UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2010


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). o Yes o No

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, 2011, 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

This Form 10-K contains forward—looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “forward—looking statement”). These forward—looking statements relate to, among other things, the following:

	•		our future financial and operating performance and results;

	•		our business strategy;

	•		our estimated net proved reserves and standardized measure;

	•		market prices;

	•		our future derivative activities; and

	•		our plans and forecasts.

We have based these forward—looking statements on our current assumptions, expectations and projections about future events.

The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward—looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward—looking” information. We do not undertake any obligation to update or revise publicly any forward—looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10-K including, but not limited to:

	•		fluctuations in prices of oil and natural gas;

	•		significant disruptions in the financial markets;

	•		future capital requirements and availability of financing;

	•		uncertainty inherent in estimating our reserves;

	•		risks associated with drilling and operating wells;

	•		discovery, acquisition, development and replacement of oil and natural gas reserves;

	•		cash flows and liquidity;

	•		timing and amount of future production of oil and natural gas;

	•		availability of drilling and production equipment;

	•		marketing of oil and natural gas;

	•		developments in oil and natural gas producing countries;

	•		competition;

	•		general economic conditions;

	•		governmental regulations;

	•		receipt of amounts owed to us by purchasers of our production and counterparties to our derivative financial instrument contracts;

	•		hedging decisions, including whether or not to enter into derivative financial instruments;

	•		events similar to those of September 11, 2001;

	•		actions of third party co—owners of interest in properties in which we also own an interest;

	•		fluctuations in interest rates and the value of the U.S. dollar in international currency markets; and

	•		our ability to effectively integrate companies and properties that we acquire.

All of our forward—looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

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 other reservoirs.

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 (“Credit Agreement”) by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Credit Agreement provides for loans and other extensions of credit to be made to us.

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.

On August 25, 2010, we entered into the Seventh Amendment to the Credit Agreement. The Credit Agreement was amended to (1) extend the termination date to April 14, 2012, (2) extend the hedge letter of credit termination date to April 14, 2012, (3) decrease the aggregate amount of the revolving commitments to $90 million, (4) decrease the borrowing base to $55 million and (5) make certain other amendments to the Credit Agreement.

DESCRIPTION OF BUSINESS

Overview

In the fourth quarter of 2010, our average net production was approximately 32.6 MMcfe per day consisting of 28.3 MMcf of natural gas and 726 Bbls of oil per day. At December 31, 2010, we owned interests in 4,368 gross (3,463 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with estimated proved reserves totaling 202.4 Bcfe consisting of 171.6 Bcf of natural gas and 5.1 MMBbl of oil. The estimated future net cash flows from these reserves had a standardized measure of approximately $199.6 million at December 31, 2010. The 12-month weighted average prices used to estimate proved reserves at December 31, 2010 were $4.76 per Mcf for natural gas and $74.63 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, 2010, EnerVest Operating operated approximately 3,833 wells, or 88% of our gross wells representing approximately 97% of the value of our estimated proved developed reserves based on their standardized measure. At December 31, 2010, we owned leases on 1,110,796 gross (415,953 net) acres, including 591,959 gross (261,456 net) undeveloped acres.

We own approximately 1,600 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 2010, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.24 and $0.20, respectively, higher than the average NYMEX monthly settle price for 2010.

Oil and Gas Reserves

The following table presents our estimated net proved oil and natural gas reserves at December 31, 2010. These estimates were prepared by Wright & Company, Inc. independent petroleum consultants.


	Oil and Gas Reserves
	Oil (MMBbl)		Gas (Bcf)		Bcfe

Proved
Developed		4.1		157.2		181.7
Undeveloped		1.0		14.4		20.7

Total		5.1		171.6		202.4

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 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 and 2010 reserves. As a result, our December 31, 2009 and 2010 reserves may not be comparable to those of prior periods. See “Glossary of Oil and Natural Gas Terms.”

At December 31, 2010 and 2009, as specified by the SEC, the prices for oil, natural gas and natural gas liquids used in this calculation were the average prices during 2010 and 2009, respectively, determined using the price on the first day of each month, except for volumes subject to fixed price contracts. At December 31, 2008, as specified by the SEC, the prices of oil, natural gas and natural gas liquids used in this calculation were regional cash price quotes on the last day of the year, except for volumes subject to fixed price contracts.

The following table sets forth the average prices 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,
	2010		2009		2008
Gas (per Mcf)	$	4.76	$	4.34	$	6.38
Oil (per Bbl)		74.63		56.33		41.00

We annually review all proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. All proved undeveloped locations conform to the SEC rules defining proved undeveloped locations. None of our proved undeveloped reserves as of December 31, 2010 have remained undeveloped for more than five years. We had 20.7 Bcfe of PUDs at December 31, 2010, compared with 17.0 Bcfe of PUDs at December 31, 2009. During 2010, we converted 1.7 Bcfe, or approximately 9.8% of our PUDs at December 31, 2009 to proved developed reserves.

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, 2010 was $199.6 million. 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 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 6 years of experience in the oil and gas industry, including over 5 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 33 years of experience in petroleum engineering.

The Audit Committee of our Board of Directors meets annually with management, including the Manager of Reservoir 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, until recently, 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 3,152 gross (2,828 net) wells in the Appalachian Basin which currently produce approximately 18.3 MMcfe net per day. Most of our production in the Appalachian Basin is derived from the shallow (1,000 to 6,500 feet) Medina, Clinton and Clarendon Formations, predominately in Pennsylvania and Ohio.

During 2010, we drilled 39 gross (39.0 net) development wells and 6 gross (1.5 net) exploratory wells of which 38 gross (38.0 net) development wells and 4 gross (1.0 net) exploratory wells were completed as producing wells. The anticipated 2011 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.

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 (635 net) wells in the Michigan Basin which currently produce approximately 14.3 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 2010, we drilled no wells to the Antrim Shale Formation. We do not plan to drill any wells in the Antrim Shale Formation in 2011.

Oil and Gas Operations and Production

Operations. EnerVest Operating operates 88% 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.

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 6 to the Consolidated Financial Statements.


	Year Ended December 31,
	2010		2009		2008

Production
Gas (MMcf)		10,109		12,034		13,217
Oil (MBbl)		272		324		334
Total production (MMcfe)		11,742		13,977		15,221
Average sales price (1)
Gas (per Mcf)	$	4.00	$	3.61	$	8.62
Oil (per Bbl)		73.92		56.49		94.40
Per Mcfe		5.16		4.42		9.55
Average costs (per Mcfe)
Production expense	$	1.75	$	1.50	$	1.73
Production taxes		0.10		0.08		0.20
Depletion		2.48		2.62		2.31


(1)		The average prices presented above include non-cash amounts related to our derivatives as a result of purchase accounting for the Merger and the Transaction. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average sales prices:


	Year Ended December 31,
	2010		2009		2008
Gas (per Mcf)	$	4.61	$	4.27	$	9.31
Oil (per Bbl)		73.92		56.49		94.40
Per Mcfe		5.68		4.98		10.15

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 2010, we spent approximately $18.0 million on development and exploratory drilling and other capital expenditures including exploratory dry hole costs. We drilled 39 gross (39.0 net) development wells and 6 gross (1.5 net) exploratory wells in 2010.

In 2011, we expect to spend approximately $17.5 million on development and exploratory drilling and other capital expenditures. The anticipated 2011 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.

Additionally, we have also tested the Niagaran Carbonate, Onondaga Limestone, Oriskany Sandstone, 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.

Typical characteristics of our drilling programs in the 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	$280 - 320
Knox	4,000 - 8,500	550 - 800
Pennsylvania:
Clarendon	1,100 - 2,100	100 - 120
Medina	5,300 - 6,200	325 - 350
Michigan:
Antrim	1,300 - 2,100	275 - 325

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
	2008		2009		2010		2008		2009		2010
Productive:
Gross		98		—		38		—		4		4
Net		83.5		—		38.0		—		2.0		1.0
Dry:
Gross		—		—		1		5		—		2
Net		—		—		1.0		4.9		—		0.5

Producing Well Data

As of December 31, 2010, we owned interests in 4,368 gross (3,463 net) producing oil and gas wells of which approximately 3,833 wells were operated by EnerVest Operating. In the fourth quarter of 2010, our average net production was approximately 32.6 MMcfe per day consisting of 28.3 MMcf of natural gas and 726 Bbls of oil per day.

The following table summarizes by state our productive wells at December 31, 2010:


	Gas Wells				Oil Wells				Total
State	Gross		Net		Gross		Net		Gross		Net
Ohio		1,057		900		672		603		1,729		1,503
Pennsylvania		1,299		1,212		106		106		1,405		1,318
New York		18		7		—		—		18		7
Michigan		1,199		633		17		2		1,216		635

		3,573		2,752		795		711		4,368		3,463

Acreage Data

The following table summarizes by state our gross and net developed and undeveloped acreage at December 31, 2010:


	Developed Acreage				Undeveloped Acreage				Total Acreage
State	Gross		Net		Gross		Net		Gross		Net
Ohio		404,898		58,592		391,844		90,849		796,742		149,441
Pennsylvania		40,676		30,372		175,093		147,624		215,769		177,996
New York		2,845		608		12,696		12,117		15,541		12,725
Michigan		70,418		64,925		12,326		10,866		82,744		75,791

		518,837		154,497		591,959		261,456		1,110,796		415,953

The following table summarizes by state our undeveloped acreage as of December 31, 2010 that is subject to expiration absent drilling activity during the three years ended December 31, 2013 and thereafter.


	Undeveloped Acreage Subject to Expiration in the Year Ended December 31,
	2011				2012				2013				Thereafter
State	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Ohio		4,217		4,212		840		489		3,941		2,157		8,375		4,664
Pennsylvania		3,769		2,316		2,280		2,236		3,092		2,634		602		101
New York		—		—		—		—		—		—		—		—
Michigan		2,143		2,143		1,079		1,079		714		714		368		366

		10,129		8,671		4,199		3,804		7,747		5,505		9,345		5,131

Disposition of Assets

In July 2010, we sold a 75% interest in certain undeveloped acreage in Ohio for $6.1 million.

In June 2010, we sold undeveloped acreage in Pennsylvania for $30.6 million.

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 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.

Acquisition of Producing Properties

In the fourth quarter of 2010, we acquired additional working interest in our wells in Michigan for approximately $4.4 million.

Employees

As of February 28, 2011, 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 2010: American Refining Group, Inc., National Fuel Resources, Inc. and Sequent Energy. 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.

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. Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making the prediction of future costs or the impact of regulatory compliance to new laws and statutes difficult. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, consequently, affects its profitability. 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:

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the location of wells;

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the method of drilling and casing wells;

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

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the plugging and abandoning of wells; and

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notice to surface owners and other third parties.

State and federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural gas between owners in a common reservoir or formation, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies that provide midstream services to us are also subject to the jurisdiction of various federal, state and county/municipal agencies, which can affect our operations. State laws also regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. States in the Appalachian Basin have taken up consideration of forced pooling. Other states rely on voluntary pooling of lands and leases.

States generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within its jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

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 producing 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 non—discrimination 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 other appropriate federal or state agencies.

Federal Regulation of Sales and Transportation of Natural Gas. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions

applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act.

Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis. FERC has announced several important transportation related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

FERC has also issued several other generally pro—competitive policy statements and initiatives affecting rates and other aspects of pipeline transportation of natural gas. On May 31, 2005, FERC generally reaffirmed its policy of allowing interstate pipelines to selectively discount their rates in order to meet competition from other interstate pipelines. On June 15, 2006, the FERC issued an order in which it declined to establish uniform standards for natural gas quality and interchangeability, opting instead for a pipeline—by—pipeline approach. On June 19, 2006, in order to facilitate development of new storage capacity, FERC established criteria to allow providers to charge market—based (i.e. negotiated) rates for storage services. On June 19, 2008, the FERC removed the rate ceiling on short—term releases by shippers of interstate pipeline transportation capacity.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

State Natural Gas Regulation. Various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

Other Regulation. In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

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 federal, state and local 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 or other approval before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require the installation of pollution control equipment, 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. Failure or delay in obtaining such permits or approvals could have a material adverse effect on our ability to develop our properties, and receipt of permits or approvals with onerous conditions could increase our compliance costs.

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 of contaminated sites and for associated 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 (“PRPs”), 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 PRPs 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 and may have disposed of those wastes at disposal sites owned and operated by others. 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 PRPs related to their ownership or operation of such property. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we have sent Hazardous Substances, we could be liable for the costs of investigation and remediation and for natural resource damages.

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 there is no guarantee that more stringent requirements will not be adopted in the future. 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, operate or lease, and have in the past owned, operated 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, operated 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 were 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 (including wastes or contamination attributable to others), 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. Major sources of air pollutants are subject to more stringent requirements, including additional permitting requirements. Other federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation of additional controls. Governmental agencies (and in the case of civil suits, private parties in certain circumstances) 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 (which could include requiring us to forego construction, modification or operation of sources of air

pollutants) and imprisonment.

More stringent laws and regulations relating to climate change and greenhouse gases (GHGs) may be adopted in the future and could cause us to incur material expenses in complying with them. The EPA has been moving forward to regulate GHS as pollutants under the CAA. By adopting rules regulating GHG emissions from motor vehicles, EPA triggered requirements to permit GHG emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V permitting programs. EPA has implemented the so-call “Tailoring Rule” requiring that the largest sources to first obtain permits for GHG emissions. There is still the possibility that federal legislation will be adopted to change the GHG permitting program put in place by EPA, but to date, efforts at a comprehensive GHG legislative package (such as a cap and trade program) appear not to be moving forward in Congress. Some members of Congress, however, continue to publicly indicate an intention to promote legislation to curb EPA’s authority to regulate GHGs. Additionally, some states, regions and localities have adopted or are considering programs to address GHGs. We may incur significant costs to control our emissions and comply with regulatory requirements associated with GHG permitting. In addition, EPA has adopted a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries. In November 2010, EPA expanded this GHG reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. 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 regarding the regulation of GHGs at the federal level. 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 or otherwise being required to control or reduce emissions. 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 under the Safe Drinking Water Act and analogous state programs. 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 (including the discharge of dredged or fill materials) 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. Currently, most hydraulic fracturing activities are regulated at the state level, as the SDWA exempts most hydraulic fracturing activities. 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. In addition, many states and other local regulatory authorities have enacted or are considering regulations on hydraulic fracturing including regulations that could restrict hydraulic fracturing in certain circumstances. In addition, EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Further, a committee of the U.S. House of Representatives is conducting an investigation of certain hydraulic fracturing activities. If new laws or regulations impose

significant restrictions or conditions on hydraulic fracturing activities, 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 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.

Oil and natural gas exploration and production activities on or pipeline crossing of federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

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.


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 66% of the expected 2011 through 2013 production from our current estimated proved reserves. These transactions may limit our potential gains if natural gas and crude oil 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:

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our production is less than expected;

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there is a narrowing of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements;

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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

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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 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 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:

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the success of our projects in the Appalachian and Michigan basins;

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our success in locating and producing new reserves;

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the level of production from existing wells; and

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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 $0.50 per Mcf, our gas sales revenues would decrease by approximately $5.1 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $2.7 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 $0.50 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas by approximately $1.6 million after considering the effects of the derivative contracts in place during 2010. This sensitivity analysis is based on our 2010 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 85% 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, 2010, a 10% reduction in the

price of oil and natural gas would have reduced our future net cash flow from proved reserves, discounted at 10%, by $49 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; economic conditions; and actions of federal, foreign, state, and local authorities.

These external factors and the volatile nature of the energy markets make it difficult to estimate future commodity prices.

If oil and natural gas prices decrease or our drilling efforts are unsuccessful, we may be required to write down the carrying value of our oil and natural gas properties.

There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. A write down could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results.

We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future net revenues, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but it will reduce our earnings and stockholders’ equity.

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 2010 and 2009, we recorded impairments to our oil and natural gas properties of $1.6 million and $30.4 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, 2010, approximately 10% 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. 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.

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 and these regulations may adversely affect the manner or feasibility of conducting our operations.

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 or to obtain permits and authorizations to conduct our operations. 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.

The EPA has been moving forward to regulate GHS as pollutants under the CAA. By adopting rules regulating GHG

emissions from motor vehicles, EPA triggered requirements to permit GHG emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V permitting programs. EPA has implemented the so-called “Tailoring Rule” requiring that the largest sources to first obtain permits for GHG emissions. There is still the possibility that federal legislation will be adopted to change the GHG permitting program put in place by EPA, but to date, efforts at a comprehensive GHG legislative package (such as a cap and trade program) appear not to be moving forward in Congress. Some members of Congress, however, continue to publicly indicate an intention to promote legislation to curb EPA’s authority to regulate GHGs. Additionally, some states, regions and localities have adopted or are considering programs to address GHGs. 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.

In addition, EPA has adopted a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries. In November 2010, EPA expanded this GHG reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. 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.

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 operations 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 most 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. EPA has initiated a study of the environmental impacts of hydraulic fracturing and a committee of the U.S. Congress is investigating certain hydraulic fracturing practices. Further, many states and other regulatory authorities have adopted or are proposing additional regulations on hydraulic fracturing. 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.

On July 21, 2010, the President signed into law the Dodd—Frank Wall Street Reform and Consumer Protection Act (the “Act”). Among other things, the Act requires the Commodity Futures Trading Commission and the SEC to enact regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility within 360 days from the date of enactment. We cannot predict the content of these regulations or the effect that these regulations will have on our hedging activities. Of particular concern, the Act does not explicitly exempt end users (such as us) from the requirements to use exchanges, which would require us to post margin in connection with hedging activities. Even if we qualify for an exception, there are other aspects of the Act that may make it more expensive for other parties to offer these hedges to us. The full effects of the Act will not be known until the regulations have been enacted and the market for these hedges has adjusted. It is possible the hedges will become more expensive, uneconomic or unavailable, which could lead to increased costs or commodity price volatility or a combination of both.

The distressed financial conditions of customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide.

Some of our customers may experience, in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

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 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.

At December 31, 2010, we had a Credit Agreement comprised of a $90 million revolving facility with a borrowing base of $55 million, of which $23.9 million was outstanding, 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. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit. Borrowings under the 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 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 Credit Agreement. The full amount borrowed under the Credit Agreement will mature on April 14, 2012.

The obligations under the Credit Agreement are secured by a first lien security interest in substantially all of our assets. The obligations under the Credit Agreement are further secured by a pledge of 100% of our capital stock held by Capital C, our parent.

The 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 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. In 2010, we amended certain of these covenants. At December 31, 2010, we were in compliance with our covenants under the Credit Agreement. Our senior secured leverage ratio was 0.80 : 1.0 and the interest coverage ratio was 1.78 : 1.0. For additional information on our Credit Agreement, see Note 8.

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 Credit Agreement and the Hedge Agreement contain, and any future refinancing of our Credit Agreement likely would contain, a number of restrictive covenants that impose significant operating and financial restrictions on us. Our Credit Agreement and, to some extent, the Hedge Agreement include covenants restricting, among other things, our ability to:

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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;

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transfer all or substantially all of our assets; and

•

enter into merger or consolidation transactions.

Our 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.

If we refinance our indebtedness, we may call the Senior Secured Notes. Following the redemption of the notes, the note holders will no longer have an investment in our debt securities and we will no longer be required to make filings with the SEC.


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, 2011, were held by Capital C.

Dividends

We paid no cash dividends in 2010 and 2009 and paid cash dividends of $2.5 million in 2008.


Item 6.		SELECTED FINANCIAL DATA

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


	As of or for the year ended December 31,
(in thousands)	2010		2009		2008			2007			2006
Continuing Operations:
Revenues	$	66,380	$	68,624	$	158,426		$	125,140		$	158,774
Depreciation, depletion and amortization		29,368		37,046		35,560			36,087			38,074
Impairment of oil and gas properties		1,565		30,445		3,924			31			546
Impairment of goodwill		—		—		90,076			—			—
Net income (loss)		40,146		2,776		(28,944	)		(35,322	)		52,199
Balance sheet data:
Working capital (deficit) from continuing operations		13,611		28,179		(16,806	)		(14,224	)		(11,635	)
Oil and gas properties and gathering systems, net		524,538		536,237		613,834			627,556			641,879
Total assets		579,022		608,078		669,464			774,225			777,023
Long-term debt, less current portion		197,822		236,707		265,863			291,118			285,560
Total shareholder’s equity		147,882		104,141		76,551			102,223			143,703


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.

At December 31, 2010, our total estimated proved reserves were 202.4 Bcfe. Natural gas comprised approximately 85% of our estimated proved reserves, and 90% 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, 2010, our Appalachian properties accounted for 57% of our estimated proved reserves, while the Michigan properties accounted for 43% 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. Oil and natural gas prices 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 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 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 66% of the expected 2011 through 2013 production from our current estimated proved reserves and will range from 62% to 72% of such expected production in any year.

The average price realized for our natural gas, inclusive of hedges that previously qualified as effective hedges, decreased from $8.62 per Mcf in 2008 to $3.61 per Mcf in 2009 and then increased to $4.00 per Mcf in 2010. The monthly average settle for natural gas trading on the NYMEX decreased from $9.04 per MMbtu in 2008 to $3.99 per MMbtu in 2009 and then increased to $4.39 per MMbtu in 2010. 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 2010, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.24 and $0.20, respectively, higher than the average NYMEX monthly settle price for 2010. The remainder of the difference is primarily due to our qualified hedging activities during these periods. Our average realized price for oil decreased from $94.40 per Bbl in 2008 to $56.49 per Bbl in 2009 and increased to $73.92 per Bbl in 2010.

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, 2010 or 2009.

Current market conditions also elevate concerns about cash and cash equivalent investments, which at December 31, 2010 totaled $35.9 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 counterparties and believe that they are 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

The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units—of—production method based on the ratio of current production to estimated total net proved oil and natural gas reserves as estimated by independent petroleum engineers. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold, platform, and pipeline costs. 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. We recorded no impairment to unproved oil and gas properties in 2010 and recorded impairments $3.6 million and $783,000 in 2009 and 2008, respectively, which reduced the book value of unproved oil and gas properties to their estimated fair value.

Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.

Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized.

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. In performing the reviews for long-lived asset recoverability, we recorded impairments of $1.6 million, $26.8 million and $3.1 million in 2010, 2009 and 2008, respectively, which reduced the book value of proved properties to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest.

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 or 2010

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. None of our derivative financial instruments are designated as cash flow hedges. The changes in fair value of our derivative instruments are reported in expense in the consolidated statements of operations as derivative fair value (gain) loss.

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, 2010, 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.

We use NYMEX-based commodity derivative contracts to hedge natural gas, because our natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, we had ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. At August 16, 2005, our oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in fair value of the oil swaps subsequent to August 15, 2005 and the ineffective portion of the natural gas swaps from July 7, 2004 through June 30, 2006 are recorded as “Derivative fair value gain or loss.” As of July 1, 2006, we determined that our gas swaps were no longer highly effective and, therefore, could no longer be designated as cash flow hedges. Changes in the fair value of the gas derivatives from that date forward are recorded in derivative fair value gain/loss. Previously 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.

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 reasonably assured. 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, 2010 or 2009. 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, 2010, 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,
	2010					2009					2008

Revenues
Oil and gas sales	$	60,601		91.3	%	$	61,761		90.0	%	$	145,398		91.8	%
Gas gathering and marketing		5,223		7.9			5,894		8.6			12,254		7.7
Other		556		0.8			969		1.4			774		0.5

		66,380		100.0			68,624		100.0			158,426		100.0

Expenses
Production expense		20,528		30.9			20,955		30.6			26,342		16.6
Production taxes		1,133		1.7			1,098		1.6			3,054		1.9
Gas gathering and marketing		4,988		7.5			5,492		8.0			10,252		6.5
Exploration expense		2,635		4.0			3,925		5.7			2,543		1.6
General and administrative expense		6,805		10.3			7,785		11.3			8,188		5.2
Depreciation, depletion and amortization		29,368		44.2			37,046		54.0			35,560		22.4
Impairment of goodwill		—		—			—		—			90,076		56.9
Inpairment of oil and gas properties		1,565		2.4			30,445		44.4			3,924		2.5
Accretion expense		1,333		2.0			1,304		1.9			1,412		0.9
Gain on asset sales		(33,644	)	(50.7	)		(34,929	)	(50.9	)		—		—
Derivative fair value gain		(32,768	)	(49.4	)		(29,631	)	(43.2	)		(55,940	)	(35.3	)

		1,943		2.9			43,490		63.4			125,411		79.2

Operating income		64,437		97.1			25,134		36.6			33,015		20.8
Other expense (income)
Gain on early extinguishment of debt		(1,006	)	(1.5	)		—		—			—		—
Interest expense		19,006		28.6			20,612		30.0			22,818		14.4
Other income, net		(92	)	(0.1	)		(131	)	(0.2	)		(495	)	(0.3	)


Income before income taxes		46,529		70.1			4,653		6.8			10,692		6.7
Provision for income taxes		6,383		9.6			1,877		2.7			39,636		25.0

Net income (loss)		40,146		60.5			2,776		4.1			(28,944	)	(18.3	)

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,
	2010		2009		2008

Production
Gas (MMcf)		10,109		12,034		13,217
Oil (MBbl)		272		324		334
Total production (MMcfe)		11,742		13,977		15,221
Average sales price (1)
Gas (per Mcf)	$	4.00	$	3.61	$	8.62
Oil (per Bbl)		73.92		56.49		94.40
Per Mcfe		5.16		4.42		9.55
Average costs (per Mcfe)
Production expense	$	1.75	$	1.50	$	1.73
Production taxes		0.10		0.08		0.20
Depletion		2.48		2.62		2.31


(1)		The average prices presented above include non-cash amounts related to our derivatives as a result of purchase accounting for the Merger and the Transaction. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average sales prices:


	Year Ended December 31,
	2010		2009		2008
Gas (per Mcf)	$	4.61	$	4.27	$	9.31
Oil (per Bbl)		73.92		56.49		94.40
Per Mcfe		5.68		4.98		10.15

2010 Compared to 2009

Revenues

Net operating revenues decreased $2.2 million from $68.6 million in 2009 to $66.4 million in 2010. The decrease was primarily due to lower gas sales revenues of $3.0 million and lower gas gathering and marketing revenues of $671,000 partially offset by higher oil sales revenues of $1.8 million.

Gas volumes sold decreased 1.9 Bcf (16%) from 12.0 Bcf in 2009 to 10.1 Bcf in 2010 resulting in a decrease in gas sales revenues of approximately $7.0 million. Oil volumes sold decreased approximately 52,000 Bbls (16%) from 324,000 Bbls in 2009 to 272,000 Bbls in 2010 resulting in a decrease in oil sales revenues of approximately $2.9 million. 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 2010 and operational projects, which increased production for some existing wells.

The average price realized for our natural gas increased $0.39 per Mcf to $4.00 per Mcf in 2010 compared to $3.61 per Mcf in 2009, which increased gas sales revenues by approximately $4.0 million. As a result of our previously qualified effective hedging activities, gas sales revenues were lower by $6.1 million ($0.61 per Mcf) in 2010 and lower by $7.9 million ($0.66 per Mcf) in 2009 than if our gas was not hedged. The average price realized for our oil increased from $56.49 per Bbl in 2009 to $73.92 per Bbl in 2010, which increased oil sales revenues by approximately $4.7 million.

The decrease in gas gathering and marketing revenues was due to a $518,000 decrease in gas marketing revenues and a $153,000 decrease in gas gathering revenues. The lower gas gathering and marketing revenues were primarily the result of lower gas sales volumes.

Costs and Expenses

Production expense decreased $427,000 from $21.0 million in 2009 to $20.5 million in 2010. The decrease was primarily due to the sale of our coalbed methane assets in Pennsylvania in July 2009 partially offset by higher ad valorem taxes in 2010. The average production cost increased from $1.50 per Mcfe in 2009 to $1.75 per Mcfe in 2010 due to the lower oil and gas sales volumes.

Production taxes were $1.1 million in 2009 and 2010. Average per unit production taxes increased from $0.08 per Mcfe in 2009 to $0.10 per Mcfe in 2010.

Gathering and marketing expense decreased $504,000 from $5.5 million in 2009 to $5.0 million in 2010 primarily due to lower gas sales volumes in 2010.

Exploration expense decreased $1.3 million from $3.9 million in 2009 to $2.6 million in 2010. The decrease was primarily due to lower expired lease expense, delay rentals and seismic costs in 2010 partially offset by higher exploratory dry hole expenses.

General and administrative expense decreased $1.0 million from $7.8 million in 2009 to $6.8 million in 2010. The decrease was primarily due to a decrease in overhead fees paid to EverVest as a result of the sale of our coalbed methane assets in Pennsylvania in July 2009 and lower insurance costs in 2010.

Depreciation, depletion and amortization decreased $7.6 million from $37.0 million in 2009 to $29.4 million in 2010. Depletion expense decreased $7.6 million due to the lower production volumes and a lower depletion rate per Mcfe. Depletion per Mcfe decreased from $2.62 in 2009 to $2.48 in 2010 primarily due to higher proved reserves as a result of higher oil and gas prices in 2010.

Impairment of oil and gas properties decreased from $30.4 million in 2009 to $1.6 million in 2010 due to the write-downs of our investment in properties in the coalbed methane and Marcellus formation in Pennsylvania during 2009 as a result of lower oil and gas prices and unfavorable development results in the Marcellus formation.

Gain on sale of assets was $33.6 million in 2010 and $34.9 million in 2009 due to the sale of undeveloped acreage in Ohio and Pennsylvania in 2010 and the sale of undeveloped acreage in Pennsylvania in 2009.

Derivative fair value gain/loss was a gain of $32.8 million in 2010 and $29.6 million in 2009. 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.

Gain on early extinguishment of debt was $1.0 million in 2010 as a result of our repurchase of $20 million of our senior secured notes at a discount.

Interest expense decreased $1.6 million from $20.6 million in 2009 to $19.0 million in 2010. This decrease was primarily due to lower outstanding debt in 2010.

Income tax expense increased from $1.9 million in 2009 to $6.4 million in 2010. The increase in income tax expense was primarily due to an increase in net income before income taxes in 2010. This was partially offset by a decrease in the effective tax rate due to the reduction of the state tax valuation allowance. The valuation allowance was reduced upon the realization of state tax net operating loss carryforwards, which resulted from taxable gains on asset sales. The decrease in the effective tax rate was also due to the elimination of the state of Ohio corporate income tax. The Ohio corporate income tax was replaced with a Commercial Activity Tax which is not considered an income tax.

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 $8.62 per Mcf in 2008, which decreased gas sales revenues by approximately $60.2 million. As a result of our previously 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.

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 EnerVest.

Depreciation, depletion and amortization increased by $1.4 million from $35.6 million in 2008 to $37.0 million in 2009. Depletion expense increased $1.5 million from 2008 to 2009 due primarily to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $2.31 in 2008 to $2.62 in 2009 due to lower proved reserves as a result of lower oil and gas prices 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.

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 $1.9 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.

Liquidity and Capital Resources

Cash Flows

We expect that our primary sources of cash in 2011 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 Credit Agreement, will be adequate to meet our short-term liquidity needs for 2011.

The primary sources of cash in the year ended December 31, 2010 were funds generated from operations 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,
	2010			2009			Change
	(in millions)
Cash flows provided by operating activities	$	18.7		$	23.9		$	(5.2	)
Cash flows provided by (used in) investing activities		19.9			38.9			(19.0	)
Cash flows (used in) financing activities		(49.4	)		(38.9	)		(10.5	)


Net increase (decrease) in cash and cash equivalents	$	(10.8	)	$	23.9		$	(34.7	)

Our operating activities provided cash flows of $18.7 million during 2010 compared to $23.9 million in 2009. The decrease was primarily due to a $2.9 million decrease in oil and gas sales, excluding the effects of hedging and a $3.2 million decrease in the change in operating assets, which was partially offset by a $980,000 decrease in general and administrative expense.

Cash flows provided by investing activities were $19.9 million in 2010 compared to cash flows used in investing activities of $38.9 million in 2009. This decrease was due to a decrease of $16.5 million in proceeds from property and equipment sales and an increase of $2.7 million in property and equipment additions.

Cash flows used in financing activities in 2010 were $49.4 million compared to $38.9 million in 2009. This increase was primarily due to the $20.0 million decrease in capital contributions, the $19.2 million repurchase of Senior Secured Notes in 2010 and the $8.3 million increase in the settlement of derivative liabilities which were partially offset by the $36.0 million decrease in debt repayments.

During 2010, our working capital decreased $14.5 million from a surplus of $28.2 million at December 31, 2009 to a surplus of $13.7 million at December 31, 2010. The decrease was primarily due to a decrease in cash of $10.8 million, a $7.2 million increase in accounts payable and accrued expenses and a $1.9 million decrease in accounts receivable, partially offset by a $9.0 million decrease in the current fair value of derivatives liability.

Capital Expenditures

The table below sets forth our total capital expenditures for each of the years ending December 31, 2010, 2009 and 2008.


	Year Ended December 31,
	2010		2009		2008
	(in millions)

Total capital expenditures
Drilling including exploratory dry hole expense	$	16	$	4	$	25
Field improvements		1		6		2
Leasehold acreage		1		2		1

Total	$	18	$	12	$	28

During 2010, we spent approximately $18.0 million, including exploratory dry hole expense, on our drilling and other capital expenditures. In 2010, we drilled 39 gross (39.0 net) development wells and 6 gross (1.5 net) exploratory wells of which 38 gross (38.0 net) development wells and 4 gross (1.0 net) exploratory wells were completed as producing wells.

We plan to spend approximately $17.5 million during 2011 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.

Financing and Credit Facilities

Senior Secured Notes due 2012

We have $139.5 million of our Senior Secured Notes outstanding as of December 31, 2010. 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. In September 2010, we repurchased additional notes. The notes repurchased in 2010 had a face value of $20.0 million and were repurchased at 95.875%, which resulted in a gain of approximately $1.0 million. 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 $139.5 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 Credit Agreement. The Senior Secured Notes are subject to redemption at our option at specific redemption prices.


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.

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 Credit Agreement provides for loans and other extensions of credit to be made to us.

At December 31, 2010, we had a Credit Agreement comprised of a $90 million revolving facility with a borrowing base of $55 million, of which $23.9 million was outstanding at December 31, 2010, 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. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit. Borrowings under the 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 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 Credit Agreement. The full amount borrowed under the Credit Agreement will mature on April 14, 2012. We are considering a refinancing of our Credit Agreement and may in connection therewith retire our Senior Secured Notes, before they come due in 2012. If we refinance our debt and call the Senior Secured Notes, then we will no longer have any notes outstanding and the note holders will no longer

have an investment in us. We can provide no assurances that our lenders will agree to refinance our Credit Agreement, or, if available, that the terms of any such refinancing will be acceptable to us.

At December 31, 2010, we were in compliance with such financial covenants under the Credit Agreement. Our senior secured leverage ratio was 0.80 : 1.0 and the interest coverage ratio was 1.78 : 1.0.

Borrowings under the revolving credit line will be used by us for general corporate purposes. In accordance with the terms of the 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 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. 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 three quarters of 2008 were paid in cash. Interest payments for the fourth quarter of 2008 and all of 2009 were made by additional borrowings against the Subordinated Note. In 2010, the first quarter interest payment was paid in cash and interest payments for the last three quarters were made by additional borrowings against the Subordinated Note. As of December 31, 2010, $32.8 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 future 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 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 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, 2010, we had interest rate swaps in place covering $23.5 million of our outstanding debt under the revolving credit facility that mature on September 30, 2013.

At December 31, 2010, the aggregate long-term debt maturing in the next five years is as follows: $10,000 (2011); $196.2 million (2012); $12,000 (2013); $13,000 (2014) and $7,000 (2015 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 66% of the expected 2011 through 2013 production from our current estimated proved reserves and will range from 62% to 72% 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 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 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 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 Credit Agreement and by a second-priority lien on the same assets securing the 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 at December 31, 2010.


	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, 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, 2010, the fair value of futures contracts covering 2011 through 2013 oil and gas production represented an unrealized loss of $39.7 million.

At December 31, 2010, we had interest rate swaps in place covering $23.5 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 $1.8 million at December 31, 2010.

Inflation and Changes in Prices

The average price realized for our natural gas decreased from $8.62 per Mcf in 2008 to $3.61 per Mcf in 2009 and then increased to $4.00 per Mcf in 2010. The average price realized for our oil decreased from $94.40 per Bbl in 2008 to $56.49 per Bbl in 2009 and then increased to $73.92 per Bbl in 2010. 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, 2010.


	Payments Due by Period
Contractual Obligations at			Less than 1						After 5
December 31, 2010	Total		Year		1 - 3 Years		4 - 5 Years		Years
	(in thousands)
Long-term debt	$	196,250	$	10	$	196,233	$	7	$	—
Asset retirement obligations		24,701		133		4,115		792		19,661
Derivative liabilities		41,501		11,347		30,154		—		—
Interest on debt (1)		26,958		17,683		9,275		—		—
Operating leases		248		210		38		—		—

Total contractual cash obligations	$	289,658	$	29,383	$	239,815	$	799	$	19,661


(1)		Amounts represent the expected cash payments for interest based on the debt outstanding and the effective interest rate as of December 31, 2010. Such amounts do not include the effects of our interest rate swaps.

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, 2010.


	Total		Amount of Commitment Expiration Per Period
Commercial Commitments at	Amounts		Less than 1						Over 5
December 31, 2010	Committed		Year		1 - 3 Years		4 - 5 Years		years
	(in thousands)
Standby Letters of Credit	$	40,792	$	40,792	$	—	$	—	$	—

Total Commercial Commitments	$	40,792	$	40,792	$	—	$	—	$	—

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 to satisfy ongoing margin requirements related to our hedges.

Off-Balance Sheet Arrangements

We have $40.8 million in letters of credit as described above.

NEW ACCOUNTING STANDARDS

In January 2010, the FASB issued Accounting Standards Update (“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 Securities and Exchange Commission’s final rule, Modernization of Oil and Gas Reporting. ASU No. 2010—03 was 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 beginning in 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 and requires new disclosures for (i) transfers between Levels 1, 2 and 3 and the reasons for such transfers and (ii) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, ASU 2010—06 amends Topic 820 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010—06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010—06 did not impact our operating results, financial position or cash flows, but did impact our disclosures on fair value measurements.

No other new accounting pronouncements issued or effective during the year ended December 31, 2010 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, 2010, we had an interest rate swap in place on $23.5 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 $23.5 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 $239,000. 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 $4,000. This sensitivity analysis is based on our financial structure at December 31, 2010.

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, 2010, we had derivatives covering a portion of our oil and gas production from 2011 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $7.9 million in 2009 and a net pre-tax loss of $6.1 million in 2010 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 $0.50 per Mcf, our gas sales revenues would decrease by approximately $5.1 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $2.7 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 $0.50 per Mcf and $10.00 per Bbl would decrease

cash flows from the sale of oil and gas by approximately $1.6 million after considering the effects of the derivative contracts in place during 2010. This sensitivity analysis is based on our 2010 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, 2010 or 2009.


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, 2010 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, 2010.

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 Mark A. Houser		/s/ James M. Vanderhider James M. Vanderhider
Chief Executive Officer, Chairman of the		President, Chief Financial Officer and Director
Board of Directors and Director

Houston, TX
March 28, 2011

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, 2010 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 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, 2011 were as follows:


Name	Age		Position

Mark A. Houser		49	Chief Executive Officer and Chairman of the Board of Directors

James M. Vanderhider		52	President, Chief Financial Officer and Director

Kenneth Mariani		49	Senior Vice President, Chief Operating Officer and Director

Frederick J. Stair		51	Vice President of Accounting

Barry K. Lay		54	Vice President of Operations

Charles Goodin		60	Vice President of Land and Legal and Secretary

Matthew Coeny		40	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 30 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. Mr. Goodin is Founder and past 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.

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 on behalf of certain Citigroup affiliates. 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 2010.

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, 2010, 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, 2011 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	%


⁽¹⁾		Subsidiaries of EnerVest, Ltd., are the general partners of the limited partnership that owns Capital C Energy Operations, L.P. EnerVest, therefore, also may be deemed to be a beneficial owner of the 1,534 shares (100%) of our Common Stock. The address of EnerVest, Ltd., is 1001 Fannin Street, Suite 800, Houston, Texas 77002. EnerVest is a Texas limited partnership. Messrs. John B. Walker, Jon Rex Jones and A.V. Jones by virtue of their direct and indirect ownership of the limited liability company that acts as EnerVest’s general partner, may be deemed to beneficially own the Common Stock beneficially owned by EnerVest. Messrs. Walker, Jon Rex Jones and A.V. Jones disclaim beneficial ownership of such Common Stock. The addresses for Messrs. Walker, Jon Rex Jones and A.V. Jones are the same as for EnerVest.

Equity Compensation Plan Information:

As of March 5, 2011, 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 2009, amounts paid to EnerVest Operating under the terms of the agreement were $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. In 2010, we paid $5.5 million for overhead fees, $5.8 million for field labor, vehicles and district office expense, $98,000 for drilling overhead fees and $886,000 for drilling labor costs.

As of December 31, 2010, we owed EnerVest Operating $634,000 and owed EnerVest $845,000.

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. 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, 2010 was $32.8 million. We borrowed an additional $2.4 million for interest payments against the note in 2010.

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, 2010. 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, 2010 were approved by the audit committee.

Fees paid to Deloitte & Touche LLP are as follows:


	December 31,
	2010		2009
Audit fees (1)	$	361,000	$	352,000
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—

	$	361,000	$	352,000


⁽¹⁾		Represents fees for professional services provided in connection with the audit of our annual financial statements and review of our quarterly financial statements.

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 Corporation’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 Corporation’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 Corporation’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 Corporation’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, incorporated by reference to Exhibit 10.11 to Belden & Blake Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009.

	10.12		Seventh 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 Corporation’s 8-K filed on August 26, 2010.

	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


*		Filed herewith

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	Chief Executive Officer Chairman of	March 28, 2011
Mark A. Houser	the Board of Directors and Director (Principal Executive Officer)	Date

/s/ James M. Vanderhider	President, Chief Financial Officer and Director	March 28, 2011
James M. Vanderhider	(Principal Financial Officer)	Date

/s/ Frederick J. Stair	Vice President of Accounting	March 28, 2011
Frederick J. Stair	(Principal Accounting Officer)	Date

/s/ Kenneth Mariani	Senior Vice President, Chief Operating Officer	March 28, 2011
Kenneth Mariani	and Director	Date

/s/ Matthew Coeny	Director	March 28, 2011
Matthew Coeny		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, 2010 and 2009		F-3

Consolidated Statements of Operations:

Years ended December 31, 2010, 2009 and 2008		F-4

Consolidated Statements of Shareholder’s Equity:

Years ended December 31, 2010, 2009 and 2008		F-5

Consolidated Statements of Cash Flows:

Years Ended December 31, 2010, 2009 and 2008		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.

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder 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, 2010 and 2009, and the related consolidated statements of operations, shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting during 2009 for oil and natural gas reserves and disclosures.

/s/DELOITTE & TOUCHE LLP
Houston, TX
March 28, 2011

F-2

BELDEN & BLAKE CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)


	December 31,
	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	35,941		$	46,740
Accounts receivable (less accumulated provision for doubtful accounts:		9,913			11,821
December 31, 2010 - $452; December 31, 2009 - $393)
Inventories		832			828
Deferred income taxes		4,266			8,272
Other current assets		209			183
Fair value of derivatives		794			413

Total current assets		51,955			68,257

Property and equipment, at cost
Oil and gas properties (successful efforts method)		701,790			684,787
Gas gathering systems		1,239			1,275
Land, buildings, machinery and equipment		2,421			2,566

		705,450			688,628
Less accumulated depreciation, depletion and amortization		179,947			151,208

Property and equipment, net		525,503			537,420
Fair value of derivatives		47			478
Other assets		1,517			1,923

	$	579,022		$	608,078

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	2,120		$	1,696
Accounts payable — related party		1,523			910
Accrued expenses		22,417			16,136
Current portion of long-term liabilities		143			238
Fair value of derivatives		12,141			21,098

Total current liabilities		38,344			40,078

Long-term liabilities
Bank and other long-term debt		23,919			43,929
Senior secured notes		141,056			162,287
Subordinated promissory note — related party		32,846			30,491
Asset retirement obligations and other long-term liabilities		24,637			22,990
Fair value of derivatives		30,201			66,876
Deferred income taxes		140,137			137,286

Total long-term liabilities		392,796			463,859

Shareholder’s equity
Common stock: without par value; 3,000 shares authorized; 1,534 shares issued		—			—
Additional paid in capital		142,500			142,500
Retained earnings (deficit)		10,168			(29,978	)
Accumulated other comprehensive loss		(4,786	)		(8,381	)

Total shareholder’s equity		147,882			104,141

	$	579,022		$	608,078

See accompanying notes.

F-3

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)


	For the Year Ended December 31,
	2010			2009			2008

Revenues
Oil and gas sales	$	60,601		$	61,761		$	145,398
Gas gathering and marketing		5,223			5,894			12,254
Other		556			969			774

		66,380			68,624			158,426

Expenses
Production expense		20,528			20,955			26,342
Production taxes		1,133			1,098			3,054
Gas gathering and marketing		4,988			5,492			10,252
Exploration expense		2,635			3,925			2,543
General and administrative expense		6,805			7,785			8,188
Depreciation, depletion and amortization		29,368			37,046			35,560
Impairment of goodwill		—			—			90,076
Impairment of oil and gas properties		1,565			30,445			3,924
Accretion expense		1,333			1,304			1,412
Gain on sale of assets		(33,644	)		(34,929	)		—
Derivative fair value gain		(32,768	)		(29,631	)		(55,940	)

		1,943			43,490			125,411

Operating income		64,437			25,134			33,015

Other expense (income)
Gain on early extinguishment of debt		(1,006	)		—			—
Interest expense		19,006			20,612			22,818
Other income, net		(92	)		(131	)		(495	)

Income before income taxes		46,529			4,653			10,692
Provision for income taxes		6,383			1,877			39,636

Net income (loss)	$	40,146		$	2,776		$	(28,944	)

See accompanying notes.

F-4

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY

(in thousands)


											Accumulated Other
	Common		Common		Paid in			Retained Earnings			Comprehensive			Total
	Shares		Stock		Capital			(Accumulated Deficit)			Loss			Equity
January 1, 2008		2		—	$	125,000		$	(3,810	)	$	(18,967	)	$	102,223
Comprehensive income (loss):
Net loss									(28,944	)					(28,944	)
Other comprehensive income (loss), net of tax:
Change in derivative fair value												(409	)		(409	)
Reclassification adjustment for derivative (gain) loss reclassified into earnings												6,181			6,181

Total comprehensive loss															(23,172	)
Dividends						(2,500	)		—						(2,500	)

December 31, 2008		2		—	$	122,500		$	(32,754	)	$	(13,195	)	$	76,551
Comprehensive income (loss):
Net income									2,776						2,776
Other comprehensive income (loss), net of tax:
Reclassification adjustment for derivative (gain) loss reclassified into earnings												4,814			4,814

Total comprehensive income									—						7,590
Contributions						20,000			—						20,000

December 31, 2009		2		—	$	142,500		$	(29,978	)	$	(8,381	)	$	104,141
Comprehensive income (loss):
Net income									40,146						40,146
Other comprehensive income (loss), net of tax:
Reclassification adjustment for derivative (gain) loss reclassified into earnings												3,595			3,595

Total comprehensive income															43,741

December 31, 2010		2		—	$	142,500		$	10,168		$	(4,786	)	$	147,882

See accompanying notes.

F-5

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	For the Year			For the Year			For the Year
	Ended			Ended			Ended
	December 31,			December 31,			December 31,
	2010			2009			2008
Cash flows from operating activities:
Net income (loss)	$	40,146		$	2,776		$	(28,944	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		29,368			37,046			35,560
Impairment of goodwill		—			—			90,076
Impairment of oil and gas properties		1,565			30,445			3,924
Gain on early extinguishment of debt		(1,006	)
Accretion expense		1,333			1,304			1,412
Gain on sale of property and equipment		(33,644	)		(34,929	)		—
Amortization of derivatives and other noncash derivative activities		(29,721	)		(24,387	)		(46,064	)
Exploration expense		2,494			2,666			1,974
Deferred income taxes		4,236			771			39,636
Other non-cash expense		2,093			3,197			747
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other current assets		1,882			7,572			(1,135	)
Inventories		(22	)		110			147
Accounts payable and accrued expenses		2			(2,624	)		(630	)


Net cash provided by operating activities		18,726			23,947			96,703

Cash flows from investing activities:
Proceeds from property and equipment disposals		36,688			53,175			3,049
Exploration expense		(2,494	)		(2,666	)		(1,974	)
Additions to property and equipment		(14,234	)		(11,574	)		(28,620	)
(Increase) decrease in other assets		(67	)		(51	)		54


Net cash provided by (used in) investing activities		19,893			38,884			(27,491	)

Cash flows from financing activities:
Debt redetermination costs		(288	)		(1,470	)		—
Payment to shareholder or dividends		—			—			(2,500	)
Capital contributions		—			20,000			—
Settlement of derivative liabilities recorded in purchase accounting		(9,664	)		(1,358	)		(59,901	)
Repayment of Senior Secured Notes		(19,175	)		—			—
Repayment of revolving line of credit		(20,000	)		(56,000	)		—
Repayment of long-term debt and other obligations		(291	)		(79	)		(9	)


Net cash used in financing activities		(49,418	)		(38,907	)		(62,410	)


Net (decrease) increase in cash and equivalents		(10,799	)		23,924			6,802

Cash and cash equivalents at beginning of period		46,740			22,816			16,014


Cash and cash equivalents at end of period	$	35,941		$	46,740		$	22,816

See accompanying notes.

F-6

BELDEN & BLAKE CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Transaction and Merger

Unless the context requires otherwise or unless otherwise noted, when we use the terms “Belden & Blake,” “we,” “us,” “our” or the “Company,” we are referring to Belden & Blake Corporation. On August 16, 2005, the former partners of the direct parent of Belden & Blake Corporation (the “Company”), Capital C Energy Operations, L.P., a Delaware limited partnership (“Capital C”), completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest, Ltd. (“EnerVest”), a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”).

On July 7, 2004, the Company, Capital C and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C (“Merger Sub”), completed a merger pursuant to which Merger Sub was merged with and into the Company (the “Merger”), with the Company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of the Company. The general partner of Capital C was controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P. and Capital C Energy Partners, L.P. until the Transaction on August 16, 2005.

The Transaction and Merger were each accounted for as a purchase effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date.

(2) Business and Significant Accounting Policies

Business

We operate in the oil and gas industry. Our principal business is the exploitation, development, production, operation and acquisition of oil and gas properties. Sales of oil are ultimately made to refineries. Sales of natural gas are ultimately made to gas utilities and industrial consumers in Ohio, Michigan, Pennsylvania and New York. The price of oil and natural gas has a significant impact on our working capital and results of operations.

Principles of Consolidation and Financial Presentation

The accompanying consolidated financial statements include the financial statements of the Company and our wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in the Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts. Significant estimates used in the preparation of our financial statements which could be subject to significant revision in the near term include estimated oil and gas reserves.

F-7

Cash Equivalents

For purposes of the statements of cash flows, cash equivalents are defined as all highly liquid investments purchased with an initial maturity of three months or less.

Concentrations of Credit Risk

Credit limits, ongoing credit evaluation and account monitoring procedures are used to minimize the risk of loss. Collateral is generally not required. Expected losses are provided for currently and actual losses have been within management’s expectations.

Inventories

Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at the lower of average cost or market.

Property and Equipment

We use the “successful efforts” method of accounting for our oil and gas properties. Under this method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry holes and costs of carrying and retaining undeveloped properties, are expensed as incurred. The costs of carrying and retaining undeveloped properties include delay rental payments made on new and existing leases, ad valorem taxes on existing leases and the cost of previously capitalized leases which are written off because the leases were dropped or expired. Exploratory dry hole costs include the costs associated with drilling an exploratory well that has been determined to be a dry hole. The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units—of—production method based on the ratio of current production to estimated total net proved oil and natural gas reserves as estimated by independent petroleum engineers. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold, platform, and pipeline costs. 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. We recorded no impairment to unproved oil and gas properties in 2010 and recorded impairments $3.6 million and $783,000 in 2009 and 2008, respectively, which reduced the book value of certain unproved oil and gas properties to their estimated fair value.

Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.

Land, buildings, machinery 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

F-8

cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. In performing the reviews for long-lived asset recoverability, we recorded impairments of $1.6 million, $26.8 million and $3.1 million in 2010, 2009 and 2008, respectively, which reduced the book value of certain proved properties to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest.

Goodwill and Other Intangible Assets

Under FASB accounting guidance, goodwill and indefinite lived intangible assets are not amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separately identifiable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life).

As described in Note 1, we recorded goodwill associated with the Transaction which resulted in goodwill of $90.1 million at December 31, 2007. In accordance with FASB accounting guidance, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2008, we performed our annual assessment of impairment of the goodwill and determined that there was no impairment. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $90.1 million due to the significant drop in oil and gas prices. There is no Goodwill as of December 31, 2010, or 2009.

At December 31, 2010 and 2009, we had $762,000 and $1.2 million, respectively, of deferred debt issuance costs. Deferred debt issuance costs are being amortized over their respective terms. Amortization expense related to deferred debt issuance costs was $761,000 in 2010, $936,000 in 2009 and $424,000 in 2008. At December 31, 2010, the amortization of deferred debt issuance costs in the next five years is as follows: $569,000 in 2011, $193,000 in 2012 and none in 2013, 2014 or 2015.

Revenue Recognition

Income Taxes

We use the asset and liability method of accounting for income taxes under FASB accounting guidance. Deferred income taxes are provided for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred income taxes also are recognized for operating losses that are available to offset future taxable income and tax credits that are available to offset future federal income taxes. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the benefits will not be realized.

F-9

Derivatives and Hedging

In accordance with FASB accounting guidance, we recognize all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that do not qualify or are not designated as cash flow hedges are adjusted to fair value through net income (loss). Under FASB accounting guidance, changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions impact earnings. If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately. See Note 6.

The relationship between the hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk, both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.

Asset Retirement Obligations

We follow FASB accounting guidance which requires us to recognize a liability for the fair value of its asset retirement obligations associated with our tangible, long-lived assets. The majority of our asset retirement obligations relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties. There has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows.

F-10

A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2010 and 2009 is as follows (in thousands):


	Year Ended			Year Ended
	December 31,			December 31,
	2010			2009
Beginning asset retirement obligations	$	23,083		$	23,885
Liabilities incurred		121			9
Liabilities settled		(187	)		(2,115	)
Accretion expense		1,333			1,304
Revisions in estimated cash flows		351			—

Ending asset retirement obligations	$	24,701		$	23,083

As of December 31, 2010 and 2009, $133,000 and $229,000, respectively, of our ARO liability is classified as current.

(3) New Accounting Pronouncements

No other new accounting pronouncements issued or effective during the year ended December 31, 2010 have had or are expected to have a material impact on our consolidated financial statements.

F-11

(4) Acquisitions

In the fourth quarter of 2010, we acquired additional working interest in our wells in Michigan for approximately $4.4 million.

(5) Dispositions

On July 1, 2010, we sold a 50% — 75% interest in certain unproved undeveloped acreage in Ohio for $6.1 million and recorded a gain on the sale of $5.3 million.

On June 14, 2010, we sold certain developed and undeveloped oil and gas properties in Pennsylvania for $30.6 million and recorded a gain on the sale of $28.5 million.

In November 2009, we sold undeveloped acreage in Bradford County, Pennsylvania for $35.8 million. We recorded a gain of $34.9 million on the sale.

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

In March, 2008, we sold a 50% — 70% option interest in certain deep rights on approximately 201,000 net acres in Ohio and Pennsylvania for $3.0 million.

(6) Derivatives and Hedging

From time to time, we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas price, crude oil price or interest rate volatility and to support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At December 31, 2010, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that we believe are a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges. The effective portion of changes in fair value of the derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time the hedged items impact earnings. The changes in fair value of non-qualifying derivative contracts will be reported in the consolidated statements of operations as derivative fair value (gain) loss. As of December 31, 2010 and 2009, all derivatives were accounted for as mark to market.

F-12

During 2010 and 2009, net losses of $6.1 million ($3.6 million after tax) and $7.9 million ($4.8 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. At December 31, 2010, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $2.4 million after tax. At December 31, 2010, we have partially reduced our exposure to the variability in future cash flows through December 2013.

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial derivatives (including settled contracts) at December 31, 2010:


	Natural Gas Swaps				Crude Oil Swaps
			NYMEX				NYMEX		Natural Gas Basis Swaps
			Price per				Price per				Basis
Year Ending	Bbtu		MMbtu		MBbls		Bbl		Bbtu		Differential
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, 2010, we had interest rate swaps in place on $23.5 million of our outstanding debt under the revolving credit facility through September 30, 2013. The swaps provide 1-month LIBOR fixed rates at 4.10% on $23.5 million through September 2013, plus the applicable margin. These interest rate swaps do not qualify for hedge accounting, therefore, all changes in the fair value of these swaps are recorded in derivative fair value gain/loss. At December 31, 2010, the fair value of the interest rate swap represented an unrealized loss of $1.8 million.

At December 31, 2010, the fair value of these derivatives was as follows (in thousands):


	Asset Derivatives				Liability Derivatives
	December 31, 2010		December 31, 2009		December 31, 2010			December 31, 2009
Oil and natural gas commodity contracts	$	841	$	864	$	(40,560	)	$	(85,593	)
Interest rate swaps		—		27		(1,782	)		(2,381	)

Total fair value	$	841	$	891	$	(42,342	)	$	(87,974	)


Location of derivatives in our consolidated balance sheets:
Derivative asset	$	794	$	413	$	—		$	—
Long—term derivative asset		47		478		—			—
Derivative liability		—		—		(12,141	)		(21,098	)
Long—term derivative liability		—		—		(30,201	)		(66,876	)

	$	841	$	891	$	(42,342	)	$	(87,974	)

The net amount due under these derivative contracts may become due and payable if our Credit Agreement or our senior secured notes become due and payable due to an event of default.

F-13

The following table presents the impact of derivatives and their location within the statements of operations (in thousands):


	For the year ended
	December 31,
	2010			2009			2008
The following amounts are recorded in Oil and gas sales:
Unrealized losses:
Oil and natural gas commodity contracts reclassified into earnings	$	(6,129	)	$	(7,893	)	$	(9,163	)


The following amounts are recorded in Interest expense:
Realized losses:
Interest rate swaps	$	—		$	—		$	1,009


The following are recorded in Derivative fair value (gain) loss:
Unrealized (gains) losses:
Oil and natural gas commodity contracts	$	(44,858	)	$	(32,437	)	$	(118,210	)
Interest rate swaps		(571	)		(1,189	)		3,044

Total		(45,429	)		(33,626	)		(115,166	)

Realized (gains) losses:
Oil and natural gas commodity contracts		9,318			1,438			58,956
Interest rate swaps		3,343			2,557			270

Total		12,661			3,995			59,226

Derivative fair value gain	$	(32,768	)	$	(29,631	)	$	(55,940	)

F-14

(7) Details of Balance Sheets


	December 31,
(in thousands)	2010			2009
Accounts receivable
Accounts receivable	$	2,470		$	3,022
Allowance for doubtful accounts		(452	)		(393	)
Oil and gas production receivable		7,895			9,192

	$	9,913		$	11,821


Inventories
Oil	$	606		$	602
Natural gas		—			—
Material, pipe and supplies		226			226

	$	832		$	828


Property and equipment, gross oil and gas properties
Producing properties	$	645,415		$	622,941
Non-producing properties
Proved		48,899			52,428
Unproved		7,476			9,418
Other		—			—

	$	701,790		$	684,787


Land, buildings, machinery and equipment
Land, buildings and improvements	$	837		$	837
Machinery and equipment		1,584			1,729

	$	2,421		$	2,566


Accrued expenses
Accrued interest expense	$	5,557		$	6,397
Accrued other expenses		3,186			3,022
Accrued general and administrative expense		1,827			1,576
Accrued lease operating expense		1,595			1,224
Accrued drilling and completion costs		7,608			273
Accrued income taxes		633			—
Ad valorem and other taxes		567			702
Undistributed production revenue		1,444			2,942

	$	22,417		$	16,136

F-15

(8) Long-Term Debt

Long-term debt consists of the following (in thousands):


	December 31,
	2010		2009
Senior secured notes	$	139,475	$	159,475
Bank revolving credit facility		23,876		43,876
Subordinated promissory note (related party)		32,846		30,491
Other		53		62

		196,250		233,904

Less current portion		10		9

Long-term debt		196,240		233,895
Fair value adjustment — senior secured notes		1,581		2,812

	$	197,821	$	236,707

Senior Secured Notes due 2012

We had $139.5 million and $159.5 million of our Senior Secured Notes outstanding as of December 31, 2010 and 2009, respectively. On September 2, 2010, we repurchased a portion of the outstanding senior secured notes. The repurchased notes had a face value of $20.0 million and were repurchased at 95.875. A gain of $1.0 million was recorded in connection with the transaction. As a result of the application of purchase accounting, the Senior Secured Notes were recorded as a liability based on the estimated fair value of $200.7 million on the Transaction date. Subsequent accretion of the premium and repurchase of bonds reduced this amount to $141.1 million at December 31, 2010.

The fair value adjustment of $1.6 million is shown separately in the table above. The accretion of $1.0 million was recorded as a reduction of interest expense in 2009 and 2010. The Senior Secured Notes mature July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year at 8.75% based on the face amount of $139.5 million (for an effective rate of 7.946% based on the fair value on the Transaction date). The Senior Secured Notes are secured on a second-priority lien on the same assets subject to the liens securing our obligations under the Credit Agreement. The Senior Secured Notes are subject to redemption at our option at specific redemption prices.


July 15, 2010 and thereafter			100.000	%

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 (“Credit Agreement”) by and among the Company and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Credit Agreement provides for loans and other extensions of credit to be made to us. The

F-16

obligations under the Credit Agreement are secured by substantially all of our assets. J.P. Morgan Chase and Amegy Bank were added to the bank group in September 2005.

The Credit Agreement provides for a revolving credit line in the aggregate principal amount of $90 million and a hedge letter of credit facility in the aggregate principal amount of $40 million. At December 31, 2010, the borrowing base was $55 million. The outstanding balance at December 31, 2010 was $23.9 million. The full amount borrowed under the Credit Agreement will mature on April 14, 2012.

The Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase our stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The 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, 2010, we were in compliance with such financial covenants under the Credit Agreement. Our senior secured leverage ratio was 0.80 : 1.0 and the interest coverage ratio was 1.78 : 1.0.

F-17

In connection with our entry into the Credit Agreement, we executed a Subordinated Promissory Note (“Subordinated Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. The Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Subordinated Note made on August 16, 2005. Interest payments on the Subordinated Note are due quarterly. 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. We made cash payments of $2.0 million and borrowed an additional $677,000 against the Subordinated Note for interest payments in 2008. We made no cash payments in 2009 and borrowed an additional $2.9 million against the Subordinated Note. In 2010, we made cash interest payments of $752,000 and borrowed an additional $2.4 million 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, future 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 Credit Agreement, the J. Aron Swap and the Senior Secured Notes.

ISDA Master Agreement

We amended and restated the Schedule and Credit Support Annex to our ISDA Master Agreement, dated as of June 30, 2004, by and between us and J. Aron & Company (“J. Aron Swap”), pursuant to which we have agreed, from time to time, to enter into cash-settled hedge transactions with J. Aron & Company, as hedge counterparty, in connection with various gas and oil commodity derivatives transactions. The amendments to the J. Aron Swap conform the terms of the Schedule and Credit Support Annex to the terms of the 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.

F-18

(9) Leases

We lease natural gas compressors under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $2.8 million in 2010, $3.0 million in 2009 and $3.8 million in 2008.

Future minimum commitments under leasing arrangements as of December 31, 2010 were as follows:


	Operating
As of December 31, 2010	Leases
	(in thousands)
2011	$	210
2012		38
2013		—
2014		—
2015 and thereafter		—

Total minimum rental payments	$	248

(10) Goodwill

(11) Impairment of Proved Oil and Gas Properties

For the years ended December 31, 2010 and 2009, we reviewed our oil and gas properties for impairment as prescribed by FASB accounting guidance. In 2010, a result of this evaluation, an impairment of $1.6 million was recorded to proved properties in the Oriskany formation in Pennsylvania. In 2009, as a result of this evaluation, an impairment of $26.8 million was recorded to proved properties in the coalbed methane formation in Pennsylvania and the Marcellus shale formation in Pennsylvania. We recorded an impairment of $2.0 million during 2008 to proved properties in the Utica Shale formation in Ohio.

F-19

(12) Taxes

The provision (benefit) for income taxes on income from continuing operations before cumulative effect of change in accounting principle includes the following (in thousands):


	For the year			For the year		For the year
	ended			ended		ended
	December 31,			December 31,		December 31,
	2010			2009		2008

Current
Federal	$	380		$	849	$	—
State		1,767			—		—

		2,147			849		—

Deferred
Federal		15,637			813		35,076
State		(11,401	)		215		4,560

		4,236			1,028		39,636

Total	$	6,383		$	1,877	$	39,636

The effective tax rate for income from continuing operations differs from the U.S. federal statutory tax rate as follows:


	For the year			For the year			For the year
	ended			ended			ended
	December 31,			December 31,			December 31,
	2010			2009			2008

Statutory federal income tax rate		35.0	%		35.0	%		35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal tax benefit		4.3			4.6			4.6
Permanent differences related to goodwill impairment		—			—			333.1
Reduction in valuation allowance (1)		(11.0	)		—			—
Reduction in state tax rate (2)		(14.7	)		—			—
Other, net		0.1			0.7			(2.0	)

Effective income tax rate for the period		13.7	%		40.3	%		370.7	%


(1)		The decrease was due to a reduction of the state tax valuation allowance. The valuation allowance was reduced upon the realization of state tax net operating loss carryforwards, which resulted from taxable gains on asset sales.

(2)		The decrease in the state tax rate was due to the elimination of the state of Ohio corporate income tax. The Ohio corporate income tax was replaced with a Commercial Activity Tax which is not considered an income tax.

Changes in the effective state tax rate due to changes in the state apportionment rates are included in state income taxes, net of federal income tax benefit.

F-20

Significant components of deferred income tax liabilities and assets are as follows (in thousands):


	December 31,			December 31,
	2010			2009
Deferred income tax liabilities:
Property and equipment, net	$	183,949		$	190,088
Other, net		276			2,732

Total deferred income tax liabilities		184,225			192,820
Deferred income tax assets:
Accrued expenses		881			881
Asset retirement obligations		9,529			9,098
Fair value of derivatives		26,072			43,420
Net operating loss carryforwards		8,308			15,444
Senior Secured Notes		1,133			2,913
Tax credit carryforwards		3,003			2,623
Other, net		1,787			903
Valuation allowance		(2,359	)		(11,476	)

Total deferred income tax assets		48,354			63,806

Net deferred income tax liability	$	135,871		$	129,014


Long-term liability	$	140,137		$	137,286
Current asset		(4,266	)		(8,272	)

Net deferred income tax liability	$	135,871		$	129,014

At December 31, 2010, we had approximately $17.0 million of net operating loss carryforwards available for federal income tax reporting purposes. These net operating loss carryforwards, if unused, will expire in 2019 through 2025. We also had state net operating losses aggregating $36.3 million, which expire between 2010 and 2025. The net operating losses are subject to annual limitations due to IRC Section 382 as a result of the Merger in 2004 and the Transaction in 2005. FASB accounting guidance requires a valuation allowance to be recorded when it is more likely than not that some or all of the deferred tax assets will not be realized. We do not believe the application of Section 382 hinders our ability to utilize the federal net operating losses and, accordingly, no valuation allowance has been recorded. The valuation allowance of $2.4 million relates to certain state net operating loss carryforwards which we estimate would expire before they could be used. We have alternative minimum tax credit carryforwards of approximately $3.0 million, which have no expiration date.

FASB accounting guidance requires us to evaluate whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions taken by us are supportable by existing laws and related interpretations, there are no material uncertain tax positions to consider in accordance with FASB accounting guidance.

(13) Commitments and Contingencies

The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows.

F-21

(14) Supplemental Disclosure of Cash Flow Information


	For the year			For the year			For the year
	ended			ended			ended
	December 31,			December 31,			December 31,
(in thousands)	2010			2009			2008
Cash paid during the period for:
Interest	$	17,784		$	17,909		$	22,764
Income taxes, net of refunds		1,494			1,100			—
Non-cash investing and financing activities:
Non-cash additions to property and equipment		(7,608	)		(273	)		(1,728	)
Non-cash additions to debt		(2,355	)		(2,868	)		(692	)

(15) Fair Value of Financial Instruments

The fair value of the financial instruments disclosed herein is not representative of the amount that could be realized or settled, nor does the fair value amount consider the tax consequences, if any, of realization or settlement. The amounts in the financial statements for cash equivalents and accounts receivable approximate fair value due to the short maturities of these instruments. The recorded amounts of outstanding bank and other long-term debt approximate fair value because interest rates are based on LIBOR or the prime rate or due to the short maturities. The $139.5 million (face amount) of our Senior Secured Notes due 2012 had an approximate fair value of $135.3 million at December 31, 2010 based on quoted market prices.

From time to time, we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas or oil price volatility. We employ a policy of hedging gas production sold under NYMEX-based contracts by selling NYMEX-based commodity derivative contracts. Our NYMEX crude oil swaps are sold locally at posted price which is different from the NYMEX price. Historically there has been a high correlation between the posted price and NYMEX. The contracts may take the form of futures contracts, swaps, collars or options which are placed with major financial institutions that we believe are minimal credit risks. At December 31, 2008, our derivative contracts consisted of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps. At December 31, 2010, the fair value of futures contracts covering 2011 through 2013 oil and gas production represented an unrealized loss of $39.7 million. At December 31, 2010, the fair value of our interest rate futures contracts covering 2011 through September 2013 represented an unrealized loss of $1.8 million.

F-22

(16) Fair Value Measurements

Recurring Basis

The following table presents the fair value hierarchy table for our assets and liabilities that are required to be measured at fair value on a recurring basis (in thousands):


				Fair Value Measurements Using:
				Quoted Prices in		Significant
				Active Markets		Other			Significant
				for Identical		Observable			Unobservable
				Assets		Inputs			Inputs
	Total Carrying Value			(Level 1)		(Level 2)			(Level 3)
At December 31, 2010:
Commodity contracts	$	(39,719	)	$	—	$	(39,719	)	$	—
Interest rate swaps		(1,782	)	$	—		(1,782	)	$	—
Total derivative liabilities	$	(41,501	)	$	—	$	(41,501	)	$	—
At December 31, 2009:
Commodity contracts	$	(84,729	)		—	$	(84,729	)		—
Interest rate swaps		(2,354	)	$	—		(2,354	)	$	—
Total derivative liabilities	$	(87,083	)		—	$	(87,083	)		—

Our derivative instruments consist of over—the—counter (“OTC”) contracts which are not traded on a public exchange. These derivative instruments are indexed to active trading hubs for the underlying commodity, and are OTC contracts commonly used in the energy industry and offered by a number of financial institutions and large energy companies.

As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2. We value these derivatives based on observable market data for similar instruments. This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data. Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs in the year ended December 31, 2010.

Nonrecurring Basis

Proved oil and gas properties with a carrying amount of $45.5 million were written down to their fair value of $18.7 million, resulting in a pretax impairment charge of $26.8 million for the year ended December 31, 2009. In 2010, proved oil and gas properties with a carrying amount of $2.2 million were written down to their fair value of $615,000, resulting in a pretax impairment charge of $1.6 million. Significant Level 3 assumptions associated with the calculation of discontinued cash flows used in the impairment analysis include our estimate of future gas and oil prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk adjusted discount rates and other relevant data.

F-23

(17) Supplementary Information on Oil and Gas Activities (Unaudited)

The following disclosures of costs incurred related to oil and gas activities from continuing operations are presented in accordance with FASB accounting guidance.


	December 31,		December 31,		December 31,
(in thousands)	2010		2009		2008
Acquisition costs:
Proved properties	$	4,349	$	—	$	1,504
Unproved properties		634		1,282		802
Developmental costs		16,386		8,357		26,845
Exploratory costs		2,635		3,925		2,543

	$	24,004	$	13,564	$	31,694

Capitalized costs relating to oil and natural gas producing activities are as follows.


	December 31,			December 31,
(in thousands)	2010			2009
Proved oil and natural gas properties	$	694,314		$	675,371
Unproved oil and natural gas properties		7,476			9,418

		701,790			684,789
Accumulated depreciation, depletion and amortization		(178,057	)		(149,442	)

Net capitalized costs	$	523,733		$	535,347

Estimated Proved Oil and Gas Reserves (Unaudited)

Our estimated proved developed and estimated proved undeveloped reserves are all located within the United States. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Estimated proved developed reserves are estimated proved reserves expected to be recovered through wells and equipment in place and under operating methods being used at the time the estimates were made. The estimates of proved reserves as of December 31, 2010, 2009 and 2008 have been prepared by Wright & Company, Inc., independent petroleum consultants.

F-24

The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated:


	Oil			Gas
	(MBbl)			(MMcf)			MMcfe
January 1, 2008		5,149			227,200			258,094
Extensions and discoveries		78			6,415			6,883
Purchase of reserves in place		22			61			193
Revisions of previous estimates		(1,082	)		(20,625	)		(27,117	)
Production		(334	)		(13,217	)		(15,221	)

December 31, 2008		3,833			199,834			222,832
Extensions and discoveries		145			2,242			3,112
Purchase of reserves in place		—			—			—
Divestiture of reserves		—			(17,753	)		(17,753	)
Revisions of previous estimates		794			(9,314	)		(4,550	)
Production		(324	)		(12,034	)		(13,978	)

December 31, 2009		4,448			162,975			189,663
Extensions and discoveries		155			3,408			4,338
Purchase of reserves in place		—			4,670			4,670
Divestiture of reserves		—			(230	)		(230	)
Revisions of previous estimates		801			10,872			15,678
Production		(272	)		(10,109	)		(11,741	)

December 31, 2010		5,132			171,586			202,378


Proved developed reserves
December 31, 2008		3,559			176,340			197,694

December 31, 2009		3,438			151,995			172,623

December 31, 2010		4,091			157,150			181,696

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following tables present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil, natural gas and natural gas liquids reserves. In computing this data, assumptions other than those required by the SEC could produce different results. Accordingly, the data should not be construed as representative of the fair market value of our estimated proved oil, natural gas and natural gas liquids reserves. The following assumptions have been made:

•

Future cash inflows were based on prices used in estimating our proved oil, natural gas and natural gas liquids reserves. Future price changes were included only to the extent provided by existing contractual agreements.

•

Future development and production costs were computed using year end costs assuming no change in present economic conditions.

F-25

•

Future net cash flows were discounted at an annual rate of 10%.

•

Future income taxes were computed using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion.

The standardized measure of discounted future net cash flows relating to estimated proved oil and gas reserves is presented below:


	December 31,
	2010			2009			2008
	(in thousands)
Estimated future cash inflows (outflows)
Revenues from the sale of oil and gas	$	1,200,350		$	958,416		$	1,431,631
Production costs		(414,615	)		(388,247	)		(534,167	)
Development costs		(57,102	)		(47,016	)		(57,491	)
Future income taxes		(236,479	)		(148,529	)		(262,865	)

Future net cash flows		492,154			374,624			577,108
10% timing discount		(292,549	)		(207,813	)		(324,433	)

Standardized measure of discounted future net cash flows	$	199,605		$	166,811		$	252,675

The following table sets forth the weighted average prices 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,
	2010		2009		2008
Gas (per Mcf)	$	4.76	$	4.34	$	6.38
Oil (per Bbl)		74.63		56.33		41.00

F-26

The principal sources of changes in the standardized measure of future net cash flows are as follows:


	Year ended			Year ended			Year ended
	December 31,			December 31,			December 31,
	2010			2009			2008
Beginning of year	$	166,811		$	252,675		$	388,886
Sale of oil and gas, net of production costs		(45,069	)		(47,601	)		(125,165	)
Extensions and discoveries, less related estimated future development and production costs		10,261			3,797			9,514
Previously estimated development costs incurred during the period		3,954			—			26,845
Purchase of reserves in place less estimated future production costs		5,811			—			643
Sale of reserves in place less estimated future production costs		(240	)		(19,988	)		—
Changes in estimated future development costs		5,404			751			31,949
Revisions of previous quantity estimates		24,138			(7,374	)		(47,442	)
Net changes in prices and production costs		77,748			(79,091	)		(195,400	)
Change in income taxes		(51,285	)		47,752			101,046
Accretion of 10% timing discount		19,366			31,253			38,889
Changes in production rates (timing) and other		(17,294	)		(15,363	)		22,910

End of period	$	199,605		$	166,811		$	252,675

(18) Industry Segment Financial Information

We operate in one reportable segment, as an independent energy company engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. Our operations are conducted entirely in the United States.

Major Customers

During 2010, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $14.9 million, $11.1 million and $10.9 million, respectively. During 2009, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $14.4 million, $14.3 million and $13.3 million, respectively. During 2008, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $32.3 million, $30.7 million and $22.9 million, respectively. 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.

F-27

(19) Quarterly Results of Operations (Unaudited)

The results of operations for the four quarters of 2010 and 2009 are shown below (in thousands).


	First			Second			Third			Fourth

2010
Operating revenues	$	17,417		$	17,034		$	16,599		$	15,331
Gross profit		2,571			3,041			2,380			(820	)
Net income (loss)		19,100			15,487			8,150			(2,591	)

2009
Operating revenues	$	17,110		$	17,367		$	17,022		$	17,125
Gross profit		(2,202	)		(74	)		117			1,298
Net income (loss)		13,242			(26,366	)		(3,616	)		19,516

(20) Related Party Transactions

On March 15, 2006, we entered into a joint operating agreement with EnerVest Operating, L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. The joint operating agreement was effective October 1, 2005 and resulted in expense to us of $6.6 million in 2008, $6.1 million in 2009 and $5.5 million in 2010 for overhead fees. We also paid $7.1 million in 2008, $5.9 million in 2009 and $5.8 million in 2010 for field labor, vehicles and district office expense; $265,000 in 2008, $82,000 in 2009 and $98,000 in 2010 for drilling overhead fees and $1.0 million in 2008, $1.2 million in 2009 and $886,000 in 2010 for drilling labor costs related to this agreement.

As of December 31, 2010, we owed EnerVest Operating $634,000 and owed EnerVest $845,000.

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. 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, 2010 was $32.8 million. In 2008, we made cash payments of $2.0 million and borrowed and additional $677,000 against the note for interest payments. In 2009, we borrowed $2.9 million against the note for interest payments. In 2010, we made cash interest payments of $752,000 and borrowed an additional $2.4 million against the note.

Messrs. Houser, Vanderhider and Mariani are officers and directors of the Company and they are officers and equity owners of EnerVest and EnerVest Operating. The institutional funds that are managed by EnerVest and own our direct parent, Capital C, also hold other investments in oil and gas assets and operations. We can give no assurance that conflicts of interest will not arise for corporate opportunities. Also, we can give no assurance that conflicts will not arise with respect to the time and attention devoted to us by Messrs. Houser, Vanderhider and Mariani.

F-28

(21) Subsequent Events

The company has determined that there are no subsequent events which require recognition or disclosure in these consolidated financial statements through the date the statements were issued.

F-29

BELDEN & BLAKE CORPORATION

March 28, 2011

/s/ Mark A. Houser

Mark A. Houser, Chief Executive Officer, Chairman

of the Board of Directors and Director

BELDEN & BLAKE CORP /OH/ 10-K