
We paid cash dividends of $2.5 million in 2008, $9.8 million in 2007 and $20.0 million in 2006.

 

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Item 6. SELECTED FINANCIAL DATA
The Selected Financial Data should be read in conjunction with the Consolidated Financial Statements at Item 15(a).
                                                         
          Predecessor I     Predecessor II  
    Successor Company     Company     Company  
                            For the 138     For the 227     For the 178     For the 188  
                            Day Period     Day Period     Day Period     Day Period  
                            from August     From January     from July     from January  
                            16, 2005 to     1, 2005 to     7, 2004 to     1, 2004 to  
    As of or for the year ended December 31,     December 31,     August 15,     December 31,     July 6,  
(in thousands)   2008     2007     2006     2005     2005     2004     2004  
Continuing Operations:
                                                        
Revenues
   $ 158,426     $ 125,140     $ 158,774     $ 76,642     $ 77,960     $ 62,256     $ 50,816  
Depreciation, depletion and amortization
     35,560       36,087       38,074       14,341       21,265       17,527       9,089  
Impairment of oil and gas properties
     3,924       31       546       —       —       —       —  
Impairment of goodwill
     90,076       —       —       —       —       —       —  
Income (loss) from continuing operations
     (28,944 )     (35,322 )     52,199       17,563       (320 )     7,263       (18,869 )
 
                                                
Balance sheet data:
                           As of 12/31/2005           As of 12/31/2004        
Working capital (deficit) from continuing operations
     (16,806 )     (14,224 )     (11,635 )     (38,999 )             (4,907 )        
Oil and gas properties and gathering systems, net
     613,834       627,556       641,879       648,417               502,765          
Total assets
     669,464       774,225       777,023       810,118               570,853          
Long-term debt, less current portion
     265,863       291,118       285,560       277,648               281,396          
Total shareholders’ (deficit) equity
     76,551       102,223       143,703       89,399               57,088          
The Transaction and Merger were each accounted for as a purchase effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at August 16, 2005 and July 7, 2004. Accordingly, financial data for the period subsequent to August 15, 2005 is presented on our new basis of accounting, while the financial data for prior periods reflect the historical results of the two predecessor companies. Vertical black lines are presented to separate the financial data of the two predecessor companies and the successor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor I Company” refers to the period from July 7, 2004 through August 15, 2005. The “Predecessor II Company” refers to the period prior to July 7, 2004.

 

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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. Capital C acquired us pursuant to a merger completed on July 7, 2004. On August 16, 2005, Capital C was acquired by institutional funds managed by EnerVest, Ltd, a Houston-based privately held oil and gas operator and institutional funds manager. The Transaction resulted in a change in control of the Company.
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, 2008, our total estimated proved reserves were 223 Bcfe. Natural gas comprised approximately 90% of our estimated proved reserves, and 89% 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, 2008, our conventional Appalachian properties accounted for 48% of our estimated proved reserves, while the Michigan properties and our Appalachian CBM properties accounted for 44% and 8%, respectively.
In connection with the Transaction, our then existing indebtedness was refinanced. The principal elements of the refinancing included entering into a $390 million credit facility, comprised of a $350 million revolving facility, which currently has a borrowing base of $100 million, and a $40 million letter of credit facility and our issuance of a $25 million Subordinated Promissory Note with a related party (see Note 20 to the Consolidated Financial Statements).
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.
Our financial results and cash flows can be significantly impacted as commodity prices fluctuate in response to changing market conditions. We use derivative financial 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”) as required by the Amended Credit Agreement and the indenture governing the Senior Secured 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 2009 through 2013 production from our current estimated proved reserves and will range from 62% to 77% of such expected production in any year.
The average price realized for our natural gas, inclusive of qualified effective hedges, decreased from $8.77 per Mcf in 2006 to $6.81 per Mcf in 2007 and then increased to $8.62 per Mcf in 2008. The monthly average settle for natural gas trading on the NYMEX decreased from $7.23 per MMbtu in 2006 to $6.86 per MMbtu in 2007 and then increased to $9.04 per MMbtu in 2008. Our selling price of natural gas is generally higher than the NYMEX price due to the proximity of our operations to natural gas markets along with a favorable Btu content of our gas. During 2008, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.45 and $0.08, respectively, higher than the average NYMEX monthly settle price for 2008. The remainder of the difference is primarily due to our qualified hedging activities during these periods. Our average realized price for oil increased from $62.78 per Bbl in 2006 to $67.42 per Bbl in 2007 and to $94.40 per Bbl in 2008.
We recorded a goodwill impairment charge of $90.1 million in the fourth quarter of 2008 due to the significant decline in oil and gas prices.

 

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Impact of the Current Financial and Credit Markets
The U.S. and other world economies are currently in a recession which could last well into 2009 and beyond. Additionally, the financial and credit markets are undergoing unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. Our exposure to the disruptions in the financial markets includes our credit facility and investments exposure.
Our credit facility extends through August 16, 2010. If the disruption in the financial markets continues for an extended period of time, replacement or amendment of the credit facility may be more expensive.
Current market conditions also elevate concerns about cash and cash equivalent investments, which at December 31, 2008 totaled $22.8 million. We have reviewed the creditworthiness of the banks and financial institutions with which we maintain investments, each of whom we believe to be creditworthy, as well as the securities underlying these investments.
We have also reviewed the creditworthiness of our hedge counterparty and believe that it is creditworthy.
Additionally, oil and gas prices are also volatile as evidenced by the significant decline during late 2008 and early 2009. Continued lower commodity prices will reduce the Company’s cash flows from operations.
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 15(a). 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 costs of carrying and retaining undeveloped properties include 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 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 all 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.

 

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Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets
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 certain 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.
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.
SFAS No. 142, “Goodwill and Other Intangible Assets” requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change could potentially result in impairment.
The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. As we have only one reporting unit, the reporting unit used for testing will be the entire company. The fair value of the reporting unit is determined and compared to the book value of that reporting unit. The fair value of the reporting unit is based on estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $90.1 million due to the significant drop in oil and gas prices resulting in part from the global economic and market crisis.
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 not qualifying for designation as cash flow hedges are reported in expense in the consolidated statements of operations as derivative fair value (gain) 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 impact earnings.
The relationship between 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 inception of the contract and on an ongoing basis. We assess effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.

 

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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 price, crude oil price or interest rate volatility and to support our capital expenditure plans. Our derivative financial instruments primarily take the form of swaps or collars. At December 31, 2008, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that we believe have a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges.
We use NYMEX-based commodity derivative contracts to hedge natural gas, because our natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, we had ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. At August 16, 2005, our oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in fair value of the oil swaps subsequent to August 15, 2005 and the ineffective portion of the natural gas swaps from July 7, 2004 to June 30, 2006 are recorded as “Derivative fair value gain or loss.” As of July 1, 2006, we determined that our gas swaps were no longer highly effective and, therefore, could no longer be designated as cash flow hedges.
Revenue Recognition
Oil and natural gas revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is probable. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under-produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no material gas imbalances at December 31, 2008 or 2007. Oil and gas marketing revenues are recognized when title passes.
Asset Retirement Obligations
We follow SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 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.
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 additional wells having been drilled and accretion expense.
At December 31, 2008, there were no assets legally restricted for purposes of settling asset retirement obligations. A reconciliation of our liability for asset retirement obligations for the years ended December 31, 2008 and 2007 is as follows (in thousands):
                 
    Year Ended     Year Ended  
    December 31,     December 31,  
    2008     2007  
Beginning asset retirement obligations
   $ 22,264     $ 20,734  
Liabilities incurred
     565       220  
Liabilities settled
     (399 )     (219 )
Accretion expense
     1,412       1,290  
Revisions in estimated cash flows
     43       239  
 
            
Ending asset retirement obligations
   $ 23,885     $ 22,264  
 
            

 

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Results of Operations
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,  
    2008     2007     2006  
 
Revenues
                                                
Oil and gas sales
   $ 145,398       91.8 %   $ 114,427       91.4 %   $ 147,122       92.7 %
Gas gathering and marketing
     12,254       7.7       10,275       8.2       11,294       7.1  
Other
     774       0.5       438       0.4       358       0.2  
 
                                    
 
     158,426       100.0       125,140       100.0       158,774       100.0  
 
                                                
Expenses
                                                
Production expense
     26,342       16.6       24,585       19.7       23,692       14.9  
Production taxes
     3,054       1.9       2,265       1.8       2,404       1.5  
Gas gathering and marketing
     10,252       6.5       8,640       6.9       9,360       5.9  
Exploration expense
     2,543       1.6       1,935       1.5       1,797       1.1  
General and administrative expense
     8,188       5.2       8,236       6.6       9,796       6.2  
Depreciation, depletion and amortization
     35,560       22.4       36,087       28.8       38,074       24.0  
Impairment of goodwill
     90,076       56.9                                  
Inpairment of oil and gas properties
     3,924       2.5       31       —       546       0.3  
Accretion expense
     1,412       0.9       1,290       1.0       1,226       0.8  
Derivative fair value (gain) loss
     (55,940 )     (35.3 )     78,120       62.5       (37,356 )     (23.5 )
 
                                    
 
     125,411       79.2       161,189       128.8       49,539       31.2  
 
                                    
Operating income (loss)
     33,015       20.8       (36,049 )     (28.8 )     109,235       68.8  
 
Other (income) expense
                                                
(Gain) on early extinguishment of debt
     —       —       —       —       (436 )     (0.3 )
Interest expense
     22,818       14.4       23,712       18.9       23,553       14.8  
Other income, net
     (495 )     (0.3 )     (516 )     (0.4 )     (316 )     (0.2 )
 
                                    
 
Income (loss) before income taxes
     10,692       6.7       (59,245 )     (47.3 )     86,434       54.5  
Provision (benefit) for income taxes
     39,636       25.0       (23,923 )     (19.1 )     34,235       21.6  
 
                                    
 
Net (loss) income
     (28,944 )     (18.3 )     (35,322 )     (28.2 )     52,199       32.9  
 
                                    

 

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The following Management’s Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted.
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. The average prices shown in the table include the effects of our qualified effective hedging activities.
                         
    Year Ended December 31,  
    2008     2007     2006  
 
                        
Production
                        
Gas (MMcf)
     13,217       13,357       14,104  
Oil (Mbbl)
     334       348       373  
Total production (MMcfe)
     15,221       15,446       16,340  
 
Average price (1)
                        
Gas (per Mcf)
   $ 8.62     $ 6.81     $ 8.77  
Oil (per Bbl)
     94.40       67.42       62.78  
Per Mcfe
     9.55       7.41       9.00  
 
Average costs (per Mcfe)
                        
Production expense
   $ 1.73     $ 1.59     $ 1.45  
Production taxes
     0.20       0.15       0.15  
Depletion
     2.31       2.31       2.30  
     
(1)   The average prices presented above include non-cash amounts related to our derivatives as a result of purchase accounting for the Merger and the Transaction. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average prices:
                         
    Year Ended December 31,  
    2008     2007     2006  
Gas (per Mcf)
   $ 9.31     $ 7.34     $ 7.22  
Oil (per Bbl)
     94.40       67.42       62.78  
Per Mcfe
     10.15       7.87       7.67  
2008 Compared to 2007
Revenues
Net operating revenues increased $33.3 million from $125.1 million in 2007 to $158.4 million in 2008. The increase was primarily due to higher gas sales revenues of $22.9 million, higher oil sales revenue of $8.1 million and higher gas gathering and marketing revenues of $2.0 million.
Gas volumes sold decreased 140 MMcf (1%) from 13.4 Bcf in 2007 to 13.2 Bcf in 2008 resulting in a decrease in gas sales revenues of approximately $950,000. Oil volumes sold decreased approximately 14,000 Bbls (4%) from 348,000 Bbls in 2007 to 334,000 Bbls in 2008 resulting in a decrease in oil sales revenues of approximately $960,000. The lower oil and gas sales volumes are due to normal production declines, which were partially offset by production from new wells drilled in 2008.

 

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The average price realized for our natural gas increased $1.81 per Mcf to $8.62 per Mcf in 2008 compared to 2007, which increased gas sales revenues by approximately $23.9 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $9.2 million ($0.69 per Mcf) in 2008 and lower by $7.1 million ($0.53 per Mcf) in 2007 than if our gas was not hedged. The average price realized for our oil increased from $67.42 per Bbl in 2007 to $94.40 per Bbl in 2008, which increased oil sales revenues by approximately $9.0 million. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting. Changes in the fair value of the gas derivatives from that date forward are recorded in derivative fair value gain/loss. Deferred gains or losses on these gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings.
The increase in gas gathering and marketing revenues was due to a $1.5 million increase in gas marketing revenues and a $510,000 increase in gas gathering revenues. The higher marketing revenues were primarily the result of higher gas prices. The increase in gas gathering revenues was primarily due to an increase in third party gathering volumes on gathering systems in Pennsylvania.
Costs and Expenses
Production expense increased $1.7 million from $24.6 million in 2007 to $26.3 million in 2008. This increase was primarily due to higher fuel costs, increases in labor and oilfield service costs, increases in gas processing fees and increased workover expense. The average production cost increased from $1.59 per Mcfe in 2007 to $1.73 per Mcfe in 2008 due to these cost increases and the lower oil and gas sales volumes in 2008.
Production taxes increased $789,000 from $2.3 million in 2007 to $3.1 million in 2008, primarily due to higher 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 $0.15 per Mcfe in 2007 to $0.20 per Mcfe in 2008.
Gathering and marketing expense increased $1.7 million from $8.6 million in 2007 to $10.3 million in 2008 primarily due to higher gas marketing costs as a result of higher gas prices in 2008.
Exploration expense increased $608,000 from $1.9 million in 2007 to $2.5 million in 2008. The increase was primarily due to an increase in expired lease expense and exploratory dry hole expense of $744,000.
General and administrative expense was $8.2 million in 2007 and 2008 and decreased $48,000 primarily due to a decrease in franchise tax and insurance expense which was partially offset by an increase in professional services expense.
Depreciation, depletion and amortization decreased by $527,000 from $36.1 million in 2007 to $35.6 million in 2008. This decrease was primarily due to a decrease in depletion expense. Depletion expense decreased $495,000 from $35.7 million in 2007 to $35.2 million in 2008 due to lower volumes produced. Depletion per Mcfe was $2.31 per Mcfe in 2007 and 2008.
Impairment of goodwill was $90.1 million in 2008 due to the significant drop in oil and gas prices resulting in part from the global economic and market crisis.
Impairment of oil and gas properties was $3.9 million in 2008 due to the write-down of our investment in properties in the Utica Shale formation in Ohio and other unproved properties.
Derivative fair value gain/loss was a gain of $55.9 million in 2008 compared to a loss of $78.1 million in 2007. 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, the ineffective portion of crude oil swaps through August 15, 2005 and the ineffective portion of natural gas swaps as a result of purchase accounting. Our oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, changes in fair value were reflected in derivative fair value gain/loss in 2006. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting and, therefore, changes in fair value subsequent to that date are reflected in derivative fair value gain/loss.
Interest expense decreased $894,000 from $23.7 million in 2007 to $22.8 million in 2008. This decrease was due to lower blended interest rates in 2008.
Income tax expense increased from a benefit of $23.9 million in 2007 to an expense of $39.6 million in 2008. The increase in income tax expense was primarily due to an increase in the net income before income taxes in 2008 and an increase in the effective tax rate due to the impairment of goodwill which is not an allowable expense in the calculation of taxable income.

 

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2007 Compared to 2006
Revenues
Net operating revenues decreased $33.7 million from $158.8 million in 2006 to $125.1 million in 2007. The decrease was due to lower gas sales revenues of $32.8 million and lower gas gathering and marketing revenues of $1.0 million.
Gas volumes sold decreased 747 MMcf (5%) from 14.1 Bcf in 2006 to 13.4 Bcf in 2007 resulting in a decrease in gas sales revenues of approximately $6.6 million. Oil volumes sold decreased approximately 25,000 Bbls (7%) from 373,000 Bbls in 2006 to 348,000 Bbls in 2007 resulting in a decrease in oil sales revenues of approximately $1.5 million. The lower oil and gas sales volumes are due to normal production declines and a lower level of drilling in 2007, which was partially offset by production from new wells drilled in 2007.
The average price realized for our natural gas decreased $1.96 per Mcf to $6.81 per Mcf in 2007 compared to 2006, which reduced gas sales revenues by approximately $26.2 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $7.1 million ($0.53 per Mcf) in 2007 and higher by $18.7 million ($1.33 per Mcf) in 2006 than if our gas was not hedged. The average price realized for our oil increased from $62.78 per Bbl in 2006 to $67.42 per Bbl in 2007, which increased oil sales revenues by approximately $1.6 million. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting. Changes in the fair value of the gas derivatives from that date forward are recorded in derivative fair value gain/loss. Deferred gains or losses on these gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings.
The decrease in gas gathering and marketing revenues was due to a $781,000 decrease in gas marketing revenues and a $238,000 decrease in gas gathering revenues. The lower marketing revenues were primarily the result of lower gas prices. The decrease in gas gathering revenues was primarily due to lower margins on a gathering system in Pennsylvania.
Costs and Expenses
Production expense increased $893,000 from $23.7 million in 2006 to $24.6 million in 2007. Production expense in 2006 includes $385,000 ($0.02 per Mcfe) due to recording the cost associated with the selling of purchased oil inventory as a result of purchase accounting for the Transaction. Oil inventory was recorded at fair value of approximately $60.50 per Bbl as of August 16, 2005. Excluding the impact of this oil inventory adjustment, production expense increased by approximately $1.3 million in 2007 compared to 2006. This increase was primarily due to higher fuel costs, increases in labor and oilfield service costs and increased workover expense. The average production cost increased from $1.45 per Mcfe in 2006 to $1.59 per Mcfe in 2007 due to these cost increases and the lower oil and gas sales volumes in 2007.
Production taxes decreased $139,000 from $2.4 million in 2006 to $2.3 million in 2007, primarily due to lower gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes were $0.15 per Mcfe in 2006 and 2007.
Gathering and marketing expense decreased $720,000 from $9.4 million in 2006 to $8.6 million in 2007 primarily due to lower gas marketing costs as a result of lower gas prices in 2007.
Exploration expense increased $138,000 from $1.8 million in 2006 to $1.9 million in 2007. The increase was primarily due to an increase in expired lease expense.
General and administrative expense decreased $1.6 million from $9.8 million in 2006 to $8.2 million in 2007 primarily due to expenses related to the Transaction recorded in 2006 and decreased compensation related expenses in 2007. In 2006, we expensed approximately $1.0 million for costs associated with the transition of accounting and administrative functions to EverVest’s Charleston, West Virginia office and approximately $355,000 related to the restatement of our 2005 Form 10-K and Forms 10-Q.

 

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Depreciation, depletion and amortization decreased by $2.0 million from $38.1 million in 2006 to $36.1 million in 2007. This decrease was primarily due to a decrease in depletion expense. Depletion expense decreased $1.9 million from $37.6 million in 2006 to $35.7 million in 2007 due to lower volumes produced. Depletion per Mcfe increased from $2.30 per Mcfe in 2006 to $2.31 per Mcfe in 2007.
Derivative fair value gain/loss was a loss of $78.1 million in 2007 compared to a gain of $37.4 million in 2006. 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, the ineffective portion of crude oil swaps through August 15, 2005 and the ineffective portion of natural gas swaps as a result of purchase accounting. Our oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, changes in fair value were reflected in derivative fair value gain/loss in 2006. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting and, therefore, changes in fair value subsequent to that date are reflected in derivative fair value gain/loss.
Interest expense increased $159,000 from $23.6 million in 2006 to $23.7 million in 2007. This increase was due to an increase in average outstanding borrowings and slightly higher blended interest rates.
Income tax expense decreased from $34.2 million in 2006 to a benefit of $23.9 million in 2007. The decrease in income tax expense was primarily due to a decrease in the net income before income taxes in 2007.
Liquidity and Capital Resources
Cash Flows
We expect that our primary sources of cash in 2009 will be from funds generated from operations, additional equity contributions from Capital C and the sale of non-strategic assets. Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our Amended Credit Agreement, will be adequate to meet our short-term liquidity needs for the foreseeable future.
The primary sources of cash in the year ended December 31, 2008 were funds generated from operations and from borrowings under our credit facilities. Funds used during this period were primarily used for operations, exploration and development expenditures, the settlement of derivatives and interest expense. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.
The following table summarizes the net cash flow for the periods presented:
                         
    Year Ended December 31,  
    2008     2007     Change  
    (in millions)  
Cash flows provided by operating activities
   $ 96.7     $ 68.1     $ 28.6  
Cash flows (used in) investing activities
     (27.5 )     (23.1 )     (4.4 )
Cash flows (used in) financing activities
     (62.4 )     (34.9 )     (27.5 )
 
                  
 
                        
Net increase (decrease) in cash and cash equivalents
   $ 6.8     $ 10.1     $ (3.3 )
 
                  
Our operating activities provided cash flows of $96.7 million during 2008 compared to $68.1 million in 2007. The increase was primarily due to a $33.0 million increase in oil and gas sales, excluding the effects of hedging which was partially offset by a $3.3 million decrease in operating assets.
Cash flows used in investing activities were $27.5 million in 2008 compared to $23.1 in 2007. This increase was due to an increase of $5.9 million in property and equipment additions which was partially offset by an increase in proceeds from property and equipment sales of $2.8 million.

 

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Cash flows used in financing activities in 2008 were $62.4 million compared to $34.9 million in 2007. This increase was primarily due to the $30.2 million increase in the settlement of derivative liabilities and a $4.5 million decrease in proceeds from the revolving line of credit which was partially offset by a decrease in payments to shareholders of $7.3 million.
During 2008, our working capital decreased $2.6 million from a deficit of $14.2 million at December 31, 2007 to a deficit of $16.8 million at December 31, 2008. The decrease was primarily due to an increase in the current portion of long-term liabilities of $24.9 million and a decrease in the deferred tax asset of $9.3 million, which was partially offset by a decrease in the current liability for the fair value of derivatives of $23.2 million and an increase in cash of $6.8 million.
Capital Expenditures
The table below sets forth our total capital expenditures for each of the years ending December 31, 2008, 2007 and 2006.
                         
    Year Ended December 31,  
    2008     2007     2006  
    (in millions)  
 
                        
Total capital expenditures
                        
Drilling including exploratory dry hole expense
   $ 25     $ 21     $ 35  
Production enhancements and field improvements
     2       1       1  
Leasehold acreage
     1       1       1  
 
                  
 
                        
Total
   $ 28     $ 23     $ 37  
 
                  
During 2008, we spent approximately $28.3 million, including exploratory dry hole expense, on our drilling and other capital expenditures. In 2008, we drilled 98 gross (83.5 net) development wells, all of which were successfully completed as producers in the target formation. We also drilled 5 gross (4.9 net) exploratory dry holes in 2008.
We plan to spend approximately $15 million during 2009 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand, available cash flow and, to a lesser extent, the sale of non-strategic assets. 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, effects of the current economic and financial crisis, 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 $159.5 million of our Senior Secured Notes outstanding as of December 31, 2008. As a result of the application of purchase accounting, the notes were recorded as a liability based on the estimated fair value of $200.7 million on the Transaction date. In June 2006, we repurchased a portion of the outstanding Senior Secured Notes. The repurchased notes had a face value of $33.025 million and were repurchased at 102.750%. A gain of $436,000 was recorded in 2006 in connection with the transaction. The notes mature July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year at 8.75% based on the face amount of $159.5 million (for an effective rate of 7.946% based on the fair value on the Transaction date.) The notes are secured on a second-priority lien on the same assets subject to the liens securing our obligations under the Amended Credit Agreement. The Senior Secured 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 %

 

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The Senior Secured 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.
Amended Credit Agreement
In 2005, we amended and restated our then existing credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.
The Amended Credit Agreement provides for a revolving credit line in the aggregate principal amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of $40 million. At December 31, 2008, the borrowing base was $113.4 million and the outstanding balance was $99.9 million. J.P. Morgan Chase and Amegy Bank became members of the bank group in September 2005. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.
The obligations under the Amended Credit Agreement are secured by a first lien security interest in substantially all of our assets. The obligations under the Amended Credit Agreement are further secured by a pledge of 100% of our capital stock held by Capital C, our parent.
The Amended Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase our stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio.
Effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement. The agreement was entered into to provide for certain waivers and modifications to the debt terms and covenants. This amendment was a direct result of the determination as of December 31, 2008, that the Company, would not maintain compliance with certain financial covenants during 2009 and 2010. Accordingly, on April 9, 2009, our bank group waived the leverage ratio for the quarters ended March 31, 2009 and June 30, 2009 and amended the Amended Credit Agreement to increase the maximum leverage ratio to 5.375 : 1.0 through December 31, 2009, 5.25 : 1.0 at March 31, 2010 and 5.0 : 1.0 at June 30, 2010. The bank group also waived the interest coverage ratio as of June 30, 2009 and amended the Amended Credit Agreement to reduce our minimum interest coverage ratio to 2.0 : 1.0 through March 31, 2010 and 2.25 : 1.0 at June 30, 2010. Additionally, Capital C, our parent, has committed to the Company to provide financial support. Taking into consideration the amended financial covenants and the financial support from Capital C, the Company, as of April 9, 2009, has projected that it would maintain compliance with such amended covenants through 2009 and 2010.
Additionally, the amendment provided that the borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 1.75% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.25% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The agreement was also amended for the following:
  •   Set the Borrowing Base at $100 million.
  •   Set the Borrowing Base redetermination dates to March 15th and September 15th each year.
  •   Prohibit payment of dividends to our shareholder.
  •   Prohibit Senior Secured Note repurchases by the Company.
  •   Prohibit principal or cash interest payments on the Capital C Subordinated Note.
  •   Prohibit borrowings to fund restructuring of the hedge agreements.
  •   Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.
  •   Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.
  •   Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.
At December 31, 2008, we were in compliance with our covenants under the Amended Credit Agreement. Our leverage ratio was 4.25 : 1.0 and the interest coverage ratio was 2.72 : 1.0.

 

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On August 3, 2007, our bank group waived the covenant compliance requirement as of June 30, 2007 and amended the Amended Credit Agreement to increase the maximum leverage ratio from 4.0 : 1.0 to 4.25 : 1.0 for the quarters ending on September 30, 2007 and December 31, 2007. If we had not received this waiver, we would not have complied with our leverage ratio covenant as it would have been 4.07 : 1.0 as of June 30, 2007. On March 24, 2008, our bank group waived the covenant compliance requirement as of December 31, 2007 and amended the Amended Credit Agreement to increase the maximum Leverage Ratio to 4.5 : 1.0 through December 31, 2008. If we had not received this waiver, we would not have complied with our Leverage Ratio covenant as it would have been 4.38 : 1.0 as of December 31, 2007.
Borrowings under the revolving credit line will be used by us for general corporate purposes. In accordance with the terms of the Amended Credit Agreement, letters of credit issued under the hedge letter of credit commitment and any related borrowings are to be used solely to secure payment of our obligations under the J. Aron Swap (defined hereinafter).
In connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note in favor of Capital C in the maximum principal amount of $94 million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. The Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Subordinated Note made on August 16, 2005. Interest payments on the Subordinated Note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the Subordinated Note by borrowing additional amounts against the Subordinated Note. The interest payments in 2006, the first quarter of 2007 and the first three quarters of 2008 were paid in cash. Interest payments for the last three quarters of 2007 and the fourth quarter of 2008 were made by additional borrowings against the Subordinated Note. The Subordinated Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. Pursuant to the Fourth Amendment to our credit agreement, cash payments for principal or interest on the Subordinated Note are prohibited. The Subordinated Note is subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and the Senior Secured Notes.
ISDA Master Agreement
In connection with the Transaction, we amended and restated the Schedule and Credit Support Annex to our ISDA Master Agreement, dated as of June 30, 2004, by and between us and J. Aron & Company (“J. Aron Swap”), pursuant to which we have agreed, from time to time, to enter into cash-settled hedge transactions with J. Aron & Company, as hedge counterparty, in connection with various gas and oil commodity derivatives transactions. The amendments to the J. Aron Swap conform the terms of the Schedule and Credit Support Annex to the terms of the Amended Credit Agreement, change certain covenants and reduce the maximum amount of the letter of credit securing the hedge obligations from $55 million to $40 million.
From time to time, we may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. At December 31, 2006, 2007 and 2008, we had interest rate swaps in place covering $80 million of our outstanding debt under the revolving credit facility that mature between September 16, 2008 and September 30, 2010.
At December 31, 2008, the aggregate long-term debt maturing in the next five years is as follows: $25.0 million (2009); $74.9 million (2010); $10,000 (2011); $187.1 million (2012) and $32,000 (2013 and thereafter).

 

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Derivative Instruments
The Hedges
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. None of our contracts currently qualify for hedge accounting.
On July 7, 2004, the date of the Merger, we became a party to long-term commodity hedges (the “Hedges”) with J. Aron pursuant to a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”.) We anticipate that the Hedges will cover approximately 69% of the expected 2009 through 2013 production from our current estimated proved reserves and will range from 62% to 77% 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 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 Secured 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 Amended Credit Agreement, with an aggregate capitalization of $40 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 Amended Credit Agreement and the Senior Secured 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 Amended Credit Agreement and the Senior Secured Notes. 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 Amended Credit Agreement and by a second-priority lien on the same assets securing the Amended Credit Agreement and the Senior Secured Notes.
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 derivative positions by entering into new transactions. The following tables reflect the natural gas and crude oil volumes and the weighted average prices under financial derivatives (including settled contracts) at February 28, 2009.
                                                 
    Natural Gas Swaps     Crude Oil Swaps     Natural Gas Basis Swaps  
            NYMEX             NYMEX                
            Price per             Price per             Basis  
Year Ending   Bbtu     Mmbtu     Mbbls     Bbl     Bbtu     Differential  
December 31, 2009
     9,529     $ 4.43       191     $ 29.34       7,390     $ 0.337  
December 31, 2010
     8,938       4.28       175       28.86       7,666       0.243  
December 31, 2011
     8,231       4.19       157       28.77       5,110       0.252  
December 31, 2012
     7,005       4.09       138       28.70       3,660       0.110  
December 31, 2013
     6,528       4.04       127       28.70       —       —  
At December 31, 2008, the fair value of futures contracts covering 2009 through 2013 oil and gas production represented an unrealized loss of $117.2 million. Commodity prices have decreased since December 31, 2008 and, as a result, the fair value of our oil and gas derivatives as of February 28, 2009 was an unrealized loss of approximately $83.7 million.
At December 31, 2008, we had a non-qualified interest rate swap in place on $80 million of our outstanding debt under the revolving credit facility through September 30, 2010. The swap provides 1-month LIBOR fixed rates at 4.07%, plus the applicable margin, on $80 million through September 2010. At December 31, 2008, the fair value of the interest rate swap represented an unrealized loss of $3.5 million.

 

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Inflation and Changes in Prices
The average price realized for our natural gas decreased from $8.77 per Mcf in 2006 to $6.81 per Mcf in 2007, and increased to $8.62 in 2008. The average price realized for our oil increased from $62.78 per Bbl in 2006 to $67.42 per Bbl in 2007 and increased to $94.40 per Bbl in 2008. These prices include the effect of our qualified effective oil and gas hedging activity.
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, 2008.
                                         
    Payments Due by Period  
Contractual Obligations at           Less than 1                     After 5  
December 31, 2008   Total     Year     1 - 3 Years     4 - 5 Years     Years  
    (in thousands)  
Long-term debt
   $ 287,044     $ 25,008     $ 74,895     $ 187,109     $ 32  
Asset retirement obligations
     23,885       229       386       17       23,253  
Derivative liabilities
     120,792       20,512       55,868       44,412       —  
Interest on debt
     64,565       19,874       35,406       9,285       —  
Operating leases
     6,749       4,523       2,226       —       —  
 
                              
Total contractual cash obligations
   $ 503,035     $ 70,146     $ 168,781     $ 240,823     $ 23,285  
 
                              
In addition to the items above, 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, 2008.
                                         
    Total     Amount of Commitment Expiration Per Period  
Commercial Commitments at   Amounts     Less than 1     1 - 3     4 - 5     Over 5  
December 31, 2008   Committed     Year     Years     Years     years  
    (in thousands)  
Standby Letters of Credit
   $ 40,850     $ 40,850     $ —     $ —     $ —  
 
                              
Total Commercial Commitments
   $ 40,850     $ 40,850     $ —     $ —     $ —  
 
                              
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.

 

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Off-Balance Sheet Arrangements
We have $40.9 million in letters of credit as described above.
NEW ACCOUNTING STANDARDS
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities. We adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and the adoption did not have a material impact on our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 was effective for fiscal years beginning after November 15, 2007. We have elected not to apply the provisions of SFAS No. 159.
In December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to significantly change the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions and will change the accounting treatment for certain specific items, including:
acquisition costs will generally be expensed as incurred;
noncontrolling interests will be valued at fair value at the date of acquisition; and
liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period.
SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008 and must be applied prospectively to business combinations completed on or after that date. We adopted SFAS No. 141(R) on January 1, 2009, and there was no impact on our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51, to establish new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS No. 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. We adopted SFAS No. 160 on January 1, 2009, and there was no impact on our consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. We adopted the disclosure requirements of SFAS No. 161 on January 1, 2009.
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States. SFAS No. 162 was effective on November 15, 2008.

 

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In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its oil and natural gas reporting disclosures. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12 month period rather than year end prices. The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending on or after December 31, 2009. We will adopt the new disclosure requirements on December 31, 2009.
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. At December 31, 2008, we had an interest rate swap in place on $80 million of our outstanding debt under the revolving credit facility through September 30, 2010. The swap provides a 1-month LIBOR fixed rates at 4.07%, plus the applicable margin, on $80 million through September 2010. These interest rate swaps do not qualify for hedge accounting, therefore, all cash settles and changes in the fair value of these swaps are recorded in derivative fair value gain/loss. If market interest rates for short-term borrowings increased 1%, the increase in our annual interest expense would be approximately $999,000. The impact of this rate increases on our cash flows would be significantly less than these amounts due to our interest rate swaps. If market interest rates increased 1% the decrease in our cash flow would be approximately $199,000. This sensitivity analysis is based on our financial structure at December 31, 2008.
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 oil and gas production 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. At December 31, 2008, we had derivatives covering a portion of our oil and gas production from 2009 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $7.1 million in 2007 and a net pre-tax loss of $9.2 million in 2008 on our qualified hedging activities.
We determined that as of August 15, 2005, our oil derivatives no longer qualify for cash flow hedge accounting and as of July 1, 2006, our gas derivatives no longer qualify for cash flow hedge accounting. From those dates forward, changes in the fair value of the oil and gas derivatives are recorded in derivative fair value gain/loss. Deferred gains or losses on the gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings. If gas prices decreased $1.00 per Mcf, our gas sales revenues would decrease by approximately $13.2 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $3.3 million. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $1.00 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas by approximately $4.4 million after considering the effects of the derivative contracts in place as of December 31, 2008. This sensitivity analysis is based on our 2008 oil and gas sales volumes.

 

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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
There were no changes in or disagreements with accountants on accounting or financial disclosures during the years ended December 31, 2008 or 2007.

 

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Item 9A. CONTROLS AND PROCEDURES
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over our financial reporting. Our internal control system was designed to provide reasonable assurance to our Management and Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Belden & Blake Corporation’s internal control over financial reporting was effective as of December 31, 2008.
Pursuant to the requirements of rules 13a-15(f) and 15d-15(f) of the Securities and Exchange Act of 1934, the Report on Internal Control over Financial Reporting has been signed below by the following person on behalf and in the capacities indicated below.
             
/s/ Mark A. Houser        /s/ James M. Vanderhider     
 
Mark A. Houser
     
 
James M. Vanderhider 		   
Chief Executive Officer, Chairman of the Board of Directors and Director
      President, Chief Financial Officer and Director    
Houston, TX
April 9, 2009
Evaluation of Disclosure Controls and Procedures
In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. 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, 2008 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management’s Annual Report On Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of published financial statements.

 

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All internal control systems, no matter how well designed, have inherent limitations. Therefore, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2008 based on the framework in “Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.” Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2008.
Changes in Internal Control Over Financial Reporting
There were no changes in the internal control over financial reporting that occurred during the year ended December 31, 2008 that materially affected, or that are reasonably likely to materially affect, internal control over financial reporting.
This annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
Item 9B. OTHER INFORMATION
Not applicable.

 

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PART III
Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE
Our executive officers and directors and their respective positions and ages of as of March 5, 2009 were as follows:
             
Name   Age   Position
 
            
Mark A. Houser
    47     Chief Executive Officer and Chairman of the Board of Directors
 
            
James M. Vanderhider
    50     President, Chief Financial Officer and Director
 
            
Kenneth Mariani
    47     Senior Vice President, Chief Operating Officer and Director
 
            
Frederick J. Stair
    49     Vice President of Accounting
 
            
Barry K. Lay
    52     Vice President of Operations
 
            
Sandra K. Fraley
    43     Vice President of Land and Legal and Secretary
 
            
David M. Elkin
    43     Vice President of Engineering
 
            
Mark L. Barnhill
    53     Vice President of Exploration
 
            
Matthew Coeny
    38     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 four members. The business experience of each executive officer and director is summarized below.
Mark A. Houser. On August 16, 2005, Mr. Houser was appointed our Chief Executive Officer and Chairman of the Board of Directors. Since 2006, Mr. Houser has served as EV Management, LLC’s President, COO and Director. EV Management is the general partner of the general partner of EV Energy Partners, LP. Since 1999, Mr. Houser has been the Executive Vice President and Chief Operating Officer of EnerVest, Ltd. Prior to that, Mr. Houser was Vice President, United States Exploration and Production, for Occidental Petroleum Corporation, or Oxy, where he helped lead Oxy’s reorganization of its domestic reserve base. Mr. Houser began his career as an engineer with Kerr-McGee Corporation. He holds a petroleum engineering degree from Texas A&M University and an MBA from Southern Methodist University.
James M. Vanderhider. Mr. Vanderhider is our President and Chief Financial Officer. Prior to that he served as President and Chief Operating Officer since his appointment on August 16, 2005. Mr. Vanderhider has been a director since August 16, 2005. He also serves as Executive Vice President and Chief Financial Officer of EnerVest and has been with EnerVest since March 1996. Prior to joining EnerVest, Mr. Vanderhider was Executive Vice President and Chief Financial Officer of Torch Energy and Senior Vice President and Chief Financial Officer of Nuevo Energy. Prior to such time, Mr. Vanderhider was a management member of the Internal Audit department of The Coastal Corporation, now a subsidiary of El Paso Corporation. He also held the position of Chief Financial Officer of Walker Energy Partners, a master limited partnership which he helped form. Mr. Vanderhider began his career with Deloitte and Touche in the audit department focusing on the energy industry.
Mr. Vanderhider received a B.B.A. degree in Accounting from Texas A&M University where he graduated summa cum laude. He is a Certified Public Accountant. Mr. Vanderhider is a native Houstonian and is actively involved with several industry and social organizations. He is a member of the Independent Petroleum Association of America, the American Institute of Certified Public Accountants, Houston Producers’ Forum, Texas Society of Certified Public Accountants, Houston Energy Finance Group, and Houston Acquisitions and Divestitures Organization. He serves on the Board of Trustees of Goodwill Industries of Houston and on the Board of Directors of the Houston Center Club, a social and athletic club.

 

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Kenneth Mariani. On October 3, 2005, Mr. Mariani was appointed Senior Vice President and Chief Operating Officer. He has been a director since August 16, 2005. Mr. Mariani is also Senior Vice President, Eastern Division, for EnerVest and Executive Vice President of CGAS Exploration, Inc., a privately-held oil and gas company owned by certain institutional funds managed by EnerVest. Prior to joining EnerVest in 2000, he served as Vice President of Operations for Energy Corporation of America.
Mr. Mariani holds a degree in Chemical Engineering from the University of Pittsburgh, graduating cum laude with a Petroleum option. He received his MBA degree from the University of Texas and is a Certified Professional Engineer. Mr. Mariani is an active member of the Independent Oil and Gas Association of West Virginia, recently serving on the Board of Directors, Commerce Committee and Safety Committee. In 2003, he was acting Vice President and Program Chair of this organization. He is past Chairman of the Society of Petroleum Engineers and a member of IPAA. Currently, Mr. Mariani serves on the Board of Directors for the Michigan Oil and Gas Association and the Ohio Oil and Gas Association. He is also active in the Independent Oil and Gas Association of Pennsylvania, the Independent Oil and Gas Association of New York and the Kentucky Oil and Gas Association.
Frederick J. Stair. Mr. Stair is Vice President of Accounting and has been our Vice President since January 2003. He previously served as our Corporate Controller from 1997 to 2005 and as Controller of the Exploration and Production Division from 1991 to 1997. Mr. Stair joined us in 1981 and has 27 years of accounting experience in the oil and gas industry. Mr. Stair is also Vice President of Accounting — Eastern Division for EnerVest. 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.
Barry K. Lay. Mr. Lay was appointed as Vice President of Operations effective August 10, 2007. Mr. Lay served as Vice President of Land and Secretary from October 16, 2006 until August 10, 2007. Prior to that he served as Vice President and General Manager of our Pennsylvania/New York District. Prior to joining us in 2002, Mr. Lay was Vice President of Engineering for Waco Oil and Gas Company. He also serves as Vice President of Operations — Eastern Division for EnerVest.
Mr. Lay has 30 years of experience in the oil and gas industry. Mr. Lay graduated from West Virginia University with a Bachelor of Science degree in Petroleum Engineering. He serves as Chairman for numerous State oil and gas regulatory boards including the West Virginia Oil and Gas Conservation Commission, West Virginia Coal Bed Methane Review Board and the West Virginia Shallow Gas Well Review Board. Mr. Lay is a registered Professional Engineer and a licensed Land Surveyor in the State of West Virginia.
Sandra K. Fraley. Ms. Fraley was appointed as Vice President of Land and Legal and Secretary effective August 10, 2007. Ms. Fraley also serves as Vice President of Land/Legal and General Counsel for the Eastern Division of EnerVest. Prior to joining EnerVest in 2007, Ms. Fraley served as Vice President and General Counsel of Equitable Production Company.
Ms. Fraley holds a B.A. from Eastern Kentucky University and a J.D. from the University of Kentucky. Ms. Fraley currently serves on the Board of Trustees for the Energy and Mineral Law Foundation and the Board of Directors for the Kentucky Oil and Gas Association.
Ms. Fraley resigned from the Company in all capacities on March 31, 2009.
David M. Elkin. Mr. Elkin was appointed Vice President of Engineering on October 16, 2006. He also serves as Vice President of Engineering — Eastern Division for EnerVest. Mr. Elkin joined EnerVest in 2003. He holds a Bachelor of Science in Petroleum and Natural Gas Engineering from The Pennsylvania State University. Prior to joining EnerVest, Mr. Elkin was employed for 17 years with Energy Corporation of America, rising to the position of Vice President of Operations. Mr. Elkin is a member of the Independent Oil and Gas Associations in West Virginia, Pennsylvania, New York, Ohio, Kentucky and Michigan. He is also a member and past officer of the Society of Petroleum Engineers. Mr. Elkin has drilled and operated production in the Appalachian, Michigan, and Powder River basins of North America, as well as the Wairoa basin of New Zealand.

 

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Mark L. Barnhill. Mr. Barnhill was appointed Vice President of Exploration on October 16, 2006. He also serves as Vice President of Exploration for EnerVest. Mr. Barnhill joined EnerVest in 2001. Prior to joining EnerVest, he was Exploration Manager for Energy Corporation of America. Mr. Barnhill has worked as both a geologist and a geophysicist for Texaco, Inc. and Cotton Petroleum. He holds a Bachelor of Science degree in Geology from Wright State University, a Master of Science in Geology from The University of Tulsa, and a Ph.D. in Geology from The University of Cincinnati.
Mr. Barnhill was a Visiting Research Scientist at Indiana University/Indiana Geological Survey from 1991 to 1994 where he headed several research projects for the Department of the Navy. He is a member of the American Association of Petroleum Geologists, the Independent Oil and Gas Association of West Virginia, the Independent Oil and Gas Association of Pennsylvania, the Ohio Oil and Gas Association and the Michigan Oil and Gas Association. Mr. Barnhill has given numerous talks at major association meetings both nationally and internationally.
Matthew Coeny. On August 16, 2005, Mr. Coeny was elected to our Board of Directors. Mr. Coeny is a Director of Citi Private Equity (“CPE”). CPE is a business unit of Citigroup Inc. (“Citigroup”) and is responsible for private equity investments, mezzanine debt investments and private equity partnership commitments on behalf of Citigroup affiliates and clients. Since joining CPE in 2000, he has participated in the evaluation, due diligence and execution of investments in a variety of industries. Prior to joining CPE, Mr. Coeny worked in Citigroup’s Investment Banking Division where he participated in numerous advisory and capital raising transactions. Prior to joining Citigroup in 1996, he was a Senior Consultant in KPMG’s Corporate Transactions practice. Mr. Coeny received a Bachelor of Science degree in Finance and Accounting from New York University.
Audit Committee
Our full Board of Directors serves as our Audit Committee.
Code of Ethics
We have adopted a Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, Vice President of Accounting and any person performing similar functions. It is available without charge upon oral or written request, by contacting:
Belden & Blake Corporation
1001 Fannin Street, Suite 800
Houston, Texas 77002
Attention: James M. Vanderhider, President
Telephone: (713) 659-3500

 

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Item 11. EXECUTIVE COMPENSATION
All of our executive officers are full-time employees of EnerVest and its subsidiaries. We have entered into an operating agreement with a subsidiary of EnerVest (described in Item 13). Pursuant to the operating agreement, we pay EnerVest a fee to operate our business, and EnerVest provides us the services of its employees, including our executive officers, to operate our business. The fee we pay to EnerVest does not include any direct reimbursement for the salaries, bonuses or other compensation paid by EnerVest to the EnerVest employees which act as our executive officers. Therefore, no executive officers of Belden & Blake received any remuneration from Belden & Blake Corporation during 2008.
Compensation of Directors
Our directors are not compensated. We have no independent directors, as independence is defined by the New York Stock Exchange.
Compensation Committee Interlocks and Insider Participation
We do not have a compensation committee. As of December 31, 2008, none of our officers are compensated by us.

 

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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 March 5, 2009 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 of  
Five Percent Shareholders   Number of Shares     Shares  
Capital C Energy Operations, LP (1)
1001 Fanin Street, Suite 800
Houston, Texas 77002
     1,534       100.0 %
     
(1)   Subsidiaries of EnerVest, Ltd., are the general partners of the limited partnership that owns Capital C Energy Operations, L.P. EnerVest, therefore, also may be deemed to be a beneficial owner of the 1,534 shares (100%) of our Common Stock. The address of EnerVest, Ltd., is 1001 Fannin Street, Suite 800, Houston, Texas 77002. EnerVest is a Texas limited partnership. Messrs. John B. Walker, Jon Rex Jones and A.V. Jones by virtue of their direct and indirect ownership of the limited liability company that acts as EnerVest’s general partner, may be deemed to beneficially own the Common Stock beneficially owned by EnerVest. Messrs. Walker, John Rex Jones and A.V. Jones disclaim beneficial ownership of such Common Stock. The addresses for Messrs. Walker, Jon Rex Jones and A.V. Jones are the same as for EnerVest.
Equity Compensation Plan Information:
As of March 5, 2009, we do not have any outstanding stock options or plans to grant any options.

 

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Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
On March 15, 2006, we entered into a joint operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. Amounts paid to EnerVest Operating under the terms of the agreement were $6.6 million for overhead fees, $7.1 million for field labor, vehicles and district office expense, $265,000 for drilling overhead fees and $1.0 million for drilling labor costs in 2008.
As of December 31, 2008, we owed EnerVest Operating $1.1 million and EnerVest owed us $12,000.
In connection with the Transaction, we executed a subordinated promissory note in favor of our parent, Capital C in the maximum amount of $94 million. Under the note, Capital C loaned $25 million to us on August 16, 2005 in connection with the Transaction. The note accrues interest at 10% per year and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the note made on August 16, 2005. Interest payments on the note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. The amount due under the note at December 31, 2008 was $27.6 million. We made cash payments of $2.0 million and borrowed an additional $677,000 for interest payments against the note in 2008.
Messrs. Houser, Vanderhider and Mariani are officers and directors of the Company and they are officers and equity owners of EnerVest. The institutional funds that are managed by EnerVest and own our direct parent, Capital C, also hold other investments in oil and gas assets and operations. We can give no assurance that conflicts of interest will not arise for 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. Houser, Vanderhider and Mariani.

 

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Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Deloitte & Touche LLP served as our independent Registered Public Accounting Firm for the years ended December 31, 2008 and 2007. Aggregate fees for professional services provided to us by Deloitte & Touche LLP for the years ended December 31, 2008 and 2007 were as follows:
                 
    December 31,  
    2008     2007  
Audit fees
   $ 470,000     $ 408,500  
Audit-related fees
     —       —  
Tax fees
     —       —  
All other fees
     —       —  
 
            
 
   $ 470,000     $ 408,500  
 
            
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. All other fees include research materials. Our Audit Committee approved 100% of these accounting services.
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.

 

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3. Exhibits
         
No.   Description
       
 
  2.1    
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    
First Amended and Restated Credit and Guaranty Agreement, dated as of August 16, 2005, by and among Belden & Blake Corporation, as borrower, certain subsidiaries of Belden & Blake Corporation, as guarantors, various lenders signatory thereto, and BNP Paribas., as sole lead arranger, sole bookrunner, syndication agent and administrative agent (incorporated by reference to Exhibit 10.1 to Belden & Blake Corporation’s Form 8-K dated August 22, 2005.
       
 
  10.3    
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).
       
 
  10.4    
Schedule to the ISDA Master Agreement, dated as of June 30, 2004 and amended and restated as of August 16, 2005, by and between J. Aron & Company and Belden & Blake Corporation (incorporated by reference to Exhibit 10.2 to Belden & Blake’s 8- K filed on August 22, 2005)
       
 
  10.5    
Credit Support Annex to the Schedule to the ISDA Master Agreement, dated as of June 30, 2004 and amended and restated as of August 16, 2005, by and between J. Aron & Company and Belden & Blake Corporation (incorporated by reference to Exhibit 10.3 to Belden & Blake’s 8-K filed on August 22, 2005)
       
 
  10.6    
Subordinated Promissory Note, dated August 16, 2005, between Capital C Energy Operations, LP and Belden & Blake Corporation (incorporated by reference to Exhibit 10.8 to Belden & Blake’s 8-K filed on August 22, 2005)
       
 
  10.7    
First Amendment to Credit Agreement, dated as of September 27, 2005, by and among Belden & Blake Corporation and BNP Paribas, incorporated by reference to Exhibit 10.25 to the Belden & Blake Corporation’s annual report on Form 10-K for the year ended December 31, 2005.
       
 
  10.8    
Operating Agreement dated October 1, 2005, by and between Belden & Blake Corporation and EnerVest Operating L.L.C. incorporated by reference to Exhibit 10.26 to the Belden & Blake Corporation’s annual report on Form 10-K for the year ended December 31, 2005.

 

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No.   Description
       
 
  10.9 *   
Fourth Amendment, Waiver and Agreement to the First Amended and Restated Credit and Guaranty Agreement dated as of August 16, 2005.
       
 
  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.
       
 
  23.1 *   
Consent of Independent Petroleum Engineering Consultants.
       
 
  31.1 *   
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

 

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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 CORPORATION    
 
                
April 9, 2009
      By:   /s/ Mark A. Houser     
 
Date
         
 
Mark A. Houser, Chief Executive Officer,
Chairman of 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/ Mark A. Houser 
  Chief Executive Officer
   April 9, 2009    
 
Mark A. Houser
  Chairman of the Board
of Directors and Director
(Principal Executive Officer) 		 
 
Date 		   
 
            
/s/ James M. Vanderhider 
  President, Chief Financial
   April 9, 2009    
 
           
James M. Vanderhider
  Officer and Director
(Principal Financial Officer) 		  Date    
 
            
/s/ Frederick J. Stair 
  Vice President of Accounting
   April 9, 2009    
 
           
Frederick J. Stair
  (Principal Accounting Officer)   Date    
 
            
/s/ Kenneth Mariani 
  Senior Vice President, Chief
   April 9, 2009    
 
           
Kenneth Mariani
  Operating Officer and Director   Date    
 
            
/s/ Matthew Coeny 
  Director   April 9, 2009    
 
           
Matthew Coeny
      Date    

 

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BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES
Item 15(a) (1) and (2)
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.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Owners of Belden & Blake Corporation
Houston, TX
We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2008. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Belden & Blake Corporation and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 7 to the consolidated financial statements, effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement.
/s/ DELOITTE & TOUCHE LLP
Houston, TX
April 9, 2009

 

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BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
                 
    December 31,  
    2008     2007  
ASSETS
                
Current assets
                
Cash and cash equivalents
   $ 22,816     $ 16,014  
Accounts receivable (less accumulated provision for doubtful accounts:
December 31, 2008 — $312; December 31, 2007 — $806)
     19,244       18,071  
Inventories
     1,004       1,084  
Deferred income taxes
     7,946       17,282  
Other current assets
     332       370  
Fair value of derivatives
     430       37  
 
            
Total current assets
     51,772       52,858  
 
                
Property and equipment, at cost
                
Oil and gas properties (successful efforts method)
     735,398       713,912  
Gas gathering systems
     1,413       1,308  
Land, buildings, machinery and equipment
     2,836       2,761  
 
            
 
     739,647       717,981  
Less accumulated depreciation, depletion and amortization
     124,175       88,549  
 
            
Property and equipment, net
     615,472       629,432  
Goodwill
     —       90,076  
Fair value of derivatives
     868       29  
Other assets
     1,352       1,830  
 
            
 
   $ 669,464     $ 774,225  
 
            
LIABILITIES AND SHAREHOLDER’S EQUITY
                
Current liabilities
                
Accounts payable
   $ 3,570     $ 2,656  
Accrued expenses
     19,251       20,363  
Current portion of long-term liabilities
     25,237       367  
Fair value of derivatives
     20,520       43,696  
 
            
Total current liabilities
     68,578       67,082  
 
                
Long-term liabilities
                
Bank and other long-term debt
     74,938       99,947  
Senior secured notes
     163,302       164,240  
Subordinated promissory note — related party
     27,623       26,931  
Asset retirement obligations and other long-term liabilities
     23,863       22,164  
Fair value of derivatives
     101,570       192,661  
Deferred income taxes
     133,039       98,977  
 
            
Total long-term liabilities
     524,335       604,920  
 
                
Shareholder’s equity
                
Common stock: without par value; 3,000 shares authorized; 1,534 shares issued
     —       —  
Additional paid in capital
     122,500       125,000  
Retained earnings
     (32,754 )     (3,810 )
Accumulated other comprehensive loss
     (13,195 )     (18,967 )
 
            
Total shareholder’s equity
     76,551       102,223  
 
            
 
   $ 669,464     $ 774,225  
 
            
See accompanying notes.

 

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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
                         
    For the Year Ended December 31,  
    2008     2007     2006  
 
                        
Revenues
                        
Oil and gas sales
   $ 145,398     $ 114,427     $ 147,122  
Gas gathering and marketing
     12,254       10,275       11,294  
Other
     774       438       358  
 
                  
 
     158,426       125,140       158,774  
 
                        
Expenses
                        
Production expense
     26,342       24,585       23,692  
Production taxes
     3,054       2,265       2,404  
Gas gathering and marketing
     10,252       8,640       9,360  
Exploration expense
     2,543       1,935       1,797  
General and administrative expense
     8,188       8,236       9,796  
Depreciation, depletion and amortization
     35,560       36,087       38,074  
Impairment of goodwill
     90,076       —       —  
Impairment of oil and gas properties
     3,924       31       546  
Accretion expense
     1,412       1,290       1,226  
Derivative fair value (gain) loss
     (55,940 )     78,120       (37,356 )
 
                  
 
     125,411       161,189       49,539  
 
                  
Operating income (loss)
     33,015       (36,049 )     109,235  
 
                        
Other expense (income)
                        
Gain on early extinguishment of debt
     —       —       (436 )
Interest expense
     22,818       23,712       23,553  
Other income, net
     (495 )     (516 )     (316 )
 
                  
 
Income (loss) before income taxes
     10,692       (59,245 )     86,434  
Provision (benefit) for income taxes
     39,636       (23,923 )     34,235  
 
                  
 
Net (loss) income
   $ (28,944 )   $ (35,322 )   $ 52,199  
 
                  
See accompanying notes.

 

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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (DEFICIT)
(in thousands)
                                                 
                                    Accumulated Other        
    Common     Common     Paid in     Equity     Comprehensive     Total  
    Shares     Stock     Capital     (Deficit)     Income     Equity  
January 1, 2006
     2       —     $ 125,000     $ 9,063     $ (44,664 )   $ 89,399  
Comprehensive income (loss):
                                                
Net income
                             52,199               52,199  
Other comprehensive income (loss), net of tax:
                                                
Change in derivative fair value
                                     19,933       19,933  
Reclassification adjustment for derivative (gain) loss reclassified into earnings
                                     2,172       2,172  
 
                                              
Total comprehensive income
                                             74,304  
Dividends
                             (20,000 )             (20,000 )
 
                                    
December 31, 2006
     2       —     $ 125,000     $ 41,262     $ (22,559 )   $ 143,703  
Comprehensive income (loss):
                                                
Net loss
                             (35,322 )             (35,322 )
Other comprehensive income (loss), net of tax:
                                                
Change in derivative fair value
                                     4,371       4,371  
Reclassification adjustment for derivative (gain) loss reclassified into earnings
                                     (779 )     (779 )
 
                                              
Total comprehensive income
                                             (31,730 )
Dividends
                             (9,750 )             (9,750 )
 
                                    
December 31, 2007
     2       —     $ 125,000     $ (3,810 )   $ (18,967 )   $ 102,223  
Comprehensive income (loss):
                                                
Net loss
                             (28,944 )             (28,944 )
Other comprehensive income (loss), net of tax:
                                                
Change in derivative fair value
                                     (409 )     (409 )
Reclassification adjustment for derivative (gain) loss reclassified into earnings
                                     6,181       6,181  
 
                                              
Total comprehensive income
                                             (23,172 )
Dividends
                     (2,500 )     —               (2,500 )
 
                                    
December 31, 2008
     2       —     $ 122,500     $ (32,754 )   $ (13,195 )   $ 76,551  
See accompanying notes.

 

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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
                         
    For the Year     For the Year     For the Year  
    Ended     Ended     Ended  
    December 31,     December 31,     December 31,  
    2008     2007     2006  
Cash flows from operating activities:
                        
Net (loss) income
   $ (28,944 )   $ (35,322 )   $ 52,199  
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
                        
Depreciation, depletion and amortization
     35,560       36,087       38,074  
Impairment of goodwill
     90,076       —       —  
Impairment of oil and gas properties
     3,924       31       546  
Accretion expense
     1,412       1,290       1,226  
(Gain) loss on debt extinguishment and disposal of property and equipment
     —       (75 )     (472 )
Amortization of derivatives and other noncash derivative activities
     (46,064 )     84,901       (56,057 )
Exploration expense
     1,974       610       738  
Deferred income taxes
     39,636       (23,923 )     33,710  
Other non-cash expense
     747       2,783       1,483  
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
                        
Accounts receivable and other current assets
     (1,135 )     1,734       5,210  
Inventories
     147       (266 )     100  
Accounts payable and accrued expenses
     (630 )     219       (10,201 )
 
                  
 
Net cash provided by operating activities
     96,703       68,069       66,556  
 
                        
Cash flows from investing activities:
                        
Proceeds from property and equipment disposals
     3,049       267       7,419  
Exploration expense
     (1,974 )     (610 )     (738 )
Additions to property and equipment
     (28,620 )     (22,696 )     (36,839 )
Decrease (increase) in other assets
     54       (10 )     (18 )
 
                  
 
Net cash used in investing activities
     (27,491 )     (23,049 )     (30,176 )
 
                        
Cash flows from financing activities:
                        
Repayment of senior secured notes
     —       —       (33,933 )
Payment to shareholders and optionholders or dividends
     (2,500 )     (9,750 )     (20,000 )
Settlement of derivative liabilities recorded in purchase accounting
     (59,901 )     (29,659 )     (28,042 )
Proceeds from revolving line of credit
     —       6,500       55,376  
Repayment of revolving line of credit
     —       (2,000 )     (12,000 )
Repayment of long-term debt and other obligations
     (9 )     (24 )     (26 )
 
                  
 
Net cash used in financing activities
     (62,410 )     (34,933 )     (38,625 )
 
                  
 
Net increase (decrease) in cash and equivalents
     6,802       10,087       (2,245 )
 
                        
Cash and cash equivalents at beginning of period
     16,014       5,927       8,172  
 
                  
 
Cash and cash equivalents at end of period
   $ 22,816     $ 16,014     $ 5,927  
 
                  
See accompanying notes.

 

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BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Transaction and 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. On August 16, 2005, the former partners of the direct parent of Belden & Blake Corporation (the “Company”), Capital C Energy Operations, L.P., a Delaware limited partnership (“Capital C”), completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest, Ltd. (“EnerVest”), a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”). The Transaction resulted in a change in control of the Company (“Change in Control”).
On July 7, 2004, the Company, 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 was controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P. and Capital C Energy Partners, L.P. until the Transaction on August 16, 2005.
The Transaction and Merger were each accounted for as a purchase effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date.
Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in the acquisition. The recorded goodwill is not deductible for tax purposes.
SFAS No. 142, Goodwill and Other Intangible Assets requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change could potentially result in an impairment.
The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. As we have only one reporting unit, the reporting unit used for testing will be the entire company. The fair value of the reporting unit is determined and compared to the book value of that reporting unit. The fair value of the reporting unit is based on estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $90.1 million due to the significant drop in oil and gas prices.
(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.

 

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Principles of Consolidation and Financial Presentation
The accompanying consolidated financial statements include the financial statements of the Company and our subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to previously reported amounts in order to conform to current year presentation. Such reclassifications do not effect earnings. Interest income is reported in “Other income, net” in the Statements of Operations. For the years ended December 31, 2007 and 2006 “Other income, net” has been adjusted to include $516,000 and $316,000, respectively, of interest income to conform with current year presentation. These amounts were previously recorded as “Other” revenue in our Statements of Operations. This reclassification had no material impact on total operating revenue, operating income or net income for the years ended December 31, 2007 and 2006.
Use of Estimates in the Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts. 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.
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 undeveloped properties, are expensed as incurred. The costs of carrying and retaining undeveloped properties include 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 certain 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. We recorded impairments of $783,000, $31,000 and $332,000 in 2008, 2007 and 2006, respectively, which reduced the book value of unproved oil and gas properties to their estimated fair value.
Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.

 

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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 2008, we recorded $3.1 million of impairments which reduced the book value of producing properties to their estimated fair value. No impairment was recorded in 2007. In performing the review for long-lived asset recoverability during 2006, we recorded $214,000 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.
Goodwill and Other 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).
As described in Note 1, we recorded goodwill associated with the Transaction which resulted in goodwill of $90.1 million at December 31, 2007. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2008, we performed our annual assessment of impairment of the goodwill and determined that there was no impairment. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $90.1 million due to the significant drop in oil and gas prices.
At December 31, 2008 and 2007, we had $717,000 and $1.1 million, respectively, of deferred debt issuance costs. Deferred debt issuance costs are being amortized over their respective terms. Amortization expense related to deferred debt issuance costs was $424,000 in 2008, 2007 and 2006. At December 31, 2008, the amortization of deferred debt issuance costs in the next five years is as follows: $424,000 in 2009, $270,000 in 2010 and none in 2011 or 2012.
Revenue Recognition
Oil and natural gas revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is probable. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under-produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no material gas imbalances at December 31, 2008 or 2007. Oil and gas marketing revenues are recognized when title passes.

 

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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. The Predecessor Companies measured 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.
We had no outstanding stock options or stock-based compensation activity in the years ended December 31, 2006, 2007 or 2008.
Derivatives and Hedging
In accordance with SFAS 133, we recognize all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not designated as cash flow hedges are adjusted to fair value through net income (loss). Under the provisions of SFAS 133, 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 impact earnings. 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 5.
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 assess effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Hedge accounting is discontinued prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.
Asset Retirement Obligations
We follow SFAS 143, “Accounting for Asset Retirement” which requires us to recognize a liability for the fair value of its asset retirement obligations associated with our 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. There has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows.

 

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A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2008 and 2007 is as follows (in thousands):
                 
    Year Ended     Year Ended  
    December 31,     December 31,  
    2008     2007  
Beginning asset retirement obligations
   $ 22,264     $ 20,734  
Liabilities incurred
     565       220  
Liabilities settled
     (399 )     (219 )
Accretion expense
     1,412       1,290  
Revisions in estimated cash flows
     43       239  
 
            
Ending asset retirement obligations
   $ 23,885     $ 22,264  
 
            
(3) New Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities. We adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and the adoption did not have a material impact on our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 was effective for fiscal years beginning after November 15, 2007. We have elected not to apply the provisions of SFAS No. 159.
In December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to significantly change the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions and will change the accounting treatment for certain specific items, including:
acquisition costs will generally be expensed as incurred;
noncontrolling interests will be valued at fair value at the date of acquisition; and
liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period.
SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008 and must be applied prospectively to business combinations completed on or after that date. We adopted SFAS No. 141(R) on January 1, 2009, and there was no impact on our consolidated financial statements.

 

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In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51, to establish new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS No. 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. We adopted SFAS No. 160 on January 1, 2009, and there was no impact on our consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. We adopted the disclosure requirements of SFAS No. 161 on January 1, 2009.
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States. SFAS No. 162 was effective on November 15, 2008.
In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its oil and natural gas reporting disclosures. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12 month period rather than year end prices. The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending on or after December 31, 2009. We will adopt the new disclosure requirements on December 31, 2009.
(4) Dispositions
On March 31, 2006, we sold our interests in 13 Oriskany wells and the associated gas gathering system for approximately $3.3 million, which approximated the net carrying value of such assets.
In August, 2006, we closed on the sale of our office building in North Canton, Ohio. Net proceeds from the sale were approximately $3.5 million, which was the carrying value of the property.

 

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In March, 2008, we sold a 50%-70% option interest in certain deep rights on approximately 201,000 net acres in Ohio and Pennsylvania for $3.0 million.
(5) 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 price, crude oil price or interest rate volatility and to support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At December 31, 2008, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that we believe are a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges. Changes in fair value of the derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time the hedged items impact earnings. The changes in fair value of non-qualifying derivative contracts will be reported in expense in the consolidated statements of operations as derivative fair value loss.
We use NYMEX-based commodity derivative contracts to hedge natural gas, because our natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, we had ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. At August 16, 2005, our oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in fair value of the oil swaps subsequent to August 15, 2005 and the ineffective portion of the natural gas swaps from July 7, 2004 through June 30, 2006 are recorded as “Derivative fair value gain or loss.” As of July 1, 2006, we determined that our gas swaps were no longer highly effective and, therefore, could no longer be designated as cash flow hedges. Changes in the fair value of the gas derivatives from that date forward are recorded in derivative fair value gain/loss. Deferred gains or losses on these gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings.
During 2008 and 2007, net losses of $10.2 million ($6.2 million after tax) and $7.6 million ($4.6 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges in accumulated other comprehensive income increased $677,000 ($409,000 million after tax) in 2008 and decreased $6.3 million ($3.8 million after tax) in 2007. At December 31, 2008, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $4.8 million. At December 31, 2008, we have partially hedged our exposure to the variability in future cash flows through December 2013.

 

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The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial derivatives (including settled contracts) at December 31, 2008:
                                                 
    Natural Gas Swaps     Crude Oil Swaps     Natural Gas Basis Swaps  
            NYMEX             NYMEX                
            Price per             Price per             Basis  
Year Ending   Bbtu     Mmbtu     Mbbls     Bbl     Bbtu     Differential  
December 31, 2009
     9,529     $ 4.43       191     $ 29.34       6,388     $ 0.344  
December 31, 2010
     8,938       4.28       175       28.86       6,388       0.255  
December 31, 2011
     8,231       4.19       157       28.77       3,285       0.325  
December 31, 2012
     7,005       4.09       138       28.70       —       —  
December 31, 2013
     6,528       4.04       127       28.70       —       —  
At December 31, 2008, we had interest rate swaps in place on $80 million of our outstanding debt under the revolving credit facility through September 30, 2010. The swaps provide 1-month LIBOR fixed rates at 4.07% on $80 million through September 2010, plus the applicable margin. These interest rate swaps do not qualify for hedge accounting, therefore, all cash settles and changes in the fair value of these swaps are recorded in derivative fair value gain/loss. At December 31, 2008, the fair value of the interest rate swap represented an unrealized loss of $3.5 million.

 

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(6) Details of Balance Sheets
                 
    December 31,  
    2008     2007  
    (in thousands)     (in thousands)  
Accounts receivable
                
Accounts receivable
   $ 3,884     $ 3,509  
Allowance for doubtful accounts
     (312 )     (806 )
Oil and gas production receivable
     15,672       15,368  
 
            
 
   $ 19,244     $ 18,071  
 
            
Inventories
                
Oil
   $ 755     $ 671  
Natural gas
     —       —  
Material, pipe and supplies
     249       413  
 
            
 
   $ 1,004     $ 1,084  
 
            
Property and equipment, gross oil and gas properties
                
Producing properties
   $ 662,473     $ 628,707  
Non-producing properties
                
Proved
     58,995       66,793  
Unproved
     13,930       18,344  
Other
     —       68  
 
            
 
   $ 735,398     $ 713,912  
 
            
Land, buildings, machinery and equipment
                
Land, buildings and improvements
   $ 838     $ 838  
Machinery and equipment
     1,998       1,923  
 
            
 
   $ 2,836     $ 2,761  
 
            
Accrued expenses
                
Accrued interest expense
   $ 6,418     $ 6,499  
Accrued other expenses
     5,837       6,230  
Accrued drilling and completion costs
     1,727       1,296  
Accrued income taxes
     —       2  
Ad valorem and other taxes
     968       985  
Undistributed production revenue
     4,301       5,351  
 
            
 
   $ 19,251     $ 20,363  
 
            

 

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(7) Long-Term Debt
Long-term debt consists of the following (in thousands):
                 
    December 31,  
    2008     2007  
Senior secured notes
   $ 159,475     $ 159,475  
Bank revolving credit facility
     99,876       99,876  
Subordinated promissory note (related party)
     27,623       26,931  
Other
     70       79  
 
            
 
     287,044       286,361  
 
                
Less current portion
     25,008       8  
 
            
Long-term debt
     262,036       286,353  
Fair value adjustment — senior secured notes
     3,827       4,765  
 
            
 
   $ 265,863     $ 291,118  
 
            
Senior Secured Notes due 2012
We have $159.5 million of our Senior Secured Notes outstanding as of December 31, 2008 and 2007. As a result of the application of purchase accounting, the Senior Secured Notes were recorded as a liability based on the estimated fair value of $200.7 million on the Transaction date. Subsequent accretion of the premium and repurchase of bonds reduced this amount to $163.3 million at December 31, 2008. The fair value adjustment of $3.8 million is shown separately in the table above. The accretion of $866,000 and $938,000 was recorded as a reduction of interest expense in 2007 and 2008. The Senior Secured Notes mature July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year at 8.75% based on the face amount of $159.5 million (for an effective rate of 7.946% based on the fair value on the Transaction date). The Senior Secured Notes are secured on a second-priority lien on the same assets subject to the liens securing our obligations under the Amended Credit Agreement. The Senior Secured 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 Senior Secured 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.
Amended Credit Agreement
In 2005, we amended and restated our then existing credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among the Company and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us. The obligations under the Amended Credit Agreement are secured by substantially all of our assets. J.P. Morgan Chase and Amegy Bank were added to the bank group in September 2005.

 

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The Amended Credit Agreement provides for a revolving credit line in the aggregate principal amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of $40 million. At December 31, 2008, the borrowing base was $113.4 million. The outstanding balance at December 31, 2008 and 2007 was $99.9 million. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.
The obligations under the Amended Credit Agreement are secured by a first lien security interest in substantially all of our assets. The obligations under the Amended Credit Agreement are further secured by a pledge of 100% of our capital stock held by Capital C, our parent.
The Amended Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase our stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio.
Effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement. The agreement was entered into to provide for certain waivers and modifications to the debt terms and covenants. This amendment was a direct result of the determination as of December 31, 2008, that the Company, would not maintain compliance with certain financial covenants during 2009 and 2010. Accordingly, on April 9, 2009, our bank group waived the leverage ratio for the quarters ended March 31, 2009 and June 30, 2009 and amended the Amended Credit Agreement to increase the maximum leverage ratio to 5.375 : 1.0 through December 31, 2009, 5.25 : 1.0 at March 31, 2010 and 5.0 : 1.0 at June 30, 2010. The bank group also waived the interest coverage ratio as of June 30, 2009 and amended the Amended Credit Agreement to reduce our minimum interest coverage ratio to 2.0 : 1.0 through March 31, 2010 and 2.25 : 1.0 at June 30, 2010. Additionally, Capital C, our parent, has committed to the Company to provide financial support. Taking into consideration the amended financial covenants and the financial support from Capital C, the Company, as of April 9, 2009, has projected that it would maintain compliance with such amended covenants through 2009 and 2010.
Additionally, the amendment provided that the borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 1.75% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.25% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The agreement was also amended for the following:
  •   Set the Borrowing Base at $100 million.
  •   Set the Borrowing Base redetermination dates to March 15th and September 15th each year.
  •   Prohibit payment of dividends to our shareholder.
  •   Prohibit Senior Secured Note repurchases by the Company.
  •   Prohibit principal or cash interest payments on the Capital C Subordinated Note.
  •   Prohibit borrowings to fund restructuring of the hedge agreements.
  •   Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.
  •   Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.
  •   Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.
At December 31, 2008, we were in compliance with our covenants under the Amended Credit Agreement. Our leverage ratio was 4.25 : 1.0 and the interest coverage ratio was 2.72 : 1.0.

 

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On August 3, 2007, our bank group waived the covenant compliance requirement as of June 30, 2007 and amended the Amended Credit Agreement to increase the maximum leverage ratio from 4.0 : 1.0 to 4.25 : 1.0 for the quarters ending on September 30, 2007 and December 31, 2007. If we had not received this waiver, we would not have complied with our leverage ratio covenant as it would have been 4.07 to 1.0 as of June 30, 2007. On March 24, 2008, our bank group waived the covenant compliance requirement as of December 31, 2007 and amended the Amended Credit Agreement to increase the maximum Leverage Ratio to 4.5 : 1.0 through December 31, 2008. If we had not received this waiver, we would not have complied with our Leverage Ratio covenant as it would have been 4.38 : 1.0 as of December 31, 2007.
Borrowings under the revolving credit line will be used by us for general corporate purposes. In accordance with the terms of the Amended Credit Agreement, letters of credit issued under the hedge letter of credit commitment and any related borrowings are to be used solely to secure payment of our obligations under the J. Aron Swap (defined hereinafter).
In connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note (“Subordinated Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. The Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Subordinated Note made on August 16, 2005. Interest payments on the Subordinated Note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the Subordinated Note by borrowing additional amounts against the Subordinated Note. The interest payments in 2006 were paid in cash. We made a cash payment of $616,000 and borrowed an additional $1.9 million against the Subordinated Note for interest payments in 2007. We made cash payments of $2.0 million and borrowed an additional $677,000 against the Subordinated Note for interest payments in 2008. The Subordinated Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. Pursuant to the Fourth Amendment to our credit agreement, cash payments for principal or interest on the Subordinated Note are prohibited. The Subordinated Note is subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and the Senior Secured Notes.
ISDA Master Agreement
We amended and restated the Schedule and Credit Support Annex to our ISDA Master Agreement, dated as of June 30, 2004, by and between us and J. Aron & Company (“J. Aron Swap”), pursuant to which we have agreed, from time to time, to enter into cash-settled hedge transactions with J. Aron & Company, as hedge counterparty, in connection with various gas and oil commodity derivatives transactions. The amendments to the J. Aron Swap conform the terms of the Schedule and Credit Support Annex to the terms of the Amended Credit Agreement, change certain covenants and reduce the maximum amount of the letter of credit securing the hedge obligations from $55 million to $40 million.
At December 31, 2008, the aggregate long-term debt maturing in the next five years is as follows: $25.0 million (2009); $74.9 million (2010); $10,000 (2011); $187.1 (2012) and $32,000 (2013 and thereafter). Our term loan facility requires mandatory prepayments annually based on the calculation of excess cash flow, as defined in the agreement.

 

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(8) Leases
We lease natural gas compressors under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $3.8 million in 2008 and $3.1 million in 2007 and 2006.
Future minimum commitments under leasing arrangements as of December 31, 2008 were as follows:
         
    Operating  
As of December 31, 2008   Leases  
    (in thousands)  
2009
   $ 4,523  
2010
     2,226  
2011
     —  
2012
    —  
2013 and thereafter
     —  
 
      
Total minimum rental payments
   $ 6,749  
 
      
(9) Goodwill
SFAS No. 142, Goodwill and Other Intangible Assets requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change could potentially result in an impairment.
The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. As we have only one reporting unit, the reporting unit used for testing will be the entire company. The fair value of the reporting unit is determined and compared to the book value of that reporting unit. The fair value of the reporting unit is based on estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $90.1 million in the due to the significant drop in oil and gas prices.
(10) Impairment of Oil and Gas Properties
For the period ended December 31, 2008, we reviewed our oil and gas properties for impairment as prescribed by SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. As a result of this evaluation an impairment of $1.9 million was recorded during the fourth quarter of 2008 to proved properties in the Utica Shale formation in Ohio and other unproved properties. We also recorded an impairment of $2.0 million during the second quarter of 2008 to proved properties in the Utica Shale formation in Ohio.

 

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(11) 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):
                         
    For the year     For the year     For the year  
    ended     ended     ended  
    December 31,     December 31,     December 31,  
    2008     2007     2006  
Current
                        
Federal
   $ —     $ (525 )   $ 525  
State
     —       —       —  
 
                  
 
     —       (525 )     525  
 
                        
Deferred
                        
Federal
     35,076       (20,499 )     29,771  
State
     4,560       (2,899 )     3,938  
 
                  
 
     39,636       (23,398 )     33,709  
 
                  
Total
   $ 39,636     $ (23,923 )   $ 34,234  
 
                  
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:
                         
    For the year     For the year     For the year  
    ended     ended     ended  
    December 31,     December 31,     December 31,  
    2008     2007     2006  
 
                        
Statutory federal income tax rate
     35.0 %     35.0 %     35.0 %
Increases (reductions) in taxes resulting from:
                        
State income taxes, net of federal tax benefit
     4.6       4.6       4.6  
Transaction related expenses
                        
Permanent differences related to goodwill impairment
     333.1       —       —  
Other, net
     (2.0 )     0.8       —  
 
                  
Effective income tax rate for the period
     370.7 %     40.4 %     39.6 %
 
                  
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.

 

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Significant components of deferred income tax liabilities and assets are as follows (in thousands):
                 
    December 31,     December 31,  
    2008     2007  
Deferred income tax liabilities:
                
Property and equipment, net
   $ 213,795     $ 213,509  
Other, net
     3,885       2,559  
Total deferred income tax liabilities
     217,680       216,068  
Deferred income tax assets:
                
Accrued expenses
     881       882  
Asset retirement obligations
     8,620       8,062  
Fair value of derivatives
     56,984       102,286  
Net operating loss carryforwards
     32,226       29,429  
Senior Secured Notes
     2,913       2,913  
Tax credit carryforwards
     1,775       1,775  
Other, net
     664       502  
Valuation allowance
     (11,476 )     (11,476 )
 
            
Total deferred income tax assets
     92,587       134,373  
 
            
Net deferred income tax liability
   $ 125,093     $ 81,695  
 
            
 
                
Long-term liability
   $ 133,039     $ 98,977  
Current asset
     (7,946 )     (17,282 )
 
            
Net deferred income tax liability
   $ 125,093     $ 81,695  
 
            
At December 31, 2008, we had approximately $68.5 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 2025. We also had state net operating losses aggregating $258 million, which expire between 2009 and 2025. The net operating losses are subject to annual limitations due to IRC Section 382 as a result of the Merger in 2004 and the Transaction in 2005. 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. We do not believe the application of Section 382 hinders our ability to utilize the federal net operating losses and, accordingly, no valuation allowance has been recorded. The valuation allowance of $11.5 million relates to certain state net operating loss carryforwards which we estimate would expire before they could be used. We have alternative minimum tax credit carryforwards of approximately $1.8 million, which have no expiration date.
FIN 48 requires us to evaluate whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions taken by us are supportable by existing laws and related interpretations, there are no material uncertain tax positions to consider in accordance with FIN 48.
(12) Stock Option Plans
We have a 1997 non-qualified stock option plan under which we are authorized to issue up to 1,466 shares of common stock to officers and employees. The exercise price of options may not be 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. No options were granted during 2006, 2007 or 2008 and as of December 31, 2008, no options were outstanding under the plan.

 

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(13) Commitments and Contingencies
The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes 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.
The following table summarizes our contractual obligations at December 31, 2008.
                                         
    Payments Due by Period  
Contractual Obligations at           Less than 1                     After 5  
December 31, 2008   Total     Year     1 - 3 Years     4 - 5 Years     Years  
    (in thousands)  
 
                                        
Long-term debt
   $ 287,044     $ 25,008     $ 74,895     $ 187,109     $ 32  
Asset retirement obligations
     23,885       229       386       17       23,253  
Derivative liabilities
     120,792       20,512       55,868       44,412       —  
Interest on debt
     64,565       19,874       35,406       9,285       —  
Operating leases
     6,749       4,523       2,226       —       —  
 
                              
Total contractual cash obligations
   $ 503,035     $ 70,146     $ 168,781     $ 240,823     $ 23,285  
 
                              
In addition to the items above, 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, 2008.
                                         
      Total      Amount of Commitment Expiration Per Period  
Commercial Commitments at   Amounts     Less than 1                     Over 5  
December 31, 2008   Committed     Year     1 - 3 Years     4 - 5 Years     years  
    (in thousands)  
 
                                        
Standby Letters of Credit
   $ 40,850     $ 40,850     $ —     $ —     $ —  
 
                              
Total Commercial Commitments
   $ 40,850     $ 40,850     $ —     $ —     $ —  
 
                              
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.

 

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(14) Supplemental Disclosure of Cash Flow Information
                         
    For the year     For the year     For the year  
    ended     ended     ended  
    December 31,     December 31,     December 31,  
(in thousands)   2008     2007     2006  
Cash paid during the period for:
                        
Interest
   $ 22,764     $ 17,939     $ 25,317  
Income taxes, net of refunds
     —       —       —  
Non-cash investing and financing activities:
                        
Non-cash additions to property and equipment
     (1,728 )     (1,296 )     (1,784 )
Non-cash additions to debt
     (692 )     (1,931 )     —  
(15) 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 $159.5 million (face amount) of our Senior Secured Notes due 2012 had an approximate fair value of $111.6 million at December 31, 2008 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, 2008, our derivative contracts consisted of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps. At December 31, 2008, the fair value of futures contracts covering 2008 through 2013 oil and gas production represented an unrealized loss of $117.2 million. At December 31, 2008, the fair value of our interest rate futures contracts covering 2009 through September 2010 represented an unrealized loss of $3.5 million.

 

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Table of Contents

(16) Fair Value Measurements
SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:
  •   Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.
 
  •   Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.
 
  •   Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets and liabilities at fair value.
A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.
The following table presents the fair value hierarchy table for our assets and liabilities that are required to be measured at fair value on a recurring basis:
                                 
            Fair Value Measurements at December 31, 2008  
            Quoted Prices in     Significant        
            Active Markets     Other     Significant  
            for Identical     Observable     Unobservable  
            Assets     Inputs     Inputs  
    Total Carrying Value     (Level 1)     (Level 2)     (Level 3)  
Derivative instruments
   $ (120,792 )   $ —     $ (120,792 )   $ —  
Our derivative instruments consist of over-the-counter (“OTC”) contracts which are not traded on a public exchange. These derivative instruments are indexed to active trading hubs for the underlying commodity, and are OTC contracts commonly used in the energy industry and offered by a number of financial institutions and large energy companies.
As the fair value of these derivative instruments is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third-party pricing services, brokers and market transactions, we have categorized these derivative instruments as Level 2.

 

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(17) Supplementary Information on Oil and Gas Activities (Unaudited)
The following disclosures of costs incurred related to oil and gas activities from continuing operations are presented in accordance with SFAS 69.
                         
    December 31,     December 31,     December 31,  
(in thousands)   2008     2007     2006  
Acquisition costs:
                        
Proved properties
   $ 1,504     $ 107     $ 16  
Unproved properties
     802       567       511  
Developmental costs
     26,845       21,910       36,052  
Exploratory costs
     2,543       1,935       2,343  
 
                  
 
     31,694       24,519       38,922  
 
                  
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, 2008, 2007 and 2006 have been prepared by Wright & Company, Inc., independent petroleum consultants.

 

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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:
                         
    Oil     Gas        
    (Mbbl)     (Mmcf)     Mmcfe  
January 1, 2006
     5,210       246,680       277,938  
Extensions and discoveries
     156       12,892       13,830  
Purchase of reserves in place
     41       881       1,130  
Sale of reserves in place
     —       (1,342 )     (1,342 )
Revisions of previous estimates
     146       (11,996 )     (11,123 )
Production
     (372 )     (14,104 )     (16,337 )
 
                  
 
December 31, 2006
     5,181       233,011       264,096  
Extensions and discoveries
     153       4,853       5,771  
Purchase of reserves in place
     —       5,340       5,340  
Revisions of previous estimates
     163       (2,647 )     (1,668 )
Production
     (348 )     (13,357 )     (15,445 )
 
                  
 
December 31, 2007
     5,149       227,200       258,094  
Extensions and discoveries
     78       6,415       6,883  
Purchase of reserves in place
     22       61       193  
Revisions of previous estimates
     (1,082 )     (20,625 )     (27,117 )
Production
     (334 )     (13,217 )     (15,221 )
 
                  
 
December 31, 2008
     3,833       199,834       222,832  
 
                  
 
Proved developed reserves
                        
December 31, 2006
     3,832       188,374       211,368  
 
                  
December 31, 2007
     3,890       186,765       210,105  
 
                  
December 31, 2008
     3,559       176,340       197,694  
 
                  
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.

 

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The standardized measure of discounted future net cash flows relating to estimated proved oil and gas reserves is presented below:
                         
    December 31,  
    2008     2007     2006  
    (in thousands)  
Estimated future cash inflows (outflows)
                        
Revenues from the sale of oil and gas
   $ 1,431,631     $ 2,190,884     $ 1,672,532  
Production costs
     (534,167 )     (590,328 )     (526,928 )
Development costs
     (57,491 )     (152,465 )     (134,553 )
Future income taxes
     (262,865 )     (497,904 )     (316,413 )
 
                  
Future net cash flows
     577,108       950,187       694,638  
10% timing discount
     (324,433 )     (561,301 )     (395,157 )
 
                  
Standardized measure of discounted future net cash flows
   $ 252,675     $ 388,886     $ 299,481  
 
                  
At December 31, 2008, 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 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 derivative financial instruments, consisting of natural gas and crude oil swaps and natural gas basis differential swaps in the determination of our oil and gas reserves.
                         
    December 31,  
    2008     2007     2006  
Gas (per Mcf)
   $ 6.38     $ 7.54     $ 5.91  
Oil (per Bbl)
     41.00       92.77       57.21  

 

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The principal sources of changes in the standardized measure of future net cash flows are as follows:
                         
    Year ended     Year ended     Year ended  
    December 31,     December 31,     December 31,  
    2008     2007     2006  
Beginning of year
   $ 388,886     $ 299,481     $ 545,764  
Sale of oil and gas, net of production costs
     (125,165 )     (96,317 )     (102,710 )
Extensions and discoveries, less related estimated future development and production costs
     9,514       14,720       25,806  
Previously estimated development costs incurred during the period
     26,845       21,910       29,477  
Purchase of reserves in place less estimated future production costs
     643       2,728       170  
Sale of reserves in place less estimated future production costs
     —       —       (4,122 )
Changes in estimated future development costs
     31,949       (7,337 )     (33,665 )
Revisions of previous quantity estimates
     (47,442 )     (237 )     (20,621 )
Net changes in prices and production costs
     (195,400 )     196,244       (354,397 )
Change in income taxes
     101,046       (75,511 )     148,217  
Accretion of 10% timing discount
     38,889       29,948       83,145  
Changes in production rates (timing) and other
     22,910       3,257       (17,583 )
 
                  
End of period
   $ 252,675     $ 388,886     $ 299,481  
 
                  
(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 2008, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $32.3 million, $30.7 million and $22.9 million, respectively. During 2007, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $26.3 million, $18.9 million and $18.1 million, respectively. During 2006, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $21.4 million, $20.1 million and $18.5 million, respectively.

 

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Table of Contents

(19) Quarterly Results of Operations (Unaudited)
The results of operations for the four quarters of 2008 and 2007 are shown below (in thousands).
                                 
    First     Second     Third     Fourth  
 
                                
2008
                                
Operating revenues
   $ 34,307     $ 50,302     $ 45,463     $ 28,354  
Gross profit
     15,526       30,884       24,926       8,565  
Net (loss) income
     (11,634 )     (58,907 )     91,705       (50,108 )
 
                                
2007
                                
Operating revenues
   $ 29,422     $ 34,801     $ 29,420     $ 31,059  
Gross profit
     11,580       15,676       11,555       12,379  
Net income
     (23,299 )     2,415       7,268       (21,706 )
(20) Related Party Transactions
On March 15, 2006, we entered into a joint operating agreement with EnerVest Operating, L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. The joint operating agreement was effective October 1, 2005 and resulted in expense to us of $5.3 million in 2006, $6.0 million in 2007 and $6.6 million in 2008 for overhead fees. We also paid $6.7 million in 2006, $7.5 million in 2007 and $7.1 million in 2008 for field labor, vehicles and district office expense; $875,000 in 2006, $331,000 in 2007 and $265,000 in 2008 for drilling overhead fees and $1.3 million in 2006, $1.2 million in 2007 and $1.0 million in 2008 for drilling labor costs related to this agreement. We reimbursed EnerVest Operating for expenses of $332,000 in 2006 related to the transition of accounting responsibilities to EnerVest Operating’s Charleston, West Virginia office.
We paid approximately $211,000 to Opportune LLP in the 2006 for consulting services related to the Company’s amended filings and the 2005 Form 10-K. John Vanderhider, brother of James Vanderhider, our President and Chief Financial Officer, is a partner with Opportune.
We paid approximately $207,000 to PetroAcct LP in 2006 for services related to the transition of accounting and information system responsibilities to EnerVest Operating. A subsidiary of EnerVest, Ltd owned 50% of PetroAcct during 2006. The 50% ownership interest in PetroAcct was sold to Opportune in March 2007.
As of December 31, 2008, we owed EnerVest Operating $1.1 million and EnerVest owed us $12,000.
In connection with the Transaction, we executed a subordinated promissory note in favor of our parent, Capital C in the maximum amount of $94 million. Under the note, Capital C loaned $25 million to us on August 16, 2005 in connection with the Transaction. The note accrues interest at 10% per year and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the note made on August 16, 2005. Interest payments on the note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. The amount due under the note at December 31, 2008 was $27.6 million. We made cash payments of $2.5 million in 2006. In 2007, we made a cash payment of $616,000 and borrowed an additional $1.9 million against the Note for interest payments. In 2008, we made cash payments of $2.0 million and borrowed and additional $677,000 against the Note for interest payments.

 

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Table of Contents

Messrs. Houser, Vanderhider and Mariani are officers and directors of the Company and they are officers and equity owners of EnerVest and EnerVest Operating. The institutional funds that are managed by EnerVest and own our direct parent, Capital C, also hold other investments in oil and gas assets and operations. We can give no assurance that conflicts of interest will not arise for 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. Houser, Vanderhider and Mariani.
(21) Subsequent Events
In January 2009, we entered into a sublease agreement covering 58,123 acres in Ohio for $2.5 million.

 

F-30

Table of Contents

EXHIBIT INDEX
     
10.9*  
Fourth Amendment, Waiver and Agreement to the First Amended and Restated Credit and Guaranty Agreement dated as of August 16, 2005.
   
 
23.1*  
Consent of Independent Petroleum Engineering Consultants.
   
 
31.1*  
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

 

 

EX-10.9 2 c83251exv10w9.htm EXHIBIT 10.9 Exhibit 10.9
Exhibit 10.9
FOURTH AMENDMENT, WAIVER AND AGREEMENT
This Fourth Amendment, Waiver and Agreement (“Agreement”) dated as of April 9, 2009 (“Effective Date”) is by and among Belden & Blake Corporation, an Ohio corporation (the “Company”), the Lenders (as defined below), and BNP Paribas, as Administrative Agent (as such term is defined below).
RECITALS
A. The Company, certain subsidiaries of the Company, as Guarantors, the lenders party thereto from time to time (the “Lenders”), and BNP Paribas, as administrative agent for such Lenders (together with its permitted successors in such capacity, the “Administrative Agent”) are parties to the First Amended and Restated Credit and Guaranty Agreement dated as of August 16, 2005, as amended by the First Amendment to Credit Agreement dated as of September 27, 2005, the Second Amendment and Waiver dated as of August 3, 2007 and the Third Amendment and Waiver dated as of March 24, 2008 (as so amended and as the same may be amended or modified from time to time, the “Credit Agreement”).
B. The Company, the Lenders and the Administrative Agent wish to, subject to the terms and conditions of this Agreement, (1) reduce the Borrowing Base (as defined in the Credit Agreement) to $100,000,000, (2) provide for a waiver of compliance with the Leverage Ratio covenant set forth in Section 6.8(b) of the Credit Agreement each day from March 31, 2009 through the Effective Date (the “Covenant Waiver”) and (3) make certain amendments to the Credit Agreement.
THEREFORE, the Company, the Administrative Agent and the Lenders hereby agree as follows:
Section 1. Defined Terms. As used in this Agreement, each of the terms defined in the opening paragraph and the Recitals above shall have the meanings herein assigned. Each term defined in the Credit Agreement and used herein without definition shall have the meaning assigned to such term in the Credit Agreement, unless expressly provided to the contrary.
Section 2. Other Definitional Provisions. Article, Section, Schedule, and Exhibit references are to Articles and Sections of and Schedules and Exhibits to this Agreement, unless otherwise specified. All references to instruments, documents, contracts, and agreements are references to such instruments, documents, contracts, and agreements as the same may be amended, supplemented, and otherwise modified from time to time, unless otherwise specified. The words “hereof”, “herein”, and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement. The term “including” means “including, without limitation,”. Paragraph headings have been inserted in this Agreement as a matter of convenience for reference only and it is agreed that such paragraph headings are not a part of this Agreement and shall not be used in the interpretation of any provision of this Agreement.
Section 3. Covenant Waiver. The Lenders agree, subject to the terms and conditions of this Agreement, to the Covenant Waiver. The waiver by the Lenders described in this Section 3 is contingent upon the satisfaction of the conditions precedent set forth below and is limited to the Covenant Waiver. Such waiver is limited to the extent described herein and shall not be construed to be a consent to or permanent waiver of any provision in Section 6.8(b) of the Credit Agreement, or any other terms, provisions, covenants, warranties, or agreements contained in the Credit Agreement or in any of the other Credit Documents. The Lenders reserve the right to exercise any rights and remedies available to them in connection with any other present or future

 

 

 

defaults with respect to the Credit Agreement or any other provision of any Credit Document. The description herein of the Covenant Waiver is based upon information provided to the Lenders on or prior to the date hereof and shall not be deemed to exclude the existence of any Defaults or Events of Default other than the Event of Default which may exist as of March 31, 2009 under Section 6.8(b) of the Credit Agreement if the Lenders do not agree to the Covenant Waiver. The failure of the Lenders to give notice to the Company of any such other Default or Event of Default is not intended to be nor shall be a waiver thereof. The Company hereby agrees and acknowledges that the Lenders require and will require strict performance by the Company of all of its obligations, agreements, and covenants contained in the Credit Agreement and the other Credit Documents, and no inaction or action regarding any Default or Event of Default is intended to be or shall be a waiver thereof.
Section 4. Amendments to the Credit Agreement.
(a) Section 1.01 of the Credit Agreement is hereby amended by deleting the definitions of “Applicable Margin”, “Asset Sale”, “Base Rate” and “Borrowing Base” in their entirety and replacing them with the following corresponding terms:
“Applicable Margin” means, on any date of its determination, a percentage per annum, determined by reference to the Utilization in effect at BNPP’s close of business in New York City on such date for the Type of Loan or the Commitment Fee as set forth below:
                         
    Applicable Margin     Applicable Margin for     Applicable Margin for  
Utilization   for Base Rate Loans     Eurodollar Rate Loans     Commitment Fees  
< 25%
     1.00 %     2.50 %     0.50 %
³ 25%
                        
< 50%
     1.25 %     2.75 %     0.50 %
³ 50%
                        
< 75%
     1.50 %     3.00 %     0.50 %
³ 75%
     1.75 %     3.25 %     0.50 %
The Applicable Margin shall increase by 2.00% during any Deficiency Period.
“Asset Sale” means a sale, lease or sub-lease (as lessor or sublessor), sale and leaseback, assignment, conveyance, transfer or other disposition to, or any exchange of property with, any Person (other than Company or any Guarantor), in one transaction or a series of transactions, of all or any part of Company’s or any of its Restricted Subsidiaries’ businesses, assets or properties of any kind, including Production Payments, whether real, personal, or mixed and whether tangible or intangible, whether now owned or hereafter acquired, including, without limitation, the Capital Stock or Securities of any of Company’s Restricted Subsidiaries, other than (i) Hydrocarbons (or other inventory or goods) sold or leased in the ordinary course of business (excluding any such sales by operations or divisions discontinued or to be discontinued), (ii) during the Adjustment Period, sales of assets (other than Hydrocarbons, other inventory or goods) for aggregate consideration of less than $100,000 with respect to any transaction or series of related transactions and less than $500,000 in the aggregate during any Fiscal Year, and (iii) upon expiration of the Adjustment Period, sales of assets (other than Hydrocarbons, other inventory or goods) for aggregate consideration of less than $250,000 with respect to any transaction or series of related transactions and less than $1,500,000 in the aggregate during any Fiscal Year.

 

2

 

“Base Rate” means, for any day, a rate per annum equal to the greatest of the then determinable (a)  Prime Rate in effect on such day, (b)  the Federal Funds Effective Rate in effect on such day plus 1/2 of 1%, and (c) the LIBO Rate on such day (or if such day is not a Business Day, the immediately preceding Business Day) plus 1.50%, provided that, in the context of this definition of Base Rate and for the avoidance of doubt, “LIBO Rate” means, for any day, the rate as quoted to BNPP’s London office for Dollar deposits of $5,000,000 having a one-month maturity at approximately 11:00 a.m. London time on such day. Any change in the Base Rate due to a change in the Prime Rate, the Federal Funds Effective Rate or the LIBO Rate shall be effective from and including the effective date of such change in the Prime Rate, the Federal Funds Effective Rate or the LIBO Rate, respectively.
“Borrowing Base” means at any particular time, the least of (a) the Dollar amount determined in accordance with Section 2.3 on account of Proven Reserves attributable to Oil and Gas Properties of the Company and the Guarantors subject to an Acceptable Security Interest and described in the most recent Independent Engineering Report or Internal Engineering Report, as applicable, delivered to the Administrative Agent and the Lenders pursuant to Section 2.3, before taking into account any reduction to such amount based on the principal amount of the Senior Secured Notes then outstanding (which, as of the Effective Date of the Fourth Amendment, is equal to $159,475,000), less 30% of the outstanding principal amount of the Senior Secured Notes; (b) the amount of the Permitted First Priority Secured Indebtedness, as such term is defined in the J. Aron Swap; (c) such amount as may be designated in writing by the Company to the Administrative Agent and the Revolving Lenders upon any redetermination under Section 2.3(b)(ii); and (d) such amount as may be designated by the Administrative Agent and the Revolving Lenders upon any redetermination under Section 2.3, subject to Section 2.3(e).
(b) Section 1.01 of the Credit Agreement is hereby amended by adding the following new defined terms in alphabetical order:
“Adjustment Period” means the period commencing on the Effective Date of the Fourth Amendment and expiring on the date that the Borrower has repaid or prepaid the Revolving Loans in an aggregate amount equal to $30,000,000 and the Borrowing Base has been, pursuant to Section 2.3(f), reduced by $30,000,000 in the aggregate; provided that, upon such expiration, the Adjustment Period shall not be reinstated regardless of any subsequent increases to the Borrowing Base.
“Effective Date of the Fourth Amendment” means the effective date of the Fourth Amendment and Agreement, which amends this Agreement.
“Equity Contribution” means an equity capital contribution of cash or Cash Equivalents by EnerVest or any other equity holder of the Company.
“Equity Issuance” means any issuance of equity securities or any other Capital Stock or Securities (including any preferred equity securities) by the Company or any of its Domestic Subsidiaries other than (i) Capital Stock issued to the Company or to a Guarantor, (ii) common, non-convertible Capital Stock issued pursuant to employee or director and officer stock option plans in the ordinary course of business, or (iii) common, non-convertible Capital Stock issued to the seller(s) as consideration in connection with any Permitted Acquisition that is permitted under Section 6.9(e).

 

3

 

“Commodity Transactions” means any and all swaps, options, forward contracts, cap transactions, floor transactions, collar transactions, spot contracts, or any other similar transactions or any combination of any of the foregoing (including any options to enter into any of the foregoing and any related confirmations) and related to oil, gas or oil and gas, whether or not any such transaction is governed by or subject to any Swap Agreement.
“Hedge Restructure” means (a) the entering into or purchase of any Commodity Transaction and (b) any supplement, modification, novation, termination, or unwinding of any Commodity Transaction, the effect of which, in either case, is to cancel or modify any existing hedge position established under the J. Aron Swap.
“Non-Ordinary Course Events” means, collectively, (a) Asset Sales, regardless of whether such Asset Sales are permitted under Section 6.9 hereof, (b) Equity Contributions, and (c) Equity Issuances.
“Non-Ordinary Course Proceeds” means (a) with respect to any Asset Sale, all cash and Cash Equivalents received by any Credit Party from such Asset Sale after (i) payment of, or provision for, all reasonable brokerage commissions, marketing expenses, estimated cash taxes attributable from such Asset Sale, and other reasonable out-of-pocket fees and expenses actually incurred directly in connection with such Asset Sale and (ii) the amount of reserves recorded in accordance with GAAP for indemnity or similar obligations of the Credit Parties directly related to such Asset Sale; (b) with respect to any Equity Contribution, the amount of such Equity Contribution after payment of all reasonable expenses of accountants, lawyers, appraisers and other professional advisors, if any, and other reasonable out-of-pocket fees and expenses actually incurred directly in connection with such Equity Contribution; and (c) with respect to any Equity Issuance, all cash and Cash Equivalents received by any Credit Party from such Equity Issuance after payment of all reasonable underwriter fees and expenses, Securities and Exchange Commission and blue sky fees, if any, reasonable expenses of accountants, lawyers and other professional advisors, brokerage commissions and other reasonable out-of-pocket fees and expenses actually incurred directly in connection with such Equity Issuance.
(c) Section 2.3 of the Credit Agreement is hereby amended by replacing each reference to “75%” found therein with a reference to “80%”.
(d) Section 2.3(a) of the Credit Agreement is hereby amended by deleting the last sentence thereof in its entirety and replacing it with the following:
Such initial Borrowing Base shall be subject to adjustment from time to time in accordance with the definition thereof, and shall be determined in accordance with the standards set forth in Section 2.3(d) and is subject to periodic redetermination pursuant to Sections 2.3(b) and 2.3(c) and periodic reduction pursuant to Section 2.3(f).

 

4

 

(e) Section 2.3(b)(i) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
(i) The Company shall deliver to the Administrative Agent and each of the Revolving Lenders on or before February 15th of each year beginning February 15, 2010, an Independent Engineering Report dated effective as of the immediately preceding January 1, and such other information as may be reasonably requested by any Revolving Lender with respect to the Oil and Gas Properties included or to be included in the Borrowing Base. The Administrative Agent shall promptly, and in any event within 30 days after the Administrative Agent’s and the Revolving Lenders’ receipt of such Independent Engineering Report and other information, deliver to each Revolving Lender the Administrative Agent’s recommendation for the redetermined Borrowing Base. The Administrative Agent and the Revolving Lenders shall promptly, and in any event on the later of (A) March 15th and (B) 15 days after the Revolving Lenders’ receipt of the Administrative Agent’s recommendation, redetermine the Borrowing Base in accordance with Section 2.3(d), and the Administrative Agent shall promptly notify the Company in writing of the amount of the Borrowing Base as so redetermined, which redetermined Borrowing Base shall become effective as of the date of such notice.
(f) Section 2.3(b)(ii) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
(ii) The Company shall deliver to the Administrative Agent and each of the Revolving Lenders on or before August 15th of each year beginning August 15, 2009, an Internal Engineering Report dated effective as of the immediately preceding July 1 and such other information as may be reasonably requested by the Administrative Agent or any Revolving Lender with respect to the Oil and Gas Properties included or to be included in the Borrowing Base. The Administrative Agent shall promptly, and in any event within 30 days after the Administrative Agent’s and the Revolving Lenders’ receipt of such Internal Engineering Report and other information, deliver to each Revolving Lender the Administrative Agent’s recommendation for the redetermined Borrowing Base. The Administrative Agent and the Revolving Lenders shall promptly, and in any event on the later of (A) September 15th and (B) 15 days after the Revolving Lenders’ receipt of the Administrative Agent’s recommendation, redetermine the Borrowing Base in accordance with Section 2.3(d), and the Administrative Agent shall promptly notify the Company in writing of the amount of the Borrowing Base as so redetermined, which redetermined Borrowing Base shall become effective as of the date of such notice.
(g) Section 2.3 of the Credit Agreement is hereby amended by adding the following new clause (f) to the end thereof:
(f) Mandatory Reduction. During the Adjustment Period, each repayment or prepayment of outstanding Revolving Loans shall automatically, and effective as of the date such repayment or prepayment is effected, reduce the then effective Borrowing Base by the amount of such repayment or prepayment.
(h) Section 2.6 of the Credit Agreement is hereby amended by adding the following to the end of the first sentence thereof:
; provided however, no portion of the proceeds of any Credit Extension shall be used to fund any obligations, liabilities, fees, or other amounts owing or otherwise occurring with respect to a Hedge Restructure.
(i) Section 2.14(a) of the Credit Agreement is hereby amended by deleting the reference to “Hedge L/C Exposure” found in clause (i) thereof with a reference to “Letter of Credit Usage.”

 

5

 

(j) Section 2.14(c) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
(c) Non-Ordinary Course Events. If (y) the Adjustment Period is in effect or (z) the Total Utilization of Revolving Commitments exceeds the lesser of the Borrowing Base or the aggregate Revolving Commitments, then, upon the occurrence of a Non-Ordinary Course Event, the Company shall prepay or repay the Loans and provide cash collateral for the Letter of Credit Usage with the Non-Ordinary Course Proceeds thereof in the order and as set forth below:
(i) unless the mandatory prepayment required under Section 2.14(d) below shall have been made, the first $20,000,000 of Non-Ordinary Course Proceeds, in the aggregate, shall be applied to prepay the Revolving Loans;
(ii) the next $40,000,000 of Non-Ordinary Course Proceeds (or the first $60,000,000 of Non-Ordinary Course Proceeds if the mandatory prepayment required under Section 2.14(d) has been made as required therein), in the aggregate, shall be applied, at the option of the Company, to fund any one or more of the following:
(A) effect any Hedge Restructure so long as (1) after giving effect to such Hedge Restructure, the Company remains protected against a decline in commodity prices at the same levels that are in effect on the Effective Date of the Fourth Amendment, and (2) prior to effecting such Hedge Restructure, the Hedge Letter of Credit Usage shall have been reduced in an amount, and subject to terms, satisfactory to the Administrative Agent,
(B) prepay the Revolving Loans, or
(C) drilling and development costs and expenses, Consolidated Capital Expenditures, the acquisition of Oil and Gas Properties or for any other general corporate purposes that is otherwise permitted under this Agreement; and
(iii) 50% of all Non-Ordinary Course Proceeds in excess of the first $60,000,000 which is to be applied as provided in clauses (i) and (ii) above, shall be applied to prepay the Revolving Loans, and if no Revolving Loans are outstanding, make deposits into a cash collateral account acceptable to the Administrative Agent to provide cash collateral for the Letter of Credit Usage.
Prepayments of the Loans and deposits of cash collateral as required pursuant to this Section 2.14(c) shall occur no later than the third Business Day following the date of receipt by Company or any of its Subsidiaries of any Non-Ordinary Course Proceeds. Each prepayment of Loans pursuant to this Section 2.14(c) shall be accompanied by accrued interest on the amount prepaid to the date of such prepayment and amounts, if any, required to be paid pursuant to Section 2.18(c) as a result of such prepayment being made on such date. Each prepayment under this Section 2.14(c) shall be applied to the Loans as provided above but otherwise as determined by the Administrative Agent and agreed to by the Requisite Revolving Lenders in their sole discretion.

 

6

 

(k) Section 2.14(d) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
(d) Mandatory Prepayment of Revolving Loans. Notwithstanding any terms to the contrary contained herein and so long as the Adjustment Period is in effect, the Company shall prepay the Revolving Loans on July 15, 2009 in an amount equal to (i) $20,000,000 less (ii) the aggregate amount of prepayments of Revolving Loans made after the Effective Date of the Fourth Amendment. Such prepayment of the Revolving Loans pursuant to this Section 2.14(d) shall be accompanied by accrued interest on the amount prepaid to the date of such prepayment and amounts, if any, required to be paid pursuant to Section 2.18(c) as a result of such prepayment being made on such date.
(l) Section 5.11(b) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
(b) No later than ninety (90) days after June 30th and December 31st of each year (other than December 31, 2008) and no later than one-hundred fifty (150) days after December 31, 2008, Company and the Guarantors shall, if required, take all such actions and execute and deliver, or cause to be executed and delivered, all such mortgages, documents, instruments, agreements, opinions and certificates similar to those described in Section 3.1(i) with respect to additional Hydrocarbon Interests which have not otherwise been made subject to the Lien of the Collateral Documents in favor of Collateral Trustee, for the benefit of Secured Parties, such that the aggregate of Hydrocarbon Interests subject to the Lien of the Collateral Documents in favor of Collateral Trustee, for the benefit of Secured Parties, shall represent no less than 80% of the Borrowing Base value of the Proven Reserves of Company and the Guarantors.
(m) Section 5.13 of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
5.13 Swap Agreements. It is contemplated by the Company that the J. Aron Swap will remain in place during the term of this Agreement on terms and conditions satisfactory to the Administrative Agent; provided, however, (a) the Company shall have the right to terminate the J. Aron Swap, but only if the Borrowing Base shall have been redetermined before giving effect to the termination and, after giving effect thereto, no Event of Default would exist and Total Utilization would not exceed the lesser of the Borrowing Base and the Revolving Commitments, and (b) the Company may effect any Hedge Restructure or otherwise amend, supplement or modify the J. Aron Swap so long as (i) no Event of Default exists or would exist as a result thereof, (ii) after giving effect thereto the Company would remain protected against a decline in commodity prices at the same levels that are in effect on the Effective Date of the Fourth Amendment, (iii) before giving effect thereto the Hedge Letter of Credit Usage shall have been reduced in an amount, and subject to terms, satisfactory to the Administrative Agent, (iv) the terms thereof does not require any additional collateral or margin requirements from the Company or any other Credit Party, and (v) the other terms thereof are not more onerous to the Company or any other Credit Party than those terms that were in existence on the Closing Date as reasonably determined by the Administrative Agent.

 

7

 

(n) Section 6.5 of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
6.5 Restricted Junior Payments. No Credit Party shall, nor shall it permit any of its Restricted Subsidiaries or Affiliates through any manner or means or through any other Person to (a) directly or indirectly, declare, order, pay, make or set apart, or agree to declare, order, pay, make or set apart, any sum for any Restricted Junior Payment, including but not limited to, principal payments on the Senior Secured Indebtedness but excluding interest payments on any Senior Secured Indebtedness or (b) otherwise make any optional or voluntary repurchase, redemption, prepayment, repayment, defeasance or any other acquisition or retirement for value (or the segregation of funds with respect to any of the foregoing in this clause (b)) of the Senior Secured Indebtedness.
(o) Section 6.8(a) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
(a) Interest Coverage Ratio. Company shall not permit the Interest Coverage Ratio as of the last day of each Fiscal Quarter, to be less than (i) 2.50 to 1.00 for each Fiscal Quarter ending on or before March 31, 2009, (ii) 2.00 to 1.00 for the Fiscal Quarters ending September 30, 2009, December 31, 2009 and March 31, 2010 , and (ii) 2.25 to 1.00 for each Fiscal Quarter ending on or after June 30, 2010; provided that the Interest Coverage Ratio test under this Section 6.8(a) shall not apply for the Fiscal Quarter ending June 30, 2009.
(p) Section 6.8(b) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
(b) Leverage Ratio. Company shall not permit, as of each day, the Leverage Ratio for the four Fiscal Quarters for which financial statements have most recently been required to be delivered under this Agreement immediately preceding such day to exceed (i) 5.375 to 1.00 from the earlier of the date that Borrower has delivered its financial statements for the Fiscal Quarter ending September 30, 2009 pursuant to Section 5.1(a) or November 16, 2009 (the “Initial Leverage Test Date”) through and including December 31, 2009, (ii) 5.25 to 1.00 from January 1, 2010 through and including March 31, 2010, and (iii) 5.00 to 1.00 thereafter; provided that, the Leverage Ratio test under this Section 6.8(b) shall not apply at any time from the Effective Date of the Fourth Amendment through the Initial Leverage Test Date.
(q) Section 6.9 of the Credit Agreement is hereby amended by deleting clauses (c), (f), (g) and (h) in their entirety and replacing them with the following:
(c) (i) during the Adjustment Period, any Asset Sale so long as the proceeds thereof are applied in accordance with Section 2.14(c); and (ii) upon expiration of the Adjustment Period, any Asset Sale, the proceeds of which (valued at the principal amount thereof in the case of non-cash proceeds consisting of notes or other debt Securities and valued at fair market value in the case of other non-cash proceeds) (A) are less than $5,000,000 with respect to any single Asset Sale or series of related Asset Sales and (B) when aggregated with the proceeds of all other Asset Sales made after the expiration of the Adjustment Period, are less than $10,000,000; provided that, with respect to any Asset Sale permitted under this clause (c), (1) the consideration received for such assets shall be in an amount at least equal to the fair market value thereof (determined in good faith by a Financial Officer of Company), and (2) no less than 75% thereof shall be paid in cash.
(f) [Reserved].

 

8

 

(g) the trade or exchange by Company or any Restricted Subsidiary of any Oil and Gas Property (or interest therein) owned or held by Company or such Restricted Subsidiary and located in an area for any other Oil and Gas Property (or interest therein) owned or held by another Person and located in the same area; provided, that, (i) the aggregate value of trades or exchanges permitted by this paragraph (g) shall not exceed $5,000,000 during any six-month period commencing January 1 and ending June 30 or commencing July 1 and ending December 31, (ii) such trade or exchange may include cash or Cash Equivalents necessary in order to achieve an exchange of equivalent value , and (iii) such trade or exchange occurs in the ordinary course of business for the purpose of developing Oil and Gas Properties that the Company or any Restricted Subsidiary owns which are not included in such trade or exchange.
(h) [Reserved].
(r) Section 6.15 of the Credit Agreement is hereby deleted in its entirety and replaced with the following:
6.15 Amendments or Waivers of Certain Related Agreements. No Credit Party shall nor shall it permit any of its Restricted Subsidiaries to, agree to any material amendment, restatement, supplement or other modification to, or waiver of, any of its material rights under any Related Agreement (other than the Senior Secured Indebtedness and future transactions otherwise permitted by the terms of this Agreement) after the Closing Date without in each case obtaining the prior written consent of Requisite Lenders to such amendment, restatement, supplement or other modification or waiver; provided that, the Company may terminate, amend, supplement or otherwise modify the J. Aron Swap in compliance with the terms of Section 5.13 of this Agreement.
Section 5. Borrowing Base. Subject to the terms of this Agreement, the parties hereto agree that, as of the Effective Date, the Borrowing Base shall be equal to $100,000,000 and such Borrowing Base shall remain in effect at such amount until the Borrowing Base is redetermined or reduced in accordance with the Credit Agreement, as amended hereby.
Section 6. Company Representations and Warranties. The Company represents and warrants that, after giving effect to this Agreement: (a) the representations and warranties contained in the Credit Agreement and the representations and warranties contained in the other Credit Documents, are true and correct in all material respects on and as of the Effective Date as if made on as and as of such date except to the extent that any such representation or warranty expressly relates solely to an earlier date, in which case such representation or warranty is true and correct in all material respects as of such earlier date; (b) no Default has occurred and is continuing; (c) the execution, delivery and performance of this Agreement are within the corporate power and authority of the Company and have been duly authorized by appropriate corporate and governing action and proceedings; (d) this Agreement constitutes the legal, valid, and binding obligation of the Company enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; (e) there are no governmental or other third party consents, licenses and approvals required in connection with the execution, delivery, performance, validity and enforceability of this Agreement; and (f) the Liens under the Security Instruments are valid and subsisting and secure Company’s obligations under the Credit Documents.

 

9

 

Section 7. Conditions to Effectiveness. This Agreement shall become effective on the Effective Date and enforceable against the Company, the Administrative Agent, and the Lenders upon the occurrence of the following conditions precedent:
(a) The Administrative Agent shall have received multiple original counterparts, as requested by the Administrative Agent, of this Agreement duly and validly executed and delivered by duly authorized officers of the Company, the Administrative Agent and the Requisite Lenders and the fee letter dated the date hereof between the Administrative Agent and the Company.
(b) The aggregate outstanding amount of the Total Utilization of Revolving Commitments shall be less than or equal to $95,000,000.
(c) The Company shall have paid to the Administrative Agent for the ratable benefit of the Lenders a waiver and amendment fee in the amount of $250,000. This fee shall be non-refundable and fully earned when paid.
(d) No Default shall have occurred and be continuing as of the Effective Date.
(e) The representations and warranties in this Agreement shall be true and correct in all material respects.
(f) The Company shall have paid all costs and expenses which have been invoiced and are payable pursuant to Section 10.2 of the Credit Agreement.
Section 8. Acknowledgments and Agreements.
(a) The Company acknowledges that on the date hereof all Obligations are payable without defense, offset, counterclaim or recoupment.
(b) The Administrative Agent and the Lenders hereby expressly reserve all of their rights, remedies, and claims under the Credit Documents. Nothing in this Agreement shall constitute a waiver or relinquishment of (i) any Default or Event of Default under any of the Credit Documents, (ii) any of the agreements, terms or conditions contained in any of the Credit Documents, (iii) any rights or remedies of the Administrative Agent or any Lender with respect to the Credit Documents, or (iv) the rights of the Administrative Agent or any Lender to collect the full amounts owing to them under the Credit Documents.
(c) Each of the Company, the Administrative Agent and the Lenders does hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby, and acknowledges and agrees that the Credit Agreement, as amended hereby, is and remains in full force and effect, and the Company acknowledges and agrees that its liabilities and obligations under the Credit Agreement, as amended hereby, are not impaired in any respect by this Agreement. From and after the Effective Date, all references to the Credit Agreement and the Credit Documents shall mean such Credit Agreement and such Credit Documents as amended by this Agreement.
(d) This Agreement is a Credit Document for the purposes of the provisions of the other Credit Documents. Without limiting the foregoing, any breach of representations, warranties, and covenants under this Agreement shall be a Default or Event of Default, as applicable, under the Credit Agreement.

 

10

 

Section 9. Counterparts. This Agreement may be signed in any number of counterparts, each of which shall be an original and all of which, taken together, constitute a single instrument. This Agreement may be executed by facsimile signature and all such signatures shall be effective as originals.
Section 10. Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement.
Section 11. Invalidity. In the event that any one or more of the provisions contained in this Agreement shall for any reason be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Agreement.
Section 12. Governing Law. This Agreement shall be deemed to be a contract made under and shall be governed by and construed in accordance with the laws of the State of New York.
Section 13. Entire Agreement. THIS AGREEMENT, THE CREDIT AGREEMENT AS AMENDED BY THIS AGREEMENT, THE NOTES, AND THE OTHER CREDIT DOCUMENTS CONSTITUTE THE ENTIRE UNDERSTANDING AMONG THE PARTIES HERETO WITH RESPECT TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ANY PRIOR AGREEMENTS, WRITTEN OR ORAL, WITH RESPECT THERETO.
THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.
[Signature pages follow.]

 

11

 

EXECUTED effective as of the date first above written.
                 
COMPANY:   BELDEN & BLAKE CORPORATION    
 
                
 
  By:   /s/ James M. Vanderhider    
             
 
      Name:   James M. Vanderhider    
 
               
 
      Title:   President and Chief Operating Officer    
 
               

 

 

 

                 
ADMINISTRATIVE AGENT/
                
LENDER:   BNP PARIBAS,    
    as Administrative Agent and as Lender    
 
                
 
  By:   /s/ Polly Schott    
             
 
      Name:   Polly Schott    
 
               
 
      Title:   Director    
 
               
 
                
 
  By:   /s/ Courtney Kubesch    
             
 
      Name:   Courtney Kubesch    
 
               
 
      Title:   Vice President    
 
               

 

 

 

                 
LENDER:   JPMORGAN CHASE BANK, N.A.    
    as Lender    
 
                
 
  By:   /s/ Michael A. Kamauf    
             
 
      Name:   Michael A. Kamauf    
 
         
 
    
 
      Title:   Vice President    
 
               

 

 

 

                 
LENDER:   AMEGY BANK NATIONAL ASSOCIATION,    
    as Lender    
 
                
 
  By:   /s/ W. Bryan Chapman    
             
 
      Name:   W. Bryan Chapman    
 
         
 
    
 
      Title:   Senior Vice President    
 
               

 

 

EX-23.1 3 c83251exv23w1.htm EXHIBIT 23.1 Exhibit 23.1
Exhibit 23.1
CONSENT OF WRIGHT & COMPANY, INC.
We hereby consent to the use of the name Wright & Company, Inc. and to the incorporation by reference of our name in the Annual Report on Form 10-K of Belden & Blake Corporation for the fiscal year ended December 31, 2008.
         
  WRIGHT & COMPANY, INC.
 		  
  By:   /s/ D. Randall Wright    
    D. Randall Wright    
    President   
 
Brentwood, Tennessee
March 25, 2009

 

EX-31.1 4 c83251exv31w1.htm EXHIBIT 31.1 Exhibit 31.1
EXHIBIT 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES -OXLEY ACT OF 2002
I, Mark A. Houser, certify that:
1. I have reviewed this annual report on Form 10-K of Belden & Blake Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
         
Date: April 9, 2009  /s/ Mark A. Houser    
  Mark A. Houser, Chief Executive Officer and   
  Chairman of the Board of Directors   

 

 

EX-31.2 5 c83251exv31w2.htm EXHIBIT 31.2 Exhibit 31.2
         
EXHIBIT 31.2
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES -OXLEY ACT OF 2002
I, James M. Vanderhider, certify that:
1. I have reviewed this annual report on Form 10-K of Belden & Blake Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
         
Date: April 9, 2009  /s/ James M. Vanderhider    
  James M. Vanderhider, President,   
  Chief Financial Officer and Director   

 

 

EX-32.1 6 c83251exv32w1.htm EXHIBIT 32.1 Exhibit 32.1
         
Exhibit 32.1
CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES -OXLEY ACT OF 2002
In connection with the Annual Report of Belden & Blake Corporation (the “Company”) on Form 10-K for the period ended December 31, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the knowledge of the undersigned:
  1.  
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
  2.  
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
         
Date: April 9, 2009  /s/ Mark A. Houser    
  Mark A. Houser, Chief Executive Officer and   
  Chairman of the Board of Directors   
This certification accompanies the Form 10-K and shall not be treated as having been filed as part of the Form 10-K.

 

 

EX-32.2 7 c83251exv32w2.htm EXHIBIT 32.2 Exhibit 32.2
Exhibit 32.2
CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES -OXLEY ACT OF 2002
In connection with the Annual Report of Belden & Blake Corporation (the “Company”) on Form 10-K for the period ended December 31, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the knowledge of the undersigned:
  1.  
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
  2.  
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
         
Date: April 9, 2009  /s/ James M. Vanderhider    
  James M. Vanderhider, President,   
  Chief Financial Officer and Director   
This certification accompanies the Form 10-K and shall not be treated as having been filed as part of the Form 10-K.

 

 

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