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        Our 2011 totalliquids-focused plays in south Texas and Oklahoma and the remaining 5% to other emerging plays and non-drilling expenditures. In 2013, we also expect to contribute approximately $12.0 million to Constitution Pipeline Company, LLC (Constitution) to fund costs associated with the development and construction of a pipeline in northeast Pennsylvania, which is incremental to our capital and exploration spending was $905.5 million comparedexpenditures. See Note 5 of the Notes to $891.5 millionthe Consolidated Financial Statements for further details regarding our investment in 2010. This increaseConstitution.

DESCRIPTION OF PROPERTIES

        Our exploration, development and production operations are primarily concentrated in spending was substantially driven by an expandedthree unconventional plays—the Marcellus shale horizontal drilling program and increasesShale in our drilling programs inPennsylvania, the Eagle Ford oil shale in south Texas and the Marmaton oil play in Oklahoma. In both 2011We also have significant non-core operations in various other unconventional and 2010, we allocatedconventional plays throughout the continental United States.

Marcellus Shale

        The Marcellus Shale is one of our planned program for capital and exploration expenditures among our variousmajor operating areas basedand represents our largest growth and capital investment area over the last four years. Our properties are principally located in Susquehanna County and to a lesser extent Bradford and Wyoming Counties, Pennsylvania. We currently hold approximately 200,000 net acres in the dry gas window of the play. Our 2012 net production in the Marcellus Shale was 209.3 Bcfe, representing approximately 78% of our total equivalent production for the year. As of December 31, 2012, we had a total of 224.2 net wells producing in the Marcellus Shale.

        During 2012, we invested $616.6 million in the Marcellus Shale and drilled 69.7 net horizontal wells and completed and turned in line 80.2 net wells. As of December 31, 2012, we had 32.0 net wells that were either in the completion stage or waiting on return expectations, availabilitycompletion or connection to a pipeline. We exited 2012 with five drilling rigs operating in the play.

Eagle Ford Shale

        Our properties in the Eagle Ford Shale are principally located in Atascosa, Frio, La Salle and Zavala Counties, Texas where we hold over 60,000 net acres in the oil window of servicesthe play. In 2012, our net liquids and human resources.natural gas production from the Eagle Ford was 1,581 Mbbl and 1.6 Bcf, respectively, or 11.1 Bcfe, representing approximately 4% of our full year equivalent production. As of December 31, 2012, we had a total of 47.7 net wells producing in the Eagle Ford.

        During 2012, we invested $171.0 million in the Eagle Ford and drilled or participated in drilling 23.2 net wells. We planexited 2012 with one drilling rig operating in the play.

Marmaton

        Our properties in the Marmaton oil play are principally located in Beaver County, Oklahoma and Ochiltree County, Texas. As of December 31, 2012, we had over 70,000 net acres in the play. In 2012, our net liquids and natural gas production from the Marmaton was 364 Mbbl and 0.6 Bcf, respectively, or 2.8 Bcfe, representing approximately 1% of our total equivalent production for the year. As of December 31, 2012, we had a total of 21.1 net wells producing in the Marmaton and 3.3 net wells completing or waiting on completion.

        During 2012, we invested $80.3 million in the Marmaton and drilled or participated in drilling 17.9 net wells. We exited 2012 with two drilling rigs operating in the play.

Other Oil and Gas Properties

        In addition to continue such method of allocationour core unconventional resource plays, we also operate or participate in 2012.other conventional and unconventional plays throughout the continental United States, including the Pearsall

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Funding ofShale in south Texas, the program is expected to be provided by operating cash flow, existing cashUtica Shale in Pennsylvania; the Cotton Valley, Haynesville, Bossier, and if required, borrowings under our credit facility.James Lime formations in east Texas; the Devonian Shale, Big Lime, Weir and Berea Shale in West Virginia; the Frio, Vicksburg and Wilcox formations in south Texas; and the Chase, Morrow and Chester formations in Oklahoma.

        In 2012,2013, we plan to spend between $750 and $790 million on capital and exploration activities.

        While we consider acquisitions from time to time, we remain focused on pursuing drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure sufficient liquidity, including cash resources and available credit. We believe these strategies are appropriate for our portfoliodrill a total of projects9.8 net wells in the current commodity pricing environmentPearsall Shale, all of which are subject to a joint development agreement with a wholly owned subsidiary of Osaka Gas Co., Ltd. (Osaka) that was entered into contemporaneously with the sale of a 35% non-operated working interest associated with certain of our Pearsall Shale undeveloped leaseholds in June 2012. Under the joint development agreement, Osaka agreed to fund 85% of our share of future drilling and completion costs associated with these leaseholds until it has paid approximately $126.0 million. The drilling and completion carry will continueterminate in June 2014.

Other Properties

        Ancillary to add shareholder value overour exploration, development and production operations, we operate a number of gas gathering and transmission pipeline systems, made up of approximately 3,134 miles of pipeline with interconnects to three interstate transmission systems and five local distribution companies and numerous end users as of the long-term.end of 2012. The majority of our pipeline infrastructure is located in West Virginia and is regulated by the Federal Energy Regulatory Commission (FERC) for interstate transportation service and the West Virginia Public Service Commission (WVPSC) for intrastate transportation service. As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC and the WVPSC. Our natural gas gathering and transmission pipeline systems in West Virginia enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system.

        We also have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The pipeline systems and storage fields are fully integrated with our operations in West Virginia.

DIVESTITURES

        In December 2012, we sold certain proved oil and gas properties located in south Texas to a private company for $29.9 million, subject to post closing adjustments, and recognized an $18.2 million loss on sale of assets.

        In June 2012, we sold a 35% non-operated working interest associated with certain of our Pearsall Shale undeveloped leaseholds in south Texas to a wholly-owned subsidiary of Osaka for $125.0 million in cash proceeds and recognized a $67.0 million gain on sale of assets.

        In 2012, we sold various other unproved properties and other assets for total proceeds of $14.4 million and recognized an aggregate gain of $1.8 million.

        In October 2011, we sold certain proved oil and gas properties located in Colorado, Utah and Wyoming to Breitburn Energy Partners, L.P. for $285.0 million. We received $283.2 million in cash proceeds, after closing adjustments, and recognized a $4.2 million gain on sale of assets.

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        In May 2011, we sold certain of our unproved Haynesville and Bossier Shale oil and gas properties in east Texas to a third party. We received approximately $47.0 million in cash proceeds and recognized a $34.2 million gain on sale of assets.

        In 2011, we sold various other unproved properties and other assets for total proceeds of $73.5 million and recognized an aggregate gain of $25.0 million.

        In December 2010, we sold our existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations to Williams Field Services (Williams), a subsidiary of Williams Partners L.P., for $150 million. Under the terms of the purchasemillion and sale agreement, we were obligated to construct pipelines to connect certain of our 2010 program wells, complete the construction of the Lathrop compressor station and complete taps into certain pipeline delivery points. These obligations were completed in 2011. As of December 31, 2010, we recognized a $49.3 million gain on sale of assets, which included the accrual of $17.9 million associated with the obligations described above. We also entered into a 25-year firm gathering contract with Williams that requires Williams to complete construction of approximately 32 miles of high pressure pipeline, 65 miles of trunklines and two compressor stations in Susquehanna County, Pennsylvania in 2011 and 2012. Additionally, Williams will connect all of our drilling program wells, which will connect our production to five interstate pipeline delivery options.assets.

        In 2010, we sold various other proved and unproved properties and other assets for total proceeds of $32.2 million and recognized an aggregate gain of $16.3 million.

        In April 2009, we sold substantially all of our Canadian proved oil and gas properties to Tourmaline Oil Corporation (Tourmaline) in exchange for cash and common shares of Tourmaline. In November 2010, we sold our investment in Tourmaline for $61.3 million and recognized a $40.7 million gain on sale of assets.

DESCRIPTION OF PROPERTIES

        Our properties are primarily located in Appalachia, east and south Texas and Oklahoma. Our activities in Appalachia are concentrated primarily in northeast Pennsylvania and in West Virginia. There are multiple producing intervals in Appalachia that includes the Devonian (including Marcellus), Big Lime, Weir and Berea shale formations at depths primarily ranging from approximately 950 to 7,800 feet, with an average depth of approximately 4,375 feet. Principal producing intervals in east Texas are in the Cotton Valley, Haynesville, Bossier, and James Lime formations and the principal producing intervals in south Texas are in the Eagle Ford, Frio, Vicksburg and Wilcox formations, with total depths ranging from approximately 2,650 to 19,650 feet, with an average depth of approximately

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11,150 feet. Our activities in Oklahoma include the Marmaton, Chase, Morrow and Chester formations in the Anadarko Basin at depths ranging from approximately 2,350 to 18,630 feet, with an average depth of approximately 10,490 feet. We also hold undeveloped acreage in the Rocky Mountains, located in Montana and Nevada.

        Ancillary to our exploration, development and production operations, we operate a number of gas gathering and transmission pipeline systems, made up of approximately 3,105 miles of pipeline with interconnects to three interstate transmission systems and five local distribution companies and numerous end users as of the end of 2011. The majority of our pipeline infrastructure is located in West Virginia and is regulated by the Federal Energy Regulatory Commission (FERC) for interstate transportation service and the West Virginia Public Service Commission (WVPSC) for intrastate transportation service. As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC and the WVPSC. Our natural gas gathering and transmission pipeline systems in West Virginia enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system.

        We also have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The pipeline systems and storage fields are fully integrated with our operations.

MARKETING

        The principal markets for our natural gas are in the northeastern and midwestern United States and the industrialized Gulf Coast area. In the northeastern United States, we sell natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system. In the Gulf Coast area and the midwestern United States, we sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Properties in the Gulf Coast area are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.

        Approximately 35-40% of our natural gas sales volume in 2011 was sold at index-based prices under contracts with terms of one year or greater. Our remaining natural gas sales volume was sold under contracts with terms less than one year. Spot market sales are made at index-based prices under month-to-month contracts, while industrial and utility sales generally are made under year-to-year contracts.

        In 2011, we produced and marketed approximately 490.0 Mmcf per day of natural gas and 4.0 Mbbls of crude oil/condensate/NGL per day at market responsive prices. Average daily production in 2011 was 513.7 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2011 was 178.8 Bcf and 1,443 Mbbls, respectively.

        In February 2012, we entered into a Precedent Agreement with Constitution Pipeline Company, LLC, a wholly owned subsidiary of Williams Partners L.P., to develop and construct a large diameter pipeline to transport our production in northeast Pennsylvania to both the New England and New York markets. Under the terms of the agreement, we will own 500,000 Mcf per day of capacity on the newly constructed pipeline and acquire a 25% equity interest in the project, subject to certain terms and conditions yet to be determined and regulatory approval.

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RISK MANAGEMENT

        From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risksrisk associated with our production. While there are many different types of derivatives available, we utilized natural gasgenerally utilize collar and crude oil swap agreements and crude oil collar agreements for portions of our 2011 production to attempt to manage price risk more effectively. During 2011, we also entered into crude oil swaps to hedge our price exposure on our 2012 production, natural gas swaps to hedge our price exposure on our 2011 and 2012 production and natural gas collars to hedge our price exposure on our 2013 production. In addition, we also have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting. In 2010 and 2009, we utilized collars and swaps to hedge our price exposure on our production.

The collar arrangements are a combination of put and call options used to establish floor and ceiling commodity prices for a fixed volume of natural gas and crude oil production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The price swapsswap agreements call for payments to, or receipts from, counterparties based on whether the marketindex price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap iswas put in place.

        For 2011,During 2012, natural gas and crude oil swaps covered 42%96.0 Bcf, or 38%, and 1,709 Mbbl, or 76%, of natural gas production and 20% of crude oil production at a weighted-averagean average price of $5.30$5.22 per Mcf and $106.20$100.12 per Bbl, respectively, and collarsrespectively. Natural gas basis swaps covered 26%17 Bcf, or 7%, of crude oilour natural gas production at a weighted-averagean average price of $90.88$(0.25) per Bbl.Mcf. Natural gas collars with a floor price of $3.60 per Mcf and a ceiling price of $4.17 per Mcf covered 3.0 Bcf, or 1%, of our natural gas production at an average price of $3.70 per Mcf.

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        As of December 31, 2011,2012, we had the following outstanding commodity derivatives:

        We will continue to evaluate the benefit of employingusing derivatives in the future. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Quantitative and Qualitative Disclosures about Market Risk" for further discussion concerning our use of derivatives.

RESERVES

        The following table presents our estimated proved reserves for the periods indicated:

        Our proved reserves totaled approximately 3,842 Bcfe at December 31, 2012, of which 96% were natural gas. This reserve level was up by 27% from 3,033 Bcfe at December 31, 2011 due to the positive results from our drilling program. In 2012, we had a net upward revision of 188.6 Bcfe, which was primarily due to an upward performance revision of 369.6 Bcfe, primarily in the Dimock field in northeast Pennsylvania, partially offset by a downward revision of 114.5 Bcfe associated with decreased reserve commodity pricing and a downward revision of 66.5 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.

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        Our reserve estimates were based on decline curve extrapolations, material balance calculations, volumetric calculations, analogies, or combinations of these methods for each well, reservoir or field. The proved reserve estimates presented herein were prepared by our petroleum engineering staff and audited by Miller and Lents, Ltd. (Miller and Lents), independent petroleum engineers. Miller and Lents made independent estimates for 100% of the proved reserves estimated by us and concluded, the following: Inin their judgment we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues. Further, Miller and Lents has concluded (1) the reserves estimation methods employed by us were appropriate, and our classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) our reserves estimation processes were comprehensive and of sufficient depth, (3) the data upon which we relied were adequate and of sufficient quality, and (4) the results of our estimates and projections are, in the aggregate, reasonable. For additional information regarding estimates of proved reserves, the audit of such estimates by Miller

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and Lents, Ltd., and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. A copy of the audit letter by Miller and Lents Ltd., dated January 31, 2012,2013, has been filed as an exhibit to this Form 10-K.

        Our reserves are sensitive to natural gas and crude oil sales prices and their effect on the economic productive life of producing properties. Our reserves are based on 12-month average crude oil and natural gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during 2012, 2011 2010 and 2009,2010, respectively. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in prices may result in negative impacts of this nature.

        For additional information regarding estimates of proved reserves, the audit of such estimates by Miller and Lents and other information about our reserves, including the risks inherent in our estimates of proved reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 and "Risk Factors—Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated" in Item 1A.

Internal Control

        Our corporate reservoir engineers report to the Vice President of Engineering and Technology, who maintains oversight and compliance responsibility for the internal reserve estimation process and provides oversight for the annual audit of our year-end reserves by our independent third party engineers, Miller and Lents, Ltd.Lents. Our corporate reservoir engineering group consists of four petroleum/chemical engineers, with petroleum/chemical engineering degrees and between onetwo and 2930 years of industry experience, between onetwo and 2930 years of reservoir engineering/management experience, and between onetwo and 1314 years managing our reserves. All four engineers are members of the Society of Petroleum Engineers.

Qualifications of Third Party Engineers

        The technical person primarily responsible for the audit of our reserve estimates at Miller and Lents Ltd. meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents Ltd. is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

        For additional information about the risks inherent in our estimates of proved reserves, see "Risk Factors—Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated" in Item 1A.

Proved Undeveloped Reserves

        At December 31, 20112012 we had 1,233.11,549 Bcfe of proved undeveloped reserves with future development costs of $1.3 billion, which represents an increase of 256.2316.1 Bcfe compared with December 31, 2010.2011. For 2011,

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2012, total capital related to the development of proved undeveloped reserves was $284.5$370.7 million, resulting in the conversion of 228.7410.9 Bcfe of reserves to proved developed. During 2011,2012, we had 556.3501.4 Bcfe of proved undeveloped reserve additions and 161.7233.5 Bcfe of positive proved undeveloped reserve performance revisions, primarily in the Dimock field in northeast Pennsylvania. These increases were partially offset by sales of proved undeveloped reserves of 43.3 Bcfe located in Colorado, Utah, Wyoming and east Texas and the removal of 189.866.5 Bcfe of proved undeveloped reserves associated with drilling locations primarily in east Texas West Virginia and Oklahoma, no longer anticipated to be developed within the next five years primarily due to a continued shift in our drilling program.

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Historical Reserves

        The following table presents our estimated proved reserves for the periods indicated.

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Production, Sales Price and Production CostsPRODUCTION, SALES PRICE AND PRODUCTION COSTS

        The following table presents historical information about our production volumes for natural gas and crude oil (including condensate and natural gas liquids), average natural gas and crude oil realized sales prices, and average production costs per equivalent, including our Dimock field located in northeast Pennsylvania, which contains more than 15% of our total proved reserves.

AcreageACREAGE

        Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right, in general, to develop oil and/or natural gas on the properties. Their primary terms range in length from approximately three to 10 years. These properties are held for longer periods if production is established.

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        The following table summarizes our gross and net developed and undeveloped leasehold and mineral fee acreage at December 31, 2011.2012. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

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Total Net Undeveloped Acreage Expiration

        Our net undeveloped acreage expiring over the next three years as of December 31, 20112012 is 128,463, 197,514202,375, 95,310 and 51,51882,660 for the years ending December 31, 2012, 2013, 2014 and 2014,2015, respectively. These amounts assume no future successful development, extension or renewal of undeveloped acreage.

Well SummaryWELL SUMMARY

        The following table presents our ownership in productive natural gas and crude oil wells at December 31, 2011.2012. This summary includes natural gas and crude oil wells in which we have a working interest.

Drilling ActivityDRILLING ACTIVITY

        We drilled wells or participated in the drilling of wells, or acquired wells as indicated in the table below.

        At December 31, 2011, 122012, 18 wells (7.6(13.1 net) were being drilled or awaiting completion.

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OTHER BUSINESS MATTERS

Title to Properties

        We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes or development obligations under oil and gas leases. As is customary in the industry in the case of undeveloped properties, often little investigation of record title is made at the time of lease acquisition. Investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

Competition

        Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times and distribution efficiencies, affect competition. We believe that in the Appalachia area our extensive acreage position existing natural gas gathering and pipeline systems in West Virginia and our access to gathering and pipeline infrastructure in Pennsylvania, along with services and equipment that we have secured for the upcoming years, and storage fields in West Virginia, enhance our competitive position over other producers who do not have similar systems or

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services in place. We also actively compete against other companies with substantially largersubstantial financial and other resources.

Major CustomerCustomers

        In 2012, three customers accounted for approximately 18%, 12% and 10%, respectively, of our total sales. In 2011, we did not have any one customer account for moregreater than 10% of our total sales. In 2010, one customer accounted for approximately 11% of our total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively, of our total sales. We do not believe that the loss of any of these customers would have a material adverse effect on us because alternative customers are readily available.

Seasonality

        Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months.

Regulation of Oil and Natural Gas Exploration and Production

        Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil

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and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.

Natural Gas Marketing, Gathering and Transportation

        Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 (NGPA), and the regulations promulgated under those statutes, the FERC regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective beginning in January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all "first sales" of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC has granted to all producers such as us a "blanket certificate of public convenience and necessity" authorizing the sale of natural gas for resale without further FERC approvals. As a result of this policy, all of our produced natural gas may now beis sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005 (2005 Act), the NGA has beenwas amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established new regulations that are intended to increase natural gas pricing transparency through,by, among other things, requiring market participants to report their gas

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sales transactions annually to the FERC, and new regulations that require certain non-interstate pipelines to post daily scheduled volume information and design capacity for certain points on their systems.FERC. The 2005 Act also significantly increased the penalties for violations of the NGA and the FERC's regulations.regulations up to $1,000,000 per day per violation. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties in an effort to add greater fairness, consistency and transparency toprocedure under its enforcement program.

        Some of our pipelines are subject to regulation by the FERC. We indirectly own an intrastate natural gas pipeline that provides interstate transportation and storage services pursuant to Section 311 of the NGPA, as well as intrastate transportation and storage services that are regulated by the West Virginia Public Service Commission. For qualified intrastate pipelines, FERC allows interstate transportation service "on behalf of" interstate pipelines or local distribution companies served by interstate pipelines without subjecting the intrastate pipeline to the more comprehensive NGA jurisdiction of the FERC. We provide Section 311 service in accordance with a publicly available Statement of Operating Conditions filed with FERC under rates that are subject to approval by the FERC. On December 26, 2012, we filed with the FERC a petition for rate approval of our existing interstate transportation rates and a proposed decrease of our storage rates. In addition, we have executed a precedent agreement with Constitution Pipeline Company, LLC, a subsidiary of Williams Partners L.P., for transportation capacity and a 25% equity interest in a pipeline to be constructed in the states of New York and Pennsylvania. In April 2012, the project sponsors requested to participate in FERC's pre-filing procedures and, once complete, will need to request and receive a certificate of public convenience and necessity from FERC prior to commencing construction. There is no guarantee that FERC will certify the project or, if they do, that the project scope or timeline for construction will remain unchanged by the regulatory permitting process. If placed into service, the project pipeline will be an interstate pipeline subject to full regulation by FERC under the NGA.

Our production and gathering facilities are not subject to jurisdiction of the FERC; however, our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation because the prices we receive for our production are affected by the cost of transporting the natural gas once sold to the consuming market. Throughmarket is a series of comprehensive rulemakings, beginningfactor in the prices we receive. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted regulatory changesa series of rulemakings that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the rolerequiring interstate

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pipeline companies to separate their wholesale gas marketing business from wholesale marketers oftheir gas to the primary role of gas transporters,transportation business, and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other, and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

        In light of these statutory and regulatory changes, most pipelines have divested their natural gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants, and mostmerchants. Most pipelines have also implemented the large-scale divestiture of their natural gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines thus now generallyare required to provide unbundled, open and nondiscriminatory transportation and transportation-related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. SellersAs a result of FERC requiring natural gas pipeline companies to separate marketing and transportation services, sellers and buyers of natural gas have gained direct access to the particular pipeline transportation services, they need, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace.

        Certain of our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation (DOT) and the West Virginia Public Service Commission. In 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (2002 Act), which contains a number of provisions intended to increase pipeline operating safety. The DOT's final regulations implementing the act became effective February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission and non-rural gathering pipeline facilities in certain locations within ten years, and at least every seven years thereafter. On March 15, 2006, the DOT revised these regulations to define more clearly the categories of gathering facilities subject to DOT regulation, establish new safety rules for certain gathering lines in rural areas, revise the current regulations applicable to safety and inspection of gathering lines in non-rural areas, and adopt new compliance deadlines. The initial baseline assessments under our integrity management program for our pipeline system in West Virginia are 96% complete and are expected to be fully complete by the December 2012 deadline. Clarification from the DOT published in 2009 brought to light the need for further baseline assessments of cased pipeline crossings covered under our integrity management program. Reassessment of our West Virginia pipeline system is scheduled to start in 2013 based on the 7 year reassessment requirement.

        In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (PIPES Act), which reauthorized the programs adopted under the 2002 Act, proposed enhancements for state programs to reduce excavation damage to pipelines, established increased federal enforcement of one-call excavation programs, and established a new program for review of

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pipeline security plans and critical facility inspections. Pursuant to the PIPES Act, the DOT issued regulations on May 5, 2011 that would, with limited exceptions, subject all low-stress hazardous liquids pipelines, regardless of location or size, to the DOT's pipeline safety regulations.

        In December 2011, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The act increases the maximum civil penalties for pipeline safety administrative enforcement actions; requires the DOT to study and report on the expansion of integrity management requirements, the sufficiency of existing gathering line regulations to ensure safety, and the use of leak detection systems by hazardous liquid pipelines; requires pipeline operators to verify their records on maximum allowable operating pressure; and imposes new emergency response and incident notification requirements.

        On December 3, 2009, the DOT adopted a regulation requiring gas and hazardous liquid pipelines that use supervisory control and data acquisition (SCADA) systems and have at least one controller and control room to develop written control room management procedures by August 1, 2011 and implement the procedures by February 1, 2013. The DOT expedited the program implementation deadline to October 1, 2011 for most of the requirements, except for certain provisions regarding adequate information and alarm management, which have a program implementation deadline of August 1, 2012. Effective January 1, 2011, natural gas and hazardous liquid pipelines became subject to updated reporting requirements with DOT. On August 25, 2011, the DOT issued an Advanced Notice of Proposed Rulemaking in which it explained that the DOT is considering changes to the pipeline safety regulations, including expanding its regulation of gas gathering lines.

We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, it is impossible towe cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despiteFurther, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry whether or to what extent that trend will continue or what the ultimate effect future policies will behave on our salessale of gas, cannot be predicted.gas.

Federal Regulation of Petroleum

        Our sales of oil and natural gas liquids are not regulated and are made at market prices. TheHowever, the price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines.pipelines, which are regulated by the FERC under the Interstate Commerce Act (ICA). FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service, and that such service not be unduly discriminatory or preferential.

        Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which annual adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase or decrease the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2010, to implement this required five-year re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 2.65 percent2.65% should be the oil pricing index for the five-year period beginning July 1, 2011. The result of indexing is a "ceiling rate" for each rate, which is the maximum at which the pipeline may set its interstate transportation rates. A pipeline may also file cost-of-service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Rates are subject to challenge by protest when they are filed or changed. For indexed rates, complaints alleging that the rates are unjust and unreasonable may only be pursued if the complainant can show that a substantial change has occurred since the enactment of Energy Policy Act of 1992 in either the economic circumstances of the pipeline or in the nature of the services provided, that were a basis for

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the rate. There is no such limitation on complaints alleging that the pipeline's rates or terms and conditions of service are unduly discriminatory or preferential.

        Another FERC matter that may impact our transportation costs relates to a policy that allows a pipeline structured as a master limited partnership or similar non-corporate entity to include in its rates a tax allowance with respect to income for which there is an "actual or potential income tax liability," to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest is required to file a tax return that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. We

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currently do not transport any of our crude oil or natural gas liquids on a pipeline structured as a master limited partnership.

        We are not ableunable to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or of the application of the FERC's policy on income tax allowances.

Pipeline Safety Regulation

        Certain of our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation (DOT) and the West Virginia Public Service Commission. In 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (2002 Act), which contains a number of provisions intended to increase pipeline operating safety. The DOT's final regulations implementing the act became effective February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission and non-rural gathering pipeline facilities in certain locations within ten years, and at least every seven years thereafter. On March 15, 2006, the DOT revised these regulations to define more clearly the categories of gathering facilities subject to DOT regulation, establish new safety rules for certain gathering lines in rural areas, revise the current regulations applicable to safety and inspection of gathering lines in non-rural areas, and adopt new compliance deadlines. The initial baseline assessments under our integrity management program for our pipeline system in West Virginia were completed in January 2013. Pipeline integrity was confirmed at each of the targeted assessment sites. A new seven-year reassessment cycle will begin in 2013.

        In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (PIPES Act), which reauthorized the programs adopted under the 2002 Act, proposed enhancements for state programs to reduce excavation damage to pipelines, established increased federal enforcement of one-call excavation programs, and established a new program for review of pipeline security plans and critical facility inspections. Pursuant to the PIPES Act, the DOT issued regulations on May 5, 2011 that would, with limited exceptions, subject all low-stress hazardous liquids pipelines, regardless of location or size, to the DOT's pipeline safety regulations.

        In December 2011, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The act increased the maximum civil penalties for pipeline safety administrative enforcement actions; required the DOT to issue regulations requiring the use of automatic or remote-controlled shutoff valves on new and rebuilt pipelines and to study and report on the expansion of integrity management requirements, the sufficiency of existing gathering line regulations to ensure safety, and the use of leak detection systems by hazardous liquid pipelines; required pipeline operators to verify their records on maximum allowable operating pressure; and imposed new emergency response and incident notification requirements. The act reflects many of the areas of possible regulatory change described in an Advance Notice of Proposed Rulemaking issued by the DOT on August 18, 2011. Aside from rules contained in the act, which include revisions to DOT's civil penalty authority and the requirement that pipelines verify maximum allowable operating pressure, the DOT has not yet promulgated any new regulations required by the act.

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        On December 3, 2009, the DOT adopted a regulation requiring gas and hazardous liquid pipelines that use supervisory control and data acquisition (SCADA) systems and have at least one controller and control room to develop written control room management procedures by August 1, 2011 and implement the procedures by February 1, 2013. The DOT expedited the program implementation deadline to October 1, 2011 for most of the requirements, except for certain provisions regarding adequate information and alarm management, which had a program implementation deadline of August 1, 2012. We developed and implemented the required control room management procedures in accordance with the deadlines. Effective January 1, 2011, natural gas and hazardous liquid pipelines also became subject to updated reporting requirements with DOT.

        The cost of compliance with DOT's integrity management rules depends on integrity testing and the repairs found to be necessary by such testing. Changes to the amount of pipe subject to integrity management, whether by expansion of the definition of the type of areas subject to integrity management procedures or of the applicability of such procedures outside of those defined areas can have a significant impact on costs we may incur to ensure compliance. In the future other laws and regulations may be enacted or adopted or existing laws may be reinterpreted in a manner that could impact our compliance costs. In addition, we may be subject to DOT's enforcement actions and penalties for failure to comply with pipeline regulations.

Environmental and Safety Regulations

        General.    Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating, and can affect the timing of installing and operating, oil and natural gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and natural gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and natural gas production could result in substantial costs and liabilities to us.

        The transition zone and shallow-water areas of the U.S. Gulf Coast are ecologically sensitive. Environmental issues have led to higher drilling costs and a more difficult and lengthy well permitting process. U.S. laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment.

        Solid and Hazardous Waste.    We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and natural gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination.

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        We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.

        Superfund.    The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the "Superfund" law, and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the current and past owners and operators of a site where the release occurred and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources

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and for the costs of certain health studies. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA's definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.

        Oil Pollution Act.    The Federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term "waters of the United States" has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns joint and several strict liability to each responsible party for oil removal costs and a variety of public and private damages. We believe that we substantially comply with the Oil Pollution Act and related federal regulations.

        Clean Water Act.    The Federal Water Pollution Control Act (Clean Water Act) and resulting regulations, which are primarily implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewaters to facilities owned by others that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations.

        Clean Air Act.    Our operations are subject to the Federal Clean Air Act and comparable local and state laws and regulations to control emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control toxic air pollutants might require installation of additional controls. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.

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        Hydraulic Fracturing.    Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or natural gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Such efforts could have an adverse effect on oil and natural gas production activities. For additional information about hydraulic fracturing and related environmental matters, please read "Item 1A. Risk"Risk Factors—Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays."

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        Greenhouse Gas.    In response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to global climate change, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases from sources within the United States between 2012 and 2050. In addition, almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The EPA has also begun to regulate carbon dioxide and other greenhouse gas emissions under existing provisions of the Clean Air Act. Please read "Item 1A. Risk"Risk Factors—Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and gas."natural gas that we produce" in Item 1A.

        OSHA and Other Laws and Regulations.    We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA), and comparable state laws. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.

Employees

        As of December 31, 2011,2012, we had 529589 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement.

Website Access to Company Reports

        We make available free of charge through our website, www.cabotog.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on our website is not a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by the Company.us. The public may read and copy materials that we file with the SEC at the SEC's Public Reference Room located at 100 F Street, NE, Washington, DC 20549. Information regarding the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330.

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Corporate Governance Matters

        The Company'sOur Corporate Governance Guidelines, Corporate Bylaws, Code of Business Conduct, Audit Committee Charter, Corporate Governance and Nominations Committee Charter, Compensation Committee Charter and AuditSafety and Environmental Affairs Committee Charter are available on the Company'sour website at www.cabotog.com, under the "Governance" section of "Investor Info."About Cabot." Requests can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas, 77024.

ITEM 1A.    RISK FACTORS

Natural gas and oil prices fluctuate widely, and low prices for an extended period of time arewould likely to have a material adverse impact on our business.

        Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Natural gas prices have decreased from an average price of $4.39 per Mmbtu in 2010 to an average price of $4.04 per Mmbtu in 2011. Natural gas prices were $3.36 per Mmbtu in December 2011 and have continued to decline to $2.68 per Mmbtu in February 2012. Natural gas prices represent the first of the month Henry Hub index price per Mmbtu. Oil prices have increased from an average price of $77.32 per barrel in 2010 to an average price of $94.01 per barrel in 2011. Depressed prices in the future would have a negative impact on our

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future financial results.results and could result in an impairment charge. See "Future natural gas and oil price declines may result in write-downs of the carrying amount of our assets, which could materially and adversely affect our results of operations." Because our reserves are predominantly natural gas, changes in natural gas prices have a more significant impact on our financial results.

        Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:include but are not limited to the following:

•

the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas from shale (such as that produced from our Marcellus properties) on the global natural gas supply;



•

the level of consumer product demand;



•

weather conditions;



•

political conditions or hostilities in natural gas and oil producing regions, including the Middle East;East, Africa and South America;



•

the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree to and maintain oil price and production controls;



•

the price level of foreign imports;



•

actions of governmental authorities;



•

pipelinethe availability, proximity and capacity constraints;of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;



•

inventory storage levels;



•

the nature and extent of domestic and foreign governmental regulations;regulations and taxation, including environmental and climate change regulation;



•

the price, availability and acceptance of alternative fuels;