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

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 (State or other jurisdiction of incorporation or organization)		34-1686642 (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 with a check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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”, “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, 2010, 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.

 

 

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.

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).

Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed oil and gas reserves. Reserves of any category that can be expected to be recovered:

•

through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and

•

through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

•

gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves;

•

drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly;

•

acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

•

provide improved recovery systems.

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.

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.

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.

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.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

•

costs of labor to operate the wells and related equipment and facilities;

•

repairs and maintenance;

•

materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities;

•

property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and

•

severance taxes.

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.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

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 otherreservoirs.

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 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.

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 (the “Merger”). On August 16, 2005, Capital C was acquired (the “Transaction”) 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

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.

On September 25, 2009, Belden & Blake Corporation entered into the Fifth Amendment to Credit Agreement. The Credit Agreement was amended to (1) reduce the borrowing base to $65 million, (2) extend the termination date by one year to August 16, 2011, (3) decrease the aggregate amount of the revolving commitments to $100 million, and (4) make certain other amendments to the Credit Agreement.

At December 31, 2009, we had an Amended Credit Agreement comprised of a five-year $100 million revolving facility with a borrowing base of $65 million, of which $43.9 million was outstanding at December 31, 2009. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a five year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. 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 2.0% 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 3.50% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2011.

On March 23, 2010, we entered into the Sixth Amendment to the Credit Agreement. The Credit Agreement was amended to (1) add a maximum senior secured leverage ratio of 2.00 : 1.00, (2) eliminate the maximum leverage ratio beginning December 31, 2009, (3) amend the minimum interest coverage ratio to 1.75 : 1.0 and (4) make certain other amendments to the Credit Agreement.

At December 31, 2009, we were in compliance with such financial covenants under the Amended Credit Agreement. Our senior secured leverage ratio was 1.10 : 1.0 and the interest coverage ratio was 1.96 : 1.0.

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 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, the fourth quarter of 2008 and all of 2009 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”).

DESCRIPTION OF BUSINESS

Overview

In the fourth quarter of 2009, our average net production was approximately 34.9 MMcfe per day consisting of 29.8 MMcf of natural gas and 849 Bbls of oil per day. At December 31, 2009, we owned interests in 4,346 gross (3,396 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with estimated proved reserves totaling 190 Bcfe consisting of 163 Bcf of natural gas and 4.4 MMbbl of oil. The estimated future net cash flows from these reserves had a standardized measure of approximately $166.8 million at December 31, 2009. The 12-month weighted average prices used to estimate proved reserves at December 31, 2009 were $4.34 per Mcf for natural gas and $56.33 per Bbl for oil.

We have 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, 2009, EnerVest Operating operated approximately 3,802 wells, or 87% of our gross wells representing approximately 98% of the value of our estimated proved developed reserves based on their standardized measure. At December 31, 2009, we owned leases on 538,202 gross (464,816 net) acres, including 212,074 gross (177,493 net) undeveloped acres.

We own approximately 1,597 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 along with the favorable Btu content of our gas has generally resulted in premium wellhead gas prices compared with the NYMEX price for gas delivered at the Henry Hub in Louisiana. During 2009, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.44 and $0.11, respectively, higher than the average NYMEX monthly settle price for 2009.

Oil and Gas Reserves

In December 2008, the SEC announced that it had approved revisions designed to modernize the reserves reporting requirement of oil and natural gas companies. The most significant amendments to the requirements included the following:

•

economic producibility of reserves and discounted cash flows are now based on a 12 month average commodity price unless contractual arrangements designate the price to be used;

•

probable and possible reserves may be disclosed separately on a voluntary basis;

•

reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time;

•

reserves may be estimated through the use of reliable technology in addition to flow test and production history;

•

we are now required to provide disclosures about the qualifications of the chief technical person who oversees the reserves estimation process and a general discussion of our internal controls used to assure the objectivity of the reserves estimate; and

•

the definition of oil and natural gas producing activities has expanded and now focuses on the marketable product rather than the method of extraction.

We adopted the new requirements effective December 31, 2009. These new requirements did not have an effect on what was classified as a reserve at December 31, 2009.

The following table presents our estimated net proved oil and natural gas reserves at December 31, 2009. These estimates were prepared by Wright & Company, Inc. independent petroleum consultants. Since January 1, 2009, no crude oil or natural gas reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC. All of our oil and gas reserves are located on-shore in the United States.

		Oil and Gas Reserves
		Oil (MMbbl)				Gas (Bcf)				Bcfe
Proved
Developed			3.4				152.0				172.6
Undeveloped			1.0				11.0				17.0
Total			4.4				163.0				189.6

The table above represents estimates only. 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. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Additionally, the SEC amended the definition of proved reserves applicable to our 2009 reserves. As a result, our December 31, 2009 reserves may not be comparable to those of prior periods. See “Glossary of Oil and Natural Gas Terms.”

The following table sets forth the average prices during the 12-month period before the ending date covered by this report as determined by an arithmatic unweighted average of the first day of the month price for each month within such period, 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,
		2009
Gas (per Mcf)		$	4.34
Oil (per Bbl)			56.33

The prices for oil and natural gas used in this calculation were regional cash price quotes on the first day of each month 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.

We annually review all proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, our PUDs are converted to proved developed reserves within five years of the date they are first booked as PUDs. We had 17.0 Bcfe of PUDs at December 31, 2009, compared with 25.1 Bcfe of PUDs at December 31, 2008. In 2009, we converted no PUDs to proved developed reserves (PDP).

See Note 17 to the Consolidated Financial Statements for more detailed information regarding our oil and gas reserves.

The standardized measure of our estimated proved reserves as of December 31, 2009 was $166.8 million. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, 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%. Standardized measure does not give effect to derivative transactions. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Controls Over Reserve Estimates

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. Compliance in reserves bookings is the responsibility of our Manager of Reservoir Engineering, who is also our principal engineer. Our principal engineer has over 5 years of experience in the oil and gas industry, including over 4 years as either a reserve evaluator, trainer or manager and is a qualified reserves estimator (QRE), as defined by the Society of Petroleum Engineers’ standards. Further professional qualifications include a degree in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserve seminars, professional industry groups and has been a member of the Society of Petroleum Engineers for over 6 years. Our principal engineer is an employee of EnerVest who provides all of our operating, administrative and technical services.

Our controls over reserve estimates included retaining Wright & Company, Inc. as our independent petroleum and geological firm. We provided information about our oil and gas properties, including production profiles, prices and costs, to Wright & Company and they prepare their own estimates of the reserves attributable to our properties. All of the information regarding reserves in this annual report is derived from the report of Wright & Company. The report of Wright & Company is included as an Exhibit to this annual report. The principal engineer at Wright & Company responsible for preparing our reserve estimates is D. Randall Wright, President of Wright & Company. Mr. Wright is a licensed professional engineer with over 32 years of experience in petroleum engineering.

The Audit Committee of our Board of Directors meets annually with management, including the Manager of Resevoir Engineering to discuss matters and policies related to reserves.

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 3,130 gross (2,804 net) wells in the Appalachian Basin which currently produce approximately 20.1 MMcfe net per day. Most of our production in the Appalachian Basin is derived from the shallow (1,000 to 6,500 feet) Medina, Clinton and Clarendon Formations, predominately in Pennsylvania and Ohio.

During 2009, we drilled 4 gross (2.0 net) exploratory wells in 2009. Due to a change in market conditions, the anticipated 2010 focus will be primarily in the following three areas: Knox exploration in Ohio and operational reworks and enhancement projects throughout our operating area. 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 1,216 gross (592 net) wells in the Michigan Basin which currently produce approximately 14.8 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 2009, we drilled no wells to the Antrim Shale Formation. We do not plan to drill any wells in the Antrim Shale Formation in 2010.

Oil and Gas Operations and Production

Operations. EnerVest Operating operates 87% of our gross 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 1,597 miles of natural gas gathering lines in Ohio, Pennsylvania, New York and Michigan, which are connected directly to various intrastate and interstate natural gas transmission systems. The interconnections with these pipelines afford us marketing access to numerous gas markets.

Production, Sales Prices and Costs. The following table sets forth certain information regarding our net oil and natural gas production, revenues and unit expenses for the years indicated. 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,
		2009				2008				2007
Production
Gas (MMcf)			12,034				13,217				13,357
Oil (Mbbl)			324				334				348
Total production (MMcfe)			13,977				15,221				15,446
Average sales price (1)
Gas (per Mcf)		$	3.61			$	8.62			$	6.81
Oil (per Bbl)			56.49				94.40				67.42
Per Mcfe			4.42				9.55				7.41
Average costs (per Mcfe)
Production expense		$	1.50			$	1.73			$	1.59
Production taxes			0.08				0.20				0.15
Depletion			2.62				2.31				2.31

		Year Ended December 31,
		2009				2008				2007
Gas (per Mcf)		$	4.27			$	9.31			$	7.34
Oil (per Bbl)			56.49				94.40				67.42
Per Mcfe			4.98				10.15				7.87

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 2009, we spent approximately $11.6 million on development and exploratory drilling and other capital expenditures including exploratory dry hole costs. We drilled 4 gross and (2.0 net) exploratory wells in 2009.

In 2010, we expect to spend approximately $12.5 million on development and exploratory drilling and other capital expenditures. Due to a change in market conditions for oil and natural gas, the anticipated 2010 focus primarily will be in the following areas: Knox exploration in Ohio and operational reworks and enhancement projects throughout our operating area. 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.

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:
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
		2007				2008				2009				2007				2008				2009
Productive:
Gross			96				98				—				—				—				4
Net			92.0				83.5				—				—				—				2.0
Dry:
Gross			—				—				—				—				5				—
Net			—				—				—				—				4.9				—
Wells in progress:
Gross			—				—				—				—				—				—
Net			—				—				—				—				—				—

Producing Well Data

As of December 31, 2009, we owned interests in 4,346 gross (3,396 net) producing oil and gas wells of which approximately 3,802 wells were operated by EnerVest Operating. In the fourth quarter of 2009, our net production was approximately 34.9 MMcfe per day consisting of 29.8 MMcf of natural gas and 849 Bbls of oil per day.

The following table summarizes by state our productive wells at December 31, 2009:

		December 31, 2009
		Gas Wells								Oil Wells								Total
State		Gross				Net				Gross				Net				Gross				Net
Ohio			1,048				893				678				609				1,726				1,502
Pennsylvania			1,282				1,191				104				104				1,386				1,295
New York			18				7				—				—				18				7
Michigan			1,199				590				17				2				1,216				592
			3,547				2,681				799				715				4,346				3,396

Acreage Data

The following table summarizes by state our gross and net developed and undeveloped acreage at December 31, 2009:

		December 31, 2009
		Developed Acreage								Undeveloped Acreage								Total Acreage
State		Gross				Net				Gross				Net				Gross				Net
Ohio			98,748				82,213				118,252				111,915				217,000				194,128
Pennsylvania			40,203				29,895				174,982				147,438				215,185				177,333
New York			2,845				591				16,958				14,248				19,803				14,839
Michigan			70,278				64,794				15,900				13,686				86,178				78,480
Indiana			—				—				36				36				36				36
			212,074				177,493				326,128				287,323				538,202				464,816

The following table summarizes by state our undeveloped acreage as of December 31, 2009 that is subject to expiration absent drilling activity during the three years ended December 31, 2012 and thereafter.

		Undeveloped Acreage Subject to Expiration in the Year Ended December 31,
		2010								2011								2012								Thereafter
State		Gross				Net				Gross				Net				Gross				Net				Gross				Net
Ohio			3,765				3,765				12,485				12,485				686				598				4,448				1,997
Pennsylvania			1,854				1,548				3,492				2,312				2,255				2,211				376				376
New York			455				269				—				—				—				—				—				—
Michigan			5,893				3,339				4,233				2,553				1,357				657				1,455				723
Indiana			36				36				—				—				—				—				—				—
			12,003				8,957				20,210				17,350				4,298				3,466				6,279				3,096

Disposition of Assets

In November 2009, we sold undeveloped acreage in Bradford County, Pennsylvania for $35.8 million.

In July 2009, we sold our coalbed methane properties in Pennsylvania for $16.7 million.

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, 2010, 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.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

Principal Customers

The market for our oil, natural gas and natural gas liquids production depends on factors beyond our control, including the extent of domestic production and imports of oil, natural gas and natural gas liquids, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil, natural gas and natural gas liquids, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil, natural gas and natural gas liquids production is sold to a variety of purchasers. The terms of sale under the majority of existing contracts are short-term, usually one year or less in duration. The prices received for oil, natural gas and natural gas liquids sales are generally tied to monthly or daily indices as quoted in industry publications.

Each of the following customers accounted for 10% or more of our consolidated revenues during 2009: Integrys Energy, National Fuel Resources, Inc. and American Refining Group, Inc. We believe that the loss of a major customer would have a temporary effect on our revenues but that over time, we would be able to replace our major customers. We do not believe that 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.

Regulation

Regulation of Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

•

the location of wells;

•

the method of drilling and casing wells;

•

the surface use and restoration of properties upon which wells are drilled; and

•

the plugging and abandoning of wells.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

In addition, 11 states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and specific expenses for exploration and activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, or Minerals Management Service or other appropriate federal or state agencies.

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, restrict materials used in our operations, 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.

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. On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009” which among other things, would enact a “cap and trade” system to control GHGs. Under this cap and trade system, a cap on the amount of GHGs would be established annually, which would be reduced annually. Each covered emission source would be required to obtain GHG emission allowances corresponding to its annual emissions of GHGs. The Senate has passed from committee its legislation proposing a similar cap and trade system to regulate GHG emissions, but the Senate legislation has not been voted upon by the full Senate. In the absence of a comprehensive federal legislation on GHG emission control, the Environmental Protection Agency (“EPA”) has been moving forward with rulemaking under the Clean Air Act (“CAA”) to regulate GHGs as pollutants under the CAA. Should EPA regulate GHGs under the CAA, we could incur significant costs to control our emissions and comply with regulatory requirements. In addition, EPA has adopted a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries. We do not believe our operations to be subject to this program as currently proposed, but there is no guarantee that EPA will not expand the program to additional industries. Should we be required to report GHG emissions, it could require us to incur costs to monitor, keep records of, and report emissions of GHGs.

Because of the lack of any comprehensive legislative program addressing GHGs, 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 regional 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. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

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. 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 Safe Drinking Water Act (the “SWDA”) regulates, among other things, underground injection operations. Recent legislative activity has occurred which, if successful, would impose additional regulation under the SDWA upon the use of hydraulic fracturing fluids. Congress is considering two companion bills entitled the Fracturing Responsibility and Chemical Awareness Act of 2009 (the “FRAC Act”). If enacted, the legislation would impose on our hydraulic fracturing operations permit and financial assurance requirements, requirements that we adhere to construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, the proposed legislation would require the disclosure of the chemicals within the hydraulic fluids, which could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water. Neither piece of legislation has been passed. If this or similar legislation is enacted, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

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.

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 73% of the expected 2010 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, 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.

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.

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 $11.7 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $3.2 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 $3.5 million after considering the effects of the derivative contracts in place as of December 31, 2009. This sensitivity analysis is based on our 2009 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 86% 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, 2009, a 10% reduction in the price of oil and natural gas would have reduced our future net cash flow from proved reserves by $37 million. Various factors beyond our control can affect prices of oil and 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, including recovery from the recent recession; 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.

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 2009 and 2008, we recorded an impairments to our oil and natural gas properties of $30.4 million and $3.9 million, respectively.

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, 2009, approximately 9% 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.

The SEC amended the definition of proved reserves for all reserves estimated included in filings after January 1, 2010. As a result, our estimates of proved reserves filed in reports prior to January 1, 2010 may not be comparable to reports filed after that date, including those in this annual report.

Analysts and investors should not construe the present value of future net reserves, or PV-10 or the standardized measure, 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 Standardized Measure 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.

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.”

Climate Change Legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and gas we produce.

On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support for legislation to reduce greenhouse emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The U.S. Senate and House of Representatives are currently considering bills entitled, the “Fracturing Responsibility and Awareness of Chemicals Act,” or the “FRAC Act,” that would amend the federal Safe Drinking Water Act, or the “SDWA,” to repeal an exemption from regulation for hydraulic fracturing. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells and increase our costs of compliance and doing business.

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.”

The adoption of derivatives legislation or regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

Legislation has been proposed in Congress and by the Treasury Department to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. Under proposed legislation, OTC derivative dealers and other major OTC derivative market participants could be subjected to substantial supervision and regulation. The legislation generally would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, to mandate clearance of derivative contracts through registered derivative clearing organizations, and to impose conservative capital and margin requirements and strong business conduct standards on OTC derivative transactions. The CFTC has proposed regulations that would implement speculative limits on trading and positions in certain commodities. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or the CFTC may issue new regulations, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

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.”

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.

On September 25, 2009, Belden & Blake Corporation entered into the Fifth Amendment to Credit Agreement. The Credit Agreement was amended to (1) reduce the borrowing base to $65 million, (2) extend the termination date by one year to August 16, 2011, (3) decrease the aggregate amount of the revolving commitments to $100 million, and (4) make certain other amendments to the Credit Agreement.

At December 31, 2009, we had an Amended Credit Agreement comprised of a five-year $100 million revolving facility with a borrowing base of $65 million, of which $43.9 million was outstanding at December 31, 2009. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a five year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. 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 2.0% 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 3.50% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2011.

On March 23, 2010, we entered into the Sixth Amendment to the Credit Agreement. The Credit Agreement was amended to (1) add a maximum senior secured leverage ratio of 2.00 : 1.00, (2) eliminate the maximum leverage ratio beginning December 31, 2009, (3) amend the minimum interest coverage ratio to 1.75 : 1.0 and (4) make certain other amendments to the Credit Agreement.

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 or prohibit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase 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 senior secured leverage ratio and a minimum current ratio. At December 31, 2009, we were in compliance with our covenants under the Amended Credit Agreement. Our senior secured leverage ratio was 1.10 : 1.0 and the interest coverage ratio was 1.96 : 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.

Our Amended Credit Agreement also includes financial covenants, including requirements that we maintain:

•

a minimum interest coverage ratio;

•

a maximum senior secured 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.	(Removed and Reserved)

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, 2010, were held by Capital C.

Dividends

We paid no cash dividends in 2009 and paid cash dividends of $2.5 million in 2008 and $9.8 million in 2007.

Item 6.	SELECTED FINANCIAL DATA

The Selected Financial Data should be read in conjunction with the Consolidated Financial Statements at Item 15(a).

																						Predecessor
		Successor Company																				Company
																		For the 138 Day				For the 227 Day
																		Period from				Period From
																		August 16, 2005				January 1, 2005
		As of or for the year ended December 31,																to December 31,				to August 15,
(in thousands)		2009				2008				2007				2006				2005				2005
Continuing Operations:
Revenues		$	68,624			$	158,426			$	125,140			$	158,774			$	76,642			$	77,960
Depreciation, depletion and amortization			37,046				35,560				36,087				38,074				14,341				21,265
Impairment of oil and gas properties			30,445				3,924				31				546				—				—
Impairment of goodwill			—				90,076				—				—				—				—
Net income (loss)			2,776				(28,944	)			(35,322	)			52,199				17,563				(320	)
Balance sheet data:																		As of 12/31/2005
Working capital (deficit) from continuing operations			28,179				(16,806	)			(14,224	)			(11,635	)			(38,999	)
Oil and gas properties and gathering systems, net			536,237				613,834				627,556				641,879				648,417
Total assets			608,078				669,464				774,225				777,023				810,118
Long-term debt, less current portion			236,707				265,863				291,118				285,560				277,648
Total shareholders’ equity			104,141				76,551				102,223				143,703				89,399

The Transaction and Merger was accounted for as a purchase effective August 16, 2005. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at August 16, 2005. 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 predecessor company. Vertical black lines are presented to separate the financial data of the predecessor company and the successor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor Company” refers to the period prior to August 15, 2005.

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, 2009, our total estimated proved reserves were 190 Bcfe. Natural gas comprised approximately 86% of our estimated proved reserves, and 91% 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, 2009, our Appalachian properties accounted for 55% of our estimated proved reserves, while the Michigan properties accounted for 45% of proved reserves.

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. While oil and natural gas prices have strengthened in recent months, they remain unstable and are expected to be, volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include the effects of the recession in the United States, the discovery of substantial accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves, North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America. As discussed above, 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 73% of the expected 2010 through 2013 production from our current estimated proved reserves and will range from 67% to 82% of such expected production in any year.

The U.S. and other world economies were in a recession which lasted well into 2009 and current economic conditions remain uncertain. The primary effect of the economic uncertainty on our business has been decreased demand for oil and natural gas and a corresponding decrease in the price we received in 2009 compared to 2008.

The average price realized for our natural gas, inclusive of qualified effective hedges, increased from $6.81 per Mcf in 2007 to $8.62 per Mcf in 2008 and then decreased to $3.61 per Mcf in 2009. The monthly average settle for natural gas trading on the NYMEX increased from $6.86 per MMbtu in 2007 to $9.04 per MMbtu in 2008 and then decreased to $3.99 per MMbtu in 2009. 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 2009, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.44 and $0.11, respectively, higher than the average NYMEX monthly settle price for 2009. The remainder of the difference is primarily due to our qualified hedging activities during these periods. Our average realized price for oil increased from $67.42 per Bbl in 2007 to $94.40 per Bbl in 2008 and decreased to $56.49 per Bbl in 2009. If the global economic instability continues, commodity prices may be depressed for an extended period of time, which could alter our acquisition, drilling and development plans.

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. There was no goodwill as of December 31, 2009, or 2008.

Current market conditions also elevate concerns about cash and cash equivalent investments, which at December 31, 2009 totaled $46.7 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.

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

We account for our oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are 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.

No gains or losses are recognized upon the disposition of oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit-of-production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development 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 and actually deliver oil and natural 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. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

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

On December 31, 2009, we adopted Accounting Standards Update (“ASU”) No. 2010—03, Extractive Activities — Oil and Gas (Topic 932), which conforms the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC in December 2008. ASU No. 2010—03 requires that we use the average of the first day of the month price during the 12 month period preceding the end of the year, rather than the year end price, when estimating reserve quantities and standardized measure. The new rules permit the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Prior year data are presented in accordance with the Financial Accounting Standards Board (“FASB”) oil and natural gas disclosure requirements effective during those periods.

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.

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 natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit-of-production amortization rate. 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.

FASB accounting guidance 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. No goodwill was recorded at December 31, 2009.

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 FASB accounting guidance, 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.

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, 2009, 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, 2009 or 2008. Oil and gas marketing revenues are recognized when title passes.

Asset Retirement Obligations

We follow FASB accounting guidance which requires us to recognize a liability for the fair value of our asset retirement obligations associated with its tangible, long-lived assets. The majority of our asset retirement obligations recorded relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties.

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, 2009, there were no assets legally restricted for purposes of settling asset retirement obligations.

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,
		2009								2008								2007
Revenues
Oil and gas sales		$	61,761				90.0	%		$	145,398				91.8	%		$	114,427				91.4	%
Gas gathering and marketing			5,894				8.6				12,254				7.7				10,275				8.2
Other			969				1.4				774				0.5				438				0.4
			68,624				100.0				158,426				100.0				125,140				100.0
Expenses
Production expense			20,955				30.6				26,342				16.6				24,585				19.7
Production taxes			1,098				1.6				3,054				1.9				2,265				1.8
Gas gathering and marketing			5,492				8.0				10,252				6.5				8,640				6.9
Exploration expense			3,925				5.7				2,543				1.6				1,935				1.5
General and administrative expense			7,785				11.3				8,188				5.2				8,236				6.6
Depreciation, depletion and amortization			37,046				54.0				35,560				22.4				36,087				28.8
Impairment of goodwill			—				—				90,076				56.9
Inpairment of oil and gas properties			30,445				44.4				3,924				2.5				31				—
Accretion expense			1,304				1.9				1,412				0.9				1,290				1.0
(Gain) on asset sales			(34,929	)			(50.9	)			—				—				—				—
Derivative fair value (gain) loss			(29,631	)			(43.2	)			(55,940	)			(35.3	)			78,120				62.5
			43,490				63.4				125,411				79.2				161,189				128.8
Operating income (loss)			25,134				36.6				33,015				20.8				(36,049	)			(28.8	)
Other (income) expense
Interest expense			20,612				30.0				22,818				14.4				23,712				18.9
Other income, net			(131	)			(0.2	)			(495	)			(0.3	)			(516	)			(0.4	)
Income (loss) before income taxes			4,653				6.8				10,692				6.7				(59,245	)			(47.3	)
Provision (benefit) for income taxes			1,877				2.7				39,636				25.0				(23,923	)			(19.1	)
Net income (loss)			2,776				4.1				(28,944	)			(18.3	)			(35,322	)			(28.2	)

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,
		2009				2008				2007
Production
Gas (MMcf)			12,034				13,217				13,357
Oil (Mbbl)			324				334				348
Total production (MMcfe)			13,977				15,221				15,446
Average sales price (1)
Gas (per Mcf)		$	3.61			$	8.62			$	6.81
Oil (per Bbl)			56.49				94.40				67.42
Per Mcfe			4.42				9.55				7.41
Average costs (per Mcfe)
Production expense		$	1.50			$	1.73			$	1.59
Production taxes			0.08				0.20				0.15
Depletion			2.62				2.31				2.31

		Year Ended December 31,
		2009				2008				2007
Gas (per Mcf)		$	4.27			$	9.31			$	7.34
Oil (per Bbl)			56.49				94.40				67.42
Per Mcfe			4.98				10.15				7.87

2009 Compared to 2008

Revenues

Net operating revenues decreased $89.8 million from $158.4 million in 2008 to $68.6 million in 2009. The decrease was primarily due to lower gas sales revenues of $70.4 million, lower oil sales revenue of $13.2 million and lower gas gathering and marketing revenues of $6.4 million.

Gas volumes sold decreased 1,183 MMcf (9%) from 13.2 Bcf in 2008 to 12.0 Bcf in 2009 resulting in a decrease in gas sales revenues of approximately $10.2 million. Oil volumes sold decreased approximately 10,000 Bbls (3%) from 334,000 Bbls in 2008 to 324,000 Bbls in 2009 resulting in a decrease in oil sales revenues of approximately $950,000. The lower oil and gas sales volumes are due to normal production declines and the sale of our coalbed methane properties in July 2009, which were partially offset by production from new wells drilled in 2009 and operational projects, which increased production for some existing wells.

The average price realized for our natural gas decreased $5.01 per Mcf to $3.61 per Mcf in 2009 compared to 2008, which decreased gas sales revenues by approximately $60.2 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $7.9 million ($0.66 per Mcf) in 2009 and lower by $9.2 million ($0.69 per Mcf) in 2008 than if our gas was not hedged. The average price realized for our oil decreased from $94.40 per Bbl in 2008 to $56.49 per Bbl in 2009, which decreased oil sales revenues by approximately $12.3 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 $5.0 million decrease in gas marketing revenues and a $1.4 million 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 an decrease in third party gathering volumes on gathering systems in Pennsylvania and lower gas prices.

Costs and Expenses

Production expense decreased $5.3 million from $26.3 million in 2008 to $21.0 million in 2009. The decrease was primarily due to decreases in labor costs, decreases in gas processing fees and decreased workover expense, the sale of the coalbed methane assets in Pennsylvania and general decreases in third party costs. The average production cost decreased from $1.73 per Mcfe in 2008 to $1.50 per Mcfe in 2009 due to these cost decreases.

Production taxes decreased $2.0 million from $3.1 million in 2008 to $1.1 million in 2009, primarily due to lower gas prices in Michigan in 2009, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes decreased from $0.20 per Mcfe in 2008 to $0.08 per Mcfe in 2009.

Gathering and marketing expense decreased $4.8 million from $10.3 million in 2008 to $5.5 million in 2009 primarily due to lower gas prices in 2009.

Exploration expense increased $1.4 million from $2.5 million in 2008 to $3.9 million in 2009. The increase was primarily due to an increase in expired lease expense in 2009.

General and administrative expense decreased $403,000 from $8.2 million in 2008 to $7.8 million in 2009. The decrease was primarily due to a decrease in overhead fees paid to EverVest.

Depreciation, depletion and amortization increased by $1.4 million from $35.6 million in 2008 to $37.0 million in 2009. Depletion expense increased due to lower proved reserves as a result of lower oil and gas prices in 2009. Depletion per Mcfe was $2.31 in 2008 and $2.62 in 2009.

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. We did not have an impairment of goodwill in 2009.

Impairment of oil and gas properties increased $26.5 million from $3.9 million in 2008 to $30.4 million in 2009 due to the write-downs of our investment in properties in the coalbed methane and Marcellus formation in Pennsylvania as a result of lower oil and gas prices and unfavorable development results in the Marcellus formation.

Derivative fair value gain/loss was a gain of $29.6 million in 2009 and $55.9 million in 2008. 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. 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. 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.

Gain on sale of assets was $34.9 million in 2009 due to the sale of undeveloped Marcellus acreage in Pennsylvania. There was no gain on the sale of assets in 2008.

Interest expense decreased $2.2 million from $22.8 million in 2008 to $20.6 million in 2009. This decrease was primarily due to lower outstanding debt in 2009.

Income tax expense decreased from $39.6 million in 2008 to $2.7 million in 2009. The decrease in income tax expense was primarily due to a decrease in the net income before income taxes in 2009 and a decrease in the effective tax rate due to the impairment of goodwill in 2008 which is not an allowable expense in the calculation of taxable income.

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.

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 in 2008, 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 in 2008.

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. We had no impairment of goodwill in 2007.

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. We had no impairment of oil and gas properties in 2007.

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.

Liquidity and Capital Resources

Cash Flows

We expect that our primary sources of cash in 2010 will be from funds generated from operations 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, 2009 were funds generated from operations, from additional equity contributions from Capital C and the sale of non-strategic assets. Funds used during this period were primarily used for operations, exploration and development expenditures, the repayment of debt, 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,
		2009				2008				Change
		(in millions)
Cash flows provided by operating activities		$	23.9			$	96.7			$	(72.8	)
Cash flows provided by (used in) investing activities			38.9				(27.5	)			66.4
Cash flows (used in) financing activities			(38.9	)			(62.4	)			23.5
Net increase (decrease) in cash and cash equivalents		$	23.9			$	6.8			$	17.1

Our operating activities provided cash flows of $23.9 million during 2009 compared to $96.7 million in 2008. The decrease was primarily due to an $84.9 million decrease in oil and gas sales, excluding the effects of hedging which was partially offset by a $5.3 million decrease in production expense and a $6.7 million increase in the change in operating assets.

Cash flows provided by investing activities were $38.9 million in 2009 compared to cash flows used in investing activities of $27.5 million in 2008. This increase was due to an increase of $50.1 million in proceeds from property and equipment sales and a decrease of $17.1 million in property and equipment additions.

Cash flows used in financing activities in 2009 were $38.9 million compared to $62.4 million in 2008. This decrease was primarily due to the $58.5 million decrease in the settlement of derivative liabilities and a $20.0 million increase in capital contributions, which were partially offset by an increase in debt repayments of $56.0 million.

During 2009, our working capital increased $45.0 million from a deficit of $16.8 million at December 31, 2008 to a surplus of $28.2 million at December 31, 2009. The increase was primarily due to an increase in cash of 23.9 million, a decrease in the current portion of long term liabilities of $25.0 million and a $4.1 million decrease in accounts payable and accrued expenses, which was partially offset by a decrease in accounts receivable of $7.4 million.

Capital Expenditures

The table below sets forth our total capital expenditures for each of the years ending December 31, 2009, 2008 and 2007.

		Year Ended December 31,
		2009				2008				2007
		(in millions)
Total capital expenditures
Drilling including exploratory dry hole expense		$	4			$	25			$	21
Field improvements			6				2				1
Leasehold acreage			2				1				1
Total		$	12			$	28			$	23

During 2009, we spent approximately $11.6 million, including exploratory dry hole expense, on our drilling and other capital expenditures. In 2009, we drilled 4 gross (2.0 net) exploratory wells in 2009.

We plan to spend approximately $12.5 million during 2010 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, worldwide economic conditions, including the effects of the recovery from the recent recession, 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, 2009. 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, 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 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.

On September 25, 2009, Belden & Blake Corporation entered into the Fifth Amendment to Credit Agreement. The Credit Agreement was amended to (1) reduce the borrowing base to $65 million, (2) extend the termination date by one year to August 16, 2011, (3) decrease the aggregate amount of the revolving commitments to $100 million, and (4) make certain other amendments to the Credit Agreement.

At December 31, 2009, we had an Amended Credit Agreement comprised of a five-year $100 million revolving facility with a borrowing base of $65 million, of which $43.9 million was outstanding at December 31, 2009. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a five year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. 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 2.0% 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 3.50% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2011.

On March 23, 2010, we entered into the Sixth Amendment to the Credit Agreement. The Credit Agreement was amended to (1) add a maximum senior secured leverage ratio of 2.00 : 1.00, (2) eliminate the maximum leverage ratio beginning December 31, 2009, (3) amend the minimum interest coverage ratio to 1.75 : 1.0 and (4) make certain other amendments to the Credit Agreement.

At December 31, 2009, we were in compliance with such financial covenants under the Amended Credit Agreement. Our senior secured leverage ratio was 1.10 : 1.0 and the interest coverage ratio was 1.96 : 1.0.

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 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 and all of 2009 were made by additional borrowings against the Subordinated Note. As of December 31, 2009 $30.5 million was outstanding 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, 2009, we had interest rate swaps in place covering $43.5 million of our outstanding debt under the revolving credit facility that mature on September 30, 2013.

At December 31, 2009, the aggregate long-term debt maturing in the next five years is as follows: $9,000 (2010); $43.9 million (2011); $190.0 million (2012); $12,000 (2013) and $20,000 (2014 and thereafter).

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 73% of the expected 2010 through 2013 production from our current estimated proved reserves and will range from 67% to 82% 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, 2010, which have not changed since December 31, 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, 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, 2009, the fair value of futures contracts covering 2010 through 2013 oil and gas production represented an unrealized loss of $84.7 million.

At December 31, 2009, we had interest rate swaps in place covering $43.5 million of our outstanding debt under the revolving credit facility that mature on September 30, 2013. The swaps provide 1-month LIBOR fixed rates of 4.10%, plus the applicable margin. The fair value of these interest rate swaps was an unrealized loss of $2.4 million at December 31, 2009.

Inflation and Changes in Prices

The average price realized for our natural gas increased from $6.81 per Mcf in 2007 to $8.62 per Mcf in 2008, and decreased to $3.61 in 2009. The average price realized for our oil increased from $67.42 per Bbl in 2007 to $94.40 per Bbl in 2008 and decreased to $56.49 per Bbl in 2009. These prices include the effect of certain derivatives which were previously qualified effective oil and gas hedges.

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, 2009.

		Payments Due by Period
Contractual Obligations at						Less than 1												After 5
December 31, 2009		Total				Year				1 - 3 Years				4 - 5 Years				Years
		(in thousands)
Long-term debt		$	233,904			$	9			$	233,863			$	26			$	6
Asset retirement obligations			23,083				229				3,545				456				18,853
Derivative liabilities			87,056				21,384				45,438				20,234				—
Interest on debt			48,417				20,047				28,370				—				—
Operating leases			7,300				4,482				2,818				—				—
Total contractual cash obligations		$	399,760			$	46,151			$	314,034			$	20,716			$	18,859

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, 2009.

		Total				Amount of Commitment Expiration Per Period
Commercial Commitments at		Amounts				Less than 1												Over 5
December 31, 2009		Committed				Year				1 - 3 Years				4 - 5 Years				years
		(in thousands)
Standby Letters of Credit		$	40,250			$	40,250			$	—			$	—			$	—
Total Commercial Commitments		$	40,250			$	40,250			$	—			$	—			$	—

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.

Off-Balance Sheet Arrangements

We have $40.3 million in letters of credit as described above.

NEW ACCOUNTING STANDARDS

In December 2007, the FASB issued new accounting guidance regarding the accounting for business combinations. This new guidance retains the acquisition method of accounting used in business combinations and establishes principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction and restructuring costs related to the acquisition be expensed. In addition, this guidance requires disclosures to enable users to evaluate the nature and financial effects of the business combination. We adopted this new guidance on January 1, 2009.

In March 2008, the FASB issued new accounting guidance requiring enhanced disclosures about an entity’s derivative and hedging activities and their effect on an entity’s financial position, financial performance and cash flows. This new guidance is effective for fiscal years and interim periods beginning after November 15, 2008. We adopted the new accounting guidance on January 1, 2009.

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 adopted the new disclosure requirements in this Form 10-K.

In June 2009, the FASB issued The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (the “Codification”). On September 15, 2009, the Codification became the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification has superseded all then existing non–SEC accounting and reporting standards. All other non grandfathered non–SEC accounting literature not included in the Codification has become non authoritative.

In January 2010, the FASB issued ASU No. 2010–03, Extractive Activities – Oil and Gas (Topic 932), to align the oil and natural gas reserve estimation and disclosure requirements of Topic 932 with the SEC’s final rule, Modernization of Oil and Gas Reporting. ASU No. 2010–03 is effective for annual reporting periods ending on or after December 31, 2009. We adopted the provisions of ASU 2010–03 in our consolidated financial statements for the year ended December 31, 2009.

In January 2010, the FASB issued ASU No. 2010–06, Fair Value Measurements and Disclosures (Topic 820), which provides amendments to Topic 820 that will provide more robust disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii) the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements and (iv) the transfers between Levels 1, 2 and 3. ASU 2010–06 is effective for interim and annual reporting periods beginning after December 31, 2009. We will adopt ASU 2010–06 for the quarter ending March 31, 2010, and we have not yet determined the impact, if any, on our consolidated financial statements.

In February 2010, the FASB issued ASU No. 2010–09, Subsequent Events (Topic 855), to amend the disclosure requirements of events that occur after the balance sheet date but before financial statements are issued or are available to be issued that was issued by the FASB in May 2009. Entities that are SEC filers (as defined in ASU No. 2010–09) are required to evaluate subsequent events through the date that the financial statements are issued, while non–SEC filers are required to evaluate subsequent events through the date that the financial statements are available to be issued. In addition, an entity that is an SEC filer is not required to disclose the date through which subsequent events have been evaluated. ASU 2010–09 is effective upon issuance. We adopted the provisions of ASU 2010–09 in our consolidated financial statements for the year ended December 31, 2009.

No other new accounting pronouncements issued or effective during the year ended December 31, 2009 have had or are expected to have a material impact on our consolidated financial statements.

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, 2009, we had an interest rate swap in place on $43.5 million of our outstanding debt under the revolving credit facility through September 30, 2013. The swap provides a 1-month LIBOR fixed rates at 4.10%, plus the applicable margin, on $43.5 million through September 2013. 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 $713,000. 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 $95,000. This sensitivity analysis is based on our financial structure at December 31, 2009.

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, 2009, we had derivatives covering a portion of our oil and gas production from 2010 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $9.2 million in 2008 and a net pre-tax loss of $7.9 million in 2009 on certain derivatives which were previously qualified as effective oil and gas hedges.

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 $11.7 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $3.2 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 $3.5 million after considering the effects of the derivative contracts in place as of December 31, 2009. This sensitivity analysis is based on our 2009 oil and gas sales volumes.

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, 2009 or 2008.

Item 9A.		CONTROLS AND PROCEDURES

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, 2009 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

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, 2009.

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
March 26, 2010

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, 2009 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 us to provide only management’s report in this annual report.

Item 9B.		OTHER INFORMATION

Not applicable.

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, 2010 were as follows:

Name		Age				Position
Mark A. Houser			48			Chief Executive Officer and Chairman of the Board of Directors
James M. Vanderhider			51			President, Chief Financial Officer and Director
Kenneth Mariani			48			Senior Vice President, Chief Operating Officer and Director
Frederick J. Stair			50			Vice President of Accounting
Barry K. Lay			53			Vice President of Operations
Charles Goodin			59			Vice President of Land and Legal and Secretary
Mark L. Barnhill			54			Vice President of Exploration
Matthew Coeny			39			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, each of whom are chosen by our Parent. 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.

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 28 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 and the Independent Oil and Gas Association of West Virginia.

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.

Charles Goodin. Mr. Goodin joined EnerVest in October of 2009 as Vice President of Land/Legal for the Eastern Division. Mr. Goodin has a Juris Doctorate of Law from the University of Denver and a Bachelor of Science in Business-Marketing from the University of Colorado. He has previously worked as Director of Land & Legal and General Counsel for Petrogulf Corporation in Denver, Co., Of Counsel with the law firm of Poulson, Odell & Peterson, Vice President of Land and Corporate Attorney for Eastern American Energy Corporation in Charleston, WV and District Landman with BP Exploration, Inc. in Colorado and Texas.

Mr. Goodin is licensed to Practice Law in Colorado, Texas and West Virginia; is a Member of the Colorado, Texas and WV Bar Associations; and is a member of the AAPL and DAPL.

Charlie Goodin is Founder and President of the new Denver Petroleum Club and has served on the Board of Directors of Junior Achievement as well as many other civic organizations.

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. Additionally, since we are wholly owned by Capital C, we have not determined that any of our directors is an “audit committee financial expert.”

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

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 2009.

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, 2009, none of our officers are compensated by us.

Item 12.		SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth certain information as of March 5, 2010 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:

		Number of				Percentage of
Five Percent Shareholders		Shares				Shares
Capital C Energy Operations, LP (1) 1001 Fanin Street, Suite 800 Houston, Texas 77002			1,534				100.0	%

Equity Compensation Plan Information:

As of March 5, 2010, we do not have any outstanding stock options or plans to grant any options.

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. In 2008, 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 2009, we paid 6.1 million for overhead fees, $5.9 million for field labor, vehicles and district office expense, $82,000 for drilling overhead fees and $1.1 million for drilling labor costs.

As of December 31, 2009, we owed EnerVest Operating $310,000 and owed EnerVest $600,000.

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, 2009 was $30.5 million. We borrowed an additional $2.9 million for interest payments against the note in 2009.

Messrs. Houser, Vanderhider and Mariani our officers and directors 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.

Item 14.		PRINCIPAL ACCOUNTANT FEES AND SERVICES

The audit committee of Belden & Blake Corporation selected Deloitte & Touche LLP, an independent registered public accounting firm, to audit our consolidated financial statements for the year ended December 31, 2009. The audit committee’s charter requires the audit committee to approve in advance all audit and non–audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit–related, tax and all other fees categories below with respect to this Annual Report on Form 10–K for the year ended December 31, 2009 were approved by the audit committee.

Fees paid to Deloitte & Touche LLP are as follows:

		December 31,
		2009				2008
Audit fees (1)		$	352,000			$	470,000
Audit-related fees			—				—
Tax fees			—				—
All other fees			—				—
		$	352,000			$	470,000

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.

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.

No.				Description
	10.9			Fourth Amendment, Waiver and Agreement to the First Amended and Restated Credit and Guarantee Agreement dated as of August 16, 2005, incorporated by reference to Exhibit 10.9 to Belden & Blake Corporation’s Annual Report on Form 10-K for the year ended December 31, 2008.
	10.10			Fifth Amendment and Agreement to the First Amended and Restated Credit and Guarantee Agreement dated as of August 16, 2005, incorporated by reference to Exhibit 10.1 to Belden & Blake’s 8-K filed on October 1, 2009).
	10.11	*		Sixth Amendment and Agreement to the First Amended and Restated Credit and Guarantee 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.
	99.1	*		Wright & Company, Inc. Reserve Report.

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.

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
Mark A. Houser		Chief Executive Officer Chairman of the Board of Directors and Director (Principal Executive Officer)		March 26, 2010 Date
/s/ James M. Vanderhider
James M. Vanderhider		President, Chief Financial Officer and Director (Principal Financial Officer)		March 26, 2010 Date
/s/ Frederick J. Stair
Frederick J. Stair		Vice President of Accounting (Principal Accounting Officer)		March 26, 2010 Date
/s/ Kenneth Mariani
Kenneth Mariani		Senior Vice President, Chief Operating Officer and Director		March 26, 2010 Date
/s/ Matthew Coeny
Matthew Coeny		Director		March 26, 2010 Date

BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES

Item 15(a) (1) and (2)

		Page
CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets as of December 31, 2009 and 2008			F-3
Consolidated Statements of Operations: Years ended December 31, 2009, 2008 and 2007			F-4
Consolidated Statements of Shareholders’ Equity: Years ended December 31, 2009, 2008 and 2007			F-5
Consolidated Statements of Cash Flows: Years Ended December 31, 2009, 2008 and 2007			F-6
Notes to Consolidated Financial Statements			F-7

All financial statement schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Belden & Blake Corporation
Houston, Texas

We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Partnership adopted Accounting Standards Update No. 2010-3, “Oil and Gas Reserve Estimation and Disclosures” on December 31, 2009.

/s/ DELOITTE & TOUCHE LLP
Houston, TX
March 26, 2010

BELDEN & BLAKE CORPORATION

		December 31,
		2009				2008
ASSETS
Current assets
Cash and cash equivalents		$	46,740			$	22,816
Accounts receivable (less accumulated provision for doubtful accounts: December 31, 2009 — $393; December 31, 2008 — $312)			11,821				19,244
Inventories			828				1,004
Deferred income taxes			8,272				7,946
Other current assets			183				332
Fair value of derivatives			413				430
Total current assets			68,257				51,772
Property and equipment, at cost
Oil and gas properties (successful efforts method)			684,787				735,398
Gas gathering systems			1,275				1,413
Land, buildings, machinery and equipment			2,566				2,836
			688,628				739,647
Less accumulated depreciation, depletion and amortization			151,208				124,175
Property and equipment, net			537,420				615,472
Fair value of derivatives			478				868
Other assets			1,923				1,352
		$	608,078			$	669,464
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable		$	1,696			$	2,522
Accounts payable — related party			910				1,048
Accrued expenses			16,136				19,251
Current portion of long-term liabilities			238				25,237
Fair value of derivatives			21,098				20,520
Total current liabilities			40,078				68,578
Long-term liabilities
Bank and other long-term debt			43,929				74,938
Senior secured notes			162,287				163,302
Subordinated promissory note — related party			30,491				27,623
Asset retirement obligations and other long-term liabilities			22,990				23,863
Fair value of derivatives			66,876				101,570
Deferred income taxes			137,286				133,039
Total long-term liabilities			463,859				524,335
Shareholder’s equity
Common stock: without par value; 3,000 shares authorized; 1,534 shares issued			—				—
Additional paid in capital			142,500				122,500
Accumulated deficit			(29,978	)			(32,754	)
Accumulated other comprehensive loss			(8,381	)			(13,195	)
Total shareholder’s equity			104,141				76,551
		$	608,078			$	669,464