~~Table~~UNITED ofSTATES ~~Contents~~SECURITIES AND EXCHANGE COMMISSION

~~UNITED~~Washington, ~~STATES~~D.C. ~~SECURITIES AND EXCHANGE COMMISSION~~20549

~~Washington,~~FORM ~~D.C. 20549~~10-K

~~FORM~~þ ~~10-K~~ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

þFor ~~ANNUAL~~the ~~REPORT~~Fiscal ~~PURSUANT~~Year TOEnded ~~SECTION~~December 31, ~~13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~2010

~~For the Fiscal Year Ended December 31, 2009~~OR

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

oCommission ~~TRANSITION~~File ~~REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~No. 0-20100

~~Commission~~BELDEN ~~File~~& ~~No. 0-20100~~BLAKE CORPORATION

~~BELDEN~~ (Exact &name ~~BLAKE~~of ~~CORPORATION~~ registrant as specified in its charter)

Ohio (~~Exact~~State ~~name~~or other jurisdiction of ~~registrant~~incorporation asor ~~specified~~organization) in34-1686642 ~~its~~(I.R.S. ~~charter~~Employer Identification Number)

~~Ohio~~1001 ~~(State~~Fannin orStreet, ~~other~~Suite 800 Houston, ~~jurisdiction~~Texas 77002 (Address of ~~incorporation~~principal orexecutive ~~organization~~offices) ~~34-1686642~~ (~~I.R.S.~~Zip ~~Employer Identification Number~~Code)

~~1001~~Registrant’s ~~Fannin~~telephone ~~Street~~number, ~~Suite~~including area code: (713) ~~800~~659-3500 ~~Houston,~~Securities ~~Texas~~registered ~~77002~~ pursuant to Section 12(~~Address~~b) of ~~principal~~the ~~executive~~Act: ~~offices)~~None Securities ~~(Zip~~registered ~~Code~~pursuant to Section 12(g) of the Act: None

~~Registrant’s~~Indicate ~~telephone~~by ~~number,~~check ~~including~~mark ~~area~~if ~~code:~~the ~~(713) 659-3500 Securities~~registrant ~~registered~~is ~~pursuant~~a towell-known ~~Section 12(b)~~seasoned ofissuer, ~~the~~as ~~Act:~~defined ~~None~~in ~~Securities registered pursuant to Section~~Rule ~~12(g)~~405 of the Securities Act:. ~~None~~Yes o No þ

Indicate by check mark if the registrant is anot ~~well-known~~required ~~seasoned~~to ~~issuer,~~file asreports ~~defined in~~pursuant ~~Rule~~to Section ~~405~~13 or Section 15(d) of the ~~Securities~~ Act. Yes oþ No þo

Indicate by check mark ifwhether the registrant is(1) has ~~not~~filed all reports required to be ~~file~~filed ~~reports~~by ~~pursuant to~~ Section 13 or ~~Section~~ 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 bywith a check mark whether the registrant ~~(1)~~ has ~~filed~~submitted ~~all~~electronically ~~reports~~and ~~required~~posted toon beits ~~filed~~corporate byWeb ~~Section 13~~site, orif ~~15(d)~~any, ofevery ~~the~~Interactive ~~Securities~~Data ~~Exchange~~File ~~Act~~required to be submitted and posted pursuant to Rule 405 of ~~1934~~regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to ~~file~~submit ~~such reports),~~ and ~~(2) has~~post ~~been subject to~~ such ~~filing requirements for the past 90 days~~files). o Yes þo No o

Indicate ~~with~~by a check mark ~~whether~~if ~~the~~disclosure ~~registrant~~of ~~has~~delinquent ~~submitted~~filers ~~electronically~~pursuant ~~and~~to ~~posted~~Item 405 onof Regulation ~~its~~S-K ~~corporate~~is ~~Web~~not ~~site,~~contained ~~if any~~herein, ~~every~~and ~~Interactive~~will ~~Data~~not ~~File~~be ~~required~~contained, to bethe ~~submitted~~best ~~and~~of ~~posted~~registrant’s knowledge, in ~~pursuant~~definitive toproxy ~~Rule 405~~or ofinformation ~~regulation~~statements ~~S-T~~incorporated ~~during~~by ~~the~~reference ~~preceding~~in 12Part ~~months~~III ~~(or~~of ~~for~~this ~~such~~Form ~~shorter period~~10-K ~~that~~or ~~the~~any ~~registrant~~amendment ~~was required~~ to ~~submit~~this ~~and~~Form ~~post such files)~~10-K. ~~Yes~~ ~~o No o~~þ

Indicate by check mark ifwhether ~~disclosure~~the ofregistrant ~~delinquent~~is ~~filers~~a ~~pursuant~~large toaccelerated ~~Item 405~~filer, ofan ~~Regulation~~accelerated ~~S-K~~filer, isa ~~not~~non-accelerated ~~contained herein~~filer, ~~and~~or ~~will~~a ~~not~~smaller bereporting ~~contained,~~company. toSee ~~the~~definition ~~best~~ of ~~registrant’s~~“large accelerated ~~knowledge~~filer”, ~~in definitive~~“accelerated ~~proxy~~filer” orand ~~information~~“smaller ~~statements~~reporting ~~incorporated~~company” ~~by reference~~ in ~~Part~~Rule ~~III~~12b-2 of ~~this Form 10-K~~the orExchange ~~any amendment to this Form 10-K~~Act. þ(Check one):

~~Indicate~~Large ~~by check mark whether the registrant is a large~~ accelerated filer, ano ~~accelerated~~ Accelerated filer, ao ~~non~~Non-accelerated filer, orþ aSmaller ~~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):~~ o

~~Large~~Indicate ~~accelerated~~by ~~filer~~check omark ~~Accelerated~~whether ~~filer~~the oregistrant ~~Non-accelerated~~is ~~filer~~a þshell ~~Smaller~~company ~~reporting~~(as ~~company~~defined in Rule 12b-2 of the Exchange Act). Yes o No þ

~~Indicate~~As byof ~~check~~February 28, ~~mark~~2011, ~~whether~~Belden ~~the~~& ~~registrant~~Blake Corporation had outstanding 1,534 shares of common stock, no par value, which is aits ~~shell~~only ~~company~~class ~~(as~~of ~~defined~~stock. inThe ~~Rule 12b-2~~common stock of Belden & Blake Corporation is not traded on any exchange and, therefore, its aggregate market value and the ~~Exchange~~value of ~~Act).~~shares held by non-affiliates cannot be determined as of the last business day of the ~~Yes~~registrant’s omost Norecently þcompleted second fiscal quarter.

AsDOCUMENTS ofINCORPORATED ~~February 28,~~BY ~~2010, Belden & Blake Corporation had outstanding 1,534 shares of common~~REFERENCE: stock, no par value, which is its only class of stock. The common stock of Belden & Blake Corporation is not traded on any exchange and, therefore, its aggregate market value and the value of shares held by non-affiliates cannot be determined as of the last business day of the registrant’s most recently completed second fiscal quarter.

~~Table of Contents~~None.

~~DOCUMENTS~~References ~~INCORPORATED~~in BYthis ~~REFERENCE:~~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.

~~None.~~Forward-Looking Statements

~~References~~This inForm 10-K ~~this~~contains ~~Annual~~forward—looking ~~report~~statements onwithin ~~Form~~the ~~10-K~~meaning toof ~~“Belden~~Section 27A &of ~~Blake~~the Securities Act of 1933,” ~~“the~~as ~~Company~~amended,” and Section 21E of the Exchange Act (each a “~~we,”~~forward—looking ~~“ours,~~statement”). ~~“us”~~These orforward—looking ~~like~~statements ~~terms~~relate ~~refer~~ to, ~~Belden~~among &other ~~Blake~~things, ~~Corporation~~the ~~and its subsidiaries.~~following:

~~Forward-Looking~~• ~~Statements~~ 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.

~~The~~We ~~information~~have inbased this document includes forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements “should,” “believe,” “expect,” “anticipate,” “intend,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “could” and variations of these ~~statements and similar expressions are~~ forward-—looking statements ason ~~are~~our ~~any~~current ~~other statements relating to developments~~assumptions, ~~events, occurrences, results, efforts or impacts. These forward-looking statements are based on current~~ expectations and projections about future events. ~~Forward-looking statements, and the business~~ prospects of Belden & Blake are subject to a number of risks and uncertainties which may cause our actual results in future periods to differ materially from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, our access to capital, the market demand for and prices of oil and natural gas, our oil and gas production and costs of operation, results of our future drilling activities, the uncertainties of reserve estimates, general economic conditions, including the financial and capital market crisis, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described on page 15 under the Heading “Risk Factors” and in our other filings with the Securities and Exchange Commission (“SEC”). We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changes in assumptions, or otherwise.

1The 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:

~~Table~~• fluctuations in prices of ~~Contents~~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;

~~GLOSSARY OF OIL AND NATURAL GAS TERMS~~1

~~Bbl.~~• ~~One~~competition; ~~stock~~• ~~tank~~general ~~barrel~~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 42not 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. ~~gallons~~dollar ~~liquid~~in ~~volume~~international currency markets; and • our ability to effectively integrate companies and properties that we acquire.

~~Bcf~~All of our forward—looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. ~~One~~Although ~~billion~~it ~~cubic~~is ~~feet~~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.

~~Bcfe~~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. ~~One~~Declines ~~billion~~in oil ~~cubic~~or ~~feet~~natural ~~equivalent~~gas prices may materially adversely affect our financial condition, ~~determined~~liquidity, ability ~~using~~to aobtain ~~ratio~~financing and operating results. Lower oil or natural gas prices also may reduce the amount of ~~six~~oil ~~Mcf~~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 ~~one~~fund our operations and our financial condition, ~~Bbl~~cash flows, results of ~~oil~~operations and access to capital. Historically, ~~condensate~~oil orand natural gas ~~liquids~~prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

~~Btu. A British thermal unit is a measurement of the heat generating capacity of natural gas. One~~2 ~~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.~~GLOSSARY ~~Installation~~OF ofOIL ~~permanent~~AND ~~equipment~~NATURAL ~~for~~GAS ~~production of oil or gas, or, in the case of a~~TERMS ~~dry well, to reporting to the appropriate authority that the well has been abandoned.~~

~~Condensate~~Bbl. AOne ~~mixture~~stock oftank ~~hydrocarbons~~barrel ~~that~~or ~~exists~~42 inU.S. ~~the~~gallons ~~gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the~~ liquid ~~phase at surface pressure and temperature~~volume.

~~Developed oil and gas reserves~~Bcf. ~~Reserves~~One ofbillion ~~any~~cubic ~~category that can be expected to be recovered:~~feet.

•Bcfe. ~~through~~One ~~existing~~billion ~~wells~~cubic ~~with~~feet ~~existing~~equivalent, ~~equipment~~determined ~~and~~using ~~operating~~a ~~methods~~ratio orof insix ~~which~~Mcf ~~the cost~~ of ~~the~~natural ~~required~~gas ~~equipment~~to isone Bbl ~~relatively~~of ~~minor~~oil, ~~compared~~condensate ~~with~~or ~~the~~natural ~~cost~~gas ~~of a new well, and~~liquids.

•Btu. ~~through~~A ~~installed~~British ~~extraction~~thermal ~~equipment~~unit ~~and~~is ~~infrastructure~~a ~~operational~~measurement atof the ~~time~~heat generating capacity of ~~the~~natural ~~reserves~~gas. ~~estimate~~One Btu ifis the ~~extraction~~heat isrequired byto ~~means~~raise ~~not~~the ~~involving~~temperature of a ~~well~~one—pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

~~Development costs~~Completion. ~~Costs~~Installation ~~incurred~~of topermanent ~~obtain~~equipment ~~access to proved reserves and to provide facilities~~ for ~~extracting,~~ ~~treating,~~production ~~gathering~~of ~~and storing the~~ oil ~~and~~or gas~~. More specifically~~, ~~development costs~~or, ~~including~~ ~~depreciation~~in ~~and~~the ~~applicable~~case ~~operating costs~~ of ~~support~~a dry ~~equipment~~well, ~~and~~to ~~facilities~~reporting ~~and~~to ~~other costs~~the ofappropriate ~~development~~authority ~~activities,~~that ~~are~~the ~~costs~~well ~~incurred~~has ~~to:~~been abandoned.

•Condensate. ~~gain~~A ~~access~~mixture toof ~~and~~hydrocarbons ~~prepare~~that ~~well~~exists ~~locations~~in ~~for drilling, including surveying well locations for~~ the ~~purpose~~gaseous ofphase ~~determining~~at ~~specific~~original ~~development~~reservoir temperature ~~drilling sites, clearing ground, draining, road building,~~ and ~~relocating public roads~~pressure, ~~gas~~but ~~lines~~that, ~~and~~when ~~power lines~~produced, tois in the ~~extent~~liquid ~~necessary~~phase inat ~~developing~~surface ~~the~~pressure ~~proved reserves;~~and temperature.

•Developed ~~drill~~oil and ~~equip~~gas ~~development~~reserves. ~~wells,~~Reserves ~~development-type stratigraphic test wells, and service wells, including the costs~~ of ~~platforms~~any ~~and~~category ofthat ~~well~~can ~~equipment~~be ~~such~~expected asto ~~casing,~~be ~~tubing, pumping equipment, and the wellhead assembly;~~recovered:

• ~~acquire,~~through ~~construct,~~existing ~~and~~wells ~~install~~with ~~production~~existing ~~facilities~~equipment ~~such~~and asoperating ~~lease~~methods ~~flow~~or ~~lines,~~in ~~separators,~~which ~~treaters,~~the ~~heaters,~~cost ~~manifolds,~~of ~~measuring~~the ~~devices,~~required ~~and~~equipment ~~production~~is ~~storage~~relatively ~~tanks,~~minor ~~natural~~compared ~~gas~~with ~~cycling~~the ~~and~~cost ~~processing~~of ~~plants,~~a ~~and~~new ~~central~~well, ~~utility~~ and ~~waste disposal systems; and~~

• ~~provide~~through ~~improved~~installed ~~recovery~~extraction ~~systems~~equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development ~~well~~costs. ACosts ~~well~~incurred ~~drilled~~to ~~within~~obtain ~~the~~access to proved ~~area~~reserves ofand anto ~~oil~~provide orfacilities ~~natural~~for extracting, ~~gas~~treating, ~~reservoir~~gathering toand storing the oil and gas. More specifically, development costs, ~~depth~~including depreciation and applicable operating costs of asupport ~~stratigraphic~~equipment ~~horizon~~and ~~known~~facilities toand beother costs ~~productive.~~of development activities, are costs incurred to:

~~Developed~~• ~~acres.~~gain ~~Acres~~access ~~spaced~~to orand ~~assigned~~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 ~~productive~~the ~~wells.~~ extent necessary in developing the proved reserves;

~~Dry~~• ~~hole~~drill orand ~~well.~~equip Adevelopment ~~well~~wells, ~~found~~development-type tostratigraphic betest ~~incapable~~wells, ofand ~~producing~~service ~~hydrocarbons~~wells, inincluding ~~sufficient~~the ~~quantities such~~costs ~~that~~of ~~proceeds~~platforms ~~from~~and ~~the~~of ~~sale~~well ofequipment such ~~production~~as ~~would~~casing, ~~exceed~~tubing, ~~production~~pumping ~~expenses~~equipment, and ~~taxes.~~ the wellhead assembly;

~~Exploratory~~• ~~well.~~acquire, Aconstruct, ~~well~~and ~~drilled~~install toproduction ~~find~~facilities ~~and~~such ~~produce~~as ~~oil~~lease orflow ~~gas~~lines, inseparators, antreaters, ~~unproved~~heaters, ~~area~~manifolds, tomeasuring ~~find~~devices, aand ~~new reservoir~~production instorage atanks, ~~field~~natural ~~previously~~gas ~~found~~cycling toand beprocessing ~~productive~~plants, inand ~~another~~central ~~reservoir,~~utility orand towaste ~~extend~~disposal asystems; ~~known reservoir.~~ and

2 • provide improved recovery systems.

~~Table~~Development well. A well drilled within the proved area of ~~Contents~~an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

~~Field~~Developed acres. AnAcres ~~area~~spaced ~~consisting of a single reservoir~~ or ~~multiple~~assigned ~~reservoirs all grouped on or related~~ to ~~the~~ ~~same~~productive ~~individual geological structural feature and/or stratigraphic condition~~wells.

~~Gross~~Dry ~~acres~~hole or ~~gross wells~~well. ~~The~~A ~~total~~well ~~acres~~found orto ~~wells,~~be asincapable of producing hydrocarbons in sufficient quantities such that proceeds from the ~~case~~sale ~~may~~of ~~be,~~such inproduction ~~which~~would aexceed ~~working interest~~production isexpenses ~~owned~~and taxes.

~~MBbl~~Exploratory well. ~~One~~A ~~thousand~~well ~~barrels~~drilled ofto find and produce oil or ~~other~~gas ~~liquid~~in ~~hydrocarbons~~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.

~~Mcf. One thousand cubic feet.~~3

~~Mcfe~~Field. ~~One~~An ~~thousand~~area ~~cubic~~consisting ~~feet~~of ~~equivalent,~~a ~~determined~~single ~~using~~reservoir ~~the~~or ~~ratio~~multiple ofreservoirs ~~six~~all ~~Mcf~~grouped ofon ~~natural~~or ~~gas~~related to ~~one~~the ~~Bbl~~same ofindividual ~~oil,~~geological ~~condensate~~structural feature and/or ~~natural~~stratigraphic ~~gas liquids~~condition.

~~MMBbl~~Gross acres or gross wells. ~~One~~The ~~million~~total ~~barrels~~acres or wells, as the case may be, in which a working interest is owned.

~~MMBtu~~MBbl. One ~~million~~thousand ~~British~~barrels ~~thermal~~of ~~units~~oil or other liquid hydrocarbons.

~~MMcf~~Mcf. One ~~million~~thousand cubic feet.

~~MMcfe~~Mcfe. One ~~million~~thousand 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~~MMBbl. ~~The~~One ~~hydrocarbon~~million ~~liquids contained within natural gas~~barrels.

~~Net acres or net wells~~MMBtu. ~~The~~One ~~sum~~million ofBritish ~~the~~thermal ~~fractional working interests owned in gross acres or gross wells, as the case may be~~units.

~~NYMEX~~MMcf. ~~The~~One ~~New~~million ~~York~~cubic ~~Mercantile Exchange~~feet.

~~Oil~~MMcfe. ~~Crude~~One ~~oil~~million ~~and~~cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

~~Production~~Natural ~~costs.~~gas 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 facilitiesliquids. ~~They~~The ~~become~~hydrocarbon ~~part~~liquids ofcontained ~~the~~within ~~cost~~natural ~~of oil and~~ gas ~~produced~~. ~~Examples of production costs~~ ~~(sometimes called lifting costs) are:~~

•Net ~~costs~~acres ofor ~~labor~~net towells. ~~operate~~The sum of the fractional working interests owned in gross acres or gross wells, ~~and~~as ~~related~~the ~~equipment~~case ~~and~~may ~~facilities;~~be.

•NYMEX. ~~repairs~~The ~~and~~New ~~maintenance;~~York Mercantile Exchange.

•Oil. ~~materials,~~Crude ~~supplies,~~oil and ~~fuel consumed and supplies utilized in operating the wells and related equipment and facilities;~~condensate.

•Production ~~property~~costs. ~~taxes~~Costs incurred to operate and ~~insurance~~maintain wells and related equipment and facilities, including depreciation and applicable tooperating ~~proved~~costs ~~properties~~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:

• ~~severance~~costs ~~taxes.~~of labor to operate the wells and related equipment and facilities;

~~Productive~~• ~~well.~~repairs ~~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.~~ maintenance;

~~Proved~~• ~~reserves. Proved oil and gas reserves are those quantities of oil and gas~~materials, ~~which~~supplies, ~~by analysis of geoscience~~ and ~~engineering~~fuel ~~data,~~consumed ~~can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirs,~~ and ~~under~~supplies ~~existing economic~~utilized ~~conditions,~~in operating ~~methods and government regulations — prior to~~ the ~~time~~wells atand ~~which contracts~~related ~~providing~~equipment ~~the~~and 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. facilities;

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

~~Table~~• ofseverance ~~Contents~~taxes.

~~Recompletion~~Productive well. ~~The~~A ~~completion~~well ~~for~~that ~~production~~is offound anto ~~existing~~be ~~wellbore~~capable inof ~~another~~producing ~~formation~~hydrocarbons ~~from~~in ~~that~~sufficient ~~which~~quantities such that proceeds from the ~~well~~sale ~~has~~of ~~been~~such ~~previously~~production ~~completed~~exceeds production expenses and taxes.

~~Reserves~~Proved reserves. ~~Estimated~~Proved ~~remaining~~oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and ~~related~~engineering ~~substances~~data, ~~anticipated~~can be estimated with reasonable certainty to be economically producible, as— offrom a given date, byforward ~~application~~from ofknown ~~development~~reservoirs, ~~projects~~and tounder ~~known~~existing ~~accumulations.~~economic ~~In addition~~conditions, ~~there~~operating ~~must~~methods ~~exist,~~and orgovernment ~~there~~regulations ~~must~~— prior beto athe ~~reasonable~~time ~~expectation~~at ~~that there~~which ~~will~~contracts ~~exist,~~providing the ~~legal~~ right to ~~produce~~operate orexpire, aunless ~~revenue~~evidence ~~interest~~indicates inthat ~~the~~renewal ~~production~~is reasonably certain, ~~installed~~regardless ~~means~~ of ~~delivering~~ ~~oil~~whether ~~and~~deterministic ~~gas~~ or ~~related~~probabilistic ~~substances~~methods are used for the estimation. The project to ~~market,~~extract ~~and~~the ~~all~~hydrocarbons ~~permits~~must ~~and~~have ~~financing~~commenced ~~required~~or tothe operator must be ~~implement~~reasonably certain that it will commence the project within a reasonable time.

~~Reservoir~~Recompletion. AThe ~~porous~~completion ~~and~~for ~~permeable~~production ~~underground~~of ~~formation~~an ~~containing~~existing awellbore ~~natural~~in ~~accumulation~~another ~~of produceable~~formation ~~oil~~from ~~and/or natural gas~~ that which isthe ~~confined~~well byhas ~~impermeable~~been ~~rock~~previously ~~or water barriers and is individual and separate from otherreservoirs~~completed.

~~Standardized measure. Standardized measure is the present value of estimated future net revenues~~4 (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~~Reserves. AEstimated ~~well~~remaining ~~capable~~quantities of ~~producing~~ 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 ~~natural~~there ~~gas~~must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in ~~commercial~~the ~~quantities~~production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

~~Undeveloped acreage~~Reservoir. ~~Lease~~A ~~acreage~~porous onand ~~which~~permeable ~~wells~~underground ~~have~~formation ~~not~~containing ~~been~~a ~~drilled~~natural oraccumulation ~~completed~~of produceable tooil aand/or ~~point that~~natural ~~would~~gas ~~permit~~that ~~the~~is ~~production~~confined ofby ~~commercial~~impermeable ~~quantities~~rock ofor ~~natural~~water ~~gas~~barriers and ~~oil regardless of~~is ~~whether~~individual ~~such~~and ~~acreage~~separate ~~contains~~from ~~proved~~other ~~reserves~~reservoirs.

~~Working~~Standardized ~~interest~~measure. ~~The~~Standardized ~~operating~~measure ~~interest~~is ~~that~~the ~~gives~~present ~~the~~value ~~owner~~of ~~the~~estimated ~~right~~future net revenues (after income taxes) to ~~drill~~be generated from the production of proved reserves, ~~produce~~determined ~~and~~in ~~conduct~~accordance ~~operating~~with ~~activities~~the onrules and regulations of the Securities and Exchange Commission without giving effect to non—property related expenses such as certain general and aadministrative ~~share~~expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of ~~production~~10%.

~~Workover~~Successful well. ~~Operations~~A onwell acapable of producing ~~well~~oil toand/or ~~restore~~natural orgas ~~increase~~in ~~production~~commercial quantities.

4Undeveloped 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.

~~TABLE~~Working OFinterest. ~~CONTENTS~~The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

PART I
	Items 1 and 2. BUSINESS AND PROPERTIES
	Item 1A. RISK FACTORS
	Item 1B. UNRESOLVED STAFF COMMENTS
	Item 3. LEGAL PROCEEDINGS
	Item 4. (Removed and Reserved)
PART II
	Item 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED
	Item 6. SELECTED FINANCIAL DATA
	Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
	Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
	Item 9A. CONTROLS AND PROCEDURES
	Item 9B. OTHER INFORMATION
PART III
	Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE
Item 11. EXECUTIVE COMPENSATION
	Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS
	Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
	Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
	Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
SIGNATURES
Exhibit 10.11
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2
Exhibit 99.1

Workover. Operations on a producing well to restore or increase production.

~~Table of Contents~~5

PART I

Items 1 and 2. BUSINESS AND PROPERTIES

GENERAL

Belden & Blake Corporation, an Ohio corporation, was formed on June 14, 1991 and is wholly owned by Capital C Energy Operations, LP (“Capital C”), a Delaware limited partnership. Capital C acquired us pursuant to a merger completed on July 7, 2004 (the “Merger”). On August 16, 2005, Capital C was acquired (the “Transaction”) by institutional funds managed by EnerVest, Ltd. (“EnerVest”).

We are an independent energy company engaged in the exploitation, development, production, operation and acquisition of oil and natural gas properties. Our operations are focused in the Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale Formation in the Michigan Basin.

We maintain our corporate offices at 1001 Fannin Street, Suite 800, Houston, Texas 77002-6707. Our telephone number at that location is (713) 659-3500.

SIGNIFICANT EVENTS

Credit Agreement

In 2005, we amended and restated our then existing credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement (“~~Amended~~ Credit Agreement”) by and among us and ~~BNP~~ BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. ~~The~~ ~~Amended~~ The Credit Agreement provides for loans and other extensions of credit to be made to us.

On ~~September~~March 2523, ~~2009~~2010, ~~Belden~~we ~~& Blake Corporation~~ entered into the ~~Fifth~~Sixth Amendment to the Credit Agreement. The Credit Agreement was amended to (1) ~~reduce~~add ~~the~~a ~~borrowing~~maximum ~~base~~senior tosecured ~~$65 million~~leverage ratio of 2.00 : 1.00, (2) ~~extend~~eliminate the ~~termination~~maximum ~~date~~leverage byratio ~~one~~beginning ~~year to August~~December 1631, ~~2011~~2009, (3) ~~decrease~~amend the ~~aggregate~~minimum ~~amount of~~interest ~~the~~coverage ~~revolving~~ratio ~~commitments~~ to ~~$100 million,~~1.75 : 1.0 and (4) make certain other amendments to the Credit Agreement.

AtOn ~~December~~August 3125, ~~2009~~2010, we ~~had~~entered aninto ~~Amended~~the ~~Credit~~Seventh ~~Agreement~~Amendment ~~comprised~~to ofthe aCredit ~~five-year~~Agreement. ~~$100 million~~The Credit ~~revolving~~Agreement ~~facility~~was ~~with~~amended ato ~~borrowing base of $65~~(1) ~~million,~~extend ofthe ~~which~~termination ~~$43.9 million~~date ~~was~~to ~~outstanding at December~~April 3114, ~~2009. This facility is for working capital requirements and general corporate purposes~~2012, ~~including~~(2) extend the ~~issuance of letters of credit; and a five year $40 million~~ hedge letter of credit ~~facility~~ ~~that~~termination ~~may~~date ~~be used only~~ to ~~provide~~April 14, ~~credit~~2012, ~~support for our obligations under the hedge agreement and other hedge transactions. Borrowings under the Amended Credit Agreement bear interest~~ (i3) atdecrease the ~~greater~~aggregate amount of the ~~prime rate, an adjusted federal funds rate or an adjusted Eurodollar~~ ~~rate,~~revolving ~~plus~~commitments ~~an applicable margin ranging from 1.0%~~ to ~~2.0% based on the aggregate principal amount outstanding under the Amended Credit Agreement~~$90 million, ~~or,~~ (ii4) atdecrease ~~our option,~~ the ~~Eurodollar~~borrowing base ~~rate plus~~to an$55 million ~~applicable~~and ~~margin~~(5) make certain ~~ranging~~other ~~from~~amendments ~~2.5%~~ to ~~3.50% based on~~ the ~~aggregate principal amount outstanding under the Amended~~ Credit Agreement. ~~The full amount borrowed under the Amended Credit~~ ~~Agreement will mature on August 16, 2011.~~

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

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

In 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.

~~Table~~We have an operating agreement with EnerVest Operating, L.L.C. (“EnerVest Operating”). Under this operating agreement, EnerVest Operating acts as operator of ~~Contents~~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.

~~In connection with our entry into the Amended Credit Agreement, we executed a Subordinated~~6 Promissory Note (“Subordinated Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. The Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. Interest payments on the Subordinated Note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the Subordinated Note by borrowing additional amounts against the Subordinated Note. The interest payments in the first quarter of 2007 and the first three quarters of 2008 were paid in cash. Interest payments for the last three quarters of 2007, the fourth quarter of 2008 and all of 2009 were made by additional borrowings against the Subordinated Note. The Subordinated Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. Pursuant to the Fourth Amendment to our credit agreement cash payments for principal or interest on the Subordinated Note are prohibited. The Subordinated Note is subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, a long-term hedging program (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) and notes issued under our Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).

~~DESCRIPTION~~We OFown ~~BUSINESS~~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.

~~Overview~~Oil and Gas Reserves

InThe ~~the~~following ~~fourth~~table ~~quarter~~presents ~~of 2009,~~ our ~~average~~estimated net ~~production~~proved ~~was approximately 34.9 MMcfe per day consisting of 29.8 MMcf of natural gas and 849 Bbls of~~ oil ~~per day. At December 31, 2009, we owned interests in 4,346 gross (3,396 net) productive oil~~ and ~~gas wells in Ohio, Pennsylvania, New York and Michigan with estimated proved reserves totaling 190 Bcfe consisting of 163 Bcf of~~ natural gas ~~and~~ ~~4.4 MMbbl of oil. The estimated future net cash flows from these~~ reserves ~~had a standardized measure of approximately $166.8 million~~ at December 31, ~~2009~~2010. ~~The~~These ~~12-month~~estimates ~~weighted~~were ~~average~~prepared ~~prices used~~by toWright ~~estimate~~& ~~proved reserves at December 31~~Company, ~~2009 were $4~~Inc.34 ~~per~~independent ~~Mcf for natural gas and $56.33~~petroleum ~~per Bbl for oil~~consultants.

We have an operating agreement with EnerVest Operating, L.L.C. (“EnerVest Operating”). Under this operating agreement, EnerVest Operating acts as operator of the oil and gas wells, the related gathering systems and production facilities where our interest entitles us to control the appointment of the operator. As operator, EnerVest Operating manages the drilling and completion of wells and the day to day operating and maintenance activities for our assets. At December 31, 2009, EnerVest Operating operated approximately 3,802 wells, or 87% of our gross wells representing approximately 98% of the value of our estimated proved developed reserves based on their standardized measure. At December 31, 2009, we owned leases on 538,202 gross (464,816 net) acres, including 212,074 gross (177,493 net) undeveloped acres.


	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

WeThe ~~own~~table ~~approximately~~above ~~1,597~~represents ~~miles~~estimates ofonly. ~~natural~~Reserves ~~gas~~estimates ~~gathering~~are ~~lines~~based inupon ~~Ohio~~various assumptions, ~~Pennsylvania,~~including ~~New York~~assumptions ~~and~~required ~~Michigan,~~by ~~which~~the ~~are~~SEC ~~connected~~relating ~~directly~~ to ~~various~~oil ~~intrastate~~ and ~~interstate~~ natural gas prices, ~~transmission~~drilling ~~systems~~and operating expenses, capital expenditures, taxes and availability of funds. The ~~interconnections~~process of ~~with~~estimating ~~these~~reserves ~~pipelines~~is ~~afford~~complex. usThis ~~marketing~~process ~~access~~requires tosignificant decisions and assumptions in ~~numerous~~the ~~gas~~evaluation ~~markets~~of available geological, ~~including~~geophysical, ~~those~~engineering inand ~~the~~economic ~~northeastern~~data ~~United~~for ~~States~~each reservoir. ~~The~~Furthermore, ~~proximity~~different reserve engineers may make different estimates of ~~our~~reserves and ~~properties~~cash inflow based on the ~~Appalachian~~same available data and ~~Michigan~~these ~~Basins~~differences tomay ~~large~~be ~~commercial~~significant. ~~and~~Therefore, these ~~industrial~~estimates are not precise. Actual future production, oil and natural gas prices, revenues, ~~markets~~taxes, ~~along~~development ~~with~~expenditures, ~~the~~operating ~~favorable~~expenses ~~Btu~~and ~~content~~quantities of ~~our~~recoverable oil and natural gas ~~has~~reserves ~~generally~~will ~~resulted~~likely invary ~~premium~~from ~~wellhead~~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 ~~compared~~and ~~with~~other ~~the~~factors, ~~NYMEX~~many ~~price~~of ~~for~~which ~~gas~~are ~~delivered~~beyond atour ~~the~~control. ~~Henry~~Proved ~~Hub~~developed reserves inare ~~Louisiana~~reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. ~~During~~Proved undeveloped reserves are proved reserves that are expected ~~2009~~to be recovered from new wells on undrilled acreage, ~~our~~or ~~average~~from ~~per~~existing ~~unit~~wells ~~gas~~where ~~prices~~a ~~(excluding~~relatively major expenditure is required for recompletion. Additionally, the ~~effects~~SEC amended the definition of proved ~~hedging)~~reserves inapplicable ~~Appalachia~~to our 2009 and ~~Michigan were~~2010 $0reserves.44 ~~and~~As ~~$0.11~~a result, ~~respectively~~our December 31, ~~higher~~2009 ~~than~~and 2010 ~~the~~reserves ~~average~~may ~~NYMEX~~not ~~monthly~~be ~~settle~~comparable ~~price~~to ~~for~~those ~~2009~~of prior periods. See “Glossary of Oil and Natural Gas Terms.”

6At 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.

~~Table~~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 ~~Contents~~natural gas and crude oil swaps and natural gas basis differential swaps, in the determination of our oil and gas reserves.

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

~~In December 2008, the SEC announced that it had approved revisions designed to modernize the~~7 ~~reserves reporting requirement of oil and natural gas companies. The most significant amendments to the requirements included the following:~~

•We ~~economic~~annually ~~producibility~~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 ~~and~~as ~~discounted~~of ~~cash~~December 31, ~~flows~~2010 ~~are~~have remained ~~now~~undeveloped ~~based~~for onmore athan 12five ~~month~~years. ~~average~~We ~~commodity~~had ~~price~~20.7 ~~unless~~Bcfe ~~contractual~~of ~~arrangements~~PUDs ~~designate~~at ~~the~~December 31, 2010, ~~price~~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 beproved ~~used;~~developed reserves.

•See ~~probable~~Note ~~and~~17 ~~possible~~to ~~reserves~~the ~~may~~Consolidated beFinancial ~~disclosed~~Statements ~~separately~~for onmore adetailed ~~voluntary~~information ~~basis;~~regarding our oil and gas reserves.

•The ~~reserves~~standardized ~~may~~measure beof ~~classified~~our asestimated proved ~~undeveloped~~reserves ifas ~~there~~of December 31, 2010 was $199.6 million. Standardized measure is athe ~~high~~present ~~degree~~value of ~~confidence~~estimated ~~that~~future ~~the~~net ~~quantities~~revenues (after ~~will~~income taxes) to be ~~recovered~~generated from the production of proved reserves, determined in accordance with the rules and ~~they~~regulations ~~are~~of ~~scheduled~~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 ~~drilled~~construed ~~within~~as the ~~next~~current ~~five~~market ~~years~~value of the reserves. The 10% discount factor, ~~unless~~which is required by Financial Accounting Standards Board pronouncements, is not necessarily the ~~specific~~most ~~circumstances~~appropriate ~~justify~~discount arate. ~~longer~~The ~~time;~~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 ~~reserves~~Over ~~may~~Reserve ~~be estimated through the use of reliable technology in addition to flow test and production history;~~Estimates

•Our wepolicies ~~are~~and ~~now~~practices ~~required~~regarding internal controls over the recording of reserves is structured to ~~provide~~objectively ~~disclosures~~and ~~about~~accurately estimate our oil and gas reserves quantities and present values in compliance with the ~~qualifications~~SEC’s ofregulations and GAAP. Compliance in reserves bookings is the responsibility ~~chief~~of ~~technical~~our ~~person~~Manager of Reservoir Engineering, who ~~oversees~~is also our principal engineer. Our principal engineer has over 6 years of experience in the ~~reserves~~oil ~~estimation~~and ~~process~~gas industry, including over 5 years as either a reserve evaluator, trainer or manager and is a ~~general~~qualified ~~discussion~~reserves estimator (QRE), as defined by the Society of ~~our~~Petroleum Engineers’ standards. Further professional qualifications include a degree in petroleum engineering, extensive internal ~~controls~~and ~~used~~external toreserve training, ~~assure~~and asset evaluation and management. In addition, the ~~objectivity~~principal engineer is an active participant in industry reserve seminars, professional industry groups and has been a member of the Society ~~reserves~~of ~~estimate;~~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 ~~the~~controls ~~definition~~over ofreserve ~~oil~~estimates included retaining Wright & Company, Inc. as our independent petroleum and ~~natural~~geological firm. We provided information about our oil and gas properties, ~~producing~~including ~~activities~~production ~~has~~profiles, ~~expanded~~prices and ~~now~~costs, ~~focuses~~to onWright & Company and they prepare their own estimates of the ~~marketable~~reserves ~~product~~attributable ~~rather~~to ~~than~~our properties. All of the ~~method~~information regarding reserves in this annual report is derived from the report of ~~extraction~~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.

WeThe ~~adopted~~Audit ~~the~~Committee ~~new~~of ~~requirements~~our ~~effective~~Board ~~December 31,~~of ~~2009.~~Directors ~~These~~meets ~~new~~annually ~~requirements~~with ~~did~~management, ~~not~~including the ~~have~~Manager anof ~~effect~~Reservoir onEngineering, ~~what~~to ~~was~~discuss ~~classified~~matters asand apolicies ~~reserve~~related atto ~~December 31, 2009~~reserves.

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

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

The 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.

~~The~~We ~~table~~currently ~~above~~own ~~represents~~working ~~estimates~~interests ~~only.~~in ~~Reserves~~3,152 ~~estimates~~gross ~~are based upon various assumptions~~(2,828 ~~including~~net) ~~assumptions~~wells ~~required~~in by the ~~SEC~~Appalachian ~~relating to oil and natural gas prices,~~Basin ~~drilling~~which ~~and~~currently ~~operating~~produce ~~expenses,~~approximately ~~capital~~18.3 ~~expenditures,~~MMcfe ~~taxes~~net ~~and~~per ~~availability of funds~~day. ~~The~~Most ~~process~~ of ~~estimating~~our ~~reserves~~production ~~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~~Appalachian ~~estimates~~Basin ~~are~~is ~~not~~derived 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~~the ~~estimated.~~shallow ~~In addition~~(1,000 ~~we may adjust estimates of proved reserves~~ to ~~reflect production history~~6,500 ~~results~~feet) ~~of exploration and development~~Medina, ~~prevailing oil~~Clinton and ~~natural gas prices and other factors, many of which are beyond our control. Proved~~Clarendon 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 acreageFormations, orpredominately ~~from~~in ~~existing~~Pennsylvania wells where a relatively major expenditure is required for recompletion. Additionally, the SEC amended the definition of proved reserves applicable to our 2009 reserves. As a result, our December 31, 2009 reserves may not be comparable to those of prior periods. See “Glossary of Oil and ~~Natural Gas Terms~~Ohio.”

~~Table~~During 2010, we drilled 39 gross (39.0 net) development wells and 6 gross (1.5 net) exploratory wells of ~~Contents~~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.

~~The~~Michigan ~~following~~Basin ~~table sets forth the average prices during the 12-month period before the ending~~Properties date covered by this report as determined by an arithmatic unweighted average of the first day of the month price for each month within such period, including fixed price contracts, for oil and gas used in determining our estimated proved reserves. We do not include our natural gas and crude oil derivative financial instruments, consisting of natural gas and crude oil swaps and natural gas basis differential swaps, in the determination of our oil and gas reserves.

	December 31,
	2009
Gas (per Mcf)	$	4.34
Oil (per Bbl)		56.33

The 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.

~~The~~Most ~~prices~~of ~~for~~our ~~oil~~production ~~and~~in ~~natural~~the ~~gas~~Michigan ~~used~~Basin inis ~~this~~derived ~~calculation~~from ~~were~~the ~~regional~~shallow ~~cash~~(700 ~~price~~to ~~quotes~~2,000 ~~on the~~feet) ~~first~~Antrim ~~day~~Shale ofFormation. ~~each~~Completion ~~month~~rates ~~except~~ for ~~volumes~~companies ~~subject~~drilling to ~~fixed~~this ~~price~~formation ~~contracts.~~have ~~Consequently~~exceeded 90%, ~~these prices~~with ~~may~~production ~~not~~often ~~reflect~~lasting 20 years or more. Because the ~~prices~~production ~~actually~~rate ~~received~~from orAntrim ~~expected~~Shale wells tois berelatively ~~received~~low, ~~for~~cost ~~oil~~containment ~~and~~is ~~natural~~a crucial aspect of our operations. Our operations in ~~gas~~the ~~due~~Michigan toBasin ~~seasonal~~are ~~price~~more ~~fluctuations~~capital intensive than our Appalachian Basin operations because of the low natural reservoir pressures and ~~other~~the ~~varying~~high ~~market~~initial ~~conditions~~water content of the Antrim Shale Formation.

WeDuring ~~annually review all proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally~~2010, ~~our~~we ~~PUDs~~drilled ~~are~~no ~~converted~~wells to ~~proved developed reserves within five years of~~ the ~~date~~Antrim ~~they~~Shale ~~are first booked as PUDs~~Formation. We ~~had~~do ~~17.0~~not ~~Bcfe~~plan ofto ~~PUDs~~drill ~~at December 31, 2009,~~any ~~compared~~wells ~~with~~in ~~25.1~~the ~~Bcfe~~Antrim ofShale ~~PUDs~~Formation atin ~~December 31, 2008~~2011. ~~In 2009, we converted no PUDs to proved~~ ~~developed reserves (PDP).~~

~~See~~Oil ~~Note~~and 17Gas toOperations ~~the Consolidated Financial Statements for more detailed information regarding our oil~~ and ~~gas reserves.~~Production

~~The~~Operations. ~~standardized~~EnerVest ~~measure~~Operating operates 88% of our ~~estimated~~gross ~~proved~~wells ~~reserves~~in aswhich ofwe ~~December 31,~~hold ~~2009 was $166.8~~working ~~million~~interests. ~~Standardized~~They ~~measure~~maintain ~~is the present value of estimated future net revenues to be generated from the~~ production offield ~~proved~~offices ~~reserves, determined~~ in ~~accordance with the rules and regulations of the SEC~~Ohio, ~~without~~Pennsylvania ~~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%~~Michigan. ~~Standardized measure does not give effect to~~Through ~~derivative~~these ~~transactions. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor~~offices, ~~which~~EnerVest isOperating ~~required~~reviews byour ~~Financial~~properties ~~Accounting Standards~~to ~~Board~~determine ~~pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter~~ what ~~discount~~action ~~rate~~can isbe ~~used,~~taken ~~is materially affected by assumptions as~~ to ~~timing of~~ ~~future~~control ~~production,~~operating ~~which~~costs ~~may~~and/or ~~prove~~improve ~~to be inaccurate~~production.

~~Controls~~We ~~Over~~own ~~Reserve~~approximately ~~Estimates~~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.

~~Our policies and practices regarding internal controls over the recording of reserves is~~9 structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. Compliance in reserves bookings is the responsibility of our Manager of Reservoir Engineering, who is also our principal engineer. Our principal engineer has over 5 years of experience in the oil and gas industry, including over 4 years as either a reserve evaluator, trainer or manager and is a qualified reserves estimator (QRE), as defined by the Society of Petroleum Engineers’ standards. Further professional qualifications include a degree in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserve seminars, professional industry groups and has been a member of the Society of Petroleum Engineers for over 6 years. Our principal engineer is an employee of EnerVest who provides all of our operating, administrative and technical services.

~~Our~~Production, ~~controls~~Sales ~~over~~Prices ~~reserve~~and ~~estimates included retaining Wright & Company, Inc~~Costs. asThe ~~our independent~~following ~~petroleum~~table ~~and~~sets ~~geological~~forth ~~firm.~~certain ~~We provided~~ information regarding ~~about~~ our net oil and natural gas ~~properties,~~ ~~including~~ production ~~profiles~~, ~~prices~~revenues and ~~costs,~~unit toexpenses ~~Wright~~for ~~& Company and they prepare their own estimates of~~ the ~~reserves attributable to our properties~~years indicated. ~~All~~The ofaverage ~~the~~prices ~~information regarding~~shown ~~reserves~~ in ~~this~~the ~~annual~~table ~~report~~include ~~is derived from~~ the ~~report~~effects 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~~qualified ~~is D. Randall Wright,~~effective ~~President~~hedging ~~of Wright & Company~~activities. ~~Mr.~~See ~~Wright~~Note is6 ato ~~licensed~~the ~~professional~~Consolidated ~~engineer~~Financial ~~with over 32 years of experience in petroleum engineering~~Statements.

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


	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

8 (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

~~Appalachian~~Exploration ~~Basin~~and ~~— Conventional Properties~~Development

~~The~~Our ~~Appalachian~~activities ~~Basin~~include isdevelopment ~~the oldest~~ and ~~geographically~~exploratory ~~one~~drilling ~~of the largest oil and gas producing regions~~ in ~~the~~both ~~United States. Although~~ the ~~Appalachian~~low ~~Basin~~risk ~~has sedimentary~~ formations ~~to depths of 15,000 feet or more, oil~~ and ~~natural~~the ~~gas~~less ~~has primarily been produced from shallow, highly~~ developed formations ~~at depths~~ of ~~1,000~~the toAppalachian ~~6,500 feet. Our drilling completion rates~~ and ~~those~~ ofMichigan ~~others drilling in these shallow, highly developed formations have historically exceeded 90%, with production generally lasting longer than 20 years~~Basins.

WeIn ~~currently~~2010, ~~own~~we ~~working~~spent ~~interests~~approximately in$18.0 million ~~3,130~~on ~~gross~~development ~~(2,804~~and ~~net)~~exploratory ~~wells~~drilling ~~in the Appalachian Basin~~and ~~which~~other ~~currently~~capital ~~produce~~expenditures ~~approximately~~including ~~20.1~~exploratory ~~MMcfe~~dry ~~net~~hole ~~per day~~costs. ~~Most~~We ofdrilled ~~our~~39 ~~production~~gross in(39.0 ~~the~~net) ~~Appalachian~~development ~~Basin~~wells isand ~~derived~~6 ~~from~~gross ~~the shallow~~ (1~~,000~~.5 ~~to 6,500 feet~~net) ~~Medina,~~exploratory ~~Clinton~~wells ~~and Clarendon Formations, predominately~~ in ~~Pennsylvania and Ohio~~2010.

~~During~~In ~~2009~~2011, we ~~drilled~~expect 4to ~~gross~~spend (2approximately $17.05 million ~~net)~~on ~~exploratory~~development ~~wells~~and inexploratory drilling ~~2009.~~and ~~Due~~other tocapital aexpenditures. ~~change~~The ~~in market conditions, the~~ anticipated ~~2010~~2011 focus primarily 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 Antrim play in Michigan, the Medina and Clarendon ~~formations~~plays in Pennsylvania and the Clinton ~~Formation~~play in Ohio ~~as market conditions improve~~.

~~Michigan~~Additionally, ~~Basin~~we ~~Properties~~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.

~~The Michigan Basin has operational similarities to the Appalachian Basin, including geographic~~10 proximity to natural gas markets, which has generally resulted in premium wellhead prices as compared to NYMEX prices. We own working interests in 1,216 gross (592 net) wells in the Michigan Basin which currently produce approximately 14.8 MMcfe net per day.

~~Most~~Typical characteristics 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 toprograms ~~this~~in ~~formation have exceeded 90%, with production often lasting 20 years or more. Because~~ the ~~production~~formations ~~rate~~we ~~from~~target ~~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~~described ~~low natural reservoir pressures and the high initial water content of the Antrim Shale Formation.~~below:

During 2009, we drilled no wells to the Antrim Shale Formation. We do not plan to drill any wells in the Antrim Shale Formation in 2010.


		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

~~Oil~~Drilling ~~and~~Results. ~~Gas~~The ~~Operations~~following ~~and~~table ~~Production~~sets forth drilling results from continuing operations with respect to wells drilled by us during the past three years:

Operations. EnerVest Operating operates 87% of our gross wells in which we hold working interests. They maintain production field offices in Ohio, Pennsylvania and Michigan. Through these offices, EnerVest Operating reviews our properties to determine what action can be taken to control operating costs and/or improve production.


	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

WeProducing ~~own~~Well ~~approximately 1,597 miles of natural gas gathering lines in Ohio, Pennsylvania, New~~Data 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.

9As 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.

~~Table~~The offollowing ~~Contents~~table summarizes by state our productive wells at December 31, 2010:

Production, Sales Prices and Costs. The following table sets forth certain information regarding our net oil and natural gas production, revenues and unit expenses for the years indicated. The average prices shown in the table include the effects of our qualified effective hedging activities. See Note 5 to the Consolidated Financial Statements.


	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

	Year Ended December 31,
	2009		2008		2007
Production
Gas (MMcf)		12,034		13,217		13,357
Oil (Mbbl)		324		334		348
Total production (MMcfe)		13,977		15,221		15,446
Average sales price (1)
Gas (per Mcf)	$	3.61	$	8.62	$	6.81
Oil (per Bbl)		56.49		94.40		67.42
Per Mcfe		4.42		9.55		7.41
Average costs (per Mcfe)
Production expense	$	1.50	$	1.73	$	1.59
Production taxes		0.08		0.20		0.15
Depletion		2.62		2.31		2.31

~~(1)~~Acreage 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:Data

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

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

Exploration and Development


	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

~~Our~~The ~~activities~~following ~~include~~table ~~development~~summarizes ~~and~~by ~~exploratory~~state ~~drilling~~our inundeveloped ~~both~~acreage ~~the~~as ~~low~~of ~~risk~~December 31, ~~formations~~2010 ~~and~~that ~~the~~is ~~less~~subject ~~developed~~to ~~formations~~expiration ofabsent drilling activity during the ~~Appalachian~~three ~~and~~years ~~Michigan~~ended ~~Basins~~December 31, 2013 and thereafter.

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


	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

InDisposition ~~2010,~~of ~~we expect to spend approximately $12.5 million on development and exploratory~~Assets drilling and other capital expenditures. Due to a change in market conditions for oil and natural gas, the anticipated 2010 focus primarily will be in the following areas: Knox exploration in Ohio and operational reworks and enhancement projects throughout our operating area. We will continue to evaluate our development drilling opportunities in our traditional areas such as the Antrim play in Michigan, the Medina and Clarendon plays in Pennsylvania and the Clinton play in Ohio.

~~The~~In ~~Antrim Shale Formation~~July 2010, ~~the~~we ~~principal~~sold ~~shallow~~a ~~formation~~75% interest in ~~the~~certain ~~Michigan~~undeveloped ~~Basin,~~acreage ~~is characterized by high formation water production~~ in ~~the~~Ohio early years of a well’s productive life with water production decreasing over time. Antrim Shale wells produce natural gas that typically climbs to peak rates of 60 Mcf to 125 Mcf per day over a three to 12 month period as the producing formation becomes less water saturated. Production generally holds flat for ~~several months, followed by initial annual decline rates of 10% to 25% that decrease over time to 5% or less~~$6. ~~Average well lives are 20~~1 ~~years or more~~million.

10In June 2010, we sold undeveloped acreage in Pennsylvania for $30.6 million.

~~Table~~In ofNovember 2009, ~~Contents~~we sold undeveloped acreage in Bradford County, Pennsylvania for $35.8 million.

~~Typical~~In ~~characteristics~~July 2009, ofwe sold our ~~drilling~~coalbed ~~programs~~methane properties in ~~the~~Pennsylvania ~~shallow,~~for ~~highly developed formations~~$16.7 million. ~~we target are described below:~~

			Range of Average Drilling
			and Completion Costs per
	Range of Well Depths		Well
	(in feet)		(in thousands)
Ohio:
Clinton		3,500 - 5,750	$	360 - 420
Pennsylvania:
Clarendon		1,100 - 2,100		120 - 150
Medina		5,300 - 6,200		370 - 400
Michigan:
Antrim		1,300 - 2,100		310 - 370

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.

~~The~~Acquisition ~~Appalachian Basin has productive and potentially productive sedimentary formations to depths~~ of ~~15,000~~Producing ~~feet or more, but the combination of long-lived production and high drilling~~Properties ~~completion rates in the shallow formations has curbed the development of the deeper formations in the basin.~~

WeIn ~~have also tested~~ the ~~Niagaran~~fourth ~~Carbonate,~~quarter ~~Onondaga~~of ~~Limestone~~2010, ~~Oriskany Sandstone, Knox, Utica Shale, Marcellus Shale and Trenton Black River Formations. In the future,~~ we ~~may~~acquired ~~allocate~~additional ~~a portion~~working ofinterest in our ~~drilling budget to drill~~ wells in Michigan ~~these~~for ~~and~~approximately ~~other deeper or less developed formations~~$4.4 million.

~~Drilling Results. The following table sets forth drilling results from continuing operations~~12 ~~with respect to wells drilled by us during the past three years:~~

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

Employees

~~Producing~~As ~~Well~~of ~~Data~~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.

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

11The 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.

~~Table~~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 ~~Contents~~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.

~~The~~We ~~following~~are ~~table~~also ~~summarizes~~affected by ~~state~~competition ~~our~~for ~~productive~~drilling ~~wells~~rigs atand ~~December 31~~the availability of related equipment. In the past, ~~2009:~~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.

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

Principal Customers

~~Acreage~~The ~~Data~~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 ~~following~~terms ~~table~~of ~~summarizes~~sale byunder ~~state~~the ~~our~~majority ~~gross~~of ~~and~~existing ~~net~~contracts ~~developed~~are ~~and~~short—term, ~~undeveloped~~usually ~~acreage~~one atyear or ~~December 31~~less in duration. The prices received for oil, ~~2009:~~natural gas and natural gas liquids sales are generally tied to monthly or daily indices as quoted in industry publications.

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

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.

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

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

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.

~~Disposition of Assets~~13

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

InRegulation ~~July 2009~~of Drilling and Production. Statutes, werules ~~sold~~and ~~our~~regulations ~~coalbed~~affecting exploration ~~methane~~and ~~properties~~production inundergo ~~Pennsylvania~~constant ~~for~~review ~~$16~~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.~~7 million~~ 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:

In• ~~March~~the location of ~~2008, we sold a 50-70% option interest in certain deep rights on approximately 201,000 net acres in Ohio and Pennsylvania for $3.0 million.~~ wells;

12 • the method of drilling and casing wells;

~~Table~~• the surface use and restoration of ~~Contents~~properties upon which wells are drilled;

~~Employees~~ • the plugging and abandoning of wells; and

As• ofnotice ~~February 28,~~to ~~2010,~~surface weowners 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~~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.

~~The~~States ~~oil~~generally ~~and~~impose ~~gas~~a ~~industry~~production, isad ~~highly~~valorem ~~competitive.~~or ~~Competition~~severance istax ~~particularly intense~~ with respect to the production ~~acquisition~~and sale of ~~producing~~oil ~~properties~~ and ~~undeveloped~~natural ~~acreage~~gas ~~and~~within ~~the~~its ~~sale~~jurisdiction. ofStates ~~oil~~do ~~and~~not generally ~~gas~~regulate ~~production.~~wellhead ~~There~~prices isor ~~competition~~engage ~~among~~in ~~oil~~other, ~~and~~similar ~~gas~~direct ~~producers~~economic asregulation, ~~well~~but asthere ~~with~~can ~~other industries~~be inno ~~supplying~~assurance ~~energy~~they ~~and~~will ~~fuel~~not todo ~~end-users~~so in the future.

~~Our~~In ~~competitors in oil and gas exploration~~addition, ~~development~~11 ~~and~~states ~~production~~have ~~include~~enacted ~~major integrated~~surface ~~oil~~damage ~~and~~statutes ~~gas~~(“SDAs”). ~~companies~~These aslaws ~~well~~are ~~as numerous independent oil and gas companies, individual~~designed ~~proprietors,~~to ~~natural~~compensate ~~gas~~for ~~pipeline~~damage ~~companies~~caused ~~and~~by ~~their~~mineral ~~affiliates~~development. ~~Many~~Most ofSDAs ~~these~~contain ~~competitors possess~~entry ~~and~~notification ~~employ financial~~ and ~~personnel resources substantially in excess of those available to~~ ~~us.~~negotiation ~~Such~~requirements ~~competitors may be able~~ to ~~pay~~facilitate ~~more~~contact ~~for~~between ~~desirable~~operators ~~prospects or producing properties~~ and to ~~evaluate,~~surface ~~bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit~~owners/users. ~~Our ability to add to our reserves in the future will depend on~~Most ~~the~~also ~~availability~~contain ofbonding ~~capital,~~requirements ~~the~~and ~~ability~~specific toexpenses ~~exploit~~for ~~our~~exploration ~~current developed~~ and ~~undeveloped~~producing ~~lease~~activities. ~~holdings~~Costs and ~~the~~delays ~~ability~~associated towith ~~select~~SDAs ~~and~~could ~~acquire~~impair ~~suitable~~operational ~~producing~~effectiveness ~~properties~~ and ~~prospects for~~increase ~~future exploration and~~ development costs.

We ~~are~~do ~~also~~not ~~affected~~control ~~by competition for drilling rigs and~~ the availability of ~~related equipment.~~transportation ~~In the past, the oil~~ and ~~natural~~processing ~~gas~~facilities ~~industry~~used ~~has~~in ~~experienced~~the marketing ~~shortages~~ of ~~drilling rigs,~~our ~~equipment,~~production. ~~pipe~~For ~~and personnel~~example, ~~which~~we ~~have~~may ~~delayed development drilling and other exploitation activities and~~ have ~~caused~~to ~~significant~~shut—in ~~price~~a ~~increases.~~productive Wenatural ~~are~~gas ~~unable~~well because toof ~~predict~~a ~~when,~~lack orof ~~if,~~available ~~such shortages~~natural ~~may~~gas ~~occur~~gathering or ~~how~~transportation ~~they would affect our development and exploitation program~~facilities.

~~Principal~~ If ~~Customers~~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.

~~The~~Federal ~~market~~Regulation ~~for~~of ~~our~~Sales ~~oil,~~and ~~natural~~Transportation ~~gas~~of ~~and~~Natural ~~natural~~Gas. ~~gas~~The ~~liquids~~availability, ~~production~~terms ~~depends on~~and ~~factors~~cost ~~beyond~~of ~~our~~transportation ~~control,~~significantly ~~including~~affect ~~the~~sales ~~extent~~ of ~~domestic~~natural ~~production~~gas. The interstate transportation and sale ~~imports~~for resale of ~~oil,~~ natural gas ~~and~~are ~~natural~~subject ~~gas~~to ~~liquids~~federal regulation, including regulation of the terms, ~~proximity~~conditions and ~~capacity~~rates offor ~~natural~~interstate ~~gas~~transportation, ~~pipelines~~storage and various other ~~transportation~~ ~~facilities~~matters, primarily by the ~~demand~~Federal ~~for~~Energy ~~oil,~~Regulatory ~~natural~~Commission ~~gas~~(“FERC”). Federal and ~~natural~~state ~~gas~~regulations govern ~~liquids,~~ the ~~marketing of~~price ~~competitive fuels~~ and ~~the~~terms ~~effect~~for ofaccess ~~state~~to ~~and~~natural ~~federal~~gas ~~regulation~~pipeline transportation. ~~The~~FERC’s ~~oil~~regulations for ~~and~~interstate natural gas ~~industry~~ ~~also~~transmission ~~competes~~in ~~with~~some ~~other~~circumstances ~~industries~~may inalso ~~supplying~~affect the ~~energy~~intrastate transportation ~~and~~of ~~fuel~~natural ~~requirements~~gas. ~~of industrial~~FERC regulates the rates, ~~commercial~~terms and ~~individual consumers.~~conditions

~~Our oil, natural gas and natural gas liquids production is sold to a variety of purchasers.~~14 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~~applicable ofto the ~~following~~interstate ~~customers~~transportation ~~accounted for 10% or more~~ of ~~our~~natural ~~consolidated~~gas ~~revenues~~by ~~during 2009:~~pipelines ~~Integrys~~under ~~Energy, National Fuel Resources, Inc. and American Refining Group, Inc. We believe that~~ the ~~loss~~Natural ~~of a major customer would have a temporary effect on our revenues but that over time,~~Gas weAct ~~would~~as bewell ~~able~~as tounder ~~replace~~Section 311 ~~our major customers. We do not believe that any~~ of ~~our~~the ~~customers~~Natural ~~are credit~~Gas ~~risks~~Policy Act.

~~Title~~Since 1985, FERC has implemented regulations intended to ~~Properties~~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.

AsFERC ishas ~~customary~~also inissued ~~the~~several ~~oil~~other ~~and~~generally ~~natural~~pro—competitive ~~gas~~policy ~~industry,~~statements weand initiatives ~~initially~~affecting ~~conduct~~rates ~~only~~and aother ~~cursory review~~aspects of ~~the~~pipeline ~~title~~transportation toof ~~our~~natural ~~properties on which we do not have proved reserves~~gas. ~~Prior~~On ~~to the~~May 31, ~~commencement~~2005, ofFERC ~~drilling~~generally ~~operations~~reaffirmed onits ~~those~~policy ~~properties,~~of weallowing ~~conduct~~interstate apipelines ~~thorough~~to ~~title~~selectively ~~examination~~discount ~~and~~their ~~perform~~rates ~~curative~~in ~~work~~order ~~with respect~~ to ~~significant~~meet ~~defects.~~competition Tofrom ~~the extent title opinions or~~ other ~~investigations~~interstate ~~reflect~~pipelines. ~~title~~On ~~defects~~June 15, ~~on those properties~~2006, ~~we are typically responsible for~~the ~~curing~~FERC ~~any~~issued ~~title~~an ~~defects~~order atin ~~our~~which ~~expense.~~it Wedeclined ~~generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior~~ to ~~completing~~establish ~~an acquisition~~uniform ofstandards ~~producing~~for natural gas ~~leases, we perform title reviews on the most significant~~quality ~~leases~~ and, ~~depending on the materiality of the properties~~interchangeability, weopting ~~may~~instead ~~obtain~~for a ~~title~~pipeline—by—pipeline ~~opinion or review previously obtained title opinions~~approach. AsOn aJune 19, ~~result~~2006, wein order ~~have~~to ~~obtained~~facilitate ~~title~~development ~~opinions on a significant portion~~ of ~~our~~new ~~natural~~storage ~~gas~~capacity, ~~properties~~FERC ~~and~~established ~~believe~~criteria ~~that we have satisfactory title~~ to ~~our producing~~allow ~~properties~~providers into ~~accordance~~charge ~~with~~market—based ~~standards~~(i.e. ~~generally~~negotiated) ~~accepted~~rates infor ~~the~~storage ~~natural gas and oil industry~~services. ~~Our~~ ~~properties~~On ~~are subject to customary royalty and other interests~~June 19, ~~liens for current taxes and~~2008, ~~other~~the ~~burdens~~FERC ~~that~~removed wethe ~~believe~~rate doceiling ~~not~~on ~~materially~~short—term ~~interfere~~releases ~~with~~by ~~the~~shippers ~~use~~ of orinterstate ~~affect our carrying~~pipeline ~~value~~transportation ~~of the properties~~capacity.

13Although 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.

~~Table~~State Natural Gas Regulation. Various states regulate the drilling for, and the production, gathering and sale of, ~~Contents~~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 ~~Drilling~~Sales and ~~Production~~Transportation of Crude Oil. Our ~~operations~~sales of crude oil and condensate are ~~subject~~not tocurrently ~~various~~regulated ~~types of~~and ~~regulation~~are made at ~~the~~market ~~federal~~prices. In a number of instances, however, ~~state~~the ability to transport and ~~local~~sell ~~levels.~~such ~~These~~products ~~types~~is ofdependent ~~regulation~~on ~~include~~pipelines ~~requiring~~whose rates, ~~permits~~terms ~~for~~and ~~the~~conditions ~~drilling~~ of ~~wells,~~service ~~drilling~~are ~~bonds~~subject ~~and~~to ~~reports~~FERC ~~concerning~~jurisdiction ~~operations.~~under ~~Most~~the ~~states~~Interstate Commerce Act. ~~and~~Certain ~~some~~regulations ~~counties~~implemented ~~and~~by ~~municipalities~~the FERC in ~~which~~recent weyears ~~operate~~could ~~also~~result ~~regulate~~in ~~one~~an orincrease ~~more~~in the cost of ~~the~~pipeline transportation service. We do not believe, however, that these regulations affect ~~following:~~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 ~~location~~discharge of ~~wells;~~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

~~• the method of drilling and casing wells;~~15

•anticipated ~~the~~costs ~~surface~~of ~~use~~plugging and ~~restoration~~abandoning ofwells, ~~properties~~and ~~upon~~can ~~which~~require remedial action to address pollution from former operations, such as plugging abandoned wells ~~are~~or ~~drilled;~~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 ~~plugging~~oil and ~~abandoning~~natural gas industry increases the cost of ~~wells~~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.

~~State~~Under ~~laws~~the ~~regulate~~federal ~~the~~Comprehensive ~~size~~Environmental Response, Compensation and ~~shape~~Liability ofAct (“CERCLA”), ~~drilling~~also known as the “Superfund” law, and ~~spacing~~comparable ~~units~~state orlaws, ~~proration~~liability ~~units~~generally is ~~governing~~joint ~~the~~and ~~pooling~~several for costs of ~~oil~~investigation and ~~natural~~remediation ~~gas~~of ~~oil~~contaminated ~~properties.~~sites ~~Some~~and ~~states~~for associated ~~allow~~natural ~~forced~~resource ~~pooling~~damages, without regard to fault or ~~integration~~ the legality of ~~tracts~~the tooriginal conduct, ~~facilitate~~on ~~exploitation~~certain ~~while~~classes ~~other~~of ~~states~~persons ~~rely~~with onrespect ~~voluntary~~to ~~pooling~~the release into the environment of ~~lands~~substances ~~and~~designated ~~leases~~under CERCLA as hazardous substances (“Hazardous Substances”). InThese ~~some~~classes of ~~instances~~persons, ~~forced~~or ~~pooling~~so-called orpotentially ~~unitization~~responsible ~~may~~parties be(“PRPs”), ~~implemented~~include bycurrent ~~third~~and certain past ~~parties~~owners and ~~may~~operators ~~reduce~~of ~~our~~a ~~interest~~facility inwhere ~~the~~there ~~unitized~~has ~~properties.~~been Ina ~~addition,~~release ~~state~~or ~~conservation~~threat of release of a ~~laws~~Hazardous ~~establish~~Substance ~~maximum~~and ~~rates~~persons who disposed of ~~production~~or ~~from~~arranged ~~oil~~for the disposal of the Hazardous Substances found at such a facility. CERCLA also authorizes the EPA and, ~~natural~~in ~~gas~~some ~~wells~~cases, ~~generally~~third parties ~~prohibit~~to take actions in response to threats to the ~~venting~~ orpublic ~~flaring~~health ofor ~~natural~~the ~~gas~~environment and ~~impose~~to ~~requirements~~seek to ~~regarding~~recover from the ~~ratability~~PRPs the costs of ~~production~~such action. Although CERCLA generally exempts “petroleum” ~~These~~from ~~laws~~the ~~and~~definition ~~regulations~~of ~~may~~Hazardous ~~limit~~Substance, in the ~~amount~~course of ~~oil~~its operations, we have generated and will ~~natural~~generate ~~gas~~wastes wethat ~~can~~fall ~~produce~~within ~~from~~CERCLA’s ~~our~~definition of Hazardous Substances and may have ~~wells~~disposed orof ~~limit~~those ~~the~~wastes ~~number~~at disposal sites owned and operated by others. We may also be an owner or operator of ~~wells~~facilities on which Hazardous Substances have been released. We may be responsible under CERCLA for all or part of the ~~locations~~costs to clean up facilities at which wesuch ~~can~~substances ~~drill.~~have ~~Moreover~~been released and for natural resource damages, ~~each~~as ~~state~~a past or present owner or operator or as an ~~generally~~arranger. ~~imposes~~To our knowledge, we have not been named a ~~production~~PRP under CERCLA nor have any prior owners or operators ~~severance~~of ~~tax~~our ~~with~~properties ~~respect~~been named as PRPs related to ~~the~~their ~~production~~ownership ~~and~~or ~~sale~~operation of ~~oil~~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 ~~natural~~of ~~gas~~investigation and ~~natural~~remediation ~~gas~~and ~~liquids~~for ~~within~~natural ~~its~~resource ~~jurisdiction~~damages.

InAlthough ~~addition,~~oil 11and ~~states~~gas ~~have~~wastes ~~enacted~~generally ~~surface~~are ~~damage~~exempt ~~statutes~~from regulation as hazardous wastes (“~~SDAs~~Hazardous Wastes”). ~~These~~under ~~laws~~the ~~are~~federal ~~designed~~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 ~~compensate~~regulation ~~for~~under ~~damage~~RCRA ~~caused~~and bystate ~~mineral~~analogs. ~~development~~The U.S. ~~Most~~EPA ~~SDAs~~and ~~contain~~various ~~entry~~state ~~notification~~agencies have limited the disposal options for certain wastes, including hazardous wastes and there is no ~~negotiation~~guarantee ~~requirements~~that tomore ~~facilitate~~stringent ~~contact~~requirements ~~between~~will ~~operators~~not ~~and~~be ~~surface~~adopted ~~owners/users~~in the future. ~~Most~~Moreover, ordinary ~~also~~industrial ~~contain~~wastes, ~~bonding~~such ~~requirements~~as ~~and~~paint ~~specific~~wastes, ~~expenses~~waste ~~for~~solvents, ~~exploration~~laboratory wastes, and ~~activities~~waste compressor oils, may be regulated as hazardous waste. ~~Costs~~Although ~~and~~the costs of managing these wastes generated ~~delays~~by ~~associated~~us ~~with~~may ~~SDAs~~be ~~could~~significant, ~~impair~~we ~~operational~~do ~~effectiveness~~not ~~and~~expect ~~increase~~to ~~development~~experience more burdensome costs than similarly situated companies involved in oil and gas exploration and production.

We docurrently ~~not~~own, ~~control~~operate or lease, and have in the ~~availability~~past owned, operated or leased, numerous properties that for many years have been used for the exploration and production of ~~transportation~~oil and ~~processing~~gas. Hydrocarbons ~~facilities~~or ~~used~~other inwastes may have been disposed of or released on or under the properties ~~marketing~~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 ~~production~~control. These ~~For~~properties ~~example~~and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we ~~may~~could ~~have~~be required to ~~shut-in~~remove aor ~~productive~~remediate ~~natural~~previously ~~gas~~disposed ~~well~~wastes ~~because~~or ofproperty acontamination ~~lack~~(including ofwastes ~~available~~or ~~natural~~contamination ~~gas~~attributable ~~gathering~~to others), or ~~transportation~~to ~~facilities~~perform remedial plugging or pit closure operations to prevent future contamination.

IfThe wefederal ~~conduct~~Clean ~~operations~~Air onAct ~~federal,~~and analogous state orlaws ~~Indian~~restricts ~~oil~~the ~~and~~emission of air pollutants from many sources, including equipment we use such as compressors to transport natural gas ~~leases,~~in our ~~these~~pipelines. Federal and state laws generally require new and modified sources of air ~~operations~~pollutants ~~must~~to ~~comply~~obtain ~~with~~permits ~~numerous~~prior ~~regulatory~~to ~~restrictions~~commencing construction, ~~including~~which ~~various~~may ~~nondiscrimination~~require, among other ~~statutes~~things, ~~royalty~~stringent, ~~and~~technical ~~related~~controls. ~~valuation~~Major sources of air pollutants are subject to more stringent requirements, ~~and~~including ~~certain~~additional ofpermitting ~~these~~requirements. ~~operations~~Other ~~must~~federal beand state ~~conducted~~laws ~~pursuant~~designed to ~~certain~~control ~~on-site~~hazardous ~~security~~(or ~~regulations~~toxic) ~~and~~air ~~other~~pollutants, ~~appropriate~~might ~~permits~~require ~~issued~~installation byof additional controls. Governmental agencies (and in the ~~Bureau~~case of ~~Land~~civil ~~Management~~suits, private parties in certain circumstances) can bring actions for failure to strictly comply with air pollution regulations or ~~Minerals~~permits ~~Management~~and ~~Service~~generally enforce compliance through administrative, civil or criminal ~~other~~enforcement ~~appropriate~~actions, ~~federal~~resulting in fines, injunctive relief (which could include requiring us to forego construction, modification or ~~state~~operation of sources of air ~~agencies.~~

~~Federal Regulation of Sales and Transportation of Natural Gas. Historically, the~~16 transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and Federal Energy Regulatory Commission (“FERC”) regulations. In the past, the federal government has regulated the prices at which natural gas could be sold. Currently, sales by producers of natural gas can be made at uncontrolled market prices. Congress could, however, reenact price controls in the future.

~~Our~~pollutants) ~~sales of natural gas are affected by the availability, terms~~ and ~~cost of transportation~~imprisonment. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the FERC that affect the economics of natural gas production, transportation and sales. In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

14More 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.

~~Table~~Because of ~~Contents~~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.

~~The~~Our ~~future~~operations ~~impact~~involve discharges to surface waters of fluids associated with the ~~complex~~production of ~~rules~~oil and ~~regulations~~gas. ~~issued~~The byfederal Clean Water Act and analogous state laws impose restrictions and strict controls regarding the ~~FERC~~discharge ~~since~~of ~~1985~~these ~~cannot~~fluids befrom oil and gas operations into state ~~predicted.~~waters Inor ~~addition~~waters of the United States, ~~many~~a ~~aspects~~term broadly defined, prohibiting discharge, except in accord with the terms of ~~these~~a ~~regulatory~~permit ~~developments~~issued ~~have~~by ~~not~~U.S. ~~become~~EPA ~~final~~or ~~but~~the state. Our facilities in Michigan use ~~are~~injection ~~still~~wells ~~pending~~to ~~judicial~~dispose ~~and~~of ~~FERC~~wastewater ~~final~~that ~~decisions~~is produced as a byproduct of oil and gas production. These Weinjection ~~cannot~~wells ~~predict~~are ~~what~~subject ~~further~~to ~~action~~stringent ~~the~~regulation ~~FERC~~and permitting requirements under the ~~will~~Safe ~~take~~Drinking onWater ~~these~~Act ~~matters~~and analogous state programs. WeAt doour ~~not~~oil ~~believe,~~and ~~however,~~gas ~~that~~wells wein Ohio and ~~will~~Pennsylvania, bewastewater ~~affected~~is collected in aboveground tanks and collected by ~~any~~third-party ~~action~~contractors for ~~taken~~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 ~~materially~~permit ~~different~~issued ~~way~~by ~~than~~the U.S. ~~other~~Army ~~natural~~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 ~~producers~~certain circumstances. Sanctions for failure to comply with Clean Water Act requirements, including ~~gatherers~~permit requirements, include administrative, civil and ~~marketers~~criminal ~~with~~penalties, ~~which~~as wewell ~~compete~~as injunctive relief.

~~Federal~~The ~~Regulation~~Safe ofDrinking ~~Sales~~Water ~~and~~Act ~~Transportation~~(the of“SWDA”) ~~Crude~~regulates, ~~Oil~~among other things, underground injection operations. ~~Our~~Recent ~~sales~~legislative ofactivity ~~crude~~has ~~oil~~occurred ~~and~~which, if successful, would impose additional ~~condensate~~regulation ~~are~~under ~~not~~the ~~currently~~SDWA ~~regulated~~upon ~~and~~the use of hydraulic fracturing fluids. Currently, most hydraulic fracturing activities are ~~made~~regulated at ~~market~~the ~~prices~~state level, as the SDWA exempts most hydraulic fracturing activities. InCongress ais ~~number~~considering two companion bills entitled the Fracturing Responsibility and Chemical Awareness Act of ~~instances~~2009 (the “FRAC Act”). If enacted, ~~however,~~ the ~~ability~~legislation would toimpose ~~transport~~on our hydraulic fracturing operations permit and ~~sell~~financial ~~such~~assurance ~~products~~requirements, requirements isthat ~~dependent~~we onadhere ~~pipelines~~to ~~whose~~construction ~~rates~~specifications, fulfill monitoring, reporting and ~~terms~~recordkeeping obligations, and ~~conditions~~meet ofplugging ~~service~~and ~~are~~abandonment ~~subject~~requirements. In addition to subjecting ~~FERC~~the ~~jurisdiction~~injection ~~under~~of hydraulic fracturing to the ~~Interstate~~SDWA ~~Commerce~~regulatory ~~Act.~~and permitting ~~Certain~~requirements, ~~regulations~~the ~~implemented~~proposed bylegislation would require the ~~FERC~~disclosure inof ~~recent~~the ~~years~~chemicals within the hydraulic fluids, which could ~~result~~make init aneasier ~~increase~~for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could ~~cost~~adversely affect ground water. Neither piece of ~~pipeline~~legislation ~~transportation~~has ~~service~~been passed. WeIn doaddition, ~~not~~many states ~~believe~~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, ~~however~~EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Further, ~~that~~a ~~these~~committee ~~regulations~~of ~~affect~~the U.S. House of Representatives is usconducting ~~any~~an ~~differently~~investigation ~~than~~of ~~other~~certain ~~producers~~hydraulic fracturing activities. If new laws or regulations impose

~~Environmental Regulations. Our oil and natural gas exploration, development, production and~~17 pipeline operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, also referred to as the “U.S. EPA,” issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief if we fail to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, restrict materials used in our operations, require bonds to be posted for the anticipated costs of plugging and abandoning wells, and can require remedial action to address pollution from former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations.

~~The~~significant ~~regulatory~~restrictions ~~burden~~or conditions on ~~the~~hydraulic ~~oil~~fracturing ~~and natural gas industry increases the cost of doing business and consequently may affect our profitability. Changes in environmental laws and regulations occur frequently~~activities, ~~and~~we ~~any changes that result in more stringent and costly regulation~~ could ~~materially~~incur ~~adversely~~substantial ~~affect~~compliance ~~our~~costs ~~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~~could isnegatively noimpact ~~assurance~~our ~~that~~ability ~~this~~to ~~trend will~~conduct ~~continue~~fracturing inactivities ~~the~~on ~~future~~our assets.

~~Under~~The ~~the~~Oil ~~federal~~Pollution ~~Comprehensive~~Act ~~Environmental~~of ~~Response~~1990, ~~Compensation~~as ~~and Liability Act (“CERCLA”)~~amended, also known as the “~~Superfund~~OPA,” ~~law,~~pertains ~~and~~to ~~comparable~~the prevention ~~state~~of ~~laws,~~and ~~liability~~response ~~generally~~to ~~is joint~~spills ~~and~~or ~~several~~discharges ~~for costs~~ of ~~investigation~~oil ~~and~~into ~~remediation~~navigable ~~and~~waters ~~for~~of ~~natural~~the ~~resource damages,~~United ~~without~~States. ~~regard~~The toOPA ~~fault~~imposes orstrict, ~~the~~joint ~~legality~~and ofseveral ~~the~~liability ~~original conduct,~~ on ~~certain~~liable ~~classes~~responsible ofparties ~~persons with~~for ~~respect~~oil toremoval ~~the~~costs ~~release~~and ~~into~~a ~~the~~variety ~~environment~~ of ~~substances~~public ~~designated~~and ~~under~~private ~~CERCLA~~damages, asincluding ~~hazardous substances~~natural ~~(“Hazardous Substances”)~~resource damages. ~~These~~A ~~classes~~liable ~~of persons, or so-called potentially~~ “responsible ~~parties~~ ~~(“PRP~~party”), ~~include~~includes ~~current~~the ~~and~~owner ~~certain~~or ~~past~~operator ~~owners and operators~~ of a facility, ~~where~~vessel ~~there~~or ~~has~~pipeline ~~been~~that is a ~~release~~source ~~or threat~~ of ~~release~~an ofoil adischarge ~~Hazardous~~or ~~Substance~~that ~~and~~poses ~~persons~~the ~~who~~substantial ~~disposed~~threat of ordischarge ~~arranged~~or, ~~for~~in the ~~disposal~~case of ~~the~~offshore ~~Hazardous~~facilities, ~~Substances~~the ~~found~~lessee ator ~~such~~permittee aof ~~facility. CERCLA also authorizes~~ the ~~EPA~~area ~~and,~~ in ~~some~~which ~~cases,~~a discharging ~~third~~facility ~~parties~~is tolocated. ~~take~~Regulations ~~actions~~under ~~in response to threats to~~ the ~~public~~ ~~health~~OPA orand the ~~environment~~Clean ~~and~~Water toAct ~~seek~~also torequire certain ~~recover~~owners ~~from~~and ~~the~~operators ~~PRP the costs~~ of ~~such~~facilities ~~action. Although~~that ~~CERCLA~~store ~~generally~~or ~~exempts~~otherwise ~~“petroleum”~~handle ~~from~~oil, ~~the~~such ~~definition~~as ~~of Hazardous Substance~~ours, ~~in the~~to ~~course~~prepare ofand ~~its~~implement ~~operations~~spill prevention, wecontrol, ~~have generated~~ and ~~will~~countermeasure, ~~generate~~or ~~wastes~~“SPCC,” ~~that~~plans ~~fall~~and ~~within CERCLA’s~~spill ~~definition~~response ofplans ~~Hazardous~~relating ~~Substances.~~to Wepossible ~~may~~discharges ~~also~~of beoil aninto ~~owner~~surface orwaters. ~~operator~~Our ofSPCC ~~facilities~~plans ~~on which Hazardous Substances~~ have been ~~released.~~updated Weto ~~may~~comply bewith ~~responsible~~the ~~under~~current ~~CERCLA~~regulations. ~~for~~We ~~all~~continue orto ~~part~~monitor ofrapid ~~the~~changes in ~~costs~~rules toand ~~clean~~requirements ~~up facilities~~ at ~~which~~both ~~such~~the ~~substances~~federal ~~have been released~~ and ~~for~~state ~~natural~~level ~~resource damages,~~regarding asspill ~~a past or present owner or operator or as an arranger~~prevention. ToWe ~~our knowledge, we have not~~cannot ~~been~~assure ~~named~~you athat ~~PRP~~costs ~~under~~that ~~CERCLA~~may ~~nor~~be ~~have~~necessary ~~any~~for ~~prior~~compliance ~~owners~~with orthese ~~operators~~SPCC ofand ~~our~~comparable ~~properties been named~~state asrequirements ~~PRP’s~~will ~~related~~not tobe ~~their ownership or operation of such property~~material.

~~Although~~The ~~oil and gas wastes generally are exempt from regulation as hazardous wastes (“Hazardous Wastes”) under the~~ federal ~~Resource~~Occupational ~~Conservation~~Safety and ~~Recovery~~Health Act (“~~RCRA~~OSHA”) and comparable state statutes, itimpose requirements isrelated ~~possible~~to ~~some~~disclosure ~~wastes~~and weorganization ~~generate~~of ~~presently~~certain orinformation inrelated ~~the future may be subject~~ to ~~regulation under RCRA and state analogs~~hazardous materials. The ~~U.S.~~OSHA ~~EPA~~hazard ~~and~~communication ~~various~~standard, ~~state agencies have limited~~ the ~~disposal~~EPA ~~options~~community ~~for certain wastes, including hazardous wastes and is considering adopting stricter disposal standards for non~~right-~~hazardous~~to-know ~~wastes. Moreover, ordinary industrial~~regulations ~~wastes,~~under ~~such~~Title asIII ~~paint~~of ~~wastes,~~CERCLA ~~waste solvents, laboratory wastes,~~ and ~~waste~~similar ~~compressor~~state ~~oils,~~statutes may ~~be regulated~~require ~~as hazardous waste. Although the costs of managing these wastes generated by~~ us ~~may be significant, we do not expect~~ to ~~experience~~organize ~~more~~and/or ~~burdensome~~disclose information ~~costs~~about ~~than~~hazardous ~~similarly~~materials ~~situated~~used ~~companies involved~~or produced in ~~oil~~our ~~and gas exploration and production~~operations.

15Oil 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.

~~Table~~In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of ~~Contents~~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.

WeItem ~~currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas~~1A. ~~Hydrocarbons~~RISK or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial plugging or pit closure operations to prevent future contamination. FACTORS

~~The~~Our ~~federal~~business ~~Clean~~activities ~~Air~~are ~~Act~~subject ~~and~~to ~~analogous~~significant ~~state~~hazards ~~laws~~and ~~restricts~~risks, ~~the~~including ~~emission of air pollutants~~those ~~from~~described ~~many~~below. ~~sources,~~If ~~including~~any ~~equipment~~of wethese ~~use~~events ~~such~~should asoccur, ~~compressors~~our tobusiness, ~~transport~~financial ~~natural~~condition, ~~gas in our~~liquidity ~~pipelines.~~or ~~Federal~~results ~~and~~of ~~state~~operations ~~laws~~could ~~generally~~be ~~require~~materially ~~new~~adversely ~~and~~affected. ~~modified~~Additional ~~sources~~risks ofnot ~~air pollutants to~~presently ~~obtain~~known ~~permits prior~~ to ~~commencing~~us ~~construction,~~or which ~~may~~we ~~require,~~consider ~~among~~immaterial ~~other~~based ~~things,~~on ~~stringent, technical~~information ~~controls.~~currently ~~Other~~available ~~federal and state laws designed~~ to ~~control~~us ~~hazardous~~may ~~(toxic) air~~also ~~pollutants,~~materially ~~might~~adversely ~~require~~affect ~~installation of additional controls~~us. ~~Administrative~~Please ~~enforcement~~also ~~agencies can~~refer ~~bring actions for failure~~ to ~~strictly~~the ~~comply~~cautionary ~~with~~note ~~air~~under ~~pollution regulations or permits and~~“Forward-Looking ~~generally~~Statements” ~~enforce~~on ~~compliance~~page ~~through~~1 ~~administrative,~~of ~~civil~~this orAnnual ~~criminal enforcement actions, resulting in fines, injunctive relief and imprisonment~~Report.

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

~~Because~~Hedging oftransactions the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may ~~result~~ inlimit ~~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~~potential ~~material~~gains ~~expenses to comply, e.g., by being required to purchase~~ or ~~to surrender~~expose ~~allowances~~us for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to ~~be affected any differently than other similarly situated domestic competitors~~loss.

~~Our~~To ~~operations~~manage ~~involve~~our ~~discharges~~exposure to ~~surface~~price ~~waters~~risks ofin ~~fluids associated with~~ the ~~production~~ marketing of ~~oil~~our ~~and~~natural gas., ~~The~~we ~~federal~~enter ~~Clean~~into natural ~~Water~~gas ~~Act~~fixed-price ~~and~~physical ~~analogous~~delivery ~~state~~contracts ~~laws~~as ~~impose~~well ~~restrictions~~as ~~and strict~~commodity ~~controls~~price ~~regarding~~swap ~~the discharge of these fluids from oil~~ and ~~gas operations into state~~collar ~~waters~~contracts orfrom ~~waters~~time ofto ~~the~~time ~~United States, a term broadly defined, prohibiting discharge, except in accord~~ with ~~the~~respect ~~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~~portion of ~~oil~~our ~~and~~current ~~gas~~or future production. ~~These~~ ~~injection wells are subject to stringent regulation and permitting requirements. At our oil~~In ~~and~~connection ~~gas~~with ~~wells~~the ~~in Ohio and Pennsylvania~~Merger, ~~wastewater~~we isbecame ~~collected~~a ~~in aboveground tanks and collected by third-~~party ~~contractors~~to ~~for~~a ~~disposal off~~long-~~site.~~term ~~The~~hedging ~~Clean~~program ~~Water~~with ~~Act also prohibits certain activity in wetlands unless authorized by a permit issued by the U~~J.S. ~~Army Corps of Engineers~~Aron. ~~The~~We ~~U.S.~~anticipate ~~EPA~~the ~~also~~hedges ~~has~~will ~~adopted~~cover ~~regulations~~approximately ~~requiring~~66% ~~certain~~of ~~oil~~the ~~and~~expected ~~gas~~2011 ~~exploration~~through ~~and~~2013 production ~~facilities~~from toour ~~obtain~~current ~~permits~~estimated ~~for~~proved ~~storm water discharges under certain circumstances~~reserves. ~~Sanctions~~These ~~for failure~~transactions tomay ~~comply~~limit ~~with~~our ~~Clean~~potential ~~Water~~gains ~~Act requirements, including permit requirements, include~~if ~~administrative,~~natural ~~civil~~gas and ~~criminal~~crude ~~penalties,~~oil asprices ~~well~~were ~~as injunctive relief.~~to

1618

~~Table~~rise substantially over the prices specified in the hedge agreement. In addition, such transactions may expose us to the risk of ~~Contents~~financial loss in certain circumstances, including instances in which:

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

~~The~~• ~~Oil~~there Pollution Act of 1990, as amended, also known as the “OPA,” pertains to the prevention of and response to spills or discharges of hazardous substances or oil into navigable waters of the United States. The OPA imposes strict, joint and several liability on liable responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a ~~source~~narrowing of anprice ~~oil~~differentials ~~discharge~~between ordelivery ~~that~~points ~~poses~~for ~~the~~our ~~substantial~~production ~~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~~delivery ~~Water~~points ~~Act~~assumed 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~~hedge ~~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.~~ arrangements;

~~The~~• ~~federal~~there ~~Occupational~~is ~~Safety~~a ~~and~~failure ~~Health Act (“OSHA”) and comparable state statutes impose requirements related to disclosure and organization~~ of ~~certain~~a ~~information~~hedge ~~related~~counterparty to ~~hazardous materials.~~perform ~~The~~under ~~OSHA hazard communication standard,~~ the ~~EPA~~Hedge ~~community~~Agreement ~~right-to-know~~or ~~regulations under~~other ~~Title~~hedge ~~III~~transactions ofwhich ~~CERCLA~~risk ~~and~~has ~~similar~~increased ~~state~~with ~~statutes~~the ~~may~~current ~~require~~economic ~~us to organize~~ and~~/or~~ ~~disclose information~~financial ~~about~~crisis; ~~hazardous materials used~~ or ~~produced in our operations.~~

~~Item~~• ~~1A.~~a ~~RISK~~sudden, ~~FACTORS~~unexpected event materially impacts natural gas and crude oil prices.

~~Our~~While ~~business~~we ~~activities~~believe ~~are~~J. ~~subject~~Aron to ~~significant~~be ~~hazards~~a strong and ~~risks~~creditworthy counterparty, ~~including~~disruptions ~~those~~occurring ~~described~~in ~~below.~~the Iffinancial ~~any~~markets ofcould ~~these~~lead ~~events~~to ~~should~~sudden ~~occur,~~changes ~~our~~in ~~business,~~a ~~financial~~counterparty’s ~~condition~~liquidity, ~~liquidity~~which could orimpair ~~results~~their ofability ~~operations~~to ~~could~~perform beunder ~~materially~~the ~~adversely~~terms ~~affected.~~of ~~Additional~~the ~~risks~~hedging ~~not~~contract. ~~presently known~~We toare usunable orto ~~which~~predict sudden wechanges ~~consider~~in ~~immaterial~~a ~~based~~counterparty’s oncreditworthiness ~~information~~or ~~currently~~ability ~~available~~ to usperform. ~~may~~Even ~~also materially~~if ~~adversely~~we ~~affect~~do ~~us.~~accurately predict ~~Please~~sudden ~~also~~changes, ~~refer~~our ability to negate the ~~cautionary~~risk ~~note~~may ~~under~~be ~~“Forward-Looking Statements”~~limited ondepending ~~page~~upon ~~1 of this Annual Report~~market conditions.

~~Risks~~Our ~~Relating~~operations torequire ~~Our~~large ~~Business~~amounts of capital that may not be recovered or raised.

~~Hedging~~If ~~transactions~~our ~~may~~revenues ~~limit~~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 ~~potential~~credit ~~gains~~facilities or ~~expose~~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 ~~loss~~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:

To• ~~manage our exposure to price risks in~~ the ~~marketing~~success of our ~~natural~~projects gas, we enter into natural gas fixed-price physical delivery contracts as well as commodity price swap and collar contracts from time to time with respect to a portion of our current or future production. In connection with the Merger, we became a party to a long-term hedging program with J. Aron. We anticipate the hedges will cover approximately 73% of the expected 2010 through 2013 production from our current estimated proved reserves. These transactions may limit our potential gains if natural gas prices were to rise substantially over the prices specified in the ~~hedge~~Appalachian ~~agreement.~~and ~~In addition,~~Michigan ~~such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:~~ basins;

• our ~~production~~success isin ~~less~~locating ~~than~~and ~~expected~~producing new reserves;

• ~~there~~the islevel ~~a narrowing~~ of ~~price differentials between delivery points for our~~ production ~~and~~from ~~the~~existing ~~delivery points assumed in the hedge arrangements~~wells; and

• ~~there~~prices ~~is a failure~~ of aoil ~~hedge counterparty to perform under the Hedge Agreement or other hedge transactions which risk has increased with the current economic~~ and ~~financial~~natural ~~crisis; or~~gas.

•In addition, debt financing could lead to a ~~sudden,~~diversion ~~unexpected~~of ~~event~~cash ~~materially~~flow ~~impacts~~to ~~natural~~satisfy ~~gas~~debt servicing obligations and ~~crude~~to ~~oil~~restrictions ~~prices~~on our operations.

17Oil and natural gas prices are volatile, and an extended decline in prices would hurt our profitability and financial condition.

~~Table~~While we have entered into long-term hedges covering most of ~~Contents~~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

~~While we believe J. Aron to be a strong and creditworthy counterparty, disruptions occurring~~19 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~~price ~~operations~~of ~~require~~oil ~~large~~and ~~amounts~~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 ~~capital~~oil ~~that~~and natural ~~may~~gas. ~~not~~These befactors ~~recovered~~include: North American supplies of oil and gas; political instability or ~~raised~~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.

IfThese ~~our~~external ~~revenues~~factors ~~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~~volatile ~~and~~nature ~~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~~energy ofmarkets ~~equity,~~make ~~long-term~~it ~~debt financing~~difficult ~~and short-term financing arrangements. We cannot assure you, however, that our business~~to ~~will~~estimate ~~generate sufficient cash flow from operations or that~~ future ~~borrowings~~commodity ~~will be available to us under our Amended Credit Agreement in an amount sufficient to enable us to pay our indebtedness, including the Senior Secured Notes or to fund our other liquidity needs~~prices. ~~We may need to refinance~~ all or a portion of our indebtedness, including the Senior Secured Notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our Amended Credit Agreement and the Senior Secured Notes, on commercially reasonable terms or at all, especially given the current economic and financial market crisis. Future cash flows and the availability of financing will be subject to a number of variables, such as:

•If ~~the~~oil ~~success~~and ofnatural gas prices decrease or our ~~projects~~drilling inefforts are unsuccessful, we may be required to write down the ~~Appalachian~~carrying value of our oil and ~~Michigan~~natural ~~basins;~~gas properties.

•There is a risk that we will be required to write down the carrying value of our ~~success~~oil inand ~~locating~~gas properties, which would reduce our earnings and ~~producing~~stockholders’ ~~new~~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 ~~level~~efforts method of ~~production~~accounting. ~~from~~Under ~~existing~~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 ~~prices~~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 ~~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. 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.

InWe ~~addition~~review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, ~~debt~~a ~~financing~~write ~~could~~down ~~lead~~of tooil and gas properties is not reversible at a ~~diversion~~later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of ~~cash~~price ~~flow~~volatility in the oil and gas markets, events may arise that would require us to ~~satisfy~~record ~~debt~~an ~~servicing~~impairment of the ~~obligations~~recorded book values associated with oil and togas ~~restrictions~~properties. onIn 2010 and 2009, we recorded impairments to our ~~operations~~oil and natural gas properties of $1.6 million and $30.4 million, respectively.

~~Oil~~Information ~~and~~concerning ~~natural~~our ~~gas~~reserves ~~prices are volatile,~~ and anfuture ~~extended~~net ~~decline~~revenues inis ~~prices would hurt our profitability and financial condition~~uncertain.

~~While~~This weAnnual ~~have~~Report ~~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~~other ~~remains unhedged.~~SEC Wefilings ~~expect~~contain ~~that~~estimates ~~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~~estimated ~~and~~proved ~~results of operations. Our revenues, operating results, profitability, future rate of growth and the carrying value of our~~ oil and ~~gas properties depend heavily on prevailing market~~ prices for oil and gas. If gas prices decreased $1.00 per Mcf, our gas sales revenues would decrease by approximately $11.7 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $3.2 million. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $1.00 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas by approximately $3.5 million after considering the effects of the derivative contracts in place as of December 31, 2009. This sensitivity analysis is based on our 2009 oil and gas sales volumes. A material decline could reduce our cash flow and borrowing capacity, as well as the value and the amount of our natural gas reserves. ~~Approximately~~and ~~86% of our proved reserves are natural gas. Therefore, we are more directly impacted by volatility in~~ the ~~price~~estimated ~~of natural gas. For example, as of December 31, 2009, a 10% reduction in the price of oil and natural gas would have reduced our~~ future net ~~cash~~revenues ~~flow~~ from ~~proved~~such reserves ~~by $37 million~~. ~~Various~~Actual ~~factors beyond~~results ~~our control can affect prices of oil and natural gas. These factors include: North American~~will ~~supplies~~most oflikely ~~oil~~vary ~~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~~amounts ~~recession; marketability of production; the level of consumer demand; the price~~estimated, ~~availability~~ and ~~acceptance~~any ofsignificant ~~alternative~~variance ~~fuels;~~could ~~the~~have ~~availability~~a ofmaterial ~~pipeline capacity; weather~~adverse ~~conditions,~~effect ~~including~~on ~~the~~our ~~current~~future ~~economic~~results ~~and capital market crisis; and actions~~ of ~~federal, foreign, state, and local authorities~~operations.

18Reserve 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.

~~Table~~Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of ~~Contents~~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

~~These external factors and the volatile nature of the energy markets make it difficult to~~20 ~~estimate future commodity prices.~~

Ifadjust ~~oil~~estimates ~~and~~of ~~natural~~proved ~~gas~~reserves ~~prices~~to ~~decrease~~reflect orproduction ~~our~~history, ~~drilling~~results ~~efforts~~of ~~are~~exploration ~~unsuccessful~~and development, weprevailing ~~may~~oil ~~be required~~and tonatural ~~write~~gas ~~down~~prices ~~the~~and ~~carrying~~other ~~value~~factors, many of ~~our~~which ~~oil~~are ~~and~~beyond ~~natural gas properties~~our control.

~~There~~At isDecember 31, a2010, ~~risk~~approximately ~~that~~10% weof ~~will~~our beestimated ~~required~~proved reserves were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is nearly always based on analogy to ~~write~~existing ~~down~~wells rather than the ~~carrying~~performance ~~value~~data ofused ~~our~~to estimate ~~oil~~producing ~~and~~reserves. ~~gas properties,~~Recovery ~~which~~of ~~would~~proved ~~reduce~~undeveloped ~~our~~reserves ~~earnings~~requires significant capital expenditures and ~~stockholders’~~successful ~~equity~~drilling operations. AProduction ~~write~~revenues ~~down~~from ~~could~~estimated ~~occur~~proved ~~when~~developed ~~oil~~non-producing ~~and~~reserves ~~gas~~will ~~prices~~not ~~are~~be ~~low~~realized oruntil ifsome time in the future. The reserve data assumes that we ~~have~~will ~~substantial~~make ~~downward~~significant ~~adjustments~~capital expenditures to develop our ~~estimated proved~~ reserves,. ~~increases~~Although we inhave ~~our~~prepared estimates of ~~development~~our reserves and the costs orassociated ~~deterioration~~with these reserves in accordance ~~our~~with ~~drilling~~industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated.

WeThe ~~account~~SEC ~~for~~amended ~~our natural gas and crude oil exploration and development activities using~~ the ~~successful~~ ~~efforts~~definition ~~method~~ of ~~accounting.~~proved ~~Under~~reserves ~~this~~for ~~method,~~all ~~costs~~reserves ofestimated ~~productive~~included ~~exploratory wells,~~in ~~developmental~~filings ~~dry~~after ~~holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs~~January 1, ~~including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred~~2010. ~~Exploratory~~As ~~drilling~~a ~~costs are initially capitalized~~result, ~~but~~our ~~charged~~estimates ~~to expense~~of ifproved ~~and when the well is determined not to have found~~ reserves filed in ~~commercial quantities.~~reports ~~The~~prior ~~capitalized~~to ~~costs~~January 1, of2010 ~~our oil and gas properties~~ may not ~~exceed~~be ~~the~~comparable ~~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~~reports ~~estimate~~filed ofafter ~~fair~~that ~~market value. Any such charge will not affect our cash flow from operating activities~~date, ~~but~~including itthose ~~will reduce our earnings and~~in ~~stockholders’~~this ~~equity~~annual report.

~~The~~Analysts ~~application~~and ofinvestors ~~the~~should ~~successful~~not ~~efforts~~construe ~~method of accounting requires managerial judgment to determine~~ the ~~proper~~present ~~classification~~value of ~~wells~~future ~~designated~~net asreserves, ~~developmental~~or PV-10 or ~~exploratory,~~the ~~which~~standardized ~~will ultimately~~measure, ~~determine~~as the ~~proper~~current ~~accounting~~market ~~treatment~~value of the ~~costs~~estimated ~~incurred.~~oil ~~The~~and ~~results~~natural ~~from a~~gas ~~drilling~~reserves ~~operation~~attributable ~~can take considerable time~~ to ~~analyze~~our ~~and~~properties. ~~the~~We ~~determination that commercial reserves~~ have ~~been~~based ~~discovered~~the ~~requires~~estimated ~~both~~discounted ~~judgment~~future ~~and~~net ~~industry experience. Wells may be~~cash ~~completed~~flows ~~that~~from ~~are~~estimated ~~assumed~~proved toreserves beon ~~productive~~prices ~~but may actually deliver oil~~ and ~~gas~~costs inas ~~quantities insufficient~~of ~~to be economic, which may result in~~ the ~~abandonment~~date of the ~~wells~~estimate, ~~at a later date.~~in ~~Wells~~accordance ~~are~~with ~~drilled~~applicable ~~that~~regulations, ~~have~~whereas ~~targeted~~actual ~~geologic~~future ~~structures~~prices ~~that are both developmental~~ and ~~exploratory~~ ~~in nature and an allocation of~~ costs ismay ~~required~~be tomaterially higher ~~properly~~or ~~account for the results~~lower. ~~The~~ ~~evaluation~~Many offactors ~~oil~~will ~~and~~affect ~~gas~~actual ~~leasehold~~future ~~acquisition~~net ~~costs~~cash ~~requires~~flows, ~~judgment to estimate the fair~~including: ~~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~~amount ~~of their carrying value. Once incurred, a write down of oil~~ and ~~gas~~ ~~properties~~timing ~~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~~actual volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded book values associated with oil and gas properties. In 2009 and 2008, we recorded an impairments to our oil and natural gas properties of $30.4 million and $3.9 million, respectively. production;

~~Information~~• ~~concerning~~supply ~~our reserves~~ and ~~future~~demand ~~net~~for ~~revenues~~natural ~~is uncertain.~~ gas;

~~This~~• ~~Annual~~curtailments ~~Report~~or ~~and~~increases ~~our~~in ~~other~~consumption ~~SEC~~by ~~filings contain estimates of our estimated proved oil and~~ natural gas ~~reserves~~purchasers; 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~~changes 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~~governmental ~~evaluation~~regulations ofor ~~available geological, geophysical, engineering and economic data for each reservoir~~taxation. 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~~The ~~future~~timing of the production, of oil and natural gas ~~prices,~~and ~~revenues,~~of ~~taxes,~~the ~~development expenditures,~~related ~~operating~~ expenses ~~and~~affect ~~quantities~~the timing of ~~recoverable~~actual ~~oil~~future ~~and~~net ~~natural~~cash ~~gas~~flows ~~reserves~~from ~~will most~~estimated ~~likely~~proved ~~vary~~reserves ~~from~~and, ~~those~~thus, ~~estimated~~their actual present value. ~~Any~~In ~~significant~~addition, ~~variance~~the ~~could~~10% ~~materially~~discount ~~affect~~factor, ~~the estimated~~which ~~quantities~~we ~~and~~are ~~present~~required ~~value~~to ofuse ~~reserves~~to ~~disclosed~~calculate Standardized byMeasure ~~us.~~for Inreporting ~~addition~~purposes, weis ~~may~~not ~~adjust~~necessarily the most appropriate discount ~~estimates~~factor ofgiven ~~proved~~actual ~~reserves~~interest torates ~~reflect~~and ~~production~~risks ~~history,~~to ~~results~~which ofour ~~exploration~~business ~~and~~or ~~development, prevailing~~the oil and natural gas industry ~~prices~~in ~~and~~general ~~other factors, many of which~~ are ~~beyond our control~~subject.

AtOur ~~December 31,~~exploitation ~~2009, approximately 9% of our estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves~~ and ~~proved~~development 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.~~activities 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~~successful.

19Our 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:

~~Table~~• ofunexpected ~~Contents~~drilling conditions;

~~The~~• ~~SEC~~pressure ~~amended~~or ~~the~~irregularities ~~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. formations;

~~Analysts~~• ~~and~~equipment ~~investors~~failures ~~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: accidents;

• ~~the~~ability ~~amount~~to hire and ~~timing~~train ofpersonnel ~~actual~~for ~~production~~drilling and completion services;

• ~~supply~~adverse ~~and~~weather ~~demand for natural gas~~conditions;

• ~~curtailments~~compliance orwith ~~increases~~governmental ~~in consumption by natural gas purchasers~~requirements; and ~~• changes in governmental regulations or taxation.~~

~~The~~• ~~timing~~shortages ofor ~~the~~delays ~~production~~in ~~of oil and natural gas and of~~ the ~~related~~availability ~~expenses affect the timing~~ of ~~actual~~drilling ~~future~~rig ~~net~~services ~~cash flows from estimated proved reserves~~ and, ~~thus, their actual present value. In addition,~~ the ~~10%~~delivery ~~discount~~of 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 subjectequipment.

~~Our~~In ~~exploitation~~addition, ~~and~~we ~~development~~may not be able to obtain any options or lease rights in potential drilling locations ~~activities~~that ~~may~~we ~~not~~identify. beThere ~~successful~~is no guarantee that the potential drilling locations that we have identified will ever produce oil or natural gas.

~~Our~~If ~~future~~our development drilling activities ~~may~~are 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~~be ~~all~~able orto ~~any~~replace ~~portion of our capital investment in the wells, infrastructure,~~ or ~~the underlying leaseholds. Unsuccessful~~ ~~drilling~~grow ~~activities could negatively affect~~ our ~~results of operations and financial condition~~reserves. ~~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;~~21

•We ~~pressure~~face orstrong ~~irregularities~~competition in ~~formations;~~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, ~~failures~~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 ~~accidents;~~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 ~~ability~~operations are subject to ~~hire~~the business and ~~train~~financial ~~personnel~~risk ~~for~~of ~~drilling~~oil and ~~completion~~natural ~~services;~~gas exploration.

•The ~~adverse~~business ~~weather~~of ~~conditions;~~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 ~~compliance~~business ~~with~~is ~~governmental~~subject ~~requirements;~~to ~~and~~operating hazards that could result in substantial losses.

•The ~~shortages~~oil and natural gas business involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or ~~delays~~well influids, ~~the~~fires, ~~availability~~formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of ~~drilling~~toxic ~~rig~~gas ~~services~~and other environmental hazards and ~~the~~risks, ~~delivery~~any of ~~equipment~~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.

InWe ~~addition,~~must wecomply ~~may~~with ~~not~~complex befederal, ~~able~~state toand ~~obtain~~local ~~any~~laws ~~options~~and ~~or lease rights in potential drilling locations that we identify~~regulations. ~~There is no guarantee that the potential drilling locations that we~~ ~~have identified will ever produce oil or natural gas.~~

IfFederal, ~~our~~state, ~~development~~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, ~~are~~including ~~not~~the ~~successful~~pricing and marketing of oil and natural gas production, wethe drilling ~~may~~of ~~not~~wells be(through ~~able~~permit toand ~~replace~~bonding requirements), the positioning of wells, the unitization or pooling of oil and natural gas properties, environmental matters, safety standards, ~~grow~~the ~~our~~sharing ~~reserves~~of markets, production limitations, plugging and abandonment, and restoration. These laws and regulations are under constant review for amendment or expansion.

We ~~face~~may ~~strong~~incur ~~competition~~substantial incosts ~~the~~to ~~oil~~comply ~~and~~with ~~natural~~stringent ~~gas~~environmental ~~industry,~~regulations and ~~the~~these regulations ~~resources~~may ofadversely ~~many~~affect ~~of our~~the ~~competitors~~manner ~~are~~or ~~greater~~feasibility ~~than~~of ~~ours~~conducting our operations.

WeOur ~~operate~~operations inare asubject ~~highly~~to ~~competitive~~stringent ~~industry.~~and Weconstantly ~~compete~~changing ~~with~~environmental ~~major~~laws ~~oil~~and regulations ~~companies~~adopted by federal, ~~independent producers~~state, and ~~institutional~~local ~~and~~governmental ~~individual~~authorities. ~~investors,~~We ~~who~~could ~~are~~be ~~actively~~forced ~~seeking~~to expend ~~oil~~significant ~~and~~resources ~~natural~~to ~~gas properties~~comply ~~throughout~~with ~~the~~new ~~world~~laws or regulations, ~~along~~or ~~with~~changes ~~the~~to ~~equipment,~~current requirements ~~labor~~or ~~and~~to ~~materials~~obtain ~~required~~permits and authorizations to ~~operate properties~~conduct our operations. ~~Many~~We ofwill ~~our~~continue to ~~competitors~~be ~~have~~subject ~~financial~~to ~~and~~uncertainty ~~technological~~associated ~~resources~~with ~~vastly~~new ~~exceeding~~regulatory interpretations and inconsistent ~~those~~interpretations ~~available~~between togovernmental usenvironmental agencies. ~~Many~~We ~~oil~~could face significant liabilities to the government and third parties for discharges of oil, natural gas ~~properties~~or ~~are~~other pollutants ~~sold~~into inthe aair, ~~competitive~~soil ~~bidding process~~or inwater, ~~which~~and we ~~may~~could ~~lack~~have ~~technological~~to ~~information~~spend orsubstantial ~~expertise~~amounts ~~available~~on investigations, litigation and remediation, as well as our efforts to ~~other~~prevent ~~bidders.~~future Wespills. ~~cannot~~Moreover, ~~assure~~our ~~you~~failure ~~that~~to wecomply ~~will~~with bethese ~~successful~~laws and regulations may result in ~~acquiring~~the assessment of administrative, civil and ~~developing~~criminal ~~profitable~~penalties, ~~properties~~the inimposition of investigatory and remedial obligations and the ~~face~~issuance of ~~this~~injunctions ~~competition~~that restrict or prohibit the performance of operations. See “Items 1 and 2 — Business and Properties — Regulation.”

20Climate 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.

~~Table~~The ofEPA ~~Contents~~has been moving forward to regulate GHS as pollutants under the CAA. By adopting rules regulating GHG

~~Our operations are subject to the business and financial risk of oil and natural gas~~22 ~~exploration.~~

~~The~~ emissions ~~business~~from ofmotor ~~exploring~~vehicles, ~~for~~EPA ~~and,~~triggered requirements to apermit ~~lesser~~GHG ~~extent,~~emissions ~~developing~~from stationary ~~oil~~sources under the Prevention of Significant Deterioration (PSD) and ~~natural~~Title ~~gas~~V permitting ~~properties~~programs. isEPA anhas ~~activity~~implemented ~~that~~the ~~involves~~so-called a“Tailoring ~~high~~Rule” ~~degree~~requiring ofthat ~~business~~the ~~and~~largest ~~financial~~sources ~~risk. Property~~to ~~acquisition~~first ~~decisions~~obtain ~~generally~~permits ~~are~~for ~~based~~GHG onemissions. ~~various~~There ~~assumptions~~is ~~and~~still ~~subjective~~the ~~judgments~~possibility that ~~are~~federal legislation ~~speculative.~~will Itbe isadopted ~~impossible~~ to ~~predict~~change ~~accurately~~ the ~~ultimate~~GHG ~~production~~permitting ~~potential~~program put in place by EPA, ifbut ~~any~~to date, ofefforts at a comprehensive GHG legislative package (such as a ~~particular~~cap ~~property~~and ortrade ~~well~~program) appear not to be moving forward in Congress. ~~Moreover~~Some members of Congress, ~~the~~however, ~~successful~~continue ~~completion~~to ofpublicly indicate an ~~oil~~intention to promote legislation to curb EPA’s authority to regulate GHGs. Additionally, some states, regions and localities have adopted or ~~natural~~are ~~gas~~considering ~~well~~programs to address GHGs. The adoption and ~~does~~implementation ~~not~~of ~~insure~~any aregulations ~~profit~~imposing reporting obligations on, ~~investment.~~or Alimiting ~~variety~~emissions of greenhouse ~~factors~~gases from, ~~both~~our ~~geological~~equipment and ~~market-related, can~~operations ~~cause~~could arequire ~~well~~us to ~~become~~incur ~~uneconomic~~costs to reduce emissions of greenhouse gases associated with our operations or ~~marginally~~could ~~economic~~adversely affect demand for the oil and natural gas that we produce.

~~Our~~In ~~business~~addition, isEPA ~~subject~~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 ~~operating~~include ~~hazards~~onshore ~~that~~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 ~~result~~require inus ~~substantial~~to ~~losses~~incur costs to monitor, keep records of, and report emissions of GHGs.

~~The~~Because ~~oil~~of ~~and~~the ~~natural~~lack ~~gas~~of ~~business~~any ~~involves~~comprehensive ~~operating~~legislative ~~hazards~~program ~~such~~addressing ~~as well blowouts~~GHGs, ~~craterings, explosions,~~there ~~uncontrollable~~is ~~flows~~a great deal of ~~oil,~~uncertainty ~~natural~~regarding ~~gas~~the orregulation ~~well~~of ~~fluids,~~GHGs ~~fires,~~at ~~formations~~the ~~with abnormal~~federal ~~pressures,~~level. ~~pipeline~~In ~~ruptures~~addition orto ~~spills,~~possible federal ~~pollution~~regulation, ~~releases~~a number of ~~toxic~~states, ~~gas~~individually and ~~other environmental~~regionally, ~~hazards~~also ~~and~~are ~~risks,~~considering ~~any~~or ofhave implemented ~~which~~GHG ~~could~~regulatory ~~cause~~programs. usThese apotential ~~substantial~~regional ~~loss.~~and Instate ~~addition,~~initiatives we may beresult ~~held~~in so—called ~~liable~~cap—and—trade ~~for~~programs, ~~environmental~~under ~~damage~~which ~~caused~~overall byGHG ~~previous~~emissions ~~owners~~are oflimited ~~property~~and ~~that~~GHG emissions weare ~~own~~then ~~or lease.~~allocated Asand ~~a result~~sold, weand ~~may~~possibly ~~face~~other ~~substantial~~regulatory ~~liabilities~~requirements, tothat ~~third parties or governmental entities,~~could ~~which~~result ~~could~~in ~~reduce~~our orincurring ~~eliminate~~material ~~funds~~expenses ~~available~~to ~~for operation~~comply, ~~development~~e.g., ~~production~~by ~~or acquisitions~~being orrequired ~~cause~~to uspurchase or to surrender ~~incur~~allowances ~~losses.~~for AnGHGs ~~event~~resulting ~~that~~from isour ~~not~~operations ~~fully~~or ~~covered~~otherwise bybeing ~~insurance~~required ~~(for~~to control ~~example~~or ~~losses~~reduce ~~resulting~~emissions. ~~from~~The ~~pollution~~federal, regional and ~~environmental~~local ~~risks,~~regulatory ~~which~~initiatives ~~are~~also ~~not~~could ~~fully insurable)~~adversely ~~could~~affect ~~have~~the amarketability ~~material~~of ~~adverse~~the ~~effect~~oil ~~on our financial condition~~ and ~~results~~natural ofgas ~~operations~~we produce.

WeSignificant ~~must~~physical ~~comply~~effects ~~with~~of ~~complex~~climatic ~~federal~~change have the potential to damage our facilities, disrupt ~~state~~our production activities and ~~local~~cause ~~laws~~us ~~and~~to ~~regulations~~incur significant costs in preparing for or responding to those effects.

~~Federal,~~ In ~~state~~an interpretative guidance on climate change disclosures, ~~and~~the ~~local~~SEC ~~authorities~~indicates ~~extensively~~that ~~regulate~~climate change could have an effect on the ~~oil~~severity ~~and~~of ~~natural~~weather ~~gas~~(including ~~industry.~~hurricanes and floods), sea ~~Noncompliance~~levels, ~~with~~the ~~these~~arability ~~statutes~~of farmland, and ~~regulations~~water ~~may~~availability ~~lead~~and toquality. ~~substantial~~If ~~penalties~~such effects were to occur, our exploration and production operations have the potential to be adversely affected. ~~overall~~Potential ~~regulatory~~adverse ~~burden~~effects oncould ~~the~~include ~~industry~~damages ~~increases~~to ~~the~~our ~~cost~~facilities offrom ~~doing~~powerful ~~business~~winds ~~and,~~or rising waters in ~~turn~~low-lying areas, ~~decreases~~ ~~profitability.~~disruption ~~Regulations~~of ~~affect~~our ~~various~~production ~~aspects~~activities either because of climate-related ~~oil~~damages ~~and~~to ~~natural~~our ~~gas~~facilities ~~drilling~~in ~~and~~our costs of operations potentially arising from such ~~production~~climatic ~~activities~~effects, ~~including~~less ~~the~~efficient ~~pricing~~or ~~and~~non-routine ~~marketing~~operating ofpractices ~~oil~~necessitated ~~and~~by ~~natural~~climate ~~gas~~effects or ~~production,~~increased costs for insurance coverages in the aftermath of such effects. Significant physical ~~drilling~~effects of ~~wells~~climate ~~(through~~change ~~permit~~could also have an indirect affect on our financing and ~~bonding~~operations ~~requirements),~~by disrupting the ~~positioning~~transportation ofor ~~wells~~process-related services provided by midstream companies, ~~the~~service ~~unitization~~companies or ~~pooling~~suppliers ofwith ~~oil~~whom ~~and~~we ~~natural~~have ~~gas~~a ~~properties,~~business ~~environmental~~relationship. ~~matters,~~We ~~safety~~may ~~standards, the~~not ~~sharing~~be ofable ~~markets,~~to ~~production~~recover through ~~limitations,~~insurance ~~plugging~~some ~~and~~or ~~abandonment,~~any ~~and~~of ~~restoration.~~the ~~These laws~~damages, ~~and~~losses ~~regulations~~or ~~are~~costs ~~under~~that ~~constant~~may ~~review~~result ~~for~~from ~~amendment~~potential physical oreffects ~~expansion~~of climate change.

WeFederal ~~may~~legislation ~~incur~~and ~~substantial~~state ~~costs~~legislative and regulatory initiatives relating to ~~comply~~hydraulic fracturing ~~with~~could ~~stringent~~result ~~environmental~~in ~~regulations~~increased costs and additional operating restrictions or delays.

~~Our~~The ~~operations~~U.S. Senate and House of Representatives are ~~subject~~currently toconsidering ~~stringent~~bills entitled, the “Fracturing Responsibility and ~~constantly~~Awareness ~~changing~~of ~~environmental~~Chemicals ~~laws~~Act,” ~~and regulations~~or ~~adopted~~the by“FRAC Act,” that would amend the federal Safe Drinking Water Act, ~~state~~or the “SDWA,” ~~and~~to ~~local~~repeal ~~governmental~~an ~~authorities~~exemption from regulation for most hydraulic fracturing. WeIf ~~could~~enacted, bethe ~~forced~~FRAC toAct would amend the definition of “underground ~~expend~~injection” ~~significant~~in ~~resources~~the SDWA to ~~comply~~encompass ~~with~~hydraulic ~~new~~fracturing ~~laws~~activities. orIf ~~regulations~~enacted, orsuch ~~changes~~a ~~to current~~provision ~~requirements.~~could Werequire ~~will~~hydraulic ~~continue~~fracturing operations to bemeet ~~subject~~permitting and financial assurance requirements, adhere to ~~uncertainty~~certain ~~associated~~construction ~~with~~specifications, ~~new~~fulfill ~~regulatory interpretations~~monitoring, reporting, and recordkeeping ~~inconsistent~~obligations, ~~interpretations~~and ~~between~~meet ~~governmental~~plugging ~~environmental~~and ~~agencies~~abandonment requirements. ~~We could~~The ~~face~~FRAC ~~significant~~Act ~~liabilities~~also proposes to require the ~~government~~reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties ~~for~~opposing ~~discharges~~the ofhydraulic ~~oil,~~fracturing process to ~~natural~~initiate ~~gas~~legal orproceedings ~~other~~based ~~pollutants~~on ~~into~~allegations ~~the~~that ~~air,~~specific ~~soil~~chemicals orused ~~water,~~in ~~and~~the wefracturing process could ~~have~~adversely toaffect ~~spend~~groundwater. ~~substantial amounts~~EPA onhas ~~investigations,~~initiated ~~litigation~~a study of the environmental impacts of hydraulic fracturing and ~~remediation,~~a ascommittee ~~well~~of asthe ~~our~~U.S. ~~efforts~~Congress tois ~~prevent~~investigating ~~future~~certain hydraulic ~~spills~~fracturing practices. ~~Moreover~~Further, ~~our~~many ~~failure~~states toand ~~comply~~other ~~with~~regulatory ~~these~~authorities ~~laws~~have ~~and~~adopted or are proposing additional regulations ~~may~~on ~~result~~hydraulic infracturing. ~~the assessment~~The adoption of ~~administrative,~~any ~~civil~~future ~~and~~federal ~~criminal~~or state ~~penalties,~~laws ~~the~~or ~~imposition~~implementing ofregulations ~~investigatory~~imposing ~~and remedial~~reporting obligations ~~and~~on, or otherwise limiting, the ~~issuance~~hydraulic offracturing ~~injunctions~~process ~~that~~could ~~restrict~~make orit ~~prohibit~~more ~~the~~difficult ~~performance~~to ~~of operations.~~complete ~~See~~natural ~~“Items~~gas 1wells and increase 2our —costs ~~Business~~of compliance and ~~Properties~~doing ~~— Regulation~~business.”

~~Climate Change Legislation or regulations restricting emissions of “greenhouse gasses” could result~~23 ~~in increased operating costs and reduced demand for the oil and gas we produce.~~

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

21The 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.

~~Table~~In addition, federal, state, and local regulation of ~~Contents~~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.”

~~Significant~~The ~~physical~~adoption ~~effects~~ of ~~climatic~~derivatives ~~change~~legislation ~~have~~or ~~the~~regulations ~~potential~~related to ~~damage~~derivative ~~our~~contracts ~~facilities,~~could have ~~disrupt~~an ~~our~~adverse ~~production~~impact ~~activities~~on ~~and~~our ~~cause~~ability us to ~~incur~~hedge ~~significant~~risks ~~costs~~associated inwith ~~preparing~~our ~~for or responding to those effects~~business.

InOn anJuly 21, ~~interpretative~~2010, ~~guidance~~the onPresident ~~climate~~signed ~~change~~into ~~disclosures,~~law the ~~SEC~~Dodd—Frank ~~indicates~~Wall ~~that~~Street ~~climate~~Reform and ~~change~~Consumer ~~could~~Protection ~~have~~Act an(the ~~effect~~“Act”). onAmong ~~the~~other ~~severity~~things, ofthe ~~weather~~Act ~~(including~~requires ~~hurricanes~~the ~~and~~Commodity ~~floods), sea~~Futures ~~levels,~~Trading Commission and the ~~arability~~SEC ofto ~~farmland,~~enact ~~and~~regulations ~~water~~affecting ~~availability~~derivative ~~and~~contracts, ~~quality.~~including Ifthe derivative ~~such~~contracts ~~effects~~we ~~were~~use to ~~occur,~~ hedge our ~~exploration~~exposure ~~and~~to ~~production~~price ~~operations~~volatility ~~have~~within ~~the~~360 days ~~potential~~from tothe bedate of ~~adversely affected~~enactment. ~~Potential~~ ~~adverse~~We ~~effects~~cannot ~~could~~predict ~~include~~the ~~damages~~content toof ~~our~~these ~~facilities~~regulations ~~from~~or ~~powerful~~the ~~winds~~effect orthat ~~rising~~these ~~waters~~regulations inwill ~~low-lying~~have ~~areas,~~on ~~disruption of~~ our ~~production~~hedging activities. ~~either~~Of ~~because~~particular ofconcern, the Act does not ~~climate-related~~explicitly ~~damages~~exempt toend ~~our~~users ~~facilities~~(such inas ~~our~~us) ~~costs~~from ofthe ~~operation~~requirements ~~potentially~~to ~~arising~~use ~~from~~exchanges, ~~such~~which would ~~climatic~~require ~~effects,~~us ~~less~~to ~~efficient~~post ormargin ~~non-routine~~in ~~operating~~connection ~~practices~~with ~~necessitated~~hedging byactivities. ~~climate~~Even ~~effects or~~if ~~increased~~we ~~costs~~qualify for ~~insurance~~an exception, ~~coverages~~there inare ~~the~~other ~~aftermath~~aspects of ~~such~~the ~~effects.~~Act ~~Significant~~that ~~physical effects~~may ofmake ~~climate~~it ~~change~~more ~~could~~expensive ~~also~~for ~~have~~other anparties ~~indirect~~to offer ~~affect~~these onhedges ~~our~~to ~~financing~~us. ~~and~~The ~~operations~~full ~~by disrupting~~effects of the ~~transportation~~Act orwill ~~process-related~~not ~~services~~be ~~provided~~known byuntil ~~midstream~~the ~~companies,~~regulations ~~service~~have been ~~companies~~enacted orand ~~suppliers~~the ~~with~~market ~~whom~~for ~~we have~~these ahedges ~~business~~has ~~relationship~~adjusted. WeIt ~~may~~is ~~not~~possible bethe ~~able~~hedges towill ~~recover~~become more ~~through~~expensive, ~~insurance~~uneconomic ~~some~~ or ~~any~~unavailable, ofwhich ~~the damages,~~could ~~losses~~lead orto increased costs ~~that~~or ~~may~~commodity ~~result~~price volatility ~~from~~or ~~potential~~a ~~physical~~combination ~~effects~~ of ~~climate change~~both.

~~Federal~~The ~~legislation~~distressed ~~and~~financial ~~state~~conditions ~~legislative~~of ~~and~~customers ~~regulatory~~could ~~initiatives~~have ~~relating~~an toadverse ~~hydraulic fracturing~~impact ~~could~~on ~~result~~us in ~~increased~~the ~~costs~~event these ~~and~~customers ~~additional~~are ~~operating~~unable ~~restrictions~~to pay us for the products or ~~delays~~services we provide.

~~The~~Some ~~U.S. Senate and House~~ of ~~Representatives~~our ~~are~~customers ~~currently~~may ~~considering bills entitled~~experience, in the ~~“Fracturing~~ ~~Responsibility and Awareness of Chemicals Act~~future,” orsevere ~~the~~financial ~~“FRAC~~problems ~~Act,”~~ that ~~would~~have ~~amend the~~had ~~federal~~or ~~Safe~~may ~~Drinking~~have ~~Water~~a ~~Act,~~significant orimpact ~~the~~on ~~“SDWA,”~~their tocreditworthiness. ~~repeal~~We ancannot ~~exemption~~provide ~~from~~assurance ~~regulation~~that ~~for~~one ~~hydraulic~~or ~~fracturing.~~more Ifof ~~enacted,~~our ~~the~~financially ~~FRAC~~distressed ~~Act~~customers ~~would~~will ~~amend~~not ~~the~~default ~~definition~~on oftheir ~~“underground injection”~~obligations into ~~the~~us ~~SDWA~~or tothat such ~~encompass~~a ~~hydraulic~~default ~~fracturing~~or ~~activities.~~defaults Ifwill ~~enacted,~~not ~~such~~have a ~~provision could~~material ~~require~~adverse ~~hydraulic~~effect ~~fracturing~~on ~~operations~~our tobusiness, ~~meet permitting and~~ financial ~~assurance~~ ~~requirements~~position, ~~adhere~~future toresults ~~certain~~of ~~construction~~operations ~~specifications,~~or ~~fulfill~~future ~~monitoring,~~cash ~~reporting,~~flows. ~~and recordkeeping obligations~~Furthermore, ~~and~~the ~~meet~~bankruptcy ~~plugging~~of ~~and~~one ~~abandonment requirements. The FRAC Act also~~or ~~proposes~~more toof ~~require~~our ~~the~~customers, ~~reporting~~or ~~and~~some ~~public~~other ~~disclosure~~similar ofproceeding ~~chemicals~~or ~~used~~liquidity ~~in the fracturing process~~constraint, ~~which~~might ~~could~~ make it unlikely ~~easier~~that ~~for~~we ~~third~~would ~~parties~~be ~~opposing~~able ~~the hydraulic fracturing process~~ to ~~initiate~~ ~~legal~~collect ~~proceedings~~all ~~based~~or ona ~~allegations~~significant ~~that~~portion ~~specific~~of ~~chemicals~~amounts ~~used~~owed inby the ~~fracturing~~ ~~process~~distressed ~~could~~entity ~~adversely~~or ~~affect groundwater~~entities. ~~The~~In ~~adoption~~addition, ofsuch ~~any~~events ~~future~~might ~~federal~~force orsuch ~~state~~customers ~~laws~~to reduce or ~~implementing~~curtail ~~regulations~~their ~~imposing~~future ~~reporting~~use ~~obligations~~of ~~on,~~our orproducts ~~otherwise~~and ~~limiting~~services, ~~the~~which ~~hydraulic fracturing process~~ could ~~make~~have ita ~~more~~material ~~difficult~~adverse toeffect on ~~complete natural gas wells and increase~~ our ~~costs~~ results of ~~compliance~~operations and ~~doing~~financial ~~business~~condition.

~~Our~~All ~~business~~of ~~depends~~our oncommon ~~gathering~~stock ~~and~~is ~~transportation facilities~~ owned by ~~others~~one controlling shareholder whose interests may differ from those of the holders of our Senior Secured Notes.

~~The~~We ~~marketability~~are ofa ~~our~~wholly ~~natural~~owned ~~gas~~subsidiary ~~production~~of ~~depends~~Capital inC. ~~part~~As ona ~~the~~result ~~availability~~of this ownership, ~~proximity~~Capital C is ~~and~~able ~~capacity~~to direct the election of ~~gathering~~our Board of Directors and ~~pipeline~~therefore, ~~systems~~direct ~~owned~~our bymanagement ~~third~~and policies. ~~parties,~~Capital C may unilaterally approve mergers and other fundamental corporate changes involving inus, ~~our~~which ~~contracts~~require shareholder approval. The interests of Capital C as shareholder may ~~with~~differ ~~these~~from ~~third~~the ~~parties~~interests ~~could~~of ~~materially~~holders ~~affect~~of our ~~operations~~Senior Secured Notes. See “Item 13 — Certain Relationships and Related Transactions.”

InOur ~~addition,~~structure ~~federal,~~may ~~state,~~present ~~and~~conflicts ~~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 gasinterest. ~~See “Items 1 and 2 — Business and Properties — Regulation.”~~

22Our 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.

~~Table of Contents~~24

The ~~adoption~~terms of ~~derivatives~~our ~~legislation~~Credit orAgreement, ~~regulations~~as ~~related~~well toas ~~derivative~~the ~~contracts~~J. ~~could~~Aron ~~have~~Swap and the indenture relating to the anSenior ~~adverse~~Secured ~~impact~~Notes, onrestrict our current and future operations, particularly our ability to respond ~~hedge~~to ~~risks~~industry ~~associated~~or ~~with~~economic ~~our~~changes ~~business~~or to take certain actions.

~~Legislation~~At ~~has~~December 31, ~~been~~2010, ~~proposed~~we inhad ~~Congress~~a ~~and~~Credit byAgreement ~~the~~comprised ~~Treasury~~of ~~Department~~a to$90 million ~~impose~~revolving facility ~~restrictions~~with ona ~~certain~~borrowing ~~transactions~~base ~~involving~~of ~~derivatives~~$55 million, ~~which could affect the use~~ of ~~derivatives~~ inwhich ~~hedging transactions~~$23.9 million ~~Under~~was ~~proposed legislation~~outstanding, ~~OTC~~and ~~derivative~~a ~~dealers~~five ~~and~~year ~~other~~$40 ~~major~~million ~~OTC~~letter ~~derivative~~of ~~market~~credit ~~participants~~facility ~~could~~that may be ~~subjected~~used only to ~~substantial~~provide ~~supervision~~credit ~~and regulation.~~support ~~The~~for ~~legislation~~our obligations ~~generally~~under ~~would expand~~ the ~~power~~hedge ofagreement ~~the~~and ~~Commodity~~other ~~Futures~~hedge ~~Trading Commission,~~transactions. orThis ~~CFTC,~~facility tois ~~regulate~~for ~~derivative~~working capital ~~transactions~~requirements ~~related~~and togeneral ~~energy~~corporate ~~commodities~~purposes, including ~~oil~~ ~~and~~the ~~natural~~issuance ~~gas,~~of toletters ~~mandate clearance~~ of ~~derivative~~credit. Borrowings ~~contracts~~under ~~through~~the ~~registered~~Credit ~~derivative clearing~~Agreement ~~organizations,~~bear ~~and~~interest to(i) at ~~impose~~the ~~conservative~~greater ~~capital~~of ~~and~~the ~~margin~~prime ~~requirements~~rate, ~~and strong~~an ~~business~~adjusted ~~conduct~~federal ~~standards~~funds onrate ~~OTC~~or ~~derivative~~an ~~transactions.~~adjusted ~~The~~Eurodollar ~~CFTC~~rate, ~~has~~plus ~~proposed~~an ~~regulations~~applicable ~~that would~~margin ~~implement~~ranging ~~speculative limits on trading and positions in certain commodities~~from 1.0% ~~Although it is not possible at this time~~ to ~~predict~~2.0% ~~whether~~based oron ~~when~~the ~~Congress~~aggregate ~~may~~principal ~~act~~amount onoutstanding ~~derivatives~~under ~~legislation or~~ the ~~CFTC~~Credit ~~may issue new regulations~~Agreement, ~~any laws~~ or, (ii) at ~~regulations~~our ~~that~~option, ~~may~~the beEurodollar ~~adopted~~base ~~that~~rate ~~subject~~plus usan ~~to additional~~applicable ~~capital or~~ margin ~~requirements~~ranging ~~relating~~from ~~to,~~2.5% or to ~~additional~~3.50% based ~~restrictions~~ on, ~~our trading~~the ~~and~~aggregate ~~commodity~~principal ~~positions~~amount ~~could~~outstanding ~~have~~under anthe ~~adverse~~Credit ~~effect~~Agreement. onThe ~~our~~full ~~ability~~amount borrowed tounder ~~hedge~~the ~~risks associated~~Credit ~~with~~Agreement ~~our~~will ~~business~~mature or on ~~the~~April 14, ~~cost of our hedging activity~~2012.

~~All~~The ofobligations ~~our~~under ~~common~~the ~~stock~~Credit isAgreement ~~owned~~are secured by ~~one~~a ~~controlling~~first ~~shareholder~~lien ~~whose~~security ~~interests~~interest ~~may differ~~in ~~from~~substantially ~~those~~all of our assets. The obligations under the ~~holders~~Credit Agreement are further secured by a pledge of 100% of our ~~Senior~~capital ~~Secured~~stock ~~Notes~~held by Capital C, our parent.

WeThe ~~are~~Credit aAgreement ~~wholly~~contains ~~owned~~covenants ~~subsidiary~~that ofwill ~~Capital~~limit C.or Asprohibit aour ~~result~~ability ofto, ~~this~~among other ~~ownership~~things, ~~Capital~~incur Cor ~~is able~~guarantee toadditional ~~direct~~indebtedness; ~~the~~create ~~election~~liens; ofpay ~~our~~dividends ~~Board~~on ofor repurchase ~~Directors~~stock; pay principal and ~~therefore,~~interest ~~direct~~on ~~our~~certain ~~management~~subordinated ~~and~~debt; make certain types of ~~policies.~~investments; ~~Capital~~sell Cassets ~~may~~or ~~unilaterally~~merge ~~approve~~with ~~mergers~~another ~~and~~entity; ~~other~~pledge ~~fundamental~~or ~~corporate~~otherwise ~~changes~~encumber our capital ~~involving~~stock; ~~us,~~or ~~which~~enter ~~require~~into ~~shareholder~~transactions ~~approval~~with affiliates. The ~~interests~~Credit ofAgreement ~~Capital~~also Crequires ascompliance with ~~shareholder~~customary ~~may~~financial covenants, including a minimum interest coverage ratio, a maximum senior ~~differ~~secured ~~from~~leverage ~~the~~ratio ~~interests~~and ofa ~~holders~~minimum ofcurrent ~~our~~ratio. ~~Senior~~In ~~Secured~~2010, ~~Notes~~we amended certain of these covenants. ~~See~~At ~~“Item~~December 1331, —2010, ~~Certain~~we were in compliance with our covenants under the Credit ~~Relationships~~Agreement. Our senior secured leverage ratio was 0.80 : 1.0 and ~~Related~~the ~~Transactions~~interest coverage ratio was 1.”78 : 1.0. For additional information on our Credit Agreement, see Note 8.

~~Our~~In ~~structure~~addition, our existing debt agreements and any new debt agreements may ~~present~~impose ~~conflicts~~financial restrictions ofand ~~interest~~other covenants on us that may be more restrictive than those applicable to the Senior Secured Notes.

Our ~~sole~~Credit ~~shareholder,~~Agreement ~~Capital~~and C,the isHedge ~~owned~~Agreement bycontain, ~~institutional funds managed by EnerVest. Messrs. Houser~~ and ~~Vanderhider~~any ~~are~~future ~~executive~~refinancing ~~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~~Credit ofAgreement ~~EnerVest~~likely ~~Operating~~would contain, ana ~~affiliate~~number of ~~EnerVest.~~restrictive ~~EnerVest~~covenants ~~Operating~~that ~~controls~~impose ~~the~~significant ~~operations of our~~operating ~~wells~~ and ~~the~~financial ~~wells~~restrictions ~~owned~~on ~~by other EnerVest managed funds~~us. WeOur ~~can~~Credit ~~give~~Agreement ~~no assurance~~and, ~~that conflicts of interest will not arise with respect~~ to ~~corporate~~some ~~opportunities. Also~~extent, ~~we can give no assurance that conflicts will not arise with respect to~~ the ~~time~~Hedge ~~and attention~~Agreement ~~devoted~~include tocovenants usrestricting, byamong ~~Messrs. Houser~~other things, ~~Vanderhider~~our ~~and~~ability ~~Mariani.~~to:

~~The~~• ~~terms~~incur ofadditional our Amended Credit Agreement, as well as the J. Aron Swap and the indenture relating to the Senior Secured Notes, restrict our current and future operations, particularly our ability to respond to industry or economic changes or to take certain actions. debt;

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

At• ~~December 31,~~incur 2009, we had an Amended Credit Agreement comprised of a five-year $100 million revolving facility with a borrowing base of $65 million, of which $43.9 million was outstanding at December 31, 2009. This facility is for working capital ~~requirements and general corporate purposes, including the issuance of letters of credit~~expenditures; and a five year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 2.0% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.50% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2011.

~~On March 23,~~• ~~2010,~~create 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. liens;

~~The~~• ~~obligations~~use ~~under~~ the ~~Amended~~proceeds ~~Credit~~from ~~Agreement~~sales ~~are secured by a first lien security interest in substantially all~~ of ~~our~~ assets. ~~The~~and ~~obligations under the Amended Credit Agreement are further secured by a pledge of 100% of our~~ capital stock ~~held by Capital C, our parent.~~ ;

23 • enter into sale and leaseback transactions;

~~Table~~• ofenter ~~Contents~~into transactions with affiliates;

~~The~~• ~~Amended~~transfer ~~Credit~~all ~~Agreement contains covenants that will limit~~ or ~~prohibit~~substantially ~~our~~all 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~~our assets ~~or merge with another entity~~; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum senior secured leverage ratio and a minimum current ratio. At December 31, 2009, we were in compliance with our covenants under the Amended Credit Agreement. Our senior secured leverage ratio was 1.10 : 1.0 and the interest coverage ratio was 1.96 : 1.0.

In• ~~addition,~~enter ~~our~~into ~~existing~~merger ~~debt~~or ~~agreements~~consolidation ~~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~~transactions.

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

• ~~incur~~a ~~additional~~minimum ~~debt;~~interest •coverage ~~pay dividends and make investments, loans or advances~~ratio; • incur capital expenditures; • create liens; • use the proceeds from sales of assets and capital stock; • enter into sale and leaseback transactions; • enter into transactions with affiliates; • transfer all or substantially all of our assets; and • enter into merger or consolidation transactions.

~~Our~~• ~~Amended~~a ~~Credit~~maximum ~~Agreement~~senior ~~also~~secured ~~includes~~leverage ~~financial~~ratio; ~~covenants, including requirements that we maintain:~~ and

• a minimum ~~interest~~current ~~coverage~~ ratio;.

•The aindenture ~~maximum~~relating ~~senior~~to ~~secured~~the ~~leverage~~Senior ~~ratio;~~Secured ~~and~~Notes also contains covenants including, among other things, restrictions on our ability to:

• aincur ~~minimum~~additional ~~current ratio.~~indebtedness;

~~The~~• ~~indenture~~pay ~~relating~~dividends toor ~~the~~make ~~Senior~~other ~~Secured~~distributions ~~Notes~~on ~~also contains covenants including~~stock, ~~among other~~redeem ~~things,~~stock ~~restrictions~~or onredeem ~~our~~subordinated ~~ability to:~~ obligations;

• ~~incur~~make ~~additional indebtedness~~investments;

~~• pay dividends or make other distributions on stock, redeem stock or redeem subordinated obligations;~~25

• ~~make~~create ~~investments~~liens or other encumbrances; and

• ~~create~~sell ~~liens~~or otherwise dispose of all or ~~other~~substantially ~~encumbrances;~~all ~~and~~of our assets, or merge or consolidate with another entity.

• If ~~sell~~we orrefinance ~~otherwise~~our ~~dispose~~indebtedness, ofwe ~~all~~may orcall ~~substantially~~the ~~all~~Senior Secured Notes. Following the redemption of ~~our~~the ~~assets~~notes, orthe ~~merge~~note orholders will ~~consolidate~~no longer have an investment in our debt securities and we will no longer be required to make filings with ~~another~~the ~~entity~~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)

24PART II

~~Table~~Item of5. ~~Contents~~MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

~~PART~~There IIis no established public trading market for our equity securities.

~~Item~~All 5.of ~~MARKET~~our ~~FOR~~equity ~~THE~~securities ~~REGISTRANT’S~~at ~~COMMON~~March 5, ~~EQUITY~~2011, ~~RELATED~~were ~~STOCKHOLDER~~held ~~MATTERS~~by ~~AND~~Capital ~~ISSUER PURCHASES OF EQUITY SECURITIES~~C.

~~There is no established public trading market for our equity securities.~~Dividends

~~All~~We ofpaid ~~our~~no ~~equity~~cash ~~securities~~dividends atin ~~March 5,~~ 2010, ~~were~~and ~~held~~2009 byand ~~Capital~~paid Ccash dividends of $2.5 million in 2008.

~~Dividends~~26

WeItem ~~paid no cash dividends in 2009 and paid cash dividends of $2~~6.~~5 million~~ inSELECTED ~~2008~~FINANCIAL ~~and $9.8 million in 2007.~~ DATA

25The 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 6. SELECTED FINANCIAL DATA~~27

~~The~~Item ~~Selected~~7. ~~Financial~~MANAGEMENT’S ~~Data~~DISCUSSION ~~should~~AND beANALYSIS ~~read~~OF inFINANCIAL ~~conjunction~~CONDITION ~~with~~AND ~~the~~RESULTS ~~Consolidated~~OF ~~Financial Statements at Item 15(a).~~ OPERATIONS

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

Overview

~~The~~We ~~Transaction~~are ~~and~~an ~~Merger~~Ohio ~~was~~corporation ~~accounted~~wholly ~~for~~owned asby aCapital ~~purchase effective August 16, 2005~~C. ~~The~~ ~~Transaction~~Capital ~~and~~C ~~Merger~~acquired ~~resulted~~us inpursuant ato ~~new basis of accounting reflecting estimated fair values~~a ~~for~~merger ~~assets~~completed ~~and~~on ~~liabilities at August~~July 167, ~~2005~~2004. ~~Accordingly,~~On ~~financial data for the period subsequent to~~ August 1516, 2005 ~~is presented on our new basis of accounting~~, ~~while~~Capital ~~the~~C ~~financial~~was ~~data for~~acquired ~~prior~~by ~~periods reflect the historical results of the predecessor company. Vertical black lines~~institutional ~~are~~funds ~~presented~~managed toby ~~separate~~EnerVest, ~~the~~Ltd, ~~financial~~a ~~data~~Houston-based ofprivately ~~the~~held ~~predecessor~~oil ~~company~~ and ~~the~~gas ~~successor~~operator ~~company. The “Successor Company” refers to the period from August 16, 2005~~ and ~~forward. The “Predecessor~~ ~~Company”~~institutional ~~refers~~funds ~~to the period prior to August 15, 2005~~manager.

26We 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.

~~Table~~At December 31, 2010, our total estimated proved reserves were 202.4 Bcfe. Natural gas comprised approximately 85% of ~~Contents~~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.

~~Item~~During 7.the ~~MANAGEMENT’S~~periods ~~DISCUSSION~~discussed, ~~AND~~we ~~ANALYSIS~~earned OFrevenue ~~FINANCIAL~~through ~~CONDITION~~the ~~AND~~production ~~RESULTS~~and OFsale ~~OPERATIONS~~of oil and natural gas and, to a lesser extent, from gas gathering and marketing.

~~Overview~~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.

WeThe ~~are~~average anprice ~~Ohio~~realized ~~corporation~~for ~~wholly~~our ~~owned~~natural bygas, ~~Capital~~inclusive C.of ~~Capital~~hedges Cthat ~~acquired~~previously qualified usas ~~pursuant~~effective hedges, decreased from $8.62 per Mcf in 2008 to a$3.61 per Mcf in 2009 and ~~merger~~then ~~completed~~increased to $4.00 per Mcf in 2010. The monthly average settle for natural gas trading on ~~July 7,~~the NYMEX ~~2004~~decreased from $9.04 Onper ~~August 16,~~MMbtu ~~2005,~~in ~~Capital~~2008 Cto ~~was~~$3.99 ~~acquired~~per byMMbtu ~~institutional~~in 2009 and then increased to $4.39 ~~funds~~per ~~managed~~MMbtu byin ~~EnerVest,~~2010. ~~Ltd,~~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 ~~Houston-based~~favorable ~~privately~~Btu ~~held~~content ~~oil~~of ~~and~~our gas. During 2010, our average per unit gas ~~operator~~prices ~~and~~(excluding the effects of hedging) in Appalachia ~~institutional~~and ~~funds~~Michigan ~~manager~~were $0.24 and $0.20, respectively, higher than the average NYMEX monthly settle price for 2010. The ~~Transaction~~remainder ~~resulted~~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 a2008 ~~change~~to $56.49 per Bbl in ~~control~~2009 ofand ~~the~~increased ~~Company~~to $73.92 per Bbl in 2010.

We ~~are~~recorded ana ~~independent~~goodwill ~~energy~~impairment ~~company~~charge ~~engaged~~of $90.1 million in the ~~exploitation,~~fourth ~~development,~~quarter ~~production, operation and acquisition~~ of ~~oil~~2008 due ~~and~~to ~~natural~~the ~~gas~~significant ~~properties.~~decline ~~Our operations are focused~~ in ~~the Appalachian~~oil ~~Basin in Ohio, Pennsylvania~~ and ~~New~~gas ~~York~~prices. ~~and~~There inwas ~~the~~no ~~Antrim~~goodwill ~~Shale~~as ~~Formation~~of ~~in the~~December 31, ~~Michigan~~2010 ~~Basin~~or 2009.

AtCurrent ~~December 31,~~market ~~2009,~~conditions ~~our~~also ~~total~~elevate ~~estimated~~concerns ~~proved~~about ~~reserves~~cash ~~were~~and ~~190~~cash ~~Bcfe.~~equivalent ~~Natural gas comprised~~investments, ~~approximately~~which ~~86%~~at ~~of our estimated proved reserves~~December 31, ~~and~~2010 ~~91%~~totaled of$35.9 million. ~~our~~We ~~estimated~~have ~~proved~~reviewed ~~reserves~~the ~~were classified~~creditworthiness ~~as proved developed. Substantially all~~ of ~~our~~the banks ~~reserves~~and ~~are~~financial ~~located~~institutions inwith ~~shallow,~~which ~~highly developed~~we ~~formations~~maintain ~~with long-lived~~investments, ~~stable~~each ~~production~~of ~~profiles.~~whom Atwe ~~December 31,~~believe ~~2009,~~to ~~our~~be ~~Appalachian~~creditworthy, ~~properties~~as ~~accounted~~well ~~for~~as ~~55% of our estimated proved reserves, while~~ the ~~Michigan properties~~securities ~~accounted~~underlying ~~for~~these ~~45% of proved reserves~~investments.

~~During~~We ~~the~~have ~~periods~~also ~~discussed,~~reviewed ~~we earned revenue through~~ the ~~production~~creditworthiness ~~and sale~~ of ~~oil~~our ~~and natural~~hedge ~~gas~~counterparties and, tobelieve athat ~~lesser~~they are ~~extent, from gas gathering and marketing~~creditworthy.

~~Our financial results and cash flows can be significantly impacted as commodity prices~~28 fluctuate in response to changing market conditions. While oil and natural gas prices have strengthened in recent months, they remain unstable and are expected to be, volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include the effects of the recession in the United States, the discovery of substantial accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves, North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America. As discussed above, we use derivative financial instruments on a significant portion of our oil and natural gas production to reduce the volatility of oil and natural gas prices and to protect cash flow available for our development drilling program. In connection with the acquisition by Capital C, at the effective time of the Merger, we became a party to a long-term hedging program (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) as required by the Amended Credit Agreement and the indenture governing the Senior Secured Notes, we will maintain such Hedges with J. Aron or its successor permitted assigns. We anticipate that the Hedges will cover approximately 73% of the expected 2010 through 2013 production from our current estimated proved reserves and will range from 67% to 82% of such expected production in any year.

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

~~The~~We ~~average~~prepare ~~price realized for~~ our ~~natural~~consolidated ~~gas,~~financial ~~inclusive~~statements ofin ~~qualified~~accordance ~~effective~~with ~~hedges,~~accounting principles ~~increased~~generally ~~from~~accepted ~~$6.81 per Mcf~~ in ~~2007~~the toUnited ~~$8.62~~States ~~per~~(“GAAP”) ~~Mcf in 2008~~ and ~~then~~SEC ~~decreased to $3~~guidance.61 ~~per~~See ~~Mcf in 2009. The monthly average settle for natural gas trading on~~ the ~~NYMEX~~“Notes ~~increased~~to ~~from~~Consolidated Financial ~~$6.86~~Statements” ~~per MMbtu~~included in ~~2007 to $9~~“Item 15(a).04 ~~per~~Financial ~~MMbtu~~Statements ~~in 2008~~ and ~~then~~Supplementary ~~decreased~~Data” tofor ~~$3.99 per MMbtu in 2009. Our~~a ~~selling~~more ~~price~~comprehensive ofdiscussion ~~natural gas is generally higher than the NYMEX price due to the proximity~~ of our ~~operations~~ tosignificant ~~natural~~accounting ~~gas markets along with a favorable Btu content of our gas~~policies. ~~During~~GAAP ~~2009,~~requires ~~our~~information in ~~average~~financial ~~per~~statements ~~unit~~about ~~gas prices (excluding~~ the ~~effects~~accounting ofprinciples ~~hedging) in Appalachia~~ and ~~Michigan~~methods ~~were $0.44~~used and ~~$0.11, respectively, higher than~~ the ~~average~~risks ~~NYMEX monthly settle price for 2009. The~~and ~~remainder~~uncertainties ofinherent ~~the difference is primarily due to our qualified hedging activities during these periods. Our average realized price for oil increased from $67.42 per Bbl~~ in ~~2007~~significant toestimates ~~$94.40~~including ~~per Bbl~~choices inbetween ~~2008~~acceptable ~~and decreased to $56~~methods.~~49 per Bbl in 2009. If the global economic instability~~ ~~continues,~~Following ~~commodity~~is ~~prices~~a ~~may~~discussion ~~be depressed for an extended period~~ of ~~time, which could alter~~ our ~~acquisition,~~ ~~drilling~~most ~~and~~critical ~~development~~accounting ~~plans.~~policies:

27Successful Efforts Method of Accounting

~~Table~~We account for our oil and natural gas properties using the successful efforts method of accounting. ~~Contents~~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.

WeNo ~~recorded~~gains aor ~~goodwill~~losses ~~impairment~~are ~~charge~~recognized upon the disposition of ~~$90.1 million~~oil inand ~~the~~natural ~~fourth~~gas ~~quarter~~properties except ofin ~~2008~~transactions ~~due~~such to as the significant ~~decline~~disposition inof ~~oil~~an ~~and~~amortizable ~~gas~~base ~~prices~~that significantly affects the unit—of—production amortization rate. ~~There~~Sales ~~was~~proceeds noare ~~goodwill~~credited to asthe ofcarrying ~~December 31,~~value ~~2009,~~of orthe ~~2008~~properties.

~~Current~~The ~~market~~application ~~conditions~~of ~~also~~the ~~elevate~~successful ~~concerns~~efforts ~~about~~method ~~cash~~of ~~and~~accounting ~~cash~~requires ~~equivalent~~managerial ~~investments,~~judgment to determine the proper classification of wells designated as development or exploratory which atwill ultimately ~~December 31,~~determine ~~2009~~the ~~totaled~~proper ~~$46~~accounting treatment of the costs incurred.~~7 million.~~ WeThe results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have ~~reviewed~~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 ~~creditworthiness~~abandonment of the wells at a later date. ~~banks~~Wells ~~and~~are ~~financial~~drilled ~~institutions~~that ~~with~~have ~~which~~targeted wegeologic ~~maintain~~structures ~~investments~~that are both developmental and exploratory in nature, ~~each~~and an allocation of ~~whom~~costs weis ~~believe~~required to beproperly account for the results. ~~creditworthy~~Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, asbut ~~well~~often asthese seismic programs extend beyond the ~~securities~~reserve ~~underlying~~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 ~~investments~~costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

WeThe ~~have~~major ~~also~~difference ~~reviewed~~between the ~~creditworthiness~~successful ofefforts ~~our~~method ~~hedge~~of ~~counterparty~~accounting and ~~believe~~the ~~that~~full itcost method is under the full cost method of accounting, such exploration costs and expenses are ~~creditworthy~~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.

~~Critical~~Oil ~~Accounting~~and ~~Policies~~Gas Reserves

WeOn ~~prepare~~December 31, ~~our~~2009, ~~consolidated~~we ~~financial~~adopted ~~statements~~Accounting inStandards ~~accordance~~Update ~~with~~(“ASU”) ~~accounting~~No. 2010—03, ~~principles~~Extractive ~~generally~~Activities ~~accepted~~— inOil ~~the~~and ~~United~~Gas ~~States~~ (~~“GAAP”~~Topic 932), ~~and~~which ~~SEC~~conforms ~~guidance.~~the ~~See~~definition ~~the~~of ~~“Notes~~proved toreserves ~~Consolidated~~with the ~~Financial~~SEC ~~Statements”~~Modernization ~~included~~of Oil and Gas Reporting rules, which were issued by the SEC in ~~“Item~~December ~~15(a)~~2008. ASU ~~Financial~~No. 2010—03 ~~Statements~~requires ~~and~~that ~~Supplementary~~we ~~Data”~~use ~~for~~the ~~a more~~average ~~comprehensive~~of ~~discussion~~the offirst ~~our~~day ~~significant~~of ~~accounting~~the ~~policies.~~month ~~GAAP~~price ~~requires~~during ~~information~~the in12 ~~financial~~month ~~statements~~period ~~about~~preceding the ~~accounting~~end ~~principles~~of ~~and~~the ~~methods~~year, ~~used~~rather ~~and~~than the ~~risks~~year end price, when estimating reserve quantities and standardized measure. The new rules permit the use of reliable technologies to ~~uncertainties~~determine ~~inherent~~proved inreserves, ~~significant~~if ~~estimates~~those ~~including~~technologies ~~choices~~have ~~between~~been ~~acceptable~~demonstrated ~~methods~~to result in reliable conclusions about reserves volumes. Prior year data are presented in accordance with the Financial ~~Following~~Accounting isStandards aBoard ~~discussion~~(“FASB”) ofoil ~~our~~and ~~most~~natural ~~critical~~gas ~~accounting~~disclosure ~~policies:~~requirements effective during those periods.

~~Successful~~Our ~~Efforts~~estimated ~~Method~~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 ~~Accounting~~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

~~We account for our~~29 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.

Noproduction ~~gains~~of orthe ~~losses are~~oil ~~recognized~~and ~~upon~~gas reserves may not occur in the ~~disposition~~periods ofassumed ~~oil~~and actual prices realized and ~~natural~~actual ~~gas~~costs ~~properties~~incurred ~~except~~may invary ~~transactions~~significantly ~~such~~from assumptions used. Estimated proved asreserves ~~the~~represent ~~significant~~estimated ~~disposition~~quantities of annatural ~~amortizable~~gas ~~base~~and oil that ~~significantly~~geological ~~affects~~and ~~the~~engineering data ~~unit-of-production~~demonstrate, ~~amortization~~with ~~rate~~reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. ~~Sales~~Estimated proved ~~proceeds~~developed reserves are ~~credited~~estimated proved reserves expected to ~~the~~be ~~carrying~~recovered ~~value~~through ofwells ~~the~~and ~~properties~~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~~• ~~application of~~ the ~~successful~~ ~~efforts~~quality 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~~quantity 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~~available 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. data;

~~The~~• ~~major difference between~~ the ~~successful~~interpretation ~~efforts method~~ of ~~accounting~~that 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. data;

~~Oil~~• ~~and~~the ~~Gas~~accuracy ~~Reserves~~ of various mandated economic assumptions; and

~~On December 31,~~• ~~2009, we adopted Accounting Standards Update (“ASU”) No. 2010—03, Extractive Activities — Oil and Gas (Topic 932), which conforms~~ the ~~definition~~judgment of ~~proved reserves with~~ the ~~SEC~~ ~~Modernization~~persons ofpreparing ~~Oil and Gas Reporting rules, which were issued by~~ the ~~SEC in December 2008~~estimate. 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.

28Our 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.

~~Table~~Capitalization, Depreciation, Depletion and Impairment of ~~Contents~~Long-Lived Assets

~~Our~~The ~~estimated~~capitalized ~~proved~~costs ~~developed~~of ~~and~~our ~~estimated~~producing ~~proved~~oil ~~undeveloped reserves are all located within the Appalachian~~ and ~~Michigan~~natural ~~basins~~gas inproperties ~~the United States. There~~ are ~~many~~depreciated ~~uncertainties~~and ~~inherent~~depleted inby ~~estimating proved reserve quantities and in projecting future production rates and~~ the ~~timing~~ units—of—production ~~development~~method ~~expenditures.~~based Inon ~~addition,~~the ~~estimates~~ratio of ~~new~~current ~~discoveries~~production ~~are~~to ~~more imprecise~~estimated ~~than~~total ~~those~~net ofproved ~~properties~~oil ~~with~~and anatural ~~production~~gas ~~history.~~reserves ~~Accordingly,~~as ~~these~~estimated ~~estimates~~by ~~are~~independent ~~expected~~petroleum toengineers. ~~change~~Proved asdeveloped ~~future~~reserves ~~information~~are ~~becomes~~used ~~available.~~in ~~Material~~computing ~~revisions~~unit ofrates ~~reserve~~for ~~estimates~~drilling ~~may~~and ~~occur in the future,~~ development ~~and~~costs ~~production of the oil~~ and total ~~gas~~proved reserves ~~may~~are ~~not~~used ~~occur~~for indepletion ~~the~~rates ~~periods assumed~~of ~~and~~leasehold, ~~actual~~platform, ~~prices realized~~ and ~~actual~~pipeline costs. ~~incurred may vary significantly from~~No ~~assumptions~~gains ~~used.~~or ~~Estimated~~losses ~~proved~~are ~~reserves~~recognized ~~represent~~upon ~~estimated~~the ~~quantities~~disposition of ~~natural gas and~~ oil ~~that~~ ~~geological~~ and ~~engineering~~natural ~~data~~gas ~~demonstrate,~~properties ~~with~~except ~~reasonable certainty, to be recoverable~~ in ~~future~~transactions ~~years~~such ~~from~~as ~~known~~the ~~reservoirs~~significant ~~under~~disposition ~~economic~~of ~~and~~an ~~operating~~amortizable ~~conditions~~base ~~existing~~that atsignificantly affects the ~~time~~unit—of—production ~~the estimates~~amortization ~~were made~~rate. ~~Estimated~~Sales ~~proved~~proceeds ~~developed reserves~~ are ~~estimated~~credited ~~proved~~to ~~reserves~~the ~~expected~~carrying tovalue of bethe ~~recovered~~properties. ~~through~~Maintenance ~~wells~~ and ~~equipment~~repairs inare ~~place~~expensed, and ~~under~~expenditures ~~operating~~which ~~methods~~enhance ~~being used at~~ the ~~time~~ ~~the~~value ~~estimates were made. The accuracy~~ of properties aare ~~reserve estimate is a function of:~~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 ~~quality~~costs are charged to expense. We recorded no impairment to unproved oil and ~~quantity~~gas properties in 2010 and recorded impairments $3.6 million and $783,000 in 2009 and 2008, respectively, which reduced the book value of ~~available~~unproved ~~data;~~oil and gas properties to their estimated fair value.

•Gas ~~the~~gathering ~~interpretation~~systems ofare ~~that~~stated ~~data;~~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 ~~accuracy~~straight-line method over the useful lives of ~~various~~the ~~mandated~~assets ~~economic~~ranging ~~assumptions;~~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 ~~judgment~~carrying amount may not be recoverable. If the sum of the ~~persons~~expected ~~preparing~~future undiscounted cash flows is less than the ~~estimate~~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.

~~Our~~FASB ~~estimated~~accounting ~~proved~~guidance ~~reserve~~requires ~~information~~that ~~for~~intangible ~~all~~assets ~~periods~~with ~~included~~indefinite inlives, ~~this~~including goodwill, ~~Annual~~be ~~Report~~evaluated ~~is based~~ on ~~estimates~~an ~~prepared~~annual bybasis ~~independent~~for ~~petroleum~~impairment ~~consultants.~~or ~~Estimates~~more ~~prepared~~frequently byif ~~others~~an ~~may be~~event ~~higher~~occurs or circumstances ~~lower~~change ~~than~~could ~~these~~potentially ~~estimates~~result in impairment.

~~Capitalization,~~The ~~Depreciation~~impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. As we have only one reporting unit, ~~Depletion~~the reporting unit used for testing will be the entire company. The fair value of the reporting unit is determined and ~~Impairment~~compared to the book value of ~~Long-Lived~~that ~~Assets~~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

~~Capitalized~~30 costs related to estimated proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties are calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit-of-production amortization rate. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.

~~Unproved~~drop in oil and gas ~~properties~~prices ~~are~~resulting ~~stated~~in atpart ~~cost~~from ~~and~~the ~~consist~~global ofeconomic ~~undeveloped~~and ~~leases~~market crisis. ~~These~~No ~~costs~~goodwill ~~are~~was ~~assessed~~recorded ~~periodically~~at ~~to determine whether their value has been impaired~~December 31, ~~and~~2009 ~~if impairment~~or ~~is indicated, the costs are charged to expense.~~2010

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

~~Property~~Our ~~and~~financial ~~equipment~~results ~~are~~and ~~stated~~cash atflows ~~cost.~~can ~~Depreciation~~be ofsignificantly ~~non-oil~~impacted ~~and~~as ~~gas~~commodity ~~properties is~~prices ~~computed~~fluctuate ~~using~~widely ~~the~~in ~~straight-line~~response ~~method~~to ~~over~~changing ~~the~~market ~~useful~~conditions. ~~lives~~Under of the ~~assets~~provisions ~~ranging~~of ~~from 3 to 15~~FASB ~~years~~accounting ~~for~~guidance, ~~machinery~~we ~~and~~recognize ~~equipment~~all ~~and~~derivative 30financial toinstruments ~~40 years~~as ~~for~~either ~~buildings. When~~ assets ~~other than oil and~~or ~~gas~~liabilities ~~properties~~at ~~are~~fair ~~retired~~value. orNone ~~otherwise~~of ~~disposed~~our ~~of,~~derivative ~~the~~financial ~~cost~~instruments ~~and~~are ~~related~~designated ~~accumulated~~as ~~depreciation~~cash ~~are~~flow ~~removed~~hedges. ~~from~~The ~~the~~changes ~~accounts,~~in ~~and~~fair ~~any~~value ~~resulting~~of ~~gain~~our orderivative ~~loss~~instruments isare ~~reflected~~reported in ~~income~~expense ~~for the~~in ~~period.~~the ~~The~~consolidated ~~cost~~statements of ~~maintenance~~operations ~~and repairs is expensed~~ as ~~incurred,~~derivative ~~and~~fair ~~significant~~value ~~renewals and betterments are capitalized~~(gain) loss.

~~Long-lived~~From ~~assets~~time ~~are~~to ~~reviewed~~time ~~for~~we ~~impairment~~may ~~whenever~~enter ~~events~~into ora ~~changes~~combination inof ~~circumstances indicate~~futures ~~that~~contracts, ~~the~~commodity ~~carrying~~derivatives and ~~amount~~fixed-price ~~may~~physical ~~not~~contracts beto ~~recoverable.~~manage Ifour ~~the~~exposure ~~sum~~to ofnatural ~~the~~gas ~~expected~~price, ~~future undiscounted~~crude ~~cash~~oil ~~flows~~price isor interest ~~less~~rate ~~than~~volatility ~~the~~and ~~carrying~~to ~~amount~~support ofour ~~the~~capital ~~asset,~~expenditure aplans. ~~loss~~Our isderivative ~~recognized for the~~financial ~~difference~~instruments ~~between~~primarily ~~the~~take ~~fair value and~~ the ~~carrying~~form ~~amount~~ of ~~the~~swaps ~~asset~~or collars. ~~Fair~~At ~~value~~December 31, is2010, ~~determined~~our derivative ~~based~~contracts onwere ~~management’s~~comprised ~~outlook~~ of ~~future~~natural ~~oil~~gas ~~and~~swaps, natural gas ~~prices~~basis ~~and~~differential ~~estimated~~swaps, ~~future~~crude ~~cash flows~~oil toswaps beand ~~generated~~interest byrate ~~the assets~~swaps, ~~discounted~~which atwere aplaced ~~market~~with ~~rate~~major offinancial ~~interest.~~institutions ~~Impairment~~that ofwe ~~unproved~~believe ~~properties~~have isa ~~based~~minimal oncredit ~~the estimated fair value of the property~~risk.

~~FASB~~We ~~accounting~~use ~~guidance~~NYMEX-based ~~requires~~commodity ~~that~~derivative ~~intangible~~contracts ~~assets~~to ~~with~~hedge ~~indefinite~~natural ~~lives~~gas, ~~including~~because our natural ~~goodwill~~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 ~~evaluated~~highly effective on an ~~annual~~on-going basis. ~~for~~This ~~impairment~~occurred ordue ~~more~~to ~~frequently~~the ifapplication of anpurchase ~~event~~accounting ~~occurs~~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 ~~circumstances~~no ~~change~~longer highly effective and, therefore, could ~~potentially~~no ~~result~~longer be designated as cash flow hedges. Changes in ~~impairment~~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.

~~The~~Revenue ~~impairment test requires the allocation of goodwill and all other assets and liabilities~~Recognition 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.

29Oil 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.

~~Table~~Asset ofRetirement ~~Contents~~Obligations

~~Derivatives~~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 ~~Hedging~~abandonment (excluding salvage value) of our oil and gas properties.

~~Our~~There ~~financial~~has ~~results~~been ~~and~~no ~~cash~~significant ~~flows~~current ~~can~~period beactivity ~~significantly~~with ~~impacted~~respect ~~as commodity prices fluctuate widely in response~~ to ~~changing~~additional ~~market conditions. Under the provisions of FASB~~retirement ~~accounting guidance~~obligations, wesettled ~~recognize~~obligations, ~~all~~accretion ~~derivative~~expense ~~financial~~and ~~instruments~~revisions asof ~~either~~estimated ~~assets~~cash ~~or liabilities at fair value~~flows. The ~~changes in fair value of derivative instruments not qualifying for~~ ~~designation~~asset asretirement ~~cash~~obligations ~~flow~~increased ~~hedges are reported in expense in the consolidated statements of operations~~ as ~~derivative~~a ~~fair~~result ~~value (gain) loss. Changes in the fair value~~ of ~~derivative instruments~~additional ~~that~~wells ~~are~~having ~~cash~~been ~~flow~~drilled ~~hedges are recognized in other comprehensive income (loss) until~~and ~~such~~accretion ~~time as the hedged items impact earnings~~expense.

~~The~~At ~~relationship~~December 31, ~~between~~2010, ~~hedging~~there ~~instruments~~were ~~and~~no ~~the~~assets ~~hedged~~legally ~~items~~restricted ~~must~~for bepurposes ~~highly effective in achieving the offset~~ of ~~changes~~settling ~~in fair values or cash flows attributable to the hedged risk, both~~asset atretirement ~~inception of the contract and on an ongoing basis~~obligations. ~~We assess effectiveness at least quarterly~~ based on the relative changes in fair value between the derivative contract and the hedged item over time. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.

From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas price, crude oil price or interest rate volatility and to support our capital expenditure plans. Our derivative financial instruments primarily take the form of swaps or collars. At December 31~~, 2009, our derivative~~ contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that we believe have a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges.

WeResults 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~~Operations designated as cash flow hedges through August 16, 2005. At August 16, 2005, our oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in fair value of the oil swaps subsequent to August 15, 2005 and the ineffective portion of the natural gas swaps from July 7, 2004 to June 30, 2006 are recorded as “Derivative fair value gain or loss.” As of July 1, 2006, we determined that our gas swaps were no longer highly effective and, therefore, could no longer be designated as cash flow hedges.

~~Revenue~~The ~~Recognition~~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.

Oil and natural gas revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is probable. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under-produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no material gas imbalances at December 31, 2009 or 2008. Oil and gas marketing revenues are recognized when title passes.


	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	)

~~Asset Retirement Obligations~~32

WeThe ~~follow~~following ~~FASB~~Management’s ~~accounting~~Discussion ~~guidance~~and ~~which~~Analysis ~~requires~~is usbased toon ~~recognize a liability for~~ the ~~fair value~~results of ~~our~~operations from ~~asset~~continuing ~~retirement obligations associated with its tangible~~operations, ~~long-lived~~unless ~~assets.~~otherwise ~~The majority of our asset retirement obligations recorded relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties~~noted.

~~There has been no significant current period activity with respect to additional retirement obligations~~Production, ~~settled~~Sales ~~obligations,~~Prices ~~accretion expense~~ and ~~revisions of estimated cash flows. The~~Costs ~~asset retirement obligations increased as a result of additional wells having been drilled and accretion expense.~~

30The 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

At(1) ~~December 31,~~The ~~2009,~~average ~~there~~prices ~~were~~presented noabove ~~assets~~include ~~legally~~non-cash ~~restricted~~amounts ~~for~~related ~~purposes~~to our derivatives as a result of ~~settling~~purchase ~~asset retirement~~accounting ~~obligations~~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:

Results of Operations


	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

~~The~~2010 ~~following~~Compared ~~table~~to ~~sets forth financial data for the periods indicated. Dollars are stated~~2009 ~~in thousands and percentages are stated as a percentage of total revenues.~~

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

Revenues

31Net 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.

~~Table~~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 ~~Contents~~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 following Management’s Discussion and Analysis is based on the results of operations~~33 ~~from continuing operations, unless otherwise noted.~~

~~Production~~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, ~~Sales~~which ~~Prices~~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 ~~Costs~~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 ~~following~~decrease ~~table~~in ~~sets~~gas ~~forth~~gathering ~~certain~~and ~~information~~marketing ~~regarding~~revenues ~~our~~was ~~net~~due ~~oil~~to ~~and~~a ~~natural~~$518,000 decrease in gas ~~production,~~marketing revenues and ~~expenses~~a ~~for~~$153,000 ~~the~~decrease ~~years~~in ~~indicated.~~gas ~~This~~gathering ~~table includes continuing operations only~~revenues. The ~~average~~lower ~~prices~~gas ~~shown~~gathering inand marketing ~~the~~revenues ~~table~~were ~~include~~primarily the ~~effects~~result of ~~our~~lower ~~qualified effective~~gas ~~hedging~~sales ~~activities~~volumes.

	Year Ended December 31,
	2009		2008		2007
Production
Gas (MMcf)		12,034		13,217		13,357
Oil (Mbbl)		324		334		348
Total production (MMcfe)		13,977		15,221		15,446
Average sales price (1)
Gas (per Mcf)	$	3.61	$	8.62	$	6.81
Oil (per Bbl)		56.49		94.40		67.42
Per Mcfe		4.42		9.55		7.41
Average costs (per Mcfe)
Production expense	$	1.50	$	1.73	$	1.59
Production taxes		0.08		0.20		0.15
Depletion		2.62		2.31		2.31

Costs and Expenses

~~(1)~~Production ~~The~~expense ~~average~~decreased ~~prices~~$427,000 ~~presented~~from ~~above~~$21.0 million ~~include~~in ~~non-cash~~2009 ~~amounts~~to ~~related~~$20.5 million in 2010. The decrease was primarily due to the sale of our ~~derivatives~~coalbed asmethane aassets ~~result~~in ofPennsylvania ~~purchase~~in ~~accounting~~July 2009 ~~for~~partially ~~the~~offset ~~Merger~~by ~~and~~higher ~~the~~ad ~~Transaction~~valorem taxes in 2010. ~~Excluding~~The ~~these~~average ~~non-cash~~production ~~amounts~~cost increased from ~~oil~~$1.50 ~~and~~per ~~gas~~Mcfe ~~sales~~in ~~revenues~~2009 ~~would~~to ~~result~~$1.75 per Mcfe in 2010 due to the ~~following~~lower ~~average~~oil and gas sales ~~prices:~~volumes.

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

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 ~~Compared~~to $5.0 million in 2010 primarily due to ~~2008~~lower gas sales volumes in 2010.

~~Revenues~~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.

~~Net~~General ~~operating~~and ~~revenues~~administrative expense decreased $891.80 million from $~~158~~7.48 million in ~~2008~~2009 to $~~68.~~6 .8 million in ~~2009~~ 2010. The decrease was primarily due to ~~lower~~a ~~gas~~decrease ~~sales~~in ~~revenues~~overhead offees ~~$70.4 million,~~paid ~~lower~~to ~~oil~~EverVest ~~sales~~as ~~revenue~~a result of ~~$13.2 million~~the ~~and~~sale ~~lower~~of ~~gas~~our ~~gathering~~coalbed methane assets in Pennsylvania in July 2009 and ~~marketing~~lower ~~revenues~~insurance costs ofin $62010.~~4 million.~~

~~Gas~~Depreciation, ~~volumes~~depletion ~~sold~~and amortization decreased ~~1,183~~$7.6 million ~~MMcf (9%)~~ from 13$37.~~2 Bcf in 2008 to 12.~~0 million ~~Bcf~~ in 2009 ~~resulting~~to in$29.4 million ~~a decrease~~ in ~~gas~~2010. ~~sales~~Depletion ~~revenues~~expense ofdecreased ~~approximately~~ $107.26 million. ~~Oil~~due ~~volumes~~to ~~sold~~the ~~decreased~~lower production ~~approximately~~volumes ~~10,000~~and ~~Bbls~~a ~~(3%)~~lower ~~from~~depletion ~~334,000~~rate ~~Bbls~~per inMcfe. ~~2008~~Depletion toper ~~324,000~~Mcfe ~~Bbls~~decreased infrom ~~2009~~$2.62 ~~resulting~~ in ~~a decrease~~2009 ~~in oil sales revenues of approximately~~ to $~~950,000~~2.48 ~~The~~in ~~lower~~2010 ~~oil~~primarily ~~and gas sales volumes are~~ due to ~~normal~~higher ~~production~~proved ~~declines~~reserves ~~and~~as ~~the~~a ~~sale~~result of ~~our~~higher ~~coalbed~~oil ~~methane~~and ~~properties~~gas inprices ~~July 2009, which were partially offset by production from new wells drilled~~ in ~~2009 and operational projects,~~ ~~which increased production for some existing wells~~2010.

32Impairment 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.

~~Table~~Gain on sale of ~~Contents~~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.

~~The~~Derivative ~~average~~fair ~~price~~value ~~realized~~gain/loss ~~for~~was ~~our natural gas decreased $5.01 per Mcf to $3.61 per Mcf in 2009 compared to 2008, which decreased gas sales revenues by approximately $60.2 million. As~~ a ~~result~~ gain of ~~our qualified effective hedging activities, gas sales revenues were lower by~~ $732.98 million ~~($0.66~~ ~~per Mcf)~~ in ~~2009~~2010 and ~~lower by~~ $929.26 million ~~($0.69 per Mcf)~~ in ~~2008 than if our gas was not hedged. The average price realized for our oil decreased from $94.40 per Bbl in 2008 to $56.49 per Bbl in~~ 2009~~, which decreased oil sales revenues by approximately $12~~.~~3 million. As of July 1,~~ ~~2006,~~The wederivative ~~determined~~fair ~~that~~value ~~our~~gain/loss ~~gas~~reflects ~~derivatives~~the nochanges ~~longer qualified for cash flow hedge accounting. Changes~~ in ~~the~~ fair value of ~~the~~certain ~~gas~~derivative instruments ~~derivatives from~~ that ~~date forward~~ are ~~recorded~~not indesignated ~~derivative fair value gain/loss. Deferred gains~~ or ~~losses~~do onnot ~~these~~qualify ~~gas derivatives are recognized~~ as ~~increases~~ orcash ~~decreases~~flow ~~to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings~~hedges.

~~The~~Gain ~~decrease~~on inearly ~~gas~~extinguishment ~~gathering~~of ~~and~~debt ~~marketing revenues~~ was ~~due to a~~ $51.0 million ~~decrease~~ in ~~gas marketing~~2010 ~~revenues~~as ~~and~~ a ~~$1.4 million decrease in gas gathering revenues. The lower marketing revenues were primarily the~~ result of ~~lower~~our ~~gas~~repurchase ~~prices. The decrease in gas gathering revenues was~~of ~~primarily~~$20 million ~~due~~of toour ansenior ~~decrease~~secured innotes ~~third~~at ~~party~~a ~~gathering volumes on gathering systems in Pennsylvania and lower gas prices~~discount.

~~Costs~~Interest ~~and~~expense ~~Expenses~~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.

~~Production~~ Income tax expense ~~decreased~~increased ~~$5.3 million~~ from $261.39 million in ~~2008~~2009 to $216.04 million in ~~2009~~2010. The ~~decrease~~increase in income tax expense was primarily due to ~~decreases~~an increase in ~~labor~~net ~~costs,~~income ~~decreases~~before income taxes in ~~gas~~2010. This ~~processing~~was ~~fees~~partially ~~and decreased~~offset ~~workover~~by ~~expense,~~a decrease in the ~~sale~~effective tax rate due to the reduction of the ~~coalbed~~state ~~methane~~tax valuation ~~assets~~allowance. inThe ~~Pennsylvania~~valuation ~~and~~allowance ~~general decreases~~was inreduced ~~third~~upon ~~party~~the ~~costs.~~realization ~~The~~of ~~average~~state ~~production~~tax net ~~cost~~operating ~~decreased~~loss carryforwards, which resulted from ~~$1.73~~taxable ~~per~~gains ~~Mcfe~~on inasset ~~2008~~sales. toThe ~~$1.50~~decrease ~~per~~in ~~Mcfe~~the ineffective ~~2009~~tax rate was also due to ~~these~~the ~~cost~~elimination ~~decreases~~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.

~~Production taxes decreased $2.0 million from $3.1 million in 2008 to $1.1 million in 2009,~~34 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~~Compared ~~due~~ to ~~lower gas prices in 2009.~~2008

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

~~General~~Net ~~and~~operating ~~administrative~~revenues ~~expense~~ decreased $~~403,000~~89.8 million from $8158.24 million in 2008 to $768.8 6 million in 2009. The decrease was primarily due to alower ~~decrease~~gas insales ~~overhead~~revenues ~~fees~~of ~~paid~~$70.4 million, tolower ~~EverVest~~oil sales revenue of $13.2 million and lower gas gathering and marketing revenues of $6.4 million.

~~Depreciation,~~Gas ~~depletion~~volumes ~~and~~sold ~~amortization~~decreased ~~increased~~1,183 byMMcf ~~$1.4 million~~(9%) from ~~$35~~13.~~6 million~~2 Bcf in 2008 to ~~$37~~12.0 ~~million~~ Bcf in 2009 resulting in a decrease in gas sales revenues of approximately $10.2 million. ~~Depletion~~Oil ~~expense~~volumes ~~increased~~sold ~~due~~decreased approximately 10,000 Bbls (3%) from 334,000 Bbls in 2008 to ~~lower~~324,000 ~~proved~~Bbls ~~reserves~~in as2009 resulting in a decrease ~~result~~in oil sales revenues of approximately $950,000. The lower oil and gas ~~prices~~sales volumes are due to normal production declines and the sale of our coalbed methane properties in July 2009., which ~~Depletion~~were ~~per~~partially ~~Mcfe~~offset ~~was~~by ~~$2.31~~production infrom ~~2008~~new ~~and~~wells ~~$2.62~~drilled in 2009 and operational projects, which increased production for some existing wells.

~~Impairment~~The ofaverage ~~goodwill~~price ~~was~~realized for our natural gas decreased $905.~~1 million~~01 inper ~~2008~~Mcf ~~due~~to $3.61 per Mcf in 2009 compared to ~~the~~$8.62 ~~significant~~per ~~drop~~Mcf in ~~oil~~2008, ~~and~~which decreased gas sales revenues by approximately $60.2 ~~prices~~million. ~~resulting~~As ina ~~part~~result ~~from~~of ~~the~~our ~~global~~previously ~~economic~~qualified effective hedging activities, gas sales revenues were lower by $7.9 million ($0.66 per Mcf) in 2009 and ~~market~~lower ~~crisis~~by $9.2 million We($0.69 ~~did~~per Mcf) in 2008 than if our gas was not ~~have~~hedged. anThe ~~impairment~~average price realized for our oil decreased from $94.40 ofper ~~goodwill~~Bbl in 2008 to $56.49 per Bbl in 2009, which decreased oil sales revenues by approximately $12.3 million.

~~Impairment~~The ofdecrease ~~oil~~in gas gathering and ~~gas~~marketing ~~properties~~revenues ~~increased~~was ~~$26.5 million~~due ~~from~~to a $35.90 million decrease in ~~2008 to~~gas marketing revenues and a $301.4 million decrease in ~~2009~~gas ~~due~~gathering torevenues. ~~the~~The ~~write-downs~~lower ofmarketing revenues ~~our~~were ~~investment~~primarily inthe ~~properties~~result inof ~~the~~lower ~~coalbed~~gas ~~methane and~~prices. ~~Marcellus~~The ~~formation~~decrease in ~~Pennsylvania~~gas asgathering arevenues ~~result~~was primarily ofdue ~~lower~~to ~~oil~~an ~~and~~decrease ~~gas~~in ~~prices~~third ~~and~~party ~~unfavorable development~~gathering ~~results~~volumes on gathering systems in ~~the~~Pennsylvania and ~~Marcellus~~lower ~~formation~~gas prices.

~~Derivative~~Costs ~~fair value gain/loss was a gain of $29.6 million in 2009~~ and ~~$55.9 million in 2008.~~Expenses The derivative fair value gain/loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges. Our oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, changes in fair value were reflected in derivative fair value gain/loss. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting and, therefore, changes in fair value subsequent to that date are reflected in derivative fair value gain/loss.

~~Gain~~Production onexpense ~~sale~~decreased of$5.3 million ~~assets~~from ~~was~~$26.3 million in 2008 to $3421.90 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 ~~undeveloped~~the ~~Marcellus acreage~~coalbed methane assets in Pennsylvania and general decreases in third party costs. ~~There~~The ~~was~~average noproduction ~~gain~~cost ondecreased ~~the~~from ~~sale~~$1.73 ofper ~~assets~~Mcfe in 2008 to $1.50 per Mcfe in 2009 due to these cost decreases.

33Production 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.

~~Table~~Gathering ofand ~~Contents~~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.

~~Interest~~Exploration expense ~~decreased~~increased $21.24 million from $222.85 million in 2008 to $203.69 million in 2009. ~~This~~The ~~decrease~~increase was primarily due to ~~lower~~an ~~outstanding~~increase ~~debt~~in expired lease expense in 2009.

~~Income~~General ~~tax~~and administrative expense decreased $403,000 from $398.62 million in 2008 to $2.7 .8 million in 2009. The decrease in ~~income tax expense~~ was primarily due to a decrease in ~~the~~overhead ~~net~~fees ~~income~~paid ~~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~~EnerVest.

Depreciation, depletion and amortization increased by $1.4 million from $35.6 million in 2008 to ~~Compared~~$37.0 million in 2009. Depletion expense increased $1.5 million from 2008 to ~~2007~~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.

~~Revenues~~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.

~~Net operating revenues increased $33.3 million from $125.1 million in 2007 to $158.4 million~~35 ~~in 2008. The increase was primarily due to higher gas sales revenues of $22.9 million, higher oil sales revenue of $8.1 million and higher gas gathering and marketing revenues of $2.0 million.~~

~~Gas~~Impairment ~~volumes~~of ~~sold~~oil ~~decreased~~and ~~140~~gas ~~MMcf~~properties ~~(1%)~~increased ~~from 13~~$26.45 million ~~Bcf~~from ~~in 2007 to 13~~$3.29 million ~~Bcf~~ in 2008 ~~resulting~~to ~~in a decrease in gas sales revenues of approximately~~ $~~950,000~~30.4 million ~~Oil~~in ~~volumes~~2009 ~~sold~~due ~~decreased approximately~~to ~~14,000~~the ~~Bbls~~write-downs ~~(4%)~~of ~~from~~our ~~348,000~~investment ~~Bbls~~ in ~~2007~~properties toin ~~334,000~~the ~~Bbls~~coalbed inmethane and ~~2008~~Marcellus ~~resulting~~formation in ~~a decrease~~Pennsylvania inas ~~oil~~a ~~sales~~result ~~revenues~~ of ~~approximately $960,000. The~~ lower oil and gas ~~sales~~prices ~~volumes~~and ~~are~~unfavorable ~~due~~development toresults ~~normal~~in ~~production~~the ~~declines,~~Marcellus ~~which were partially offset by production from new wells drilled in 2008~~formation.

~~The~~Derivative ~~average~~fair ~~price~~value ~~realized~~gain/loss ~~for~~was ~~our natural gas increased $1.81 per Mcf to $8.62 per Mcf in 2008 compared to 2007, which increased gas sales revenues by approximately $23.9 million. As~~ a ~~result~~ gain of ~~our qualified effective hedging activities, gas sales revenues were lower by~~ $929.26 million ~~($0.69~~ ~~per Mcf)~~ in ~~2008~~2009 and ~~lower by~~ $755.19 million ~~($0.53 per Mcf)~~ in ~~2007 than if our gas was not hedged. The average price realized for our oil increased from $67.42 per Bbl in 2007 to $94.40 per Bbl in~~ 2008~~, which increased oil sales revenues by approximately $9~~.~~0 million. As of July 1, 2006,~~ weThe ~~determined~~derivative ~~that~~fair ~~our~~value ~~gas~~gain/loss ~~derivatives~~reflects nothe ~~longer~~changes ~~qualified for cash flow hedge accounting. Changes~~ in ~~the~~ fair value of ~~the~~certain ~~gas~~derivative instruments ~~derivatives from~~ that ~~date forward~~ are ~~recorded~~not indesignated ~~derivative fair value gain/loss. Deferred gains~~ or ~~losses~~do onnot ~~these~~qualify ~~gas derivatives are recognized~~ as ~~increases~~cash ~~or decreases~~flow ~~to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings~~hedges.

~~The~~Gain ~~increase~~on insale ~~gas~~of ~~gathering~~assets ~~and marketing revenues~~ was ~~due to a~~ $134.59 million ~~increase~~ in ~~gas marketing~~2009 ~~revenues~~due ~~and~~to ~~a $510,000 increase in gas gathering revenues. The higher marketing revenues were primarily~~ the ~~result~~sale of ~~higher~~undeveloped ~~gas~~Marcellus acreage ~~prices. The increase~~ in ~~gas~~Pennsylvania. ~~gathering~~There ~~revenues~~ was ~~primarily~~ ~~due~~no togain anon ~~increase~~the insale ~~third~~of ~~party~~assets ~~gathering volumes on gathering systems~~ in ~~Pennsylvania~~2008.

~~Costs~~Interest ~~and~~expense ~~Expenses~~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.

~~Production~~Income tax expense ~~increased~~decreased ~~$1.7 million~~ from $2439.6 million in ~~2007~~2008 to $261.39 million in ~~2008~~2009. The decrease ~~This~~in ~~increase~~income tax expense was primarily due to ~~higher~~a ~~fuel~~decrease ~~costs, increases~~ in ~~labor~~the ~~and~~net ~~oilfield~~income ~~service costs,~~before ~~increases~~income taxes in ~~gas processing fees~~ 2009 and ~~increased~~a ~~workover~~decrease ~~expense.~~in ~~The~~the ~~average~~effective ~~production cost~~tax ~~increased~~rate ~~from~~due ~~$1.59 per Mcfe in 2007~~ to ~~$1.73~~the ~~per~~impairment ~~Mcfe~~of goodwill in 2008 ~~due~~which tois ~~these~~not ~~cost increases~~an ~~and~~allowable ~~the~~expense ~~lower~~in ~~oil~~the ~~and~~calculation ~~gas~~of ~~sales~~taxable ~~volumes in 2008~~income.

~~Production~~Liquidity ~~taxes~~and ~~increased~~Capital ~~$789,000 from $2.3 million in 2007 to $3.1 million in 2008,~~Resources primarily due to higher gas prices in Michigan in 2008, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes increased from $0.15 per Mcfe in 2007 to $0.20 per Mcfe in 2008.

~~Gathering~~Cash ~~and marketing expense increased $1.7 million from $8.6 million in 2007 to $10.3~~Flows ~~million in 2008 primarily due to higher gas marketing costs as a result of higher gas prices in 2008.~~

~~Exploration~~We ~~expense~~expect ~~increased~~that ~~$608,000~~our ~~from~~primary ~~$1.9 million~~sources of cash in ~~2007~~2011 towill ~~$2.5 million~~be infrom ~~2008.~~funds ~~The~~generated from ~~increase~~operations ~~was~~and ~~primarily~~the ~~due~~sale toof annon-strategic ~~increase~~assets. inBased ~~expired~~on ~~lease~~our ~~expense~~current level of operations, we believe our cash flow from operations, available cash and ~~exploratory~~available ~~dry~~borrowings ~~hole~~under ~~expense of~~our ~~$744~~Credit Agreement,~~000~~ inwill ~~2008~~be adequate to meet our short-term liquidity needs for 2011.

~~General~~The ~~and~~primary ~~administrative~~sources ~~expense~~of ~~was~~cash ~~$8.2~~in the year ended December ~~million~~31, in2010 ~~2007~~were funds generated from operations and ~~2008~~the sale of non-strategic assets. Funds used during this period were primarily used for operations, exploration and ~~decreased~~development ~~$48~~expenditures,~~000 primarily~~ ~~due~~the torepayment aof ~~decrease~~debt, inthe ~~franchise~~settlement ~~tax~~of derivatives and ~~insurance~~interest expense. ~~which~~Our ~~was~~liquidity ~~partially~~and ~~offset~~capital byresources anare closely related to and ~~increase~~dependent inupon ~~professional~~the ~~services~~current ~~expense~~prices paid for our oil and natural gas.

3436

~~Table~~The offollowing ~~Contents~~table summarizes the net cash flow for the periods presented:

Depreciation, depletion and amortization decreased by $527,000 from $36.1 million in 2007 to $35.6 million in 2008. This decrease was primarily due to a decrease in depletion expense. Depletion expense decreased $495,000 from $35.7 million in 2007 to $35.2 million in 2008 due to lower volumes produced. Depletion per Mcfe was $2.31 per Mcfe in 2007 and 2008.


	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	)

~~Impairment~~ Our operating activities provided cash flows of ~~goodwill~~$18.7 million ~~was~~during 2010 compared to $9023.19 million in ~~2008~~2009. The decrease was primarily due to ~~the~~a ~~significant~~$2.9 million ~~drop~~decrease in oil and gas ~~prices~~sales, ~~resulting~~excluding ~~in part from~~ the ~~global~~effects ~~economic~~of hedging and ~~market~~a ~~crisis~~$3.2 million Wedecrease ~~had~~in nothe ~~impairment~~change ofin operating ~~goodwill~~assets, which was partially offset by a $980,000 decrease in ~~2007~~general and administrative expense.

~~Impairment~~Cash offlows ~~oil~~provided ~~and~~by ~~gas~~investing ~~properties~~activities ~~was~~were $319.9 million in ~~2008~~2010 ~~due~~compared to ~~the~~cash ~~write-down of our~~flows ~~investment~~used in ~~properties~~investing inactivities ~~the~~of ~~Utica~~$38.9 million ~~Shale~~in ~~formation~~2009. inThis ~~Ohio~~decrease ~~and~~was ~~other~~due ~~unproved~~to ~~properties.~~a Wedecrease of ~~had~~$16.5 million noin ~~impairment~~proceeds offrom ~~oil~~property and ~~gas~~equipment ~~properties~~sales and an increase of $2.7 million in property ~~2007~~and equipment additions.

~~Derivative~~Cash ~~fair~~flows ~~value~~used ~~gain/loss~~in ~~was~~financing aactivities ~~gain~~in of2010 were $5549.94 million ~~in 2008~~ compared to ~~a loss of~~ $7838.19 million in ~~2007~~2009. ~~The~~This ~~derivative~~increase ~~fair~~was ~~value~~primarily ~~gain/loss~~due ~~reflects~~to the ~~changes~~$20.0 million decrease in ~~fair~~capital ~~value of certain derivative instruments that are not designated or do not qualify as cash flow hedges~~contributions, ~~the~~ ~~ineffective~~the ~~portion~~$19.2 million repurchase of ~~crude~~Senior ~~oil~~Secured ~~swaps~~Notes ~~through~~in ~~August 15,~~2010 ~~2005~~ and the ~~ineffective portion of natural gas swaps as a result of purchase accounting~~$8.3 million ~~Our~~increase ~~oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, changes~~ in ~~fair value were~~the ~~reflected~~settlement inof derivative ~~fair~~liabilities ~~value~~which ~~gain/loss~~were inpartially ~~2006.~~offset Asby ofthe ~~July~~$36.0 1,million ~~2006,~~decrease ~~we determined that our gas derivatives no longer qualified for cash flow hedge accounting and, therefore, changes~~ in ~~fair~~ ~~value~~debt ~~subsequent to that date are reflected in derivative fair value gain/loss~~repayments.

~~Interest~~During ~~expense~~2010, our working capital decreased $~~894,000~~14.5 million from a surplus of $2328.72 million inat December 31, ~~2007~~2009 to a surplus of $2213.87 million inat ~~2008~~December 31, 2010. ~~This~~ The decrease was primarily due to ~~lower~~a ~~blended~~decrease ~~interest~~in ~~rates~~cash of $10.8 million, a $7.2 million increase in ~~2008~~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.

~~Income~~Capital ~~tax expense increased from a benefit of $23.9 million in 2007 to an expense of $39.6~~Expenditures million in 2008. The increase in income tax expense was primarily due to an increase in the net income before income taxes in 2008 and an increase in the effective tax rate due to the impairment of goodwill which is not an allowable expense in the calculation of taxable income.

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

Cash Flows


	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

WeDuring ~~expect~~2010, ~~that~~we ~~our~~spent ~~primary~~approximately ~~sources~~$18.0 million, ofincluding ~~cash~~exploratory indry ~~2010~~hole expense, ~~will~~on beour ~~from~~drilling ~~funds generated from operations~~ and ~~the~~other ~~sale~~capital ~~of non-strategic assets~~expenditures. ~~Based~~In on2010, ~~our~~we ~~current~~drilled ~~level~~39 ofgross ~~operations,~~(39.0 wenet) ~~believe~~development ~~our~~wells ~~cash~~and ~~flow~~6 ~~from~~gross ~~operations,~~(1.5 ~~available~~net) ~~cash~~exploratory ~~and~~wells ~~available~~of ~~borrowings~~which ~~under~~38 ~~our~~gross ~~Amended Credit~~(38.0 ~~Agreement,~~net) ~~will~~development wells beand ~~adequate~~4 togross ~~meet~~(1.0 ~~our~~net) ~~short-term~~exploratory ~~liquidity~~wells ~~needs~~were ~~for~~completed ~~the~~as ~~foreseeable future~~producing wells.

~~The primary sources of cash in the year ended December 31, 2009 were funds generated from~~37 operations, from additional equity contributions from Capital C and the sale of non-strategic assets. Funds used during this period were primarily used for operations, exploration and development expenditures, the repayment of debt, the settlement of derivatives and interest expense. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

~~The~~We ~~following~~plan ~~table~~to ~~summarizes~~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 ~~net~~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 ~~periods~~effects ~~presented:~~of the recovery from the recent recession, the scope and success of our drilling activities and our ability to acquire additional producing properties.

	Year Ended December 31,
	2009			2008			Change
	(in millions)
Cash flows provided by operating activities	$	23.9		$	96.7		$	(72.8	)
Cash flows provided by (used in) investing activities		38.9			(27.5	)		66.4
Cash flows (used in) financing activities		(38.9	)		(62.4	)		23.5
Net increase (decrease) in cash and cash equivalents	$	23.9		$	6.8		$	17.1

Financing and Credit Facilities

35Senior Secured Notes due 2012

~~Table~~We have $139.5 million of ~~Contents~~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.

~~Our~~July ~~operating activities provided cash flows of $23.9 million during 2009 compared to $96.7 million in 2008. The decrease was primarily due to an $84.9 million decrease in oil and gas sales~~15, ~~excluding~~2010 ~~the effects of hedging which was partially offset by a $5.3 million decrease in production expense~~ and athereafter $6100.~~7 million~~000 ~~increase in the change in operating assets.~~ %

~~Cash~~ ~~flows~~The ~~provided~~Senior Secured Notes are governed by ~~investing~~an ~~activities~~indenture ~~were~~(the ~~$38.9 million~~“Indenture”), inwhich contains ~~2009~~certain ~~compared~~covenants that limit our ability to ~~cash~~incur ~~flows used~~additional inindebtedness ~~investing~~and ~~activities~~issue ofstock, pay ~~$27.5 million~~dividends, inmake ~~2008.~~distributions, ~~This~~make ~~increase~~investments, ~~was~~make ~~due~~certain toother anrestricted ~~increase~~payments, ofenter ~~$50.1 million~~into incertain ~~proceeds~~transactions ~~from~~with ~~property~~affiliates, ~~and~~dispose ~~equipment~~of ~~sales~~certain ~~and~~assets, aincur ~~decrease~~liens securing indebtedness of ~~$17.1 million~~any ~~in property~~kind other than permitted liens and ~~equipment~~engage ~~additions~~in mergers and consolidations.

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

~~During~~In ~~2009~~2005, ~~our~~we ~~working~~amended ~~capital~~and ~~increased~~restated ~~$45.0 million~~our ~~from~~then aexisting ~~deficit~~credit ~~of $16.8 million at December 31~~agreement, ~~2008~~by toentering into a ~~surplus~~First Amended ofand ~~$28.2 million~~Restated atCredit ~~December 31,~~and ~~2009.~~Guaranty ~~The~~Agreement ~~increase~~by ~~was~~and ~~primarily due~~among tous anand ~~increase~~BNP inParibas, ~~cash~~as ofsole ~~23.9 million~~lead arranger, asole ~~decrease~~book inrunner, ~~the~~syndication ~~current~~agent ~~portion of long term liabilities of $25.0 million~~ and aadministrative $4agent.~~1 million~~ ~~decrease~~The inCredit ~~accounts payable and accrued expenses,~~Agreement ~~which~~provides ~~was~~for ~~partially~~loans ~~offset~~and byother aextensions ~~decrease~~of incredit ~~accounts~~to ~~receivable~~be ofmade $7to us.~~4 million.~~

~~Capital~~On ~~Expenditures~~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 ~~table~~Credit Agreement ~~below~~was ~~sets~~amended ~~forth~~to ~~our~~(1) extend ~~total~~the ~~capital~~termination ~~expenditures~~date ~~for~~to ~~each~~April 14, 2012, (2) extend the hedge letter of credit termination date to April 14, 2012, (3) decrease the ~~years~~aggregate ~~ending~~amount of the ~~December~~revolving commitments to $90 31million, ~~2009,~~(4) decrease ~~2008~~the borrowing base to $55 million and ~~2007~~(5) make certain other amendments to the Credit Agreement.

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

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

~~During 2009, we spent approximately $11.6 million, including exploratory dry hole~~38 ~~expense, on our drilling and other capital expenditures. In 2009, we drilled 4 gross (2.0 net) exploratory wells in 2009.~~

Wehave ~~plan~~an toinvestment ~~spend~~in ~~approximately $12~~us.~~5 million~~ ~~during 2010 on our drilling activities and other capital expenditures.~~ We ~~intend~~can toprovide ~~finance~~no ~~our~~assurances ~~planned~~that ~~capital expenditures through~~ our ~~cash~~lenders ~~on hand,~~will ~~available~~agree ~~cash flow and,~~ to ~~a lesser extent, the sale of non-strategic assets. The level of~~ refinance our ~~future~~Credit ~~cash flow will depend on a number of factors including the demand for and price levels of oil and gas~~Agreement, ~~worldwide economic conditions~~or, ~~including~~if ~~the effects of the recovery from the recent recession~~available, ~~the scope and success of our drilling activities and our ability to acquire additional producing properties. There can be no assurance~~ that the ~~future~~terms ~~drilling~~ of ~~our~~any ~~proved undeveloped~~such ~~locations~~refinancing will ~~provide~~be acceptable ~~adequate~~to ~~liquidity in the future~~us.

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

~~Senior~~Borrowings ~~Secured~~under ~~Notes~~the ~~due~~revolving ~~2012~~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).

WeIn ~~have~~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 $~~159.5~~94 million. ofUnder ~~our~~the ~~Senior~~Subordinated Note, ~~Secured~~Capital ~~Notes~~C ~~outstanding~~loaned as$25 million ofto ~~December~~us on August 3116, ~~2009~~2005. AsThe aSubordinated Note accrues interest ~~result~~at a rate of ~~the~~10% ~~application~~per ofannum ~~purchase~~and ~~accounting,~~matures ~~the~~on ~~notes~~August 16, ~~were~~2012. ~~recorded~~We asreceived a ~~liability~~fairness ~~based~~opinion onfrom an ~~the~~unrelated ~~estimated~~financial ~~fair~~services ~~value~~firm with respect to the terms of ~~$200~~the Subordinated Note made on August 16, 2005.~~7 million~~ Interest payments on the ~~Transaction~~Subordinated ~~date~~Note are due quarterly. In ~~June 2006,~~lieu weof ~~repurchased~~cash apayments, ~~portion~~we ofhave the ~~outstanding~~option ~~Senior~~to ~~Secured~~make ~~Notes~~interest payments on the Subordinated Note by borrowing additional amounts against the Subordinated Note. The ~~repurchased~~interest ~~notes~~payments ~~had~~in athe ~~face~~first ~~value~~three quarters of ~~$33.025~~2008 ~~million and~~ were ~~repurchased~~paid atin ~~102~~cash.~~750%.~~ AInterest ~~gain~~payments for the fourth quarter of ~~$436,000~~2008 ~~was~~and ~~recorded~~all inof ~~2006~~2009 inwere ~~connection~~made by ~~with~~additional borrowings against the ~~transaction~~Subordinated Note. ~~The~~In ~~notes~~2010, ~~mature~~the ~~July 15,~~first ~~2012.~~quarter ~~Interest~~interest ispayment was ~~payable~~paid ~~semi-annually~~in ~~on January 15~~cash and ~~July 15~~interest ofpayments ~~each~~for ~~year~~the atlast ~~8.75%~~three ~~based~~quarters onwere made by additional borrowings against the ~~face~~Subordinated ~~amount~~Note. As of December 31, 2010, $~~159~~32.58 million ~~(for~~was anoutstanding ~~effective~~against ~~rate~~the ofSubordinated 7Note.~~946%~~ ~~based~~The onSubordinated ~~the~~Note ~~fair~~has ~~value~~no onprepayment ~~the~~penalty ~~Transaction~~or ~~date.)~~premium ~~The~~and ~~notes~~may be ~~are~~prepaid ~~secured~~in ~~on a~~whole ~~second-priority~~or ~~lien~~in onpart ~~the~~at ~~same~~any ~~assets~~time. ~~subject~~Pursuant to the ~~liens~~Fourth ~~securing~~Amendment to our ~~obligations~~credit agreement ~~under~~future ~~the Amended~~cash ~~Credit~~payments ~~Agreement.~~for ~~The~~principal ~~Senior~~or ~~Secured~~interest ~~Notes~~on the Subordinated Note are ~~subject~~prohibited. The toSubordinated ~~redemption~~Note atis subordinate to our ~~option~~senior atdebt, which includes obligations under the ~~specific~~Credit ~~redemption~~Agreement, ~~prices~~the J. Aron Swap and the Senior Secured Notes.

July 15, 2009			102.188	%
July 15, 2010 and thereafter			100.000	%

ISDA Master Agreement

36In 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.

~~Table~~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 ~~Contents~~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.

~~The~~At ~~Senior~~December 31, ~~Secured~~2010, ~~Notes~~the ~~are~~aggregate ~~governed~~long-term bydebt anmaturing ~~indenture~~in (the ~~“Indenture”),~~next ~~which~~five ~~contains certain~~years ~~covenants~~is ~~that limit our ability to incur additional indebtedness and issue stock, pay~~as ~~dividends,~~follows: ~~make distributions~~$10,000 ~~make~~(2011); ~~investments,~~$196.2 million ~~make~~(2012); ~~certain other restricted payments~~$12,000 ~~enter~~(2013); ~~into certain transactions with affiliates~~$13,000 ~~dispose~~(2014) and ~~of certain assets~~$7,000 ~~incur~~(2015 ~~liens securing indebtedness of any kind other than permitted liens~~ and ~~engage in mergers and consolidations~~ thereafter).

~~Amended~~Derivative ~~Credit Agreement~~Instruments

In 2005, we amended and restated our then existing credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The ~~Amended Credit~~Hedges ~~Agreement provides for loans and other extensions of credit to be made to us.~~

OnTo ~~September 25,~~manage ~~2009,~~our ~~Belden~~exposure &to ~~Blake~~natural ~~Corporation~~gas ~~entered~~or ~~into~~oil ~~the~~price ~~Fifth~~volatility, ~~Amendment~~we tomay ~~Credit Agreement.~~partially ~~The~~hedge ~~Credit~~our physical ~~Agreement~~gas ~~was~~or ~~amended~~oil tosales ~~(1) reduce~~prices ~~the~~by ~~borrowing~~selling ~~base~~futures tocontracts ~~$65 million,~~on ~~(2) extend~~ the ~~termination~~NYMEX ~~date~~or by ~~one~~selling NYMEX-based ~~year~~commodity toderivative ~~August 16,~~contracts ~~2011,~~which ~~(3) decrease~~are ~~the~~placed ~~aggregate~~with ~~amount~~major offinancial institutions that we believe are minimal credit risks. The contracts may take the ~~revolving~~form ~~commitments~~of tofutures ~~$100 million~~contracts, ~~and~~swaps, collars ~~(4) make~~or ~~certain~~options. ~~other~~None ~~amendments~~of toour ~~the~~contracts ~~Credit Agreement~~currently qualify for hedge accounting.

AtOn ~~December~~July 317, ~~2009~~2004, wethe ~~had~~date ~~an Amended Credit Agreement comprised~~ of athe ~~five-year $100 million revolving facility with a borrowing base of $65 million~~Merger, ofwe ~~which~~became ~~$43.9 million was outstanding at December 31, 2009. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and~~ a ~~five~~party ~~year~~to ~~$40 million~~long-term ~~letter~~commodity ofhedges ~~credit~~(the ~~facility~~“Hedges”) ~~that~~with ~~may~~J. beAron ~~used~~pursuant ~~only~~ to ~~provide~~a ~~credit~~master ~~support for our obligations under the hedge~~ agreement and ~~other~~related ~~hedge~~confirmations ~~transactions.~~and ~~Borrowings~~documentation (collectively, ~~under~~ the ~~Amended~~“Hedge ~~Credit~~ Agreement ~~bear interest (i~~”.) at ~~the~~We ~~greater~~anticipate ofthat the ~~prime~~Hedges ~~rate,~~will ancover ~~adjusted~~approximately ~~federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0~~66% ~~to 2.0% based on the aggregate principal amount~~ ~~outstanding~~of ~~under~~ the ~~Amended~~expected ~~Credit~~2011 ~~Agreement,~~through ~~or,~~2013 ~~(ii) at~~production from our ~~option,~~current ~~the~~estimated ~~Eurodollar~~proved ~~base~~reserves ~~rate~~and will ~~plus~~range ~~an applicable margin ranging~~ from ~~2.5~~62% to ~~3.50~~72% ~~based~~of onsuch ~~the~~expected ~~aggregate~~production ~~principal~~in ~~amount outstanding~~any ~~under the Amended Credit Agreement~~year. The ~~full~~Hedges ~~amount borrowed under the Amended Credit~~primarily ~~Agreement will mature on August 16, 2011.~~

On39 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.

Attake ~~December 31~~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, ~~2009~~we pay NYMEX-based floating price per MMbtu, in the case of Hedges on natural gas, and we ~~were~~pay a NYMEX-based floating price per Bbl, in ~~compliance~~the ~~with~~case ~~such~~of ~~financial~~Hedges ~~covenants~~on ~~under~~crude oil, for each month during the ~~Amended~~term ~~Credit~~of ~~Agreement.~~the ~~Our~~Hedges ~~senior~~and receive ~~secured~~a fixed price per MMbtu or Bbl (as the case may be) according to a monthly ~~leverage~~schedule ~~ratio~~of ~~was~~fixed 1prices that we established upon completion of the Merger.10 :The 1transactions will be settled on a net basis.0 ~~and~~The notional amounts of the Hedges were designed to provide sufficient hedged cash flow to cover operating expenditures, general and administrative expenses, interest expenses ~~coverage~~and ~~ratio~~the ~~was~~majority ~~1.96~~of :capital 1expenditures needed to develop proved reserves.0.

~~Borrowings~~We ~~under~~are ~~the~~required ~~revolving~~to ~~credit~~cause ~~line~~the ~~will~~Hedge beAgreement ~~used~~to byremain usin effect for ~~general~~so ~~corporate~~long ~~purposes~~as any portion of the Senior Secured Notes remains outstanding. The Hedges are documented under a standard InInternational ~~accordance~~Swap Dealers Association (“ISDA”) agreement with ~~the~~customized credit terms, ofdesigned to mitigate the ~~Amended~~liquidity ~~Credit~~pressures ~~Agreement,~~in ~~letters~~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 ~~hedge~~support ~~letter~~any exposure in excess of amounts supported by the letters of credit, ~~commitment~~we ~~and~~have ~~any~~granted ~~related~~J. Aron ~~borrowings~~a ~~are~~second tolien beon ~~used~~the ~~solely~~same toassets that secure the Credit Agreement and the Senior Secured ~~payment~~Notes ofand, to the extent our obligations ~~under~~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 ~~Swap~~hedges ~~(defined~~may ~~hereinafter)~~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.

37Our 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		—		—

InAt ~~connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note in favor of Capital C in the maximum principal amount of $94~~December ~~million. Under the Subordinated Note~~31, ~~Capital C loaned $25 million to us on August 16~~2010, ~~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~~fair ofvalue ~~the Subordinated Note made on August 16, 2005. Interest payments on the Subordinated Note are due quarterly commencing September 30, 2005. In lieu~~ of ~~cash~~futures ~~payments,~~contracts wecovering ~~have~~2011 ~~the~~through ~~option~~2013 ~~to make interest payments on the~~oil ~~Subordinated Note by borrowing additional amounts against the Subordinated Note. The interest payments in the first quarter of 2007~~ and ~~the~~gas ~~first~~production ~~three~~represented ~~quarters~~an ofunrealized ~~2008~~loss ~~were paid in cash. Interest payments for the last three quarters~~ of ~~2007 and the fourth quarter of 2008 and all of 2009 were made by additional borrowings against the Subordinated Note. As of December 31, 2009~~ $3039.57 million ~~was outstanding against the Subordinated Note~~. ~~The Subordinated Note has no~~ prepayment penalty or premium and may be prepaid in whole or in part at any time. Pursuant to the Fourth Amendment to our credit agreement cash payments for principal or interest on the Subordinated Note are prohibited. The Subordinated Note is subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and the Senior Secured Notes.

~~ISDA~~At ~~Master~~December 31, ~~Agreement~~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.

InInflation ~~connection with the Transaction, we amended~~ and ~~restated~~Changes 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~~Prices various gas and oil commodity derivatives transactions. The amendments to the J. Aron Swap conform the terms of the Schedule and Credit Support Annex to the terms of the Amended Credit Agreement, change certain covenants and reduce the maximum amount of the letter of credit securing the hedge obligations from $55 million to $40 million.

~~From~~The ~~time~~average toprice ~~time,~~realized wefor ~~may~~our ~~enter~~natural ~~into~~gas ~~interest~~decreased ~~rate~~from ~~swaps~~$8.62 toper ~~hedge~~Mcf ~~the~~in ~~interest~~2008 ~~rate~~to ~~exposure~~$3.61 ~~associated~~per ~~with~~Mcf ~~the~~in ~~credit~~2009 ~~facility,~~and ~~whereby~~then aincreased ~~portion~~to of$4.00 ~~our~~per ~~floating~~Mcf ~~rate~~in ~~exposure~~2010. isThe ~~exchanged~~ average price realized for aour oil ~~fixed~~decreased ~~interest~~from ~~rate~~$94.40 Atper ~~December 31,~~Bbl ~~2009,~~in we2008 ~~had~~to ~~interest~~$56.49 ~~rate~~per ~~swaps~~Bbl in ~~place~~2009 ~~covering~~ and then increased to $4373.~~5 million~~92 per ofBbl ~~our~~in ~~outstanding~~2010. ~~debt~~These ~~under~~prices include the ~~revolving~~effect ~~credit~~of ~~facility~~certain ~~that~~derivatives ~~mature~~which onwere ~~September~~previously ~~30,~~qualified ~~2013~~effective oil and gas hedges.

AtThe ~~December 31,~~price ~~2009,~~of ~~the~~oil ~~aggregate~~and ~~long-term~~natural ~~debt~~gas ~~maturing~~has ina ~~the~~significant ~~next~~impact ~~five~~on ~~years~~our isresults asof operations. Oil ~~follows:~~and $9natural gas prices fluctuate based on market conditions and,~~000~~ ~~(2010);~~accordingly, ~~$43.9 million~~cannot ~~(2011);~~be ~~$190~~predicted.~~0 million~~ Costs ~~(2012);~~to ~~$12~~drill,~~000~~ ~~(2013)~~ complete and ~~$20,000~~service wells can fluctuate based on demand for these services which ~~(2014~~is generally influenced by high or low commodity prices. Our costs and ~~thereafter)~~expenses may be subject to inflationary pressures if oil and gas prices are favorable.

~~Derivative Instruments~~40

~~The~~A ~~Hedges~~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.

ToContractual ~~manage our exposure to natural gas or oil price volatility, we may partially hedge our~~Obligations 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.

OnWe ~~July 7,~~have ~~2004,~~various ~~the~~commitments ~~date~~primarily ~~of the Merger, we became a party to long-term commodity hedges (the “Hedges”) with J. Aron pursuant to a master agreement and~~ related confirmations and documentation (collectively, the “Hedge Agreement”.) We anticipate that the Hedges will cover approximately 73% of the expected 2010 through 2013 production from our current estimated proved reserves and will range from 67% to ~~82%~~leases ~~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~~office ~~market standard NYMEX futures contracts on crude oil and natural gas. Under such transactions~~space, ~~we pay NYMEX-based floating price per MMbtu~~vehicles, ~~in the case of Hedges on~~ natural gas, ~~and~~compressors ~~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~~ acomputer ~~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~~equipment. ~~The~~We ~~transactions~~expect ~~will be settled on a net basis. The notional amounts of the Hedges were designed~~ to ~~provide~~fund ~~sufficient~~these ~~hedged~~commitments with cash ~~flow~~ ~~to cover operating expenditures, general and administrative expenses, interest expenses and~~generated ~~the~~from ~~majority of capital expenditures needed to develop proved reserves~~operations.

38The 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

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”~~1) ~~agreement~~Amounts ~~with~~represent ~~customized credit terms, designed to mitigate~~ the ~~liquidity~~expected ~~pressures~~cash inpayments afor ~~high~~interest ~~commodity price environment. The initial collateral requirements and ongoing margin requirements (~~based on ~~market movements) are satisfied by letters of credit issued under~~ the ~~Amended~~debt ~~Credit~~outstanding Agreement, with an aggregate capitalization of $40 million. To support any exposure in excess of amounts supported by the letters of credit, we have granted J. Aron a second lien on the same assets that secure the Amended Credit Agreement and the ~~Senior~~ ~~Secured~~effective ~~Notes~~interest ~~and,~~rate toas ~~the extent our obligations exceed such letters~~ of ~~credit~~December 31, ~~such obligations are secured by a second-priority lien on the same assets securing the Amended Credit Agreement and the Senior Secured Notes~~2010. WeSuch ~~may~~amounts ~~enter~~do ~~into~~not ~~crude~~include ~~oil and natural gas hedges with parties other than J. Aron, which hedges may be secured by~~ the ~~letters~~effects of ~~credit~~our ~~issued~~interest ~~under~~rate ~~the Amended Credit Agreement and by a second-priority lien on the same assets securing the Amended Credit Agreement and the Senior Secured Notes~~swaps.

~~Our~~In ~~financial~~addition ~~results and cash flows can be significantly impacted as commodity prices fluctuate widely in response~~ to ~~changing~~the ~~market~~items ~~conditions. Accordingly~~above, we ~~may~~have ~~modify~~entered ~~our fixed price contract and financial derivative positions by entering~~ into ~~new~~joint ~~transactions.~~operating ~~The~~agreements, ~~following~~area of ~~tables~~mutual ~~reflect~~interest ~~the~~agreements ~~natural gas~~ and ~~crude~~joint ~~oil~~venture ~~volumes~~agreements ~~and~~with ~~the~~other ~~weighted~~companies. ~~average~~These ~~prices~~agreements ~~under~~may ~~financial~~include ~~derivatives~~drilling ~~(including~~commitments ~~settled~~or ~~contracts)~~other atobligations ~~February 28,~~in ~~2010,~~the ~~which~~normal ~~have~~course ~~not~~of ~~changed since December 31, 2009~~business.

	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
Year Ending	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
December 31, 2010		8,938	$	4.28		175	$	28.86		7,666	$	0.243
December 31, 2011		8,231		4.19		157		28.77		5,110		0.252
December 31, 2012		7,005		4.09		138		28.70		3,660		0.110
December 31, 2013		6,528		4.04		127		28.70		—		—

The following table summarizes our commercial commitments at December 31, 2010.

At December 31, 2009, the fair value of futures contracts covering 2010 through 2013 oil and gas production represented an unrealized loss of $84.7 million.


	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	$	—	$	—	$	—

AtIn ~~December 31,~~the ~~2009,~~normal wecourse ~~had~~of ~~interest~~business, ~~rate~~we ~~swaps~~have inperformance ~~place~~obligations ~~covering~~which ~~$43.5 million~~are ofsupported ~~our~~by ~~outstanding~~surety ~~debt~~bonds ~~under~~or ~~the~~letters ~~revolving~~of credit. ~~facility~~These ~~that~~obligations ~~mature~~are onprimarily ~~September 30,~~site ~~2013.~~restoration ~~The swaps~~and ~~provide~~dismantlement, ~~1-month~~royalty ~~LIBOR~~payments ~~fixed~~and ~~rates~~exploration ofprograms ~~4.10%,~~where ~~plus~~governmental ~~the~~organizations ~~applicable~~require such ~~margin~~support. ~~The~~We ~~fair~~also ~~value~~have letters of ~~these interest~~credit ~~rate~~with ~~swaps~~our ~~was~~hedging ancounterparty ~~unrealized~~to ~~loss~~satisfy ofongoing margin ~~$2.4 million~~requirements atrelated ~~December 31,~~to ~~2009~~our hedges.

~~Inflation~~Off-Balance ~~and~~Sheet ~~Changes in Prices~~Arrangements

~~The~~We ~~average~~have ~~price realized for our natural gas increased from~~ $640.~~81 per Mcf in 2007 to $~~8~~.62 per~~ million ~~Mcf~~ in ~~2008,~~letters and decreased to $3.61 in 2009. The average price realized for our oil increased from $67.42 per Bbl in 2007 to $94.40 per Bbl in 2008 and decreased to $56.49 per Bbl in 2009. These prices include the effect of ~~certain~~credit ~~derivatives~~as ~~which~~described ~~were previously qualified effective oil and gas hedges~~above.

~~The price of oil and natural gas has a significant impact on our results of operations. Oil~~41 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.

ANEW ~~large~~ACCOUNTING ~~portion of our natural gas is sold subject to market sensitive contracts. Natural gas~~STANDARDS 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~~In ~~Obligations~~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.

WeIn ~~have~~January 2010, ~~various~~the ~~commitments~~FASB ~~primarily~~issued ~~related~~ASU No. 2010—06, Fair Value Measurements and Disclosures (Topic 820), which provides amendments to ~~leases~~Topic 820 and requires new disclosures for ~~office~~(i) transfers between ~~space~~Levels 1, ~~vehicles~~2 and 3 and the reasons for such transfers and (ii) activity in Level 3 fair value measurements to show separate information about purchases, ~~natural~~sales, issuances and settlements. ~~gas~~In ~~compressors~~addition, ASU 2010—06 amends Topic 820 to clarify existing disclosures around the disaggregation level of fair value measurements and ~~computer~~disclosures ~~equipment~~for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). WeThe ~~expect~~provisions in ASU 2010—06 are applicable to ~~fund~~interim ~~these~~and ~~commitments~~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 ~~generated~~flows, but did impact our ~~from~~disclosures ~~operations~~on fair value measurements.

39No 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.

~~Table~~Item of7A. ~~Contents~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~The~~Among ~~following~~other ~~table~~risks, ~~summarizes~~we ~~our~~are ~~contractual~~exposed ~~obligations~~to atinterest ~~December 31,~~rate ~~2009~~and commodity price risks.

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

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.

InThe ~~addition~~commodity price risk relates to ~~the~~our ~~items~~natural ~~above~~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 ~~have~~may ~~entered~~enter into ~~joint~~a ~~operating~~combination ~~agreements~~of futures contracts, ~~area~~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 ~~mutual~~or ~~interest~~more. ~~agreements~~We employ a policy of hedging oil and ~~joint~~gas ~~venture~~production ~~agreements~~by selling NYMEX-based commodity derivative contracts which are placed with ~~other~~major ~~companies~~financial institutions that we believe are minimal credit risks. ~~These~~The ~~agreements~~contracts may ~~include~~ ~~drilling~~take ~~commitments~~the form of futures contracts, swaps or ~~other~~options. ~~obligations~~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 ~~the~~2009 ~~normal~~and ~~course~~a net pre-tax loss of ~~business~~$6.1 million in 2010 on certain derivatives which were previously qualified as effective oil and gas hedges.

~~The~~We ~~following~~determined ~~table~~that ~~summarizes~~as of August 15, 2005, our ~~commercial~~oil ~~commitments~~derivatives atno ~~December~~longer qualify for cash flow hedge accounting and as of July 311, ~~2009~~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

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

Incash flows from the ~~normal~~sale ~~course~~ of ~~business,~~oil weand ~~have~~gas ~~performance obligations which are supported~~ by ~~surety~~ ~~bonds~~approximately ~~or letters of credit~~$1.6 million ~~These~~after ~~obligations~~considering ~~are~~the ~~primarily~~effects ~~site restoration and~~of ~~dismantlement,~~the ~~royalty~~derivative ~~payments~~contracts ~~and~~in ~~exploration~~place ~~programs~~during ~~where~~2010. ~~governmental~~This ~~organizations~~sensitivity ~~require such~~analysis ~~support.~~is Webased ~~also~~on ~~have~~our ~~letters~~2010 ofoil and ~~credit~~gas ~~with~~sales ~~our hedging counterparty~~volumes.

~~Off-Balance~~Item ~~Sheet~~8. ~~Arrangements~~ FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

WeThe ~~have~~Index ~~$40.3 million~~to Consolidated Financial Statements and Schedules on page F-1 sets forth the financial statements included in ~~letters~~this ofAnnual ~~credit~~Report on Form 10-K and their location herein. Schedules have been omitted as ~~described~~not ~~above~~required or not applicable because the information required to be presented is included in the financial statements and related notes.

~~NEW~~Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ~~STANDARDS~~ AND FINANCIAL DISCLOSURE

InThere ~~December 2007,~~were ~~the~~no ~~FASB~~changes ~~issued~~in ~~new~~or ~~accounting~~disagreements ~~guidance~~with ~~regarding~~accountants ~~the~~on accounting ~~for business~~or ~~combinations. This new guidance retains the acquisition method of accounting used in~~financial business combinations and establishes principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction and restructuring costs related to the acquisition be expensed. In addition, this guidance requires disclosures toduring ~~enable users to evaluate~~ the ~~nature~~years ~~and~~ended ~~financial effects of the business combination. We adopted this new guidance on January~~December 131, 2010 or 2009.

~~In March 2008, the FASB issued new accounting guidance requiring enhanced disclosures about an~~43 entity’s derivative and hedging activities and their effect on an entity’s financial position, financial performance and cash flows. This new guidance is effective for fiscal years and interim periods beginning after November 15, 2008. We adopted the new accounting guidance on January 1, 2009.

InItem ~~December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its oil and natural gas reporting disclosures~~9A. ~~The~~CONTROLS ~~new~~AND disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12 month period rather than year end prices. The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending on or after December 31, 2009. We adopted the new disclosure requirements in this Form 10-K. PROCEDURES

40Evaluation of Disclosure Controls and Procedures

~~Table~~In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of ~~Contents~~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.

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

~~In January 2010~~Management, ~~the~~including ~~FASB~~our ~~issued~~Chief ~~ASU~~Executive ~~No. 2010–03,~~Officer ~~Extractive~~and ~~Activities~~Chief –Financial ~~Oil~~Officer, is responsible for establishing and ~~Gas~~maintaining ~~(Topic~~adequate internal control over our financial reporting. Our ~~932),~~internal control system was designed to ~~align~~provide ~~the~~reasonable ~~oil~~assurance ~~and~~to ~~natural~~our ~~gas~~Management ~~reserve~~and Directors ~~estimation~~regarding the preparation and ~~disclosure~~fair ~~requirements~~presentation of ~~Topic~~published ~~932~~financial statements. ~~with~~Because ~~the~~of ~~SEC’s~~its ~~final~~inherent ~~rule~~limitations, ~~Modernization~~internal ofcontrol ~~Oil~~over ~~and~~financial ~~Gas~~reporting ~~Reporting.~~may ~~ASU~~not Noprevent or detect misstatements. ~~2010–03~~ isAlso, ~~effective for~~projections ~~annual~~of ~~reporting~~any evaluation of effectiveness to future periods ~~ending~~are subject onto orthe ~~after~~risk ~~December 31,~~that ~~2009.~~controls Wemay ~~adopted~~become ~~the~~inadequate ~~provisions~~because of ~~ASU~~ ~~2010–03~~changes in ~~our~~conditions, ~~consolidated~~or ~~financial~~that the ~~statements~~degree ~~for~~of compliance with the ~~year~~policies ~~ended~~or ~~December 31,~~procedures ~~2009~~may deteriorate.

InManagement ~~January 2010,~~conducted ~~the~~an ~~FASB~~evaluation ~~issued~~of ~~ASU~~the ~~No. 2010–06,~~effectiveness ~~Fair~~of ~~Value~~internal ~~Measurements~~control ~~and~~over ~~Disclosures~~financial ~~(Topic~~reporting ~~820),~~based ~~which~~on ~~provides~~the ~~amendments~~Internal toControl ~~Topic~~— ~~820~~Integrated ~~that~~Framework ~~will~~issued ~~provide~~by ~~more robust disclosures about (i)~~ the ~~different~~Committee ~~classes~~ of ~~assets and liabilities measured at fair value, (ii) the valuation~~ ~~techniques~~Sponsoring ~~and~~Organizations ~~inputs~~of ~~used, (iii)~~ the ~~activity~~Treadway inCommission. ~~Level~~Based 3on ~~fair~~this ~~value~~evaluation, ~~measurements and (iv) the~~management ~~transfers~~concluded ~~between~~that ~~Levels~~Belden 1,& 2Blake ~~and~~Corporation’s 3.internal ~~ASU~~control ~~2010–06~~over isfinancial ~~effective~~reporting ~~for~~was ~~interim and annual reporting~~effective ~~periods~~as ~~beginning~~of ~~after~~ December 31, ~~2009. We will adopt ASU~~ 2010~~–06 for the quarter ending March 31, 2010, and we have not yet determined the impact, if any, on our consolidated financial statements~~.

InPursuant ~~February 2010, the FASB issued ASU No. 2010–09, Subsequent Events (Topic 855),~~ to ~~amend~~ the ~~disclosure~~ requirements of ~~events that occur after the balance sheet date but before financial statements are issued or are available to be issued that was issued by the FASB in May~~Rules ~~2009. Entities that are SEC filers~~ 13a-15(asf) ~~defined~~and ~~in ASU No. 2010–09~~15d-15(f) ~~are~~of ~~required~~the toSecurities ~~evaluate~~and ~~subsequent~~Exchange ~~events~~Act ~~through~~of ~~the date that the financial statements are issued~~1934, ~~while non–SEC filers are required to evaluate subsequent events through~~ the ~~date~~Report ~~that~~on ~~the~~Internal ~~financial~~Control ~~statements~~over ~~are~~Financial ~~available~~Reporting tohas ~~be issued.~~been Insigned ~~addition,~~below anby ~~entity that is an SEC filer is not required to disclose~~ the ~~date through~~ ~~which~~following ~~subsequent~~person ~~events~~on ~~have~~behalf ~~been~~and ~~evaluated. ASU 2010–09 is effective upon issuance. We adopted the provisions of ASU 2010–09~~ in ~~our consolidated financial statements for~~ the ~~year~~capacities ~~ended~~indicated ~~December 31, 2009~~below.

No/s/ ~~other~~Mark ~~new~~A. ~~accounting~~Houser ~~pronouncements~~Mark ~~issued~~A. orHouser ~~effective~~/s/ ~~during~~James ~~the~~M. ~~year~~Vanderhider ~~ended~~James ~~December 31, 2009~~M. ~~have~~Vanderhider ~~had~~Chief orExecutive ~~are~~Officer, ~~expected~~Chairman toof ~~have~~the aPresident, ~~material~~Chief ~~impact~~Financial onOfficer ~~our~~and ~~consolidated~~Director ~~financial~~Board ~~statements.~~ of Directors and Director

41Houston, TX March 28, 2011

~~Table of Contents~~44

~~Item~~Changes ~~7A.~~in ~~QUANTITATIVE~~Internal ~~AND~~Control ~~QUALITATIVE~~Over ~~DISCLOSURES~~Financial ~~ABOUT MARKET RISK~~Reporting

~~Among~~There ~~other~~were ~~risks~~no changes in the internal control over financial reporting that occurred during the year ended December 31, we2010 that materially affected, or that are ~~exposed~~reasonably likely to materially ~~interest~~affect, ~~rate~~internal ~~and~~control ~~commodity~~over ~~price~~financial ~~risks~~reporting.

~~The~~This ~~interest~~annual ~~rate~~report ~~risk~~does ~~relates~~not toinclude ~~existing~~an ~~debt~~attestation ~~under~~report ~~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~~company’s ~~rate~~registered ~~exposure associated with the~~public ~~credit~~accounting ~~agreement,~~firm ~~whereby~~regarding ainternal ~~portion~~control ofover ~~our~~financial ~~floating rate exposure is exchanged for a fixed interest rate~~reporting. AManagement’s ~~portion~~report ofwas ~~our long-term debt consists of senior secured notes where the interest~~not ~~component~~subject isto ~~fixed.~~attestation Atby ~~December 31, 2009, we had an interest rate swap in place on $43.5 million of our outstanding debt under~~ the ~~revolving~~company’s ~~credit~~registered ~~facility~~public through September 30, 2013. The swap provides a 1-month LIBOR fixed rates at 4.10%, plus the applicable margin, on $43.5 million through September 2013. These interest rate swaps do not qualify for hedge accounting, ~~therefore,~~firm ~~all~~pursuant ~~cash~~to ~~settles~~rules ~~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~~Securities inand ~~our annual~~Exchange ~~interest~~Commission ~~expense~~that ~~would~~permit beus ~~approximately $713,000. The impact of this rate increases on our cash flows would be significantly less than these amounts due~~ to ~~our~~provide ~~interest~~only ~~rate~~management’s ~~swaps. If~~report ~~market interest rates increased 1% the decrease~~ in ~~our~~this ~~cash~~annual ~~flow would be approximately $95,000~~report. ~~This sensitivity analysis is based on our financial structure at December 31, 2009.~~

~~The~~Item ~~commodity price risk relates to our natural gas and crude oil produced, held in storage and marketed~~9B. ~~Our~~OTHER financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to commodity price volatility. The fixed-price physical contracts generally have terms of a year or more. We employ a policy of hedging oil and gas production by selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. At December 31, 2009, we had derivatives covering a portion of our oil and gas production from 2010 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $9.2 million in 2008 and a net pre-tax loss of $7.9 million in 2009 on certain derivatives which were previously qualified as effective oil and gas hedges.INFORMATION

WeNot 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 accountingapplicable. ~~From those dates forward, changes in the fair value of the oil and gas derivatives are~~ recorded in derivative fair value gain/loss. Deferred gains or losses on the gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings. If gas prices decreased $1.00 per Mcf, our gas sales revenues would decrease by approximately $11.7 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $3.2 million. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $1.00 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas by approximately $3.5 million after considering the effects of the derivative contracts in place as of December 31, 2009. This sensitivity analysis is based on our 2009 oil and gas sales volumes.

~~Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA~~45

~~The~~PART ~~Index to Consolidated Financial Statements and Schedules on page F-1 sets forth the~~III 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 910. ~~CHANGES~~DIRECTORS IN AND ~~DISAGREEMENTS~~EXECUTIVE ~~WITH~~OFFICERS ~~ACCOUNTANTS~~OF ONTHE ~~ACCOUNTING~~REGISTRANT AND ~~FINANCIAL~~CORPORATE ~~DISCLOSURE~~GOVERNANCE

~~There~~Our ~~were~~executive noofficers ~~changes~~and indirectors orand ~~disagreements~~their ~~with~~respective ~~accountants~~positions onand ~~accounting~~ages orof ~~financial disclosures~~as ~~during~~of ~~the years ended December~~March 315, 2011 ~~2009~~were oras ~~2008.~~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

~~Table~~All of ~~Contents~~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.

~~Item~~Mark 9AA. ~~CONTROLS~~Houser. ~~AND~~On ~~PROCEDURES~~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.

~~Evaluation~~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 ~~Disclosure~~EnerVest ~~Controls~~and has been with EnerVest since March 1996. Prior to joining EnerVest, Mr. Vanderhider was Executive Vice President and ~~Procedures~~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.

InMr. Vanderhider ~~accordance~~received ~~with~~a ~~Exchange~~B.B.A. ~~Act~~degree ~~Rule 13a-15~~in ~~and~~Accounting ~~15d-15,~~from weTexas ~~carried~~A&M ~~out~~University anwhere ~~evaluation, under~~he ~~the~~graduated ~~supervision~~summa ~~and~~cum ~~with~~laude. ~~the~~He ~~participation~~is ofa ~~management,~~Certified ~~including~~Public ~~our~~Accountant. ~~Chief~~Mr. Vanderhider ~~Executive~~is ~~Officer~~a ~~and~~native ~~our~~Houstonian ~~Chief~~and ~~Financial~~is ~~Officer,~~actively ofinvolved ~~the~~with ~~effectiveness~~several ofindustry ~~our~~and ~~disclosure~~social ~~controls~~organizations. ~~and~~He ~~procedures~~is asa ofmember ~~the end~~ of the ~~period~~Independent ~~covered~~Petroleum byAssociation ~~this~~of ~~report. Based on that evaluation~~America, ~~our~~the ~~Chief~~American ~~Executive~~Institute ~~Officer and~~of ~~Chief~~Certified ~~Financial Officer concluded that our disclosure controls and procedures were effective as~~Public ~~of December 31~~Accountants, ~~2009~~Houston toProducers’ ~~provide~~Forum, ~~reasonable~~Texas ~~assurance~~Society ~~that~~of ~~information~~Certified ~~required~~Public toAccountants, ~~be disclosed in~~Houston ~~our~~Energy ~~reports~~Finance ~~filed or submitted under the Exchange Act is recorded~~Group, ~~processed, summarized~~ and ~~reported~~ ~~within~~Houston ~~the~~Acquisitions ~~time periods specified in the Securities~~ and ~~Exchange~~Divestitures ~~Commission’s rules and forms~~Organization. ~~Our~~He ~~disclosure~~serves ~~controls~~on ~~and procedures include controls and procedures designed to provide~~the ~~reasonable~~Board ~~assurance~~of ~~that~~Trustees ~~information~~of ~~required~~Goodwill toIndustries beof ~~disclosed~~Houston inand ~~reports~~on ~~filed or submitted under~~ the ~~Exchange~~Board ~~Act~~of isDirectors ~~accumulated~~of ~~and~~the ~~communicated~~Houston Center ~~to our management~~Club, ~~including~~a ~~our~~social ~~Chief Executive Officer~~ and ~~Chief~~athletic ~~Financial Officer, as appropriate, to allow timely decisions regarding required disclosure~~club.

~~Management’s~~Kenneth ~~Annual~~Mariani. ~~Report~~ On ~~Internal~~October 3, ~~Control~~2005, ~~Over~~Mr. Mariani ~~Financial~~was ~~Reporting~~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

~~Management, including our Chief Executive Officer and Chief Financial Officer, is responsible~~46 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~~EnerVest ~~conducted~~and anExecutive ~~evaluation~~Vice ofPresident ~~the effectiveness~~ of ~~internal~~CGAS ~~control~~Exploration, ~~over~~Inc., ~~financial reporting~~a ~~based~~privately-held onoil ~~the~~and ~~Internal~~gas company ~~Control~~owned ~~– Integrated Framework issued~~ by ~~the~~certain ~~Committee~~institutional ~~of Sponsoring~~funds ~~Organizations~~managed ofby ~~the Treadway Commission~~EnerVest. ~~Based~~Prior onto ~~this~~joining ~~evaluation,~~EnerVest ~~management~~in ~~concluded~~2000, ~~that~~he ~~Belden~~served &as ~~Blake~~Vice ~~Corporation’s~~President ~~internal~~of ~~control~~Operations ~~over~~for ~~financial~~Energy ~~reporting~~Corporation ~~was effective as~~ of ~~December 31, 2009~~America.

~~Pursuant~~Mr. Mariani toholds a degree in Chemical Engineering from the ~~requirements~~University of ~~Rules 13a-15(f)~~Pittsburgh, graduating cum laude with a Petroleum option. He received his MBA degree from the University of Texas and ~~15d-15(f)~~is a Certified Professional Engineer. Mr. Mariani is an active member of the ~~Securities~~Independent Oil and ~~Exchange Act~~Gas Association of ~~1934~~West Virginia, ~~the~~recently ~~Report~~serving on ~~Internal~~the ~~Control~~Board ~~over~~of ~~Financial~~Directors, ~~Reporting~~Commerce Committee ~~has~~and ~~been~~Safety ~~signed~~Committee. ~~below~~In by2003, 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. ~~following~~Currently, ~~person~~Mr. Mariani serves on ~~behalf~~the Board of Directors for the Michigan Oil and Gas Association and the Ohio Oil and Gas Association. He is also active in the ~~capacities~~Independent ~~indicated~~Oil ~~below~~and Gas Association of Pennsylvania, the Independent Oil and Gas Association of New York and the Kentucky Oil and Gas Association.

/s/ Mark A. Houser		/s/ James M. Vanderhider
Mark A. Houser		James M. Vanderhider
Chief Executive Officer, Chairman of the Board of Directors and Director		President, Chief Financial Officer and Director
Houston, TX
March 26, 2010

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.

43Barry 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.

~~Table~~Mr. Lay has 30 years of ~~Contents~~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.

~~Changes~~Charles Goodin. Mr. Goodin joined EnerVest in ~~Internal~~October ~~Control~~of ~~Over~~2009 ~~Financial~~as ~~Reporting~~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.

~~There~~Mr. Goodin ~~were~~is nolicensed ~~changes~~to Practice Law in ~~the~~Colorado, ~~internal~~Texas ~~control~~and ~~over~~West ~~financial~~Virginia; ~~reporting~~is ~~that~~a ~~occurred~~Member ~~during~~of the ~~year~~Colorado, ~~ended~~Texas ~~December~~and WV Bar Associations; and is a member of the AAPL and DAPL. Mr. ~~31,~~Goodin ~~2009~~is Founder ~~that~~and ~~materially~~past ~~affected,~~President orof ~~that~~the ~~are~~new ~~reasonably~~Denver ~~likely~~Petroleum toClub and has served on the Board of ~~materially~~Directors ~~affect,~~of ~~internal~~Junior ~~control~~Achievement ~~over~~as ~~financial~~well ~~reporting~~as many other civic organizations.

~~This~~Matthew ~~annual~~Coeny. ~~report~~On ~~does~~August 16, ~~not~~2005, ~~include~~Mr. Coeny anwas ~~attestation~~elected ~~report~~to ofour ~~the~~Board ~~company’s~~of ~~registered~~Directors. ~~public~~Mr. ~~accounting~~Coeny ~~firm~~is ~~regarding~~a ~~internal~~Director ~~control~~of ~~over~~Citi ~~financial~~Private ~~reporting~~Equity (“CPE”). ~~Management’s~~CPE ~~report~~is ~~was~~a ~~not~~business unit of Citigroup Inc. ~~subject~~(“Citigroup”) toand ~~attestation~~is byresponsible ~~the~~for ~~company’s~~private ~~registered~~equity ~~public~~investments ~~accounting~~on ~~firm~~behalf ~~pursuant~~of tocertain ~~temporary~~Citigroup ~~rules~~affiliates. ofSince joining CPE in 2000, he has participated in the ~~Securities~~evaluation, due diligence and execution ~~Exchange~~of ~~Commission~~investments ~~that~~in ~~permit~~a usvariety of industries. Prior to ~~provide~~joining ~~only~~CPE, ~~management~~Mr. Coeny worked in Citigroup’s ~~report~~Investment Banking Division where he participated in numerous advisory and capital raising transactions. Prior to joining Citigroup in ~~this~~1996, ~~annual~~he ~~report~~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.

~~Item 9B. OTHER INFORMATION~~47

~~Not~~Audit ~~applicable.~~Committee

44Our 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.”

~~Table~~Code of ~~Contents~~Ethics

~~PART~~We ~~III~~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:

~~Item~~Belden ~~10.~~& ~~DIRECTORS~~Blake ~~AND~~Corporation 1001 ~~EXECUTIVE~~Fannin ~~OFFICERS~~Street, OFSuite 800 Houston, ~~THE~~Texas ~~REGISTRANT~~77002 Attention: ~~AND~~James ~~CORPORATE~~M. ~~GOVERNANCE~~Vanderhider, President Telephone: (713) 659-3500

~~Our executive officers and directors and their respective positions and ages of as of March 5,~~48 ~~2010 were as follows:~~

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


Item 11.		EXECUTIVE COMPENSATION

All of our executive officers ~~serve~~are atfull-time ~~the~~employees ~~pleasure~~ of ~~our~~EnerVest ~~Board~~and ofits ~~Directors~~subsidiaries. ~~None~~We have entered into an operating agreement with a subsidiary of ~~our~~EnerVest (described in Item 13). ~~executive~~Pursuant ~~officers~~to isthe ~~related~~operating agreement, we pay EnerVest a fee to ~~any~~operate ~~other~~our business, and EnerVest provides us the services of its employees, including our executive ~~officer~~officers, orto ~~director~~operate our business. The ~~Board~~fee ofwe ~~Directors consists~~pay ofto ~~four~~EnerVest ~~members,~~does ~~each~~not ofinclude ~~whom~~any ~~are~~direct ~~chosen~~reimbursement for the salaries, bonuses or other compensation paid by EnerVest to the EnerVest employees which act as our ~~Parent~~executive officers. ~~The~~Therefore, ~~business~~no ~~experience~~executive officers of ~~each executive~~Belden ~~officer~~& ~~and~~Blake ~~director~~received isany ~~summarized~~remuneration ~~below~~from Belden & Blake Corporation during 2010.

~~Mark~~Compensation ~~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~~Our M.directors ~~Vanderhider.~~are ~~Mr. Vanderhider~~not ~~is our President and Chief Financial Officer~~compensated. ~~Prior~~We ~~to that~~have heno ~~served~~independent ~~as President and Chief Operating Officer since his appointment on August 16~~directors, ~~2005. Mr. Vanderhider has been a director since August 16, 2005. He also serves~~ as ~~Executive~~independence ~~Vice~~is ~~President~~defined ~~and~~by 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~~New ~~Audit~~York ~~department~~Stock ~~of The Coastal Corporation, now a subsidiary of El Paso Corporation~~Exchange. ~~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~~Compensation ~~received~~Committee aInterlocks ~~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 isInsider ~~actively involved with several industry and social organizations. He is a member~~Participation 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.

45We do not have a compensation committee. As of December 31, 2010, none of our officers are compensated by us.

~~Table of Contents~~49

~~Kenneth~~Item ~~Mariani~~12. OnSECURITY ~~October 3,~~OWNERSHIP ~~2005,~~OF ~~Mr. Mariani~~CERTAIN ~~was~~BENEFICIAL ~~appointed Senior Vice President and Chief Operating Officer. He has been a director since August 16~~OWNERS, ~~2005.~~MANAGEMENT ~~Mr. Mariani~~AND isRELATED ~~also~~STOCKHOLDER 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. MATTERS

~~Mr. Mariani~~The ~~holds~~following atable ~~degree~~sets inforth ~~Chemical~~certain ~~Engineering~~information ~~from~~as ~~the University~~ of ~~Pittsburgh~~March 5, ~~graduating~~ ~~cum~~2011 ~~laude~~regarding ~~with a Petroleum option. He received his MBA degree from~~ the beneficial ~~University~~ownership of ~~Texas~~ ~~and~~our iscommon astock ~~Certified~~by ~~Professional~~each ~~Engineer.~~person ~~Mr. Mariani~~who isbeneficially anowns ~~active~~more ~~member~~than ~~of the Independent~~five ~~Oil~~percent ~~and Gas Association~~ of ~~West~~our ~~Virginia,~~outstanding ~~recently~~common ~~serving on the Board of Directors~~stock, ~~Commerce Committee~~each ~~and Safety Committee. In 2003~~director, hethe ~~was~~Chief ~~acting~~Executive ~~Vice~~Officer ~~President~~ and ~~Program~~the ~~Chair of this~~four ~~organization.~~other Hemost ishighly ~~past~~compensated ~~Chairman~~executive ofofficers ~~the Society of Petroleum Engineers~~ and aby ~~member~~all of ~~IPAA. Currently,~~our ~~Mr. Mariani~~directors ~~serves on the Board of Directors for the Michigan Oil~~ and ~~Gas Association~~executive ~~and the Ohio Oil and Gas Association. He is also active in the Independent Oil and Gas Association of Pennsylvania~~officers, ~~the~~as ~~Independent~~a ~~Oil and Gas Association of New York and the Kentucky Oil and Gas~~group: ~~Association.~~

Frederick J. Stair. Mr. Stair is Vice President of Accounting and has been our Vice President since January 2003. He previously served as our Corporate Controller from 1997 to 2005 and as Controller of the Exploration and Production Division from 1991 to 1997. Mr. Stair joined us in 1981 and has 28 years of accounting experience in the oil and gas industry. Mr. Stair is also Vice President of Accounting – Eastern Division for EnerVest. He graduated from the University of Akron where he received a Bachelor of Science degree in Accounting. Mr. Stair is a member of the Council of Petroleum Accountants Societies of Appalachia and the Independent Oil and Gas Association of West Virginia.


	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	%

~~Barry~~(1) K.Subsidiaries ~~Lay.~~of MrEnerVest, Ltd. ~~Lay~~, ~~was~~are ~~appointed~~the asgeneral ~~Vice~~partners ~~President~~ of ~~Operations~~the ~~effective~~limited ~~August 10~~partnership that owns Capital C Energy Operations, ~~2007.~~ MrL. ~~Lay~~P. ~~served~~EnerVest, astherefore, ~~Vice~~also ~~President~~may be deemed to be a beneficial owner of ~~Land~~the ~~and~~1,534 ~~Secretary~~shares ~~from~~(100%) ~~October 16~~of our Common Stock. The address of EnerVest, ~~2006~~Ltd., ~~until~~is ~~August 10~~1001 Fannin Street, ~~2007~~Suite 800, Houston, Texas 77002. ~~Prior~~EnerVest tois ~~that~~a heTexas ~~served~~limited aspartnership. ~~Vice~~Messrs. ~~President~~John B. Walker, Jon Rex Jones and ~~General~~A.V. ~~Manager~~Jones by virtue of ~~our~~their ~~Pennsylvania/New York~~direct ~~District.~~and ~~Prior~~indirect ownership of the limited liability company that acts as EnerVest’s general partner, may be deemed to ~~joining~~beneficially usown inthe ~~2002~~Common Stock beneficially owned by EnerVest. Messrs. Walker, MrJon Rex Jones and A. ~~Lay~~V. ~~was~~Jones ~~Vice~~disclaim ~~President~~beneficial ownership of ~~Engineering~~such ~~for~~Common ~~Waco~~Stock. ~~Oil and~~The ~~Gas~~addresses ~~Company~~for Messrs. HeWalker, ~~also~~Jon ~~serves~~Rex asJones ~~Vice~~and ~~President~~A.V. ofJones ~~Operations~~are –the ~~Eastern~~same ~~Division~~as for EnerVest.

~~Mr. Lay~~Equity ~~has~~Compensation ~~30 years~~Plan ~~of experience in the oil and gas industry. Mr. Lay graduated from West~~Information: 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~~As ~~Goodin. Mr. Goodin joined EnerVest in October~~ of ~~2009 as Vice President of Land/Legal for the Eastern Division. Mr.~~March 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 Denver5, ~~Co.~~2011, ~~Of Counsel~~we ~~with~~do ~~the~~not ~~law~~have ~~firm~~any ofoutstanding ~~Poulson,~~stock ~~Odell~~options &or ~~Peterson,~~plans ~~Vice~~to ~~President~~grant ~~of Land and Corporate~~any ~~Attorney for Eastern American Energy Corporation in Charleston, WV and District Landman with BP Exploration, Inc~~options. ~~in Colorado and Texas.~~

~~Mr. Goodin is licensed to Practice Law in Colorado, Texas and West Virginia; is a Member of~~50 ~~the Colorado, Texas and WV Bar Associations; and is a member of the AAPL and DAPL.~~

~~Charlie~~Item ~~Goodin~~13. isCERTAIN ~~Founder~~RELATIONSHIPS ~~and~~AND ~~President~~RELATED ~~of the new Denver Petroleum Club and has served on the Board of Directors of Junior Achievement as well as many other civic organizations.~~ TRANSACTIONS

~~Mark~~On ~~L. Barnhill. Mr.~~March ~~Barnhill~~15, ~~was~~2006, ~~appointed~~we ~~Vice~~entered ~~President~~into ofa ~~Exploration~~joint onoperating ~~October 16, 2006.~~agreement Hewith ~~also~~EnerVest ~~serves~~Operating asL.L.C. (“EnerVest ~~Vice~~Operating”), ~~President~~a subsidiary of ~~Exploration for~~ EnerVest. ~~Mr. Barnhill~~In ~~joined~~2009, ~~EnerVest in~~amounts ~~2001.~~paid ~~Prior~~ to ~~joining~~ EnerVest, heOperating under ~~was~~the ~~Exploration~~terms ~~Manager~~of ~~for~~the ~~Energy~~agreement ~~Corporation~~were ~~of America~~$6. ~~Mr.~~1 ~~Barnhill~~million ~~has~~for ~~worked~~overhead asfees, ~~both~~$5.9 million afor ~~geologist~~field labor, vehicles and adistrict ~~geophysicist~~office ~~for~~expense, ~~Texaco~~$82,000 ~~Inc.~~for ~~and~~drilling ~~Cotton Petroleum.~~overhead Hefees ~~holds~~and a$1.1 million ~~Bachelor~~for drilling oflabor ~~Science~~costs. ~~degree~~In in2010, ~~Geology~~we ~~from~~paid ~~Wright~~$5.5 million ~~State~~for ~~University~~overhead fees, a$5.8 million ~~Master~~for field oflabor, ~~Science~~vehicles inand ~~Geology~~district ~~from~~office ~~The~~expense, ~~University of Tulsa~~$98,000 ~~and~~for adrilling ~~Ph.D.~~overhead infees ~~Geology~~and ~~from~~$886,000 ~~The~~for drilling ~~University~~labor ~~of Cincinnati~~costs.

~~Mr. Barnhill~~As ~~was a Visiting Research Scientist at Indiana University/Indiana Geological Survey from 1991 to 1994 where he headed several research projects for the Department~~ of ~~the Navy. He is a member of the American Association of Petroleum Geologists~~December 31, ~~the Independent Oil and Gas Association of West Virginia~~2010, ~~the~~we ~~Independent~~owed ~~Oil~~EnerVest ~~and~~Operating ~~Gas Association of Pennsylvania~~$634,000 ~~the Ohio Oil~~ and ~~Gas~~owed ~~Association~~EnerVest ~~and the Michigan Oil and Gas Association~~$845,000. ~~Mr. Barnhill has given numerous talks at major association meetings both nationally and internationally.~~

46In 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.

~~Table~~Messrs. Houser, Vanderhider and Mariani our officers and directors and they are officers and equity owners of ~~Contents~~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.

~~Matthew Coeny. On August 16, 2005, Mr. Coeny was elected to our Board of Directors. Mr.~~51 Coeny is a Director of Citi Private Equity (“CPE”). CPE is a business unit of Citigroup Inc. (“Citigroup”) and is responsible for private equity investments, mezzanine debt investments and private equity partnership commitments on behalf of Citigroup affiliates and clients. Since joining CPE in 2000, he has participated in the evaluation, due diligence and execution of investments in a variety of industries. Prior to joining CPE, Mr. Coeny worked in Citigroup’s Investment Banking Division where he participated in numerous advisory and capital raising transactions. Prior to joining Citigroup in 1996, he was a Senior Consultant in KPMG’s Corporate Transactions practice. Mr. Coeny received a Bachelor of Science degree in Finance and Accounting from New York University.

~~Audit~~Item ~~Committee~~ 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

~~Our~~The ~~full~~audit ~~Board~~committee of ~~Directors~~Belden ~~serves~~& asBlake ~~our~~Corporation ~~Audit~~selected ~~Committee.~~Deloitte ~~Additionally~~& Touche LLP, ~~since~~an independent weregistered ~~are~~public ~~wholly~~accounting firm, to audit our consolidated financial statements for ~~owned~~the byyear ~~Capital~~ended CDecember 31, we2010. ~~have~~The ~~not~~audit ~~determined~~committee’s ~~that~~charter ~~any~~requires ofthe audit committee to approve in advance all audit and non—audit services to be provided by our ~~directors~~independent isregistered public anaccounting “firm. All services reported in the audit, ~~committee~~audit—related, tax and all other fees ~~financial~~categories ~~expert~~below with respect to this Annual Report on Form 10—K for the year ended December 31, 2010 were approved by the audit committee.”

~~Code~~Fees ofpaid ~~Ethics~~to Deloitte & Touche LLP are as follows:

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:


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

	$	361,000	$	352,000

~~Belden~~(1) &Represents ~~Blake~~fees ~~Corporation 1001~~for ~~Fannin~~professional ~~Street,~~services ~~Suite 800 Houston,~~provided ~~Texas~~in ~~77002 Attention:~~connection ~~James~~with M.the ~~Vanderhider,~~audit ~~President Telephone:~~of ~~(713) 659-3500~~ our annual financial statements and review of our quarterly financial statements.

47Audit Committee Pre-Approval Policies and Procedures

~~Table~~The Audit Committee has adopted a policy that requires advance approval of ~~Contents~~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.

~~Item~~PART ~~11. EXECUTIVE COMPENSATION~~IV

~~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~~15. ~~The~~EXHIBITS ~~fee~~AND weFINANCIAL ~~pay~~STATEMENT to EnerVest does not include any direct reimbursement for the salaries, bonuses or other compensation paid by EnerVest to the EnerVest employees which act as our executive officers. Therefore, no executive officers of Belden & Blake received any remuneration from Belden & Blake Corporation during 2009. SCHEDULES

~~Compensation~~(a) Documents filed as a part of ~~Directors~~this report:

~~Our directors are not compensated~~1. Financial ~~We have no independent directors, as independence is~~Statements ~~defined by the New York Stock Exchange.~~

~~Compensation~~The ~~Committee~~financial ~~Interlocks~~statements listed in the accompanying Index to Consolidated Financial Statements and ~~Insider~~Schedules ~~Participation~~are filed as part of this Annual Report on Form 10-K.

~~We do not have a compensation committee~~2. ~~As of December~~ ~~31,~~Financial ~~2009,~~Statement ~~none of our officers are~~Schedules ~~compensated by us.~~

48No financial statement schedules are required to be filed as part of this Annual Report on Form 10-K.

~~Table of Contents~~52

~~Item 12~~3. ~~SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS~~ Exhibits

The following table sets forth certain information as of March 5, 2010 regarding the beneficial ownership of our common stock by each person who beneficially owns more than five percent of our outstanding common stock, each director, the Chief Executive Officer and the four other most highly compensated executive officers and by all of our directors and executive officers, as a group:


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.

	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, John Rex Jones and A.V. Jones disclaim beneficial ownership of such Common Stock. The addresses for Messrs. Walker, Jon Rex Jones and A.V. Jones are the same as for EnerVest.


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

~~Equity~~* ~~Compensation~~Filed ~~Plan Information:~~ herewith

~~As of March 5, 2010, we do not have any outstanding stock options or plans to grant any~~54 ~~options.~~

49SIGNATURES

~~Table~~Pursuant to the requirements of ~~Contents~~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.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

OnPursuant ~~March 15, 2006, we entered into a joint operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. In 2008, amounts paid~~ to ~~EnerVest Operating under~~ the ~~terms~~requirements of the ~~agreement~~Securities ~~were~~Exchange ~~$6.6 million~~Act ~~for~~of ~~overhead fees~~1934, ~~$7.1 million~~this ~~for~~report ~~field~~has ~~labor,~~been ~~vehicles~~signed ~~and~~below ~~district~~by ~~office~~the ~~expense,~~following ~~$265,000~~persons ~~for~~on ~~drilling~~behalf ~~overhead~~of ~~fees~~the ~~and~~registrant ~~$1.0 million for drilling labor costs. In 2009, we paid 6.1 million for overhead fees, $5.9 million for field labor, vehicles~~ and ~~district~~in ~~office~~the ~~expense,~~capacities ~~$82,000 for drilling overhead fees~~ and ~~$1.1 million~~on the ~~for~~dates ~~drilling labor costs~~indicated.

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


/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

~~In connection with the Transaction, we executed a subordinated promissory note in favor of our~~55 parent, Capital C in the maximum amount of $94 million. Under the note, Capital C loaned $25 million to us on August 16, 2005 in connection with the Transaction. The note accrues interest at 10% per year and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the note made on August 16, 2005. Interest payments on the note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. The amount due under the note at December 31, 2009 was $30.5 million. We borrowed an additional $2.9 million for interest payments against the note in 2009.

~~Messrs. Houser,~~BELDEN ~~Vanderhider~~& ~~and~~BLAKE ~~Mariani our officers and directors and they are officers and~~CORPORATION ~~equity~~INDEX ~~owners~~TO ~~of EnerVest. The institutional funds that are managed by EnerVest and own our direct~~CONSOLIDATED ~~parent,~~FINANCIAL ~~Capital~~STATEMENTS C,AND ~~also hold other investments in oil and gas assets and operations. We can give~~SCHEDULES 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.

50Item 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

~~Item~~All ~~14.~~financial ~~PRINCIPAL~~statement ~~ACCOUNTANT~~schedules ~~FEES~~have ~~AND~~been ~~SERVICES~~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.

~~The audit committee of Belden & Blake Corporation selected Deloitte & Touche LLP, an~~F-1 independent registered public accounting firm, to audit our consolidated financial statements for the year ended December 31, 2009. The audit committee’s charter requires the audit committee to approve in advance all audit and non–audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit–related, tax and all other fees categories below with respect to this Annual Report on Form 10–K for the year ended December 31, 2009 were approved by the audit committee.

~~Fees~~REPORT ~~paid~~OF toINDEPENDENT ~~Deloitte~~REGISTERED &PUBLIC ~~Touche~~ACCOUNTING ~~LLP are as follows:~~FIRM

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

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

~~(1)~~We ~~Represents~~have ~~fees~~audited ~~for~~the ~~professional~~accompanying ~~services~~consolidated ~~provided~~balance insheets ~~connection~~of ~~with~~Belden & Blake Corporation and subsidiaries (the ~~audit~~“Company”) as of ~~our~~December 31, ~~annual~~2010 ~~financial~~and 2009, and the related consolidated statements of operations, ~~review~~shareholder’s equity, and cash flows for each of ~~our~~the ~~quarterly~~three years in the period ended December 31, 2010. These financial statements ~~and~~are ~~audits~~the ~~performed~~responsibility asof ~~part~~the ofCompany’s management. ~~our~~Our ~~registration~~responsibility ~~filings~~is to express an opinion on these financial statements based on our audits.

~~Audit~~We ~~Committee~~conducted ~~Pre-Approval~~our ~~Policies~~audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and ~~Procedures~~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.

~~The~~In ~~Audit~~our ~~Committee~~opinion, ~~has~~such ~~adopted~~consolidated afinancial ~~policy~~statements ~~that~~present ~~requires~~fairly, ~~advance~~in ~~approval of~~ all ~~audit~~material respects, ~~audit-related, and other services performed by~~ the ~~independent~~financial ~~auditor~~position orof ~~other~~Belden ~~public~~& ~~accounting firms.~~Blake ~~The~~Corporation ~~policy~~and ~~provides~~subsidiaries ~~for~~as ~~pre-approval by the Audit Committee~~ of ~~specifically~~December 31, ~~defined~~2010 ~~audit~~ and ~~non-audit services. Unless the specific service has been previously pre-approved with respect~~ ~~to that year~~2009, ~~the~~and ~~Audit Committee must approve~~ the ~~permitted~~results ~~service~~of ~~before~~their ~~the~~operations ~~independent~~and ~~auditor or~~their ~~public~~cash ~~accounting~~flows ~~firm~~for iseach ~~engaged~~of tothe ~~perform~~three ~~it.~~years ~~The~~in ~~Audit Committee has delegated to~~ the ~~Chairman~~period ofended ~~the~~December 31, ~~Audit Committee authority to approve permitted services up to $75~~2010,~~000~~ ~~per~~in ~~year provided~~conformity ~~that~~with ~~the~~accounting ~~Chairman~~principles ~~reports~~generally ~~any~~accepted ~~decisions~~in to the ~~committee at its next scheduled meeting.~~ ~~All~~United ~~services~~States of ~~$75,000 or more are required to be approved by a majority of the committee members~~America.

~~PART~~As IVdiscussed 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.

~~Item~~/s/DELOITTE ~~15.~~& ~~EXHIBITS~~TOUCHE ~~AND~~LLP Houston, ~~FINANCIAL~~TX March 28, ~~STATEMENT SCHEDULES~~2011

~~(a) Documents filed as a part of this report:~~F-2

~~1. Financial~~BELDEN ~~Statements~~& BLAKE CORPORATION

~~The~~CONSOLIDATED ~~financial~~BALANCE ~~statements listed in the accompanying Index to Consolidated Financial Statements and Schedules are filed as part of this Annual Report on Form 10-K.~~ SHEETS

~~2. Financial~~(in ~~Statement~~thousands, ~~Schedules~~ except share data)

No financial statement schedules are required to be filed as part of this Annual Report on Form 10-K.


	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

BELDEN & BLAKE CORPORATION

March 28, 2011

/s/ Mark A. Houser

Mark A. Houser, Chief Executive Officer, Chairman

of the Board of Directors and Director

Filing Compare · BELDEN & BLAKE CORP /OH/