10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2012

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

For the transition period from                 to                

Commission file number 001-33614

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

Yukon Territory, Canada	N/A
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification number)
400 North Sam Houston Parkway East, Suite 1200, Houston, Texas	77060
(Address of principal executive offices)	(Zip code)

(281) 876-0120

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Shares, without par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    YES  þ        NO  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    YES  ¨        NO  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    YES  þ        NO  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    YES  þ        NO    ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  þ	Accelerated filer  ¨	Non-accelerated filer  ¨	Smaller reporting company  ¨
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     YES  ¨        NO  þ

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $3,528,103,567 as of June 30, 2012 (based on the last reported sales price of $23.07 of such stock on the New York Stock Exchange on such date).

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of February 15, 2013 was 152,929,907.

Documents incorporated by reference: The definitive Proxy Statement for the 2013 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2012, is incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS

		Page
PART I
	Certain Definitions		3
Item 1.	Business		7
Item 1A.	Risk Factors		19
Item 1B.	Unresolved Staff Comments		27
Item 2.	Properties		27
Item 3.	Legal Proceedings		35
Item 4.	Mine Safety Disclosures		35
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		36
Item 6.	Selected Financial Data		38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		51
Item 8.	Financial Statements and Supplementary Data		52
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures		82
Item 9A.	Controls and Procedures		82
Item 9B.	Other Information		82
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		83
Item 11.	Executive Compensation		83
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		83
Item 13.	Certain Relationships, Related Transactions and Director Independence		83
Item 14.	Principal Accounting Fees and Services		83
PART IV
Item 15.	Exhibits, Financial Statement Schedules		84
	Signatures		86

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Certain Definitions

Terms used to describe quantities of oil and natural gas and marketing

• Bbl — One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

• Bcf — One billion cubic feet of natural gas.

• Bcfe — One billion cubic feet of natural gas equivalent.

• Tcfe — One trillion cubic feet of natural gas equivalent.

• BOE — One barrel of oil equivalent, converting natural gas to oil at the ratio of 6 Mcf of natural gas to 1 Bbl of oil.

• BTU — British Thermal Unit.

• Condensate — An oil-like, liquid hydrocarbon which is produced in association with natural gas production that condenses from natural gas as it is produced and delivered into a separator or similar equipment prior to the delivery of such natural gas to the natural gas gathering pipeline system.

• MBbl — One thousand barrels of crude oil or other liquid hydrocarbons.

• Mcf — One thousand cubic feet of natural gas.

• Mcfe — One thousand cubic feet of natural gas equivalent, converting oil or condensate to natural gas at the ratio of 1 Bbl of oil or condensate to 6 Mcf of natural gas. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or condensate to an Mcf of natural gas. The sales price of one barrel of oil or condensate has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to one barrel of oil or condensate.

• MMBbl — One million barrels of crude oil or other liquid hydrocarbons.

• MMcf — One million cubic feet of natural gas.

• MBOE — One thousand BOE.

• MMBOE — One million BOE.

• MMBTU — One million British Thermal Units.

Terms used to describe the Company’s interests in wells and acreage

• Gross oil and natural gas wells or acres — The Company’s gross wells or gross acres represent the total number of wells or acres in which the Company owns a working interest.

• Net oil and natural gas wells or acres — Determined by multiplying “gross” oil and natural gas wells or acres by the working interest that the Company owns in such wells or acres represented by the underlying properties.

• Prospect — A location where hydrocarbons such as oil and gas are believed to be present in quantities which are economically feasible to produce.

Terms used to assign a present value to the Company’s reserves

• Standardized measure of discounted future net cash flows, after income taxes — The present value, discounted at 10%, of the after tax future net cash flows attributable to estimated net proved reserves. The Company calculates this amount by assuming that it will sell the oil and natural gas production

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attributable to the proved reserves estimated in its independent engineer’s reserve report for the oil and natural gas spot prices based on the average price during the 12-month period before the ending date of the period covered by the report determined as an un-weighted, arithmetic average of the first-day-of-the-month price for each month within such period, adjusted for quality and transportation. The Company also assumes that the cost to produce the reserves will remain constant at the costs prevailing on the date of the report. The assumed costs are subtracted from the assumed revenues resulting in a stream of future net cash flows. Estimated future income taxes, using rates in effect on the date of the report, are deducted from the net cash flow stream. The after-tax cash flows are discounted at 10% to result in the standardized measure of the Company’s proved reserves.

• Standardized measure of discounted future net cash flows before income taxes — The discounted present value of proved reserves is identical to the standardized measure described above, except that estimated future income taxes are not deducted in calculating future net cash flows. The Company discloses the discounted present value without deducting estimated income taxes to provide what it believes is a better basis for comparison of its reserves to the producers who may have different income tax rates.

Terms used to classify the Company’s reserve quantities

The Securities and Exchange Commission (“SEC”) definition of proved oil and natural gas reserves, per Regulation S-X, is as follows:

Economically producible — A resource that generates revenue that exceeds (or is reasonably expected to exceed) costs of the operation.

Estimated ultimate recovery (“EUR”) — The sum of reserves remaining as of a given date and cumulative production as of that date.

Proved oil and gas reserves — Proved oil and natural gas reserves are those quantities of oil and gas, which, by analysis of available geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirs and under existing economic conditions, operating methods, and government regulation — before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of the reservoir considered as proved includes all of the following:

a. The area identified by drilling and limited fluid contacts, if any,

b. Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

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Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

a. Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based.

b. The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved developed oil and gas reserves — Proved oil and gas reserves that can be expected to be recovered:

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

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

Proved undeveloped oil and gas reserves — Proved oil and gas reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Reasonable certainty — If deterministic methods are used, a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Reliable technology — A grouping of one or more technologies (including computational methods) that has been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Resources — Quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

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Terms used to describe the legal ownership of the Company’s oil and natural gas properties

• Revenue interest — The amount of the interest owned in the proceeds derived from a producing well less all royalty interests.

• Working interest — A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property.

Terms used to describe seismic operations

• Seismic data — Oil and natural gas companies use seismic data as their principal source of information to locate oil and natural gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations.

• 2-D seismic data — 2-D seismic survey data has been the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data.

• 3-D seismic data — 3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is generally considered a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated.

Other Terms

• All-in costs — For any period, means the sum of lease operating expenses, severance taxes, gathering costs, transportation charges, depletion, depreciation and amortization, interest expense and general and administrative expenses divided by production on an Mcfe basis during the period.

• Reserve replacement ratio — The sum of the estimated net proved reserves added through extensions, discoveries, revisions and additions (including purchases of reserves) for a specified period of time divided by production for that same period of time.

• Finding and development costs — The sum of property acquisition costs, exploration costs and development costs for a specified period of time, divided by the total of proved reserve extensions, discoveries, revisions and additions (including purchases) for that same period of time.

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PART I

Item 1.    Business.

General

Ultra Petroleum Corp. (“Ultra” or the “Company”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. The Company was incorporated on November 14, 1979, under the laws of the Province of British Columbia, Canada. Ultra remains a Canadian company, but since March 2000, has operated under the laws of The Yukon Territory, Canada pursuant to Section 190 of the Business Corporations Act (Yukon Territory). The Company’s operations are primarily located in the Green River Basin of southwest Wyoming and the north-central Pennsylvania area of the Appalachian Basin.

The Company’s annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to such reports and all other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge to the public on the Company’s website at www.ultrapetroleum.com. To access the Company’s SEC filings, select “SEC Filings” under the Investor Relations tab on the Company’s website. You may also request a copy of these filings at no cost by making written or telephone requests for copies to Ultra Petroleum Corp., Manager, Investor Relations, 400 N. Sam Houston Pkwy. E., Suite 1200, Houston, TX 77060, (281) 876-0120. Any materials that the Company has filed with the SEC may be read and/or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding the Company. The SEC’s website address is www.sec.gov.

Oil and Gas Properties Overview

Ultra’s current operations in southwest Wyoming are focused on developing its long-life natural gas reserves in a tight gas sand trend located in the Green River Basin with targets in the sands of the upper Cretaceous Lance Pool in the Pinedale and Jonah fields. The Lance Pool, as administered by the Wyoming Oil and Gas Conservation Commission (“WOGCC”), includes sands of both the Lance (found at subsurface depths of approximately 8,000 to 12,000 feet) and Mesaverde (found at subsurface depths of approximately 12,000 to 14,000 feet) in the Pinedale and Jonah fields area of Sublette County, Wyoming. As of December 31, 2012, Ultra owned interests in approximately 84,000 gross (49,000 net) acres in Wyoming covering approximately 190 square miles.

Ultra’s current operations in north-central Pennsylvania are focused on assessing, exploring and developing its position in the Marcellus Shale and other horizons. At December 31, 2012, the Company owned interests in approximately 497,000 gross (261,000 net) acres in Pennsylvania.

In eastern Colorado, at December 31, 2012, the Company owned interests in approximately 154,000 gross (139,000 net) acres. The Company has no immediate plans for further exploration in this area.

Business Strategy

Ultra’s mission is to profitably grow an upstream oil and gas company for the long-term benefit of its shareholders. Ultra’s strategy includes building a robust portfolio of high return investment opportunities, maintaining a disciplined approach to capital investment, maximizing earnings and cash flows by controlling costs and maintaining financial flexibility. Consistent with our mission and this strategy, the Company significantly reduced its activity during 2012 as a result of the low prevailing natural gas prices during the year. The Company believes the low natural gas prices are unsustainable because capital investment in natural gas drilling has been reduced broadly across the industry and the Company believes natural gas supply will decline as

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a result. For additional information about steps the Company is taking to address low natural gas prices, see the “Marketing and Pricing” section of Item 1. Business.

High Return Portfolio.    Ultra seeks to maintain a portfolio of properties that provide long-term, profitable growth through development in areas that support sustainable, lower-risk, repeatable, high return drilling projects. The Company continually evaluates opportunities for the acquisition, exploration and development of additional oil and natural gas properties that afford risk-adjusted returns in excess of or equal to its current set of investment alternatives.

Disciplined Capital Investment.    Part of the Company’s business strategy includes proactive and regular review of its portfolio of investment opportunities with a focus on investments that produce positive returns in order to optimize return to its shareholders. Accordingly, in response to the current low natural gas price environment, the Company reduced capital expenditures by reducing the number of drilling rigs operating in its Wyoming fields and is encouraging the parties operating projects on its behalf in Pennsylvania to reduce their activity as well. Reductions in the Company’s activity resulted in reduced capital spending during the current year as compared to the prior year.

Low Cost Producer.    Ultra strives to maintain one of the lowest cost structures in the industry in terms of both adding and producing oil and natural gas reserves. The Company continues to focus on improving its drilling and production results through the use of advanced technologies and detailed technical analysis of its properties. For the year ended 2012, the Company’s all-in costs were $3.00 per Mcfe.

Financial Flexibility.    Preserving financial flexibility and a strong balance sheet are also key components of Ultra’s business strategy. At December 31, 2012, the Company had cash on hand of $12.9 million and outstanding debt was $1.8 billion. At December 31, 2012, the Company had $723.0 million of available borrowing capacity under its revolving credit facility. The Company’s average debt maturity is approximately seven years and the Company’s weighted average cost of debt is approximately 5.1%.

During December 2012, the Company sold a system of its liquids gathering pipelines and central gathering facilities and certain associated real property rights in the Pinedale Anticline in Wyoming. The net cash proceeds received for the assets were $203.0 million and $23.0 million in marketable securities which were sold during December 2012 for net cash proceeds of $21.2 million. The Company used the net proceeds of the sale to reduce its outstanding indebtedness under its revolving credit facility.

Exploration and Production

Green River Basin, Wyoming

During 2012, the Company participated in the drilling of 135 wells in Wyoming and continued to improve its drilling and completion efficiency on its operated wells as measured by spud to total depth. During 2012, the Company averaged 11.5 days to drill a well, as measured by spud to total depth. This compares to an average of 12 days to drill during 2011, a 4% reduction. Similarly, Ultra reached total depth in 10 days or less on 33% of all operated wells drilled in 2012 as compared to 12% of operated wells in 2011. Total days per well, measured by rig-release to rig-release, decreased 3% to 14.5 days in 2012 compared to 15 days during 2011.

During 2013, the Company plans to continue the ongoing development of its acreage position in the tight gas sand trend in the Green River Basin in southwest Wyoming. The Company expects that wells drilled during 2013 in the Pinedale field will target the sands of the upper Cretaceous Lance Pool.

All of the Company’s drilling activity is conducted utilizing its extensive integrated geological and geophysical data set. This data set is being utilized to map the potentially productive intervals, to refine areas of drilling focus, to identify areas for future extension of the Lance fairway and to identify deeper objectives which may warrant drilling.

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Pennsylvania

Ultra continued the assessment of its Pennsylvania acreage during 2012. During the year, the Company participated in the drilling of 59 horizontal wells. At the end of 2012, approximately 71% of the Company’s acreage holdings in Pennsylvania were covered by high quality 3D seismic data, which the Company uses to guide its investment decisions.

During 2013, the Company plans to continue its exploration and development activities in the Middle Devonian Marcellus Shale Play on its acreage in Pennsylvania. The Company also plans to continue evaluating the potential for the Upper Devonian Geneseo Shale Play across its Pennsylvania acreage position. Ultra’s current activities are located in Potter, Tioga, Clinton, Centre and Lycoming counties. Activities include lease acquisition, 3-D seismic, drilling, completion, infrastructure construction and production operations.

Colorado

In early 2012, Ultra expanded its acreage position in eastern Colorado’s Denver Julesburg Basin to 154,000 gross (139,000 net) acres. The Company drilled three vertical wells during the year to evaluate oil potential in the Cretaceous aged Niobrara formation. The Company also supported an offset operator’s efforts to drill and test a Niobrara horizontal well in return for data from that well. The results of these efforts indicate the play is non-commercial, and the Company has no immediate plans for additional exploration in the area.

Marketing and Pricing

Overview

Ultra derives its revenues from the sale of its natural gas and associated condensate produced from wells operated by the Company and others in the Green River Basin in southwest Wyoming and from the sale of natural gas produced from wells operated by the Company and others in the Appalachian Basin in Pennsylvania. During 2012, 97% of the Company’s production and 90% of its revenues, after realized gains on hedging transactions, were attributable to natural gas, with the balance attributable to associated condensate.

The Company’s revenues are determined by prevailing natural gas market prices in the Rocky Mountain region of the United States, specifically, southwest Wyoming, and, as a result of the completion of the Rockies Express Pipeline (“REX”) in 2009 and increased production in Pennsylvania during 2011 and 2012, by natural gas market prices in the Midwestern and Eastern regions of the United States.

Prevailing natural gas prices for the Company’s production were lower during 2012 than over the past several years. The average realized price per Mcf for the Company’s natural gas production, before realized gains on hedging transactions, for 2008, 2009, 2010, 2011 and 2012 was $7.11, $3.49, $4.31, $4.15, and $2.79, respectively. Although the Company does not believe the current low natural gas prices can be sustained, the low gas prices had an adverse effect on its results during 2012: the Company’s 2012 revenues were lower than 2011 even though it achieved record annual production in 2012; the Company was required to record a $2.9 billion, non-cash, ceiling test write-down of the carrying value of its oil and gas properties during 2012; and the Company’s proved undeveloped reserves at year-end 2012 were down compared to the prior year.

During 2012, the Company took several steps in response to the low gas price environment:

• Reduced net capital investment from $1.5 billion in 2011 to $615.2 million;

• Monetized its Wyoming liquids gathering system; and,

• Entered 2013 without hedging its future production at what it believes are unsustainably low forward natural gas prices.

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Prevailing natural gas forward prices for the Company’s future production were also lower during 2012 than over the past several years. As a result of the Company’s belief that overall domestic natural gas supply will fall and natural gas forward prices will increase in response, the Company has not hedged any of its 2013 production. During 2010, 2011 and 2012, respectively, the Company hedged a substantial portion of its forecast natural gas production at an average price per Mcf of $5.54, $5.53, and $5.35. A significant portion of the Company’s earnings during these years was attributable to these derivative transactions. As a result of the Company not having hedged any of its 2013 production, its earnings and cash flow may be more volatile during 2013 than in prior years.

Natural Gas Marketing

Ultra currently sells all of its natural gas production to a diverse group of third-party, non-affiliated entities in a portfolio of transactions of various durations and prices (daily, monthly and longer term). The Company’s customer base includes a significant number of customers situated in the various regions of the United States. The sale of the Company’s natural gas is “as produced”. As such, the Company does not maintain any significant inventories or imbalances of natural gas.

Midstream services.    For its natural gas production in Wyoming, the Company has entered into various gathering and processing agreements with several midstream service providers that gather, compress and process natural gas owned or controlled by the Company from its producing wells in the Pinedale Anticline and Jonah fields. Under these agreements, the midstream service providers have routinely expanded their facilities’ capacities in southwest Wyoming to accommodate growing volumes from wells in which the Company owns an interest. The Company believes that the capacity of the midstream infrastructure related to its production will continue to be adequate to allow it to sell essentially all of its available natural gas production.

In Pennsylvania, the Company and its partners are constructing gas gathering pipelines and facilities, compression facilities and pipeline delivery stations to gather production from its newly completed natural gas wells. Construction on these facilities continued throughout 2012, so the Company can manage its midstream capacity to coincide with capacity requirements from its drilling activities. These facilities are gathering systems and related infrastructure, and their construction is expected to continue, to some extent, until the Company’s properties in Pennsylvania are fully developed. To date, none of the Company’s natural gas production in Pennsylvania has required processing, treating or blending in order to remove natural gas liquids or other impurities and it is anticipated that treating facilities of this type will not be required in the future to accommodate the Company’s Pennsylvania production.

Pipeline infrastructure.    The Company has taken actions to facilitate expansion of the pipeline infrastructure available to move its natural gas supplies across the country, to provide sufficient capacity to transport its natural gas production and to provide for reasonable prices for its natural gas in the future. Three pipeline projects (REX, Ruby Pipeline, and Kern Pipeline’s Apex Expansion) have added aggregate export pipeline capacity for Rockies/Wyoming gas of approximately 2.1 Bcf per day. The Company continues to review pipeline projects in proximity to its reserves to determine the application of the new capacity to its core business.

Basis differentials.    The market price for natural gas is influenced by a number of regional and national factors which are beyond the Company’s ability to control. These factors include, among others, weather, natural gas supplies, natural gas demand, inventory levels in natural gas storage fields, and natural gas pipeline capacity to export gas from the basins where the Company’s production is located.

The Rocky Mountain region is a net exporter of natural gas because local natural gas production exceeds local demand, especially during non-winter months. As a result, natural gas production in southwest Wyoming has historically sold at a discount relative to other U.S. natural gas production sources or market areas. These regional pricing differentials, or discounts, are typically referred to as “basis” or “basis differentials” and are reflective, to some extent, of i.) the costs associated with transporting the Company’s gas to markets in other regions or states, and ii.) the availability of pipeline capacity to move the Company’s gas to market.

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Basis differentials in the Opal area have diminished to negligible levels when measured annually. This meaningful decrease in basis is largely attributable to the increased availability of transportation capacity out of the Rocky Mountains region due to the addition of Ruby Pipeline and Rockies Express Pipeline.

The Inside FERC First of Month Index for Northwest Pipeline — Rocky Mountains is the price that is reflective of the Company’s gas sold in the Opal, Wyoming area and the Inside FERC First of Month Index for Dominion-South Pool is the price that is reflective of the Company’s gas sold in Pennsylvania.

The table below provides a historical and future perspective on average annual basis differentials for Wyoming natural gas (NW Rockies) and historically premium markets in the Northeast (Dominion South). The basis differential is expressed as a percentage of the Henry Hub price as reported by Platt’s M2M (Mark to Market) Report on December 31, 2012.

	2009			2010			2011			2012			2013			2014			2015
NW Rockies		77	%		90	%		94	%		94	%		96	%		97	%		98	%
Dominion South		107	%		104	%		104	%		100	%		97	%		97	%		97	%

Derivatives

The Company, from time to time and in the regular course of its business, hedges a portion of its natural gas production primarily through the use of financial swaps with creditworthy financial counterparties (See Note 12), or through the use of fixed price, forward sales of physical gas. The Company may elect to hedge additional portions of its forecasted natural gas production in the future, in much the same manner as it has done previously. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

As a result of the Company’s belief that overall natural gas supply will fall and the low prevailing natural gas forward sale prices will improve in response, the Company has not yet entered into any hedging transactions for its 2013 production. As a result, the Company’s earnings and cash flows may be more volatile during 2013 than in prior years.

The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval. As of January 1, 2010, 2011 and 2012, the quantities that the Company hedged for the succeeding twelve month periods represented 46%, 67% and 51%, respectively, of the Company’s forecasted production for such periods. During 2011 and 2012, Ultra’s board approved hedges of greater than 50% of the Company’s forecast production for each respective period.

Oil Marketing and Liquids Gathering System

The Company markets its Wyoming condensate to various purchasers, which are primarily refiners in the Salt Lake City, Utah area. The Company’s condensate realized pricing is typically based on New York Mercantile Exchange crude futures daily settlement prices, less a negotiated location/transportation discount or differential. All of the Company’s condensate sales are denominated in U.S. dollars per barrel and are paid for on a monthly basis. The Company routinely maintains only operating inventories of condensate production and sells its product on an “as produced” basis. A portion of the Company’s condensate sales are performed by its operating partners in the Pinedale field.

At the end of 2012, more than 80% of the Company’s operated condensate production in Wyoming was delivered directly into a pipeline, further reducing truck traffic and improving flow assurance as well as realized pricing.

During December 2012, the Company entered into a Purchase and Sale Agreement (the “LGS PSA”) to sell its system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real

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property rights in the Pinedale Anticline in Wyoming. The net cash proceeds received for the assets were $203.0 million and additional consideration of $23.0 million in the form of marketable securities which were sold during December 2012 for net cash proceeds of $21.2 million.

Pursuant to the LGS PSA, the Company entered into a 15-year, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The base rent during the Lease Agreement is $20.0 million per year (adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. (See Note 4).

Significant Counterparties

A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2012, the Company had no single counterparty that represented 10% or more of the Company’s total revenues.

The Company maintains credit policies intended to mitigate the risk of uncollectible accounts receivable related to the sale of natural gas and condensate as well as commodity derivatives. A more complete description of the Company’s credit policies are described in Note 12. The Company did not have any outstanding, uncollectible accounts for its natural gas and oil sales at December 31, 2012.

Environmental Matters

The U.S. Bureau of Land Management (“BLM”) initiates preparation of an Environmental Impact Statement (“EIS”) relating to potential natural gas development on federal lands in the Pinedale Anticline area in the Green River Basin of Wyoming. An EIS is required under the National Environmental Policy Act (“NEPA”) for major federal actions significantly affecting the quality of the human environment and entails consideration of environmental consequences of a proposed action and its alternatives. Although the Company co-owns leases on state and privately owned lands in the vicinity of the Pinedale Anticline that do not fall under the federal jurisdiction of the BLM and are not subject to the EIS requirement, the area north of the Jonah field, including the Pinedale Anticline, which the EIS addresses, is where most of the Company’s exploration and development is taking place. The BLM issues a Record of Decision (“ROD”) with respect to a final EIS, which allows for surface disturbances for drilling and production activities within the area covered by the EIS, but does not authorize the drilling of particular wells. Ultra, therefore, must submit applications to the BLM’s Pinedale field manager for permits and other required authorizations, such as rights-of-way for each specific well or particular pipeline location. In making its determination on whether to approve specific drilling or development activities, the BLM applies the requirements of the ROD.

The ROD imposes limits on drilling and completion activity and proposes mitigation guidelines, standard practices for industry activities and best management practices for sensitive areas. The Company cannot predict if or how these adjustments may affect permitting, development and compliance under the ROD. The BLM’s field manager may also impose additional limitations and mitigation measures as are deemed reasonably necessary to mitigate the impact of drilling and production operations in the area.

To date, the Company has expended significant resources in order to satisfy applicable environmental laws and regulations in the Pinedale Anticline area and other areas of operation under the jurisdiction of the BLM. The Company’s future costs of complying with these regulations may continue to be significant. Further, any additional limitations and mitigation measures could further increase production costs, delay exploration, development and production activities or curtail exploration, development and production activities altogether.

In August 1999, the BLM required an Environmental Assessment (“EA”) for the potential increased density drilling in the Jonah field area. An EA is a more limited environmental study than that conducted under an EIS. The EA was required to address the potential environmental impacts of developing the Jonah field on a well

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density of two wells per 80-acre drilling and spacing unit as opposed to the one well per 80-acre drilling and spacing unit as was approved in the initial Jonah field EIS approved in 1998. The new EA was completed in June 2000. With the approval of this EA and the earlier approval by the WOGCC for drilling of two wells per 80-acre drilling and spacing unit, the Company was permitted to drill infill wells at this well density on the 2,160 gross (1,322 net) acres then owned by the Company in the Jonah field. Subsequently, various other operators have received approval for the drilling of increased density wells in pilot areas at well densities ranging from four wells per 80-acre drilling and spacing unit to sixteen wells per 80-acre drilling and spacing unit. Current spacing in the Jonah field is eight wells per 80-acre drilling and spacing unit (10-acre spacing) with several pilots testing spacing at 16 wells per 80-acre drilling and spacing unit (5-acre spacing).

The BLM prepared a new EIS covering the Jonah field to assess the impact of increased density development and define the parameters under which this increased density development will be allowed to proceed. The draft EIS was made available in February 2005 and the final ROD was issued on March 14, 2006. Key components of the ROD require an annual operations plan that includes all previous year activity including the number of wells drilled, total new surface disturbance by well pads, roads, and pipelines, and current status of all reclamation activity. Also required is a plan of development for the upcoming year reflecting the planned number of wells to be drilled and an estimate of new surface disturbance and reclamation activity. Other components include a drilling rig forecast, emission reduction report, annual water well monitoring reports, a three-year operational forecast and the use of flareless-completion technology to reduce noise, visual impacts and air emissions, including greenhouse gases as well as other monitoring and mitigation measures.

During the period from 2003 through year end 2011, Ultra and other operators in the Pinedale field received approval from the WOGCC to drill increased density and pilot project wells in several areas in the Lance Pool across the Pinedale field. During 2011, based on results of its 5-acre wells drilled in 2010, Ultra sought and obtained approval from the WOGCC to file for development of its acreage in Pinedale at a well density of 32 wells per 160-acre government quarter section (5-acre equivalent).

Ultra, Shell and Questar (“Proponents”) submitted a development proposal for the Pinedale field, which includes broad application of operations principles being evaluated in the demonstration project area. The Proponents entered into a memorandum of understanding with the BLM to commence the preparation of a supplemental EIS, or SEIS, for year-round access in the Pinedale field. The SEIS process included assessment of alternative considerations and mitigation requirements that were considered as alternatives, or in addition, to those included in the proposal. The proposal included commitments to reduce surface disturbance by utilizing fewer overall pads and drilling more directional wells than called for in the 2000 Pinedale Anticline Project Area (“PAPA”) ROD.

The final ROD (“2008 SEIS ROD”) was granted on September 9, 2008. The 2008 SEIS ROD allows, among other things, for full field development from no more than 600 well pads field-wide, as well as year-round development and delineation activity within big game (pronghorn and mule deer) and greater sage-grouse seasonal use areas. Further, the Proponents agreed to implement numerous individual mitigation components. These commitments include (i) the use of a full-field liquids gathering system, (ii) the use of advanced rig engine emission reduction technology by at least 80% of the Company’s 2005 rig emission levels, (iii) a mitigation and monitoring fund to address mitigation efforts to minimize impacts from energy development, and (iv) additional funding for ground water monitoring on the PAPA. Additionally, ten-year planning and annual meetings with BLM and appropriate state agencies will allow for proper community planning.

Also as part of the 2008 SEIS ROD, Ultra has offered to suspend additional activity for at least five years from the signing of the SEIS ROD on certain leases. After the five-year period, leases under federal suspension and/or “no surface” occupancy will be considered for conversion to “available for development” when a comparable acreage in the core area of the PAPA has been returned to a functioning habitat.

In July 2009, Ultra, along with Shell and Questar, were awarded the BLM’s 2009 Environmental Best Management Practices Award for Responsible Stewardship of Air Resources in the PAPA.

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Regulation

Oil and Gas Regulation

The availability of a ready market for oil and natural gas production depends upon numerous factors beyond the Company’s control. These factors may include, among other things, federal, state and local regulation of oil and natural gas production and transportation, including regulations governing environmental quality, pollution control and limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities, and the marketing of competitive fuels.

Most states, and some counties and municipalities, in which the Company operates also regulate one or more of the following:

• The location of wells;

• The method of drilling, completing and operating wells;

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

• Produced water and waste disposal;

• The plugging and abandoning of wells; and

• Notice to surface owners and other third parties.

State and federal regulations are generally intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, 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 the Company are also subject to the jurisdiction of various federal, state and local authorities, 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 gas properties.

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

The Company’s sales of natural gas are affected by the availability, terms and costs of transportation both in the gathering systems that transport the natural gas from the wellhead to the interstate pipelines and in the interstate pipelines themselves. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act, as well as under Section 311 of the Natural Gas Policy Act. Since 1985, the FERC has issued and implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis.

The Company’s sales of oil are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil pipeline rates.

If the Company conducts operations on federal, tribal or state lands, such operations must comply with numerous regulatory restrictions, including various operational requirements and restrictions, nondiscrimination statutes and royalty and related valuation requirements. In addition, some operations must be conducted pursuant to certain on-site security regulations, bonding requirements and applicable permits issued by the Bureau of Land

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Management (“BLM”), Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, and tribal or other applicable federal, state and/or Indian Tribal agencies.

The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits ownership of any direct or indirect interest in federal onshore oil and gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas lease can be canceled in a proceeding instituted by the United States Attorney General. The Company qualifies as a corporation formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns interests in numerous federal onshore oil and gas leases. It is possible that holders of the Company’s equity interests may be citizens of foreign countries that are determined to be non-reciprocal countries under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination.

Surface Damage Acts

Several states, including Wyoming, and some tribal nations have enacted surface damage statutes. These laws are designed to compensate for damages caused by oil and gas development operations. Most surface damage statutes contain entry and negotiation requirements to facilitate contact between the operator and surface owners. Most also contain binding requirements for payments by the operator in connection with development operations. Costs and delays associated with surface damage statutes could impair operational effectiveness and increase development costs.

Environmental Regulations

General. The Company’s exploration, drilling and production activities from wells and oil and natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil, natural gas and other products are subject to stringent federal, state and local laws and regulations relating to environmental quality, including those relating to oil spills and pollution control. Although such laws and regulations can increase the cost of planning, designing, installing and operating such facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon the Company’s operations, capital expenditures, earnings or competitive position.

Solid and Hazardous Waste.    The Company has previously owned or leased and currently owns or leases, numerous properties that have been used for the exploration and production of oil and natural gas for many years. Although the Company utilized standard operating and disposal practices, hydrocarbons or other solid wastes may have been disposed of or released on or under such properties or on or under locations where such wastes have been taken for disposal. In addition, many of these properties are or have been operated by third parties over whom the Company has no control, nor has ever had control as to such entities’ treatment of hydrocarbons or other wastes or the manner in which such substances may have been disposed of or released. State and federal laws applicable to oil and natural gas wastes and properties have gradually become stricter over time. Under current and evolving law, it is possible the Company could be required to remediate property, including ground water, containing or impacted by operations by the Company or by such third party operators, or by previously disposed wastes including performing remedial plugging operations to prevent future, or mitigate existing, contamination.

Although oil and gas wastes generally are exempt from regulation as hazardous wastes (“Hazardous Wastes”) under the federal Resource Conservation and Recovery Act (“RCRA”) and some comparable state statutes, it is possible some wastes the Company generates presently or in the future may be subject to regulation under RCRA and state analogs. The Environmental Protection Agency (“EPA”) and various state agencies have

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limited the disposal options for certain wastes, including Hazardous Wastes and are considering adopting stricter disposal standards for non-hazardous wastes. Furthermore, certain wastes generated by the Company’s oil and natural gas operations that are currently exempt from designation as Hazardous Wastes may in the future be designated as Hazardous Wastes under RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements.

Hydraulic Fracturing.    Many of the Company’s exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. Congress has periodically considered legislation to amend the federal Safe Drinking Water Act to remove the exemption from permitting and regulation provided to injection for hydraulic fracturing and to require the disclosure and reporting of the chemicals used in hydraulic fracturing (except where diesel is a component of the fracturing fluid). This type of federal legislation, if adopted, could lead to additional regulation and permitting requirements that could result in operational delays making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and operating costs.

In addition, EPA has recently been considering whether to assert federal regulatory authority over hydraulic fracturing using diesel under the Safe Drinking Water Act’s Underground Injection Control Program. Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. EPA released a progress report in December 2012 and final results are expected in 2014. In addition, in December 2011, the EPA published a draft report in which it asserts that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming (not a field in which the Company owns any interest); this report has been publicly criticized by industry and government officials, including the Governor of Wyoming; it remains subject to review. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

In addition, some states have adopted, and other states have adopted or are considering adopting, regulations that require disclosure of the chemicals in the fluids used in hydraulic fracturing. Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some case impose a moratorium on hydraulic fracturing. Although none of the Company’s properties are in jurisdictions where the limits have been imposed, it is possible the jurisdictions where the Company’s properties are located may adopt such limits or other limits on hydraulic fracturing in the future. The BLM has proposed rules and regulations for hydraulic fracturing activities on federal lands. The Company and others provided written comment to the proposed rules. Further, the EPA has announced an initiative under The Toxics Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals.

Superfund.    Under the federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, liability, generally, is joint and several for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRP”), include current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous Substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to releases and threats of releases to protect the public health or the environment and to seek to recover from the PRP the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, the Company has generated and will generate wastes that fall within CERCLA’s definition of Hazardous Substances. The Company may also be an owner or operator of facilities on which Hazardous Substances have been released. The Company may be responsible under CERCLA for all or part of the costs to clean up facilities at which such

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substances have been released and for natural resource damages, as a past or present owner or operator or as an arranger. Many states have comparable laws imposing liability on similar classes of persons for releases, including for releases of materials that may not be included in CERCLA’s definition of Hazardous Substances. To its knowledge, the Company has not been named a PRP under CERCLA (or any comparable state law) nor have any prior owners or operators of its properties been named as PRPs related to their ownership or operation of such property.

National Environmental Policy Act.    The federal National Environmental Policy Act provides that, for major federal actions significantly affecting the quality of the human environment, the federal agency taking such action must prepare an environmental assessment or an environmental impact statement (EIS). In the EIS, the agency is required to evaluate alternatives to the proposed action and the environmental impacts of the proposed action and of such alternatives. Actions of the Company, such as drilling on federal lands, to the extent the drilling requires federal approval, may trigger the requirements of the National Environmental Policy Act, including the requirement that an EIS be prepared. The requirements of the National Environmental Policy Act may result in increased costs, significant delays and the imposition of restrictions or obligations on the Company’s activities, including but not limited to the restricting or prohibiting of drilling.

Oil Pollution Act.    The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the Clean Water Act (“CWA”), imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and for a variety of public and private damages. Although defenses and limitations exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, the Company could be liable for costs and damages.

Air Emissions.    The Company’s operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws generally require new and modified sources of air pollutants to obtain permits prior to commencing construction, which may require, among other things, stringent, technical controls. Other federal and state laws designed to control hazardous (toxic) air pollutants might require installation of additional controls. Administrative agencies can bring actions for failure to comply with air pollution regulations or permits and generally enforce compliance through administrative, civil or criminal enforcement actions, which may result in fines, injunctive relief and imprisonment.

On April 17, 2012, the EPA issued final rules to subject oil and gas operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs under the Clean Air Act (“CAA”), and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require operators of oil and gas wells to reduce emissions of volatile organic compounds (“VOCs”) during completions by either flaring or capturing any natural gas not delivered into gathering pipelines in a process commonly referred to as a “green completion.” During 2012, the Company conducted “green completions” on all of the wells it hydraulically fractured. In addition, the rules establish new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants, and certain other equipment. These rules may require changes to our operations, including possible installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on our business.

Clean Water Act.    The Clean Water Act (“CWA”) restricts the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined to include, among other things, certain wetlands. Under the Clean Water Act, permits must be obtained for the discharge of

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pollutants into waters of the United States. The CWA provides for administrative, civil and criminal penalties for unauthorized discharges, both routine and accidental, of pollutants and of oil and hazardous substances. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require permits to discharge storm water runoff, including discharges associated with construction activities. The CWA also prohibits the discharge of fill materials to regulated waters including wetlands without a permit.

Endangered Species Act.    The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The Company conducts operations on federal and other oil and natural gas leases that have species, such as raptors, that are listed and species, such as sage grouse, that could be listed as threatened or endangered under the ESA. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation or the mere presence of threatened or endangered species could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. If the Company were to have a portion of its leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

OSHA and other Regulations.    The Company is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require a company to organize and/or disclose information about hazardous materials used or produced in its operations.

Climate Change Legislation.    More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”), including methane and carbon dioxide, may be adopted and could cause the Company to incur material expenses in complying with them. The EPA has adopted rules under the CAA for the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources being subjected to the permitting requirements first. These permitting provisions, should they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and the Company could incur additional costs to satisfy those requirements. In November 2010, EPA published a rule establishing GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions, with the first annual report, for 2011, being due in September 2012. Although the rule does not limit the amount of GHGs that can be emitted, it could require us to incur significant costs to monitor, keep records of, and report GHG emissions associated with our operations.

In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These or other potential federal and state initiatives may result in so-called cap-and-trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in the Company incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from its operations. These regulatory initiatives also could adversely affect the marketability of the oil and natural gas the Company produces.

The Company believes that it is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company.

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Employees

As of December 31, 2012, the Company had 115 full-time employees, including officers.

Item 1A.     Risk Factors.

Our reserve estimates may turn out to be incorrect if the assumptions upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, drilling, testing and production data acquired subsequent to the date of an estimate may justify revising such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels, prices and future operating costs are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based.

The present value, discounted at 10%, of the pre-tax future net cash flows attributable to our net proved reserves included in this report should not be considered as the market value of the reserves attributable to our properties. In accordance with SEC requirements, we base the present value, discounted at 10%, of the pre-tax future net cash flows attributable to our net proved reserves on the average oil and natural gas prices during the 12-month period before the ending date of the period covered by this report determined as an unweighted, arithmetic average of the first-day-of the-month price for each month within such period, adjusted for quality and transportation. The costs to produce the reserves remain constant at the costs prevailing on the date of the estimate. Actual current and future prices and costs may be materially higher or lower. In addition, the 10% discount factor, which the SEC requires us to use in calculating our discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on our cost of capital from time to time and/or the risks associated with our business.

Competitive industry conditions may negatively affect our ability to conduct operations.

We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and natural gas companies as well as numerous independents, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development.

Factors that affect our ability to compete in the marketplace include:

• our access to the capital necessary to drill and complete wells and acquire properties;

• our ability to acquire and analyze seismic, geological and other information relating to a property;

• our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;

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• our ability to procure materials, equipment and services required to explore, develop and operate our properties; and

• our ability to access pipelines, and the locations of facilities used to produce and transport oil and natural gas production.

Factors beyond our control affect our ability to effectively market production and may ultimately affect our financial results.

The ability to market oil and natural gas depends on numerous factors beyond our control. These factors include:

• the extent of domestic production and imports of oil and natural gas;

• the availability of pipeline capacity, including facilities owned and operated by third parties;

• the proximity of natural gas production to natural gas pipelines;

• the effects of inclement weather;

• the demand for oil and natural gas by utilities and other end users;

• the availability of alternative fuel sources;

• state and federal regulations of oil and natural gas marketing and transportation; and

• federal regulation of natural gas sold or transported in interstate commerce.

Because of these factors, we may be unable to market all of the oil and natural gas that we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce.

Any derivative transactions we enter into may limit our gains and expose us to other risks.

Although we have not entered into any derivative transactions related to our 2013 production, we do enter into transactions with derivative instruments from time to time to manage our exposure to commodity price risks. These transactions limit our potential gains if commodity prices rise above the levels established by our derivative instruments. These transactions may also expose us to other risks of financial losses, for example, if our production is less than we anticipated at the time we entered into a derivative instrument or if a counterparty to our derivative instruments fails to perform the contracts.

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

During 2010, the President signed into law the Dodd–Frank Wall Street Reform and Consumer Protection Act (the “Act”). Among other things, the Act requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market.

In its rulemaking under the new legislation, the CFTC has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions); the CFTC’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the CFTC has indicated that it intends to appeal the court’s decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions.

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In addition, the Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other related rules and regulations, the Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, hedging transactions in the future would become more expensive than we experienced in the past.

A decrease in oil and natural gas prices may adversely affect our results of operations and financial condition.

Energy commodity prices have been historically highly volatile, and such high levels of volatility are expected to continue in the future. We cannot accurately predict the market prices that we will receive for the sale of our natural gas, condensate, or oil production. Unless and until we enter into any derivative transactions related to our 2013 production, our revenues and cash flow may be more volatile during 2013 than in prior years. Information about revenues attributable to our derivative transactions in 2010, 2011 and 2012 is available in Item 7-A — “Quantitative and Qualitative Disclosures About Market Risk.”

Oil and natural gas prices are subject to a variety of additional factors beyond our control, which include, but are not limited to: changes in the supply of and demand for oil and natural gas; market uncertainty; weather conditions in the United States; the condition of the United States economy; the actions of the Organization of Petroleum Exporting Countries; governmental regulation; political stability in the Middle East and elsewhere; the foreign supply of oil and natural gas; the price of foreign oil and natural gas imports; the availability of alternate fuel sources; and transportation interruption. Any substantial and extended decline in the price of oil or natural gas could have an adverse effect on the carrying value of our proved reserves, borrowing capacity, our ability to obtain additional capital, and the Company’s revenues, profitability and cash flows from operations.

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

A substantial portion of our reserves and production is natural gas. Prices for natural gas have been lower in recent years than at various times in the past and may remain lower in the future. The low natural gas prices during the past year adversely affected our 2012 revenues, cash flow and reserves. Sustained low prices for natural gas during 2013 and beyond may also adversely affect our operational and financial condition.

Natural gas prices have been lower in recent years than at various times in the past. These lower prices may be the result of increased supply resulting from among other things, increased drilling in unconventional reservoirs and/or lower demand resulting from reduced economic activity associated with the recent recession. Natural gas prices may remain at current levels, or fall to lower levels, in the future. Approximately 96% of our estimated net proved reserves is natural gas, and 97% of our production in 2012 was natural gas. Although we expect production operations on properties we currently own to be profitable at natural gas prices in effect during the past year, a continued period of sustained low natural gas prices could have further adverse effects on our results of operations and financial condition.

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Compliance with environmental and other government regulations could be costly and could negatively impact our production.

Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations may:

• require that we acquire permits before developing our properties;

• restrict the substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas; and

• require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells.

Under these laws and regulations or under the common law, the Company could be liable for personal injury and clean-up costs and other environmental, natural resource and property damages, as well as administrative, civil and criminal penalties. The Company could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine emissions, greenhouse gases and hydraulic fracturing. We maintain limited insurance coverage for sudden and accidental environmental damages, but do not maintain insurance coverage for the full potential liability that could be caused by accidental environmental damages. Accordingly, we may be subject to liability in excess of our insurance coverage or may be required to cease production from properties in the event of environmental damages.

A significant percentage of our operations are conducted on federal and state lands. These operations are subject to a wide variety of regulations as well as other permits and authorizations which must be obtained from and issued by state and federal agencies. To conduct these operations, we may be required to file applications for permits, seek agency authorizations and comply with various other statutory and regulatory requirements. Complying with any of these requirements may adversely affect our ability to complete our drilling programs at the costs and in the time periods anticipated.

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

More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause the Company to incur material expenses to comply. The EPA has adopted rules under the CAA for the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration and Title V permitting programs. These permitting provisions, should they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and the Company could incur additional material costs to satisfy those requirements.

In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA published its amendments to the 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, which may include facilities we operate. Reporting of GHG emissions from such facilities will be required on an annual basis beginning in 2012 for emissions occurring in 2011. We will have to incur costs associated with this reporting obligation.

In addition, the United States Congress has considered legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce or measure GHG emission levels, often involving the planned development of GHG emission inventories and/or regional cap and trade programs. Most of these cap and trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to reduce overall

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GHG emissions. The cost of these allowances could escalate significantly over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Potential physical effects of climate change could adversely affect our operations and cause us to incur significant costs in preparing for or responding to those effects.

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations, including the hydraulic fracturing of our wells, have the potential to be adversely affected. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from powerful winds or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

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

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level (except for fracturing activity involving the use of diesel). The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, issued a progress report in December 2012, and expects to deliver the final results of the study in 2014. In addition, in December 2011, the EPA published a draft report in which it asserts that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming (not a field in which the Company owns an interest); this report has been publicly criticized by industry and by government officials, including the Governor of Wyoming; it remains subject to review. A committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. Wyoming has adopted regulations requiring us to provide detailed information about wells we hydraulically fracture in that state. Many other states have adopted or are considering adopting regulations requiring disclosure of chemicals in fluids used in hydraulic fracturing. Any other new laws or regulations that significantly restrict hydraulic fracturing could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. We have conducted hydraulic fracturing operations on most of our existing wells, and we anticipate conducting hydraulic fracturing operations on substantially all of our future wells. As a result, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

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Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

While we have not experienced cyber-attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

We may not be able to obtain funding on acceptable terms or at all.

Global financial markets and economic conditions have been disrupted and volatile due to a variety of factors. As a result, the cost of raising money in the debt and equity capital markets and the availability of funds from those markets is unpredictable. Although we successfully raised capital in the past, we may not be successful in the future. In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due and we may be unable to execute our growth strategy, take advantage of other business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

We may not be able to replace our reserves or generate cash flows if we are unable to raise capital. We will be required to make substantial capital expenditures to develop our existing reserves and to discover new oil and gas reserves.

Our ability to continue exploration and development of our properties and to replace reserves may be dependent upon our ability to continue to raise significant additional financing, including debt financing or obtain other potential arrangements with industry partners in lieu of raising financing. Any arrangements that may be entered into could be expensive to us. There can be no assurance that we will be able to raise additional capital in light of factors such as the market demand for our securities, the state of financial markets for independent oil and gas companies (including the markets for debt), oil and natural gas prices and general market conditions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for a discussion of our capital budget.

We expect to continue using our bank credit facility to borrow funds to supplement our available cash flow. The loan commitment and aggregate amount of money we can borrow under the credit facility and from other sources is revised from time to time based on certain restrictive covenants. A change in our ability to meet the restrictive covenants might limit our ability to borrow. If this occurred, we may have to sell assets or seek substitute financing. We can make no assurances that we would be successful in selling assets or arranging substitute financing. For a description of the bank credit facility and its principal terms and conditions, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

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Our operations may be interrupted by severe weather or drilling restrictions.

Our operations are conducted primarily in the Rocky Mountain region of the United States and in the north-central Pennsylvania area of the Appalachian Basin. The weather in these areas can be extreme and can cause interruption in our exploration and production operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital investment. Likewise, our operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to our facilities.

Unless we are able to replace reserves that we have produced, our cash flows and production will decrease over time.

Our future success depends on our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Without successful exploration, development or acquisition activities, our reserves and production will decline. We can give no assurance that we will be able to find, develop or acquire additional reserves at acceptable costs.

We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.

The oil and natural gas business involves a variety of operating risks, including blowouts, fire, explosion, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as oil spills, natural gas leaks, discharges of toxic gases, underground migration and surface spills or mishandling of fracture fluids, including chemical additives. The occurrence of any of these events with respect to any property we own or operate (in whole or in part) could have a material adverse impact on us. We and the operators of our properties maintain insurance in accordance with customary industry practices and in amounts that management believes to be reasonable. However, insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks. The occurrence of a significant event that is not fully insured could have a material adverse effect on our financial condition.

There are risks associated with our drilling activity that could impact our results of operations.

Our oil and natural gas operations are subject to all of the risks and hazards typically associated with drilling for, and production and transportation of, oil and natural gas. These risks include the necessity of spending large amounts of money for identification and acquisition of properties and for drilling and completion of wells. In the drilling and completing of exploratory or development wells, failures and losses may occur before any deposits of oil or natural gas are found. The presence of unanticipated pressure or irregularities in formations, blow-outs or accidents may cause such activity to be unsuccessful, resulting in a loss of our investment in such activity and possible liabilities. If oil or natural gas is encountered, there can be no assurance that it can be produced in quantities sufficient to justify the cost of continuing such operations or that it can be marketed satisfactorily.

Our decision to drill a prospect is subject to a number of factors which may alter our drilling schedule or our plans to drill at all.

A prospect is an area in which our geoscientists have identified what they believe, based on available seismic and geological information, to be indications of hydrocarbons. Our prospects are in various stages of review. Whether or not we ultimately drill our prospects depends on many factors, including but not limited to: receipt of additional seismic data or reprocessing of existing data; material changes in oil or natural gas prices; the costs and availability of drilling equipment; success or failure of wells drilled in similar formations or which would use the same production facilities; the availability and cost of capital; changes in the estimates of costs to drill or complete wells; decisions of our joint working interest owners; and regulatory and permitting requirements. It is possible that these factors and others may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all.

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If oil and natural gas prices decrease, we may be required to record additional write downs of the carrying value of our oil and gas properties.

We follow the full cost method of accounting for our oil and gas properties. A separate cost center is maintained for expenditures applicable to each country in which we conduct exploration and/or production activities. Under such method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. Discounted future net revenues are estimated using oil and natural gas spot prices based on the average price during the preceding 12-month period determined as an unweighted, arithmetic average of the first-day-of-the-month price for each month within such period, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings. As a result of low gas prices during 2012, we were required to record a $2.9 billion non-cash, ceiling test write-down of the carrying value of our oil and gas properties.

We have limited control over activities conducted on properties we do not operate.

We own interests in properties that are operated by third parties. The success, timing and costs of drilling, completion, and other development activities on our non-operated properties depend on a number of factors that are beyond our control. Because we have only a limited ability to influence and control the operations of our non-operated properties, we can give no assurances that we will realize our targeted returns with respect to those properties.

We may fail to fully identify problems with any properties we acquire.

We acquired a portion of our acreage position in Pennsylvania and Colorado through property acquisitions and acreage trades, and we may acquire additional acreage in Colorado, Pennsylvania or other regions in the future. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify.

Forward-Looking Statements

This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. Except for statements of historical facts, all statements included in this document, including those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct.

Forward-looking statements include statements regarding:

• our oil and natural gas reserve quantities, and the discounted present value of those reserves;

• the amount and nature of our capital expenditures;

• drilling of wells;

• the timing and amount of future production and operating costs;

• our ability to respond to low natural gas prices;

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• business strategies and plans of management; and

• prospect development and property acquisitions.

Some of the risks which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include:

• any future global economic downturn;

• general economic conditions, including the availability of credit and access to existing lines of credit;

• the volatility of oil and natural gas prices;

• the uncertainty of estimates of oil and natural gas reserves;

• the impact of competition;

• the availability and cost of seismic, drilling and other equipment;

• operating hazards inherent in the exploration for and production of oil and natural gas;

• difficulties encountered during the exploration for and production of oil and natural gas;

• difficulties encountered in delivering oil and natural gas to commercial markets;

• changes in customer demand and producers’ supply;

• the uncertainty of our ability to attract capital and obtain financing on favorable terms;

• compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business, including those related to climate change and greenhouse gases;

• actions of operators of our oil and natural gas properties; and

• weather conditions.

The information contained in this report, including the information set forth under the heading “Risk Factors,” identifies additional factors that could affect our operating results and performance. We urge you to carefully consider these factors and the other cautionary statements in this report. Our forward-looking statements speak only as of the date made, and we have no obligation to update these forward-looking statements.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Location and Characteristics

The Company owns oil and natural gas leases in Wyoming and Pennsylvania and oil and gas leases and fee minerals in Colorado. The leases in Wyoming are primarily federal leases with 10-year lease terms until establishment of production. Production extends the lease terms until cessation of that production. In Pennsylvania, the leases are from private individuals and companies, as well as from the Commonwealth of Pennsylvania. The leases in Pennsylvania are mostly undeveloped at this time and typically have primary lease terms of five years until establishment of production. In Colorado, our oil and gas leases are from private individuals and companies, as well as from the State of Colorado, and typically have primary lease terms of five years. All of our acreage in Colorado is undeveloped at this time, and the Company has no immediate plans for further exploration in this area.

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Green River Basin, Wyoming

As of December 31, 2012, the Company owned developed oil and natural gas leases totaling approximately 84,000 gross (49,000 net) acres in the southwest Wyoming’s Green River Basin. Most of this acreage covers Pinedale and Jonah fields. Of the total acreage position in Wyoming, approximately 22,000 gross (10,000 net) acres were developed, and 62,000 gross (39,000 net) acres were undeveloped. The developed portion represents 15% of the Company’s total developed net acreage while the undeveloped portion represents approximately 10% of the Company’s total undeveloped net acreage.

Lease maintenance costs in Wyoming were approximately $0.1 million for the year ended December 31, 2012. The Company currently owns 39 leases totaling 68,000 gross (37,000 net) acres currently held by production and activities (“HBP”) in Wyoming. The HBP acreage includes all of the Company’s leases within the productive area of the Pinedale and Jonah fields.

Development Wells.    During 2012, the Company participated in the drilling of 81 gross (30.6 net) productive development wells on the Green River Basin properties. At year-end 2012, there were 16 gross (5.7 net) additional development wells that commenced during the year and were either still drilling or had operations suspended at a depth short of total depth.

Exploratory Wells.    During 2012, the Company participated in the drilling of a total of 30 gross (13.6 net) productive exploratory wells on the Green River Basin properties. At December 31, 2012, there were 8 gross (6.4 net) additional exploratory wells that commenced during the year that were either still drilling or had operations suspended at a depth short of total depth and thus a determination of productive capability could not be made at year-end.

Pennsylvania

As of December 31, 2012, the Company owned oil and gas leases covering 497,000 gross (261,000 net) acres in the Pennsylvania portion of the Appalachian Basin. This acreage is located in the heart of northeast Pennsylvania’s Marcellus Shale Gas Trend, principally in Potter, Tioga, Lycoming, Centre and Clinton counties. Of the total acreage position as of December 31, 2012, approximately 111,000 gross (58,000 net) acres were developed, and 386,000 gross (203,000 net) acres were undeveloped. The developed portion represents 85% of the Company’s total developed net acreage position while the undeveloped portion represents 53% of the Company’s total undeveloped net acreage position. The Company operates approximately 84,000 gross (58,000 net) acres of the total position.

Lease maintenance costs in Pennsylvania were approximately $2.0 million for the year ended December 31, 2012. The Company owns approximately 362,000 gross (185,000 net) acres currently held by production or activities in Pennsylvania.

Development Wells.    During 2012, the Company participated in the drilling of 16 gross (8.0 net) productive development wells in Pennsylvania, all of which were horizontal wells. At year-end 2012, there was 1 gross (0.5 net) additional development wells that commenced during the year and were either still drilling or had operations suspended at a depth short of total depth.

Exploratory Wells.    During the year ended December 31, 2012, the Company participated in the drilling of a total of 48 gross (18.9 net) productive exploratory wells on the Pennsylvania properties. At December 31, 2012, there was 1 gross (0.5 net) additional exploratory well that commenced during the year that was either still drilling or had operations suspended at a depth short of total depth and thus a determination of productive capability could not be made at year-end.

Seismic Activity.    The Company acquired 148 square miles of new 3D seismic data on its properties during 2012. The Company’s total 3D seismic coverage in Pennsylvania is 455 square miles. Of this, 425 square miles of data is owned with other parties, and 30 square miles is owned solely by the Company.

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Denver Julesburg Basin, Colorado

As of December 31, 2012, the Company owned fee minerals and oil and gas leases covering 154,000 gross (139,000 net) acres in eastern Colorado’s Denver Julesburg Basin. The total acreage in Colorado represents approximately 36% of the Company’s undeveloped net acreage position.

Lease maintenance costs in Colorado were $0.1 million for the year ended December 31, 2012. All of the Colorado acreage is undeveloped at this time; none of it is held by production. The Company has no immediate plans for further exploration in this area.

Exploratory Wells.    During 2012, the Company drilled 3 gross (3.0 net) exploratory wells in eastern Colorado. All three were vertical wells designed to evaluate oil potential in the Niobrara Formation.

Development Wells.    The Company did not participate in drilling any development wells in Colorado during 2012.

Seismic Activity.    The Company did not acquire any additional seismic data in Colorado during 2012. The Company currently owns 22 square miles of 3D seismic data in El Paso County, Colorado, and has licensed an additional 126 linear miles of 2D data in the same county. This represents the Company’s total seismic position in the area.

Oil and Gas Reserves

The following table sets forth the Company’s quantities of proved reserves for the years ended December 31, 2012, 2011, and 2010 as estimated by independent petroleum engineers Netherland, Sewell & Associates, Inc. The table summarizes the Company’s proved reserves, the estimated future net revenues from these reserves and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2012, 2011 and 2010. As of December 31, 2012, proved undeveloped reserves represent 38.7% of the Company’s total proved reserves.

	December 31,
	2012		2011		2010
Proved Developed Reserves
Natural gas (MMcf)		1,820,994		1,973,391		1,678,697
Oil (MBbl)		10,531		11,794		11,013
Proved Undeveloped Reserves
Natural gas (MMcf)		1,145,451		2,805,163		2,521,458
Oil (MBbl)		7,606		21,287		20,671
Total Proved Reserves (MMcfe)(1)		3,075,267		4,977,040		4,390,257
Estimated future net cash flows, before income tax	$	4,501,804	$	11,789,256	$	10,879,719
Standardized measure of discounted future net cash flows, before income taxes(2)	$	2,263,259	$	5,296,964	$	4,993,576
Future income tax	$	368,942	$	1,500,908	$	1,468,008
Standardized measure of discounted future net cash flows, after income tax	$	1,894,317	$	3,796,056	$	3,525,568
Calculated average price(3)
Gas ($/Mcf)	$	2.63	$	4.04	$	4.05
Oil ($/Bbl)	$	87.85	$	88.19	$	68.93

(1) Oil and condensate are converted to natural gas at the ratio of one barrel of oil or condensate to six Mcf of natural gas. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or condensate to an Mcf of natural gas. The sales price of one barrel of oil or condensate has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to one barrel of oil or condensate.

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(2) Management believes that the presentation of the standardized measure of discounted future net cash flows, before income taxes, of estimated proved reserves, discounted at 10% per annum, may be considered a non-Generally Accepted Accounting Principle financial measure as defined in Item 10(e) of Regulation S-K, therefore the Company has included this reconciliation of the measure to the most directly comparable Generally Accepted Accounting Principle (“GAAP”) financial measure (standardized measure of discounted future net cash flows, after income taxes). Management believes that the presentation of the standardized measure of future net cash flows before income taxes provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of the Company’s oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s reserves to other companies. The standardized measure of discounted future net cash flows, before income taxes, is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company. Standardized measure of discounted future net cash flows, before income taxes, should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

(3) As prescribed by Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”), reserves estimated by our independent engineers at December 31, 2012, 2011 and 2010, reflect oil and natural gas spot prices based on the average prices during the 12-month period before the ending date of the period covered by this report determined as an unweighted, arithmetic average of the first-day-of-the-month price for each month within such period.

Since January 1, 2012, 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 and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA.

Proved Undeveloped Reserves

The following table describes the changes in the Company’s proved undeveloped reserves during 2012:

	MMcfe
Proved undeveloped reserves, December 31, 2011		2,932,885
Converted to proved developed		(172,736	)
Proved undeveloped reserve extensions		756,595
Proved undeveloped reserves transferred to unproven		(2,311,045	)
Proved undeveloped reserve revisions		(14,612	)
Proved undeveloped reserves, December 31, 2012		1,191,087

In 2012, the Company converted 173 Bcfe of proved undeveloped reserves to proved developed reserves. Of these conversions, 89% were located in the Pinedale field in Wyoming. During 2012, the Company spent $207.0 million to convert proved undeveloped reserves to proved developed reserves. At December 31, 2012, the Company also transferred 2.3 Tcfe of proved undeveloped reserves to the unproven category of reserves due to lower natural gas prices utilized in the preparation of the December 31, 2012 reserve estimation. The natural gas price utilized in preparing the Company’s reserve estimate at December 31, 2012 was $2.63 per Mcf as compared to $4.04 per Mcf at December 31, 2011, a 35% decrease. At the lower gas price, some of the Company’s proved undeveloped locations are uneconomic and, accordingly, the Company transferred these locations to the unproven category.

In addition to lower gas prices, the Company reduced the capital scheduled for proved undeveloped locations to $1.4 billion at December 31, 2012 from $4.1 billion at December 31, 2011. This reduction in capital

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was largely associated with certain other proved undeveloped locations transferred to the unproven category. The Company has not scheduled any proved undeveloped reserves beyond five years nor does it have any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years.

During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected with ceiling test and other impairments in the accompanying Consolidated Statements of Operations.

Internal Controls Over Reserve Estimating Process

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. The Vice President — Reservoir Engineering & Development is primarily responsible for overseeing the preparation of the Company’s reserve estimates by our independent engineers, Netherland, Sewell & Associates, Inc. The Vice President — Reservoir Engineering and Development has a Bachelor and Master of Science degree in Petroleum Engineering and is a licensed Professional Engineer with over 18 years of experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation. Our internal professional staff works closely with our independent engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves.

All of the information regarding reserves in this annual report is derived from the report of Netherland, Sewell & Associates, Inc. The report of Netherland, Sewell & Associates, Inc. is included as an Exhibit to this annual report. The principal engineer at Netherland, Sewell & Associates, Inc. responsible for preparing our reserve estimates has a Bachelor of Science degree in Mechanical Engineering and is a licensed Professional Engineer with 30 years of experience, including significant experience throughout the Rocky Mountain basins.

In estimating proved reserves and future net revenue as of December 31, 2012, the Company’s independent reserve engineer, Netherland, Sewell & Associates, Inc., used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, Netherland, Sewell & Associates, Inc.’s conclusions necessarily represent only informed professional judgment.

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Production Volumes, Average Sales Prices and Average Production Costs

The following table sets forth certain information regarding the production volumes and average sales prices received for and average production costs associated with the Company’s sale of oil and natural gas for the periods indicated.

	Year ended December 31,
	2012		2011		2010
	(In thousands, except per unit data)
Production
Natural gas (Mcf)		249,310		236,832		205,613
Oil (Bbl)		1,282		1,408		1,334
Total (Mcfe)		257,002		245,280		213,619
Revenues
Natural gas sales	$	695,733	$	982,413	$	886,396
Oil sales		114,241		119,383		92,990
Total revenues	$	809,974	$	1,101,796	$	979,386
Lease Operating Expenses
Production costs(a)	$	64,468	$	51,758	$	45,938
Severance/production taxes		60,757		97,094		95,914
Gathering		59,004		56,511		50,126
Total lease operating expenses	$	184,229	$	205,363	$	191,978
Realized prices
Natural gas ($/Mcf, including realized gains (losses) on commodity derivatives)	$	4.01	$	5.05	$	4.88
Natural gas ($/Mcf, excluding realized gains (losses) on commodity derivatives)	$	2.79	$	4.15	$	4.31
Oil ($/Bbl)	$	89.08	$	84.79	$	69.69
Costs per Mcfe
Production costs	$	0.25	$	0.21	$	0.22
Severance/production taxes	$	0.24	$	0.40	$	0.45
Gathering	$	0.23	$	0.23	$	0.23
Transportation charges	$	0.33	$	0.26	$	0.30
DD&A	$	1.51	$	1.41	$	1.13
General & administrative	$	0.10	$	0.11	$	0.11
Interest	$	0.34	$	0.26	$	0.23
Total costs per Mcfe	$	3.00	$	2.88	$	2.68

The following table sets forth the net sales volumes, operating expenses and realized natural gas prices attributable to field(s) that contain 15% or more of our total estimated proved reserves as of December 31, 2012:

	Year ended December 31,
	2012		2011		2010
	(In thousands)
Pinedale Field:
Production (Mcfe)		179,757		196,236		190,849
Operating expenses	$	144,538	$	178,387	$	179,544
Realized price, excluding hedges ($/Mcf)	$	2.84	$	4.17	$	4.32
Realized price, including hedges ($/Mcf)	$	4.55	$	5.27	$	4.94

(a) Production costs include lifting costs and remedial workover expenses.

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Delivery Commitments

With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. As of February 8, 2013, the Company had long-term natural gas delivery commitments of 3.0 MMMBtu in 2013, 8.2 MMMBtu in 2014, 4.4 MMMBtu in 2015, 4.8 MMMBtu in 2016 and 7.9 MMMBtu in 2017 under existing agreements. None of these commitments require the Company to deliver gas produced specifically from any of the Company’s properties, and all of these commitments are priced on a floating basis with reference to an index price. These amounts are well below the Company’s forecasted 2013 and anticipated 2014 through 2017 production from its available reserves. In addition, none of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Item 1A. “Risk Factors”. The Company believes that its production and reserves are adequate to meet its delivery commitments. If for some reason the Company’s production is not sufficient to satisfy its delivery commitments, the Company expects to be able to purchase natural gas production in the market to satisfy its commitments.

With respect to the Company’s oil production, the Company does not have any long-term arrangements that commit the Company to deliver a fixed or determinable quantity of oil in the near future.

Productive Wells

As of December 31, 2012 the Company’s total gross and net wells were as follows:

Productive Wells*	Gross Wells		Net Wells
Natural Gas and Condensate		2,334		1,145.5

* Productive wells are producing wells, shut-in wells the Company deems capable of production, wells that are waiting for completion, plus wells that are drilled/cased and completed, but waiting for pipeline hook-up. A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractional working interests the company owns in gross wells.

Oil and Gas Acreage

The primary terms of the Company’s oil and gas leases expire at various dates. Much of the Company’s undeveloped acreage is held by production, which means that the Company will maintain its rights in these leases as long as oil or natural gas is produced from the acreage by it or by other parties holding interests in producing wells on those leases. In some cases, if production from a lease ceases, the lease will expire, and in some cases, if production from a lease ceases, the Company may maintain the lease by additional operations on the acreage.

The Company does not believe the remaining terms of its leases is material. At December 31, 2012, the Company had 12,245 net acres of leases in Pennsylvania, 2,000 net acres of leases in Colorado and no leases in Wyoming that expire in 2013 and it expects to maintain over 20% of those leases by production, operations, extensions or renewals. The Company does not expect to lose material lease acreage because of failure to drill due to inadequate capital, equipment or personnel. The Company has, based on its evaluation of prospective economics, allowed acreage to expire and it may allow additional acreage to expire in the future.

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As of December 31, 2012 the Company had total gross and net developed and undeveloped oil and natural gas leasehold acres in the United States as set forth below.

	Developed Acres				Undeveloped Acres
	Gross		Net		Gross		Net
Wyoming		22,000		10,000		62,000		39,000
Pennsylvania		111,000		58,000		386,000		203,000
Colorado		—		—		154,000		139,000
All States		133,000		68,000		602,000		381,000

Drilling Activities

For each of the three fiscal years ended December 31, 2012, 2011 and 2010 the number of gross and net wells drilled by the Company was as follows:

Wyoming — Green River Basin

	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		81.0		30.6		117.0		71.0		75.0		37.3
Dry		—		—		—		—		—		—
Total		81.0		30.6		117.0		71.0		75.0		37.3

At year end, there were 16 gross (5.7 net) additional development wells that were either drilling or had operations suspended. This includes wells in both the Pinedale and Jonah fields.

	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells
Productive		30.0		13.6		83.0		42.5		106.0		57.2
Dry		—		—		—		—		—		—
Total 30.0 13.6		30.0		13.6		83.0		42.5		106.0		57.2

At year end, there were 8 gross (6.4 net) additional exploratory wells that were either drilling or had operations suspended. This includes wells in both the Pinedale and Jonah fields.

Pennsylvania

	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		16.0		8.0		1.0		0.4		—		—
Dry		—		—		—		—		—		—
Total		16.0		8.0		1.0		0.4		—		—

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At year end, there were 1 gross (0.5 net) additional development wells that were either drilling or had operations suspended.

	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells
Productive		48.0		18.9		184.0		86.7		171.0		99.0
Dry		—		—		—		—		—		—
Total		48.0		18.9		184.0		86.7		171.0		99.0

At year end, there was 1 gross (0.5 net) additional exploratory well that was either drilling or had operations suspended.

Colorado

	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells
Productive		—		—		—		—		—		—
Dry		3.0		3.0		—		—		—		—
Total		3.0		3.0		—		—		—		—

At year end, there were no additional exploratory wells that were either drilling or had operations suspended.

Item 3. Legal Proceedings.

The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine or predict the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, or results of operations.

Item 4. Mine Safety Disclosures.

None.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company’s common shares trade on the New York Stock Exchange (“NYSE”) under the symbol “UPL”. The following table sets forth the high and low intra-day sales prices of the common shares for the periods indicated.

The following share price performance graph is intended to allow review of shareholder returns, expressed in terms of the appreciation of the Company’s common shares relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future share performance. The graph compares the yearly percentage change in the cumulative total shareholder return on the Company’s common shares with the cumulative total return of the NYSE Composite Index and of the Dow Jones U.S. Exploration and Production TSM Index from December 31, 2007 through December 31, 2012.

2012	High		Low
1st quarter	$	30.66	$	22.03
2nd quarter	$	23.43	$	17.62
3rd quarter	$	24.52	$	19.96
4th quarter	$	24.26	$	17.58
2011	High		Low
1st quarter	$	50.97	$	41.83
2nd quarter	$	51.20	$	42.90
3rd quarter	$	47.89	$	27.56
4th quarter	$	36.72	$	24.39

As of February 15, 2013, the last reported sales price of the common shares on the NYSE was $16.00 per share and there were approximately 340 holders of record of the common shares.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among Ultra Petroleum Corp, the NYSE Composite Index,

and the Dow Jones US Exploration & Production TSM Index

[

* $100 invested on 12/31/07 in stock or index, including reinvestment of dividentds. Fiscal year ending December 31.

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Copyright^© 2013 Dow Jones & Co. All rights reserved.

	12/07		12/08		12/09		12/10		12/11		12/12
Ultra Petroleum Corp		100.00		48.27		69.73		66.81		41.44		25.36
NYSE Composite		100.00		60.74		77.92		88.36		84.96		98.55
Dow Jones US Exploration & Production TSM		100.00		58.97		83.46		98.81		94.76		99.66

The stock price performance included in this graph is not necessarily indicative of future stock price performance.

The Company has not declared or paid and does not anticipate declaring or paying any dividends on its common shares in the near future. The Company intends to retain its cash flow from operations for the future operation and development of its business.

On May 17, 2006, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate $1 billion of the Company’s outstanding common shares which has been and will be funded by cash on hand and the Company’s senior credit facility.

	Total Number of Shares Repurchased (000’s)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (000’s)		Maximum Number (or Approximate Dollar Value) of Shares That May Yet be Purchased Under the Plans or Programs
Period
November 2012		5	$	23.10		5	$	385.4 million

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Item 6. Selected Financial Data.

The selected consolidated financial information presented below for the years ended December 31, 2012, 2011, 2010, 2009 and 2008 is derived from the Consolidated Financial Statements of the Company.

	Year Ended December 31,
	2012			2011			2010			2009			2008
				(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Natural gas sales	$	695,733		$	982,413		$	886,396		$	601,023		$	986,374
Oil sales		114,241			119,383			92,990			65,739			98,026
Total operating revenues		809,974			1,101,796			979,386			666,762			1,084,400
Expenses:
Production expenses and taxes		184,229			205,363			191,978			152,804			194,243
Transportation charges		84,470			64,243			64,965			58,011			46,310
Depletion, depreciation and amortization		388,985			346,394			241,796			201,826			184,795
Ceiling test and other impairments		2,972,464			—			—			1,037,000			—
General and administrative		14,348			12,113			11,407			8,871			11,230
Stock compensation		10,756			13,919			12,944			10,901			5,816
Interest expense		88,180			63,156			49,032			37,167			21,276
Total operating expenses		3,743,432			705,188			572,122			1,506,580			463,670
Other:
Gain on commodity derivatives		73,581			313,732			325,452			146,517			33,216
Contract cancellation fees		(15,469	)		—			—			—			—
Litigation expense		—			—			(9,902	)		—			—
Other income (expense) , net		(1,765	)		532			260			(2,888	)		833
Total other (expense) income, net		56,347			314,264			315,810			143,629			34,049
(Loss) income before income taxes		(2,877,111	)		710,872			723,074			(696,189	)		654,779
Income tax (benefit) provision		(700,213	)		257,670			258,615			(245,136	)		240,504
Net (loss) income	$	(2,176,898	)	$	453,202		$	464,459		$	(451,053	)	$	414,275
Basic (Loss) Earnings per Share:
Net (loss) income per common share —basic	$	(14.24	)	$	2.97		$	3.05		$	(2.98	)	$	2.72
Fully (Loss) Diluted Earnings per Share:
Net (loss) income per common share —fully diluted	$	(14.24	)	$	2.94		$	3.01		$	(2.98	)	$	2.65
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	654,825		$	1,033,292		$	824,728		$	592,641		$	840,803
Investing activities	$	(577,223	)	$	(1,408,795	)	$	(1,529,099	)	$	(820,611	)	$	(915,319	)
Financing activities	$	(75,988	)	$	315,976		$	760,951		$	228,067		$	78,041
Balance Sheet Data:
Cash and cash equivalents	$	12,921		$	11,307		$	70,834		$	14,254		$	14,157
Working capital (deficit)	$	(388,244	)	$	(251,059	)	$	(56,967	)	$	(137,450	)	$	(149,355	)
Oil and gas properties	$	1,657,499		$	4,189,148		$	3,075,670		$	1,794,603		$	2,350,526
Total assets	$	2,007,345		$	4,869,705		$	3,595,615		$	2,060,005		$	2,558,162
Total long-term debt	$	1,837,000		$	1,903,000		$	1,560,000		$	795,000		$	570,000
Other long-term obligations	$	76,038		$	67,008		$	52,575		$	35,858		$	46,206
Deferred income taxes, net	$	—		$	635,009		$	420,711		$	239,217		$	503,597
Total shareholders’ (deficit) equity	$	(577,867	)	$	1,593,709		$	1,138,976		$	648,197		$	1,090,786

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Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the consolidated financial statements and related notes of the Company, which are included in this report in Item 8, and the information set forth in Risk Factors under Item 1A. Except as otherwise indicated, all amounts are expressed in U.S. dollars.

Overview

Ultra Petroleum Corp. is an independent exploration and production company focused on developing its long-life natural gas reserves in the Green River Basin of Wyoming—the Pinedale and Jonah fields—and is in the early exploration and development stages in the Appalachian Basin of Pennsylvania. The Company operates in one industry segment, natural gas and oil exploration and development, with one geographical segment, the United States.

The Company currently conducts operations exclusively in the United States. Substantially all of its oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect only the Company’s proportionate interest in such activities. Inflation has not had a material impact on the Company’s results of operations. The Company continues to focus on improving its drilling and production results through gaining efficiencies with the use of advanced technologies, detailed technical analysis of its properties and leveraging its experience into improved operational efficiencies. Inflation is not expected to have a material impact on the Company’s results of operations in the future.

The Company currently generates its revenue, earnings and cash flow primarily from the production and sales of natural gas and condensate from its properties in southwest Wyoming with an increasing portion of the Company’s revenues coming from gas sales from wells located in the Appalachian Basin in Pennsylvania.

Part of the Company’s business strategy includes proactive and regular review of its portfolio of investment opportunities with a focus on investments that produce positive returns. Accordingly, in response to the current low natural gas price environment during 2012, the Company reduced its net capital investments from $1.5 billion in 2011 to $615.2 million in 2012 by releasing all but two of its operated drilling rigs in Wyoming and reducing drilling activity in Pennsylvania.

The price of natural gas is a critical factor to the Company’s business and the price of natural gas has declined significantly since the beginning of 2011. During 2012, the Company limited the impact of these low prices on its results by entering into swap agreements and/or fixed price forward physical delivery contracts for natural gas. The average price realization for the Company’s natural gas during 2012 was $4.01 per Mcf, including realized gains and losses on commodity derivatives. During the quarter ended December 31, 2012, the average price realization for the Company’s natural gas was $4.08 per Mcf, including realized gains and losses on commodity derivatives. The Company’s average price realization for natural gas, excluding realized gains and losses on commodity derivatives, was $2.79 per Mcf and $3.33 per Mcf for the year and quarter ended December 31, 2012, respectively. Because of the Company’s belief that overall domestic natural gas supply will decline and natural gas forward prices will increase in response, the Company has not hedged any of its forecast 2013 natural gas production. (See Note 7).

Mission and Strategy

Ultra’s mission is to profitably grow an upstream oil and gas company for the long-term benefit of its shareholders. Ultra’s strategy includes building a robust portfolio of high return investment opportunities, maintaining a disciplined approach to capital investment, maximizing earnings and cash flows by controlling costs and maintaining financial flexibility. Consistent with this mission and strategy, the Company significantly reduced its activity during 2012 as a result of the low prevailing natural gas prices during 2012. As a result of this reduced activity, the number of wells drilled and completed by the Company was lower in 2012 than in some

39

prior years. In addition, as a result of the low gas prices, the Company was required to record a $2.9 billion non-cash, ceiling test write-down of the carrying value of its oil and gas properties, and the Company’s proved reserves were reduced to 3.08 Tcfe at December 31, 2012 from 4.98 Tcfe at December 31, 2011. For additional information about steps the Company is taking to address low natural gas prices, see the “Marketing and Pricing” section of Item 1. Business.

Because dry natural gas drilling activities were significantly reduced by most oil and gas operators during 2012, the Company expects natural gas supply to decline. As a result, the Company believes the current low natural gas prices are unsustainable, and the Company expects natural gas prices to improve over the next two years. If natural gas prices recover as the Company expects, the Company should be able to restore its proved undeveloped reserves to at least prior prevailing levels. The reduction in proved reserves reflected in the year-end 2012 report is not the result of any change in the geologic prospectivity of the Company’s properties.

As required by SEC regulations, the Company used a calculated weighted average natural gas sales price of $2.63 per Mcf and $4.04 per Mcf for estimating its proved reserves at December 31, 2012 and 2011, respectively. The lower gas price for the 2012 reserves negatively impacted the Company in two ways. First, some of its 2011 proved reserves are uneconomic at the 2012 SEC gas price. Second, some of its 2011 proved undeveloped reserves were reclassified as unproven properties in 2012 because the 2012 SEC gas price reduced capital available for the Company to drill its proved undeveloped properties.

High Return Portfolio.    Ultra seeks to maintain a portfolio of properties that provide long-term, profitable growth through development in areas that support sustainable, lower-risk, repeatable, high return drilling projects. The Company continually evaluates opportunities for the acquisition, exploration and development of additional oil and natural gas properties that afford risk-adjusted returns in excess of or equal to its current set of investment alternatives.

Disciplined Capital Investment.    Part of the Company’s business strategy includes proactive and regular review of its portfolio of investment opportunities with a focus on investments that produce positive returns in order to optimize return to its shareholders. Accordingly, in response to the current low natural gas price environment, the Company reduced capital expenditures by reducing the number of drilling rigs operating in its Wyoming fields, and the Company is encouraging the parties operating projects on its behalf in Pennsylvania to reduce their activity as well. Reductions in the Company’s activity resulted in reduced capital spending during the current year as compared to the prior year.

Low Cost Producer.    Ultra strives to maintain one of the lowest cost structures in the industry in terms of both adding and producing oil and natural gas reserves. The Company continues to focus on improving its drilling and production results through the use of advanced technologies and detailed technical analysis of its properties.

Financial Flexibility.    Preserving financial flexibility and a strong balance sheet are also strategic to Ultra’s business philosophy. Maintaining financial discipline enables the Company to capitalize on the flexibility of its portfolio.

Critical Accounting Policies

The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. GAAP. In addition, application of GAAP requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changes in these estimates related to judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated. Set forth below is a discussion of the critical accounting policies used in the preparation of our financial statements which we believe involve the most complex or subjective decisions or assessments.

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Oil and Gas Reserves.    The reserve estimates presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance according to Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”) as updated in order to align the reserve calculation and disclosure requirements with those in SEC Release No. 33-8995.

The Company utilizes reliable technology such as seismic data and interpretation, wireline formation tests, geophysical logs and core data to assess its resources. However, none of these technologies have contributed to a material addition to the proved reserves in this report. The proved reserves estimates are prepared by Netherland, Sewell & Associates, Inc., an independent, third-party engineering firm.

Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the Company’s DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves may result from a number of factors including lower prices, evaluation of additional operating history, mechanical problems on our wells and catastrophic events. Lower prices also make it uneconomical to drill wells or produce from fields with high operating costs.

The Company’s proved reserves are a function of many assumptions, all of which could deviate materially from actual results. As a result, the estimates of proved reserves could vary over time, and could vary from actual results.

Full Cost Method of Accounting.    The Company uses the full cost method of accounting for oil and gas exploration and development activities as defined by SEC Release No. 33-8995 and FASB ASC 932. Under the full cost method of accounting, all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. The sum of net capitalized costs and estimated future development costs of oil and natural gas properties for each full cost center are depleted using the units-of-production method. Changes in estimates of proved reserves, future development costs or asset retirement obligations are accounted for prospectively in our depletion calculation.

Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized in the appropriate full cost pool.

Write-down of Oil and Gas Properties.    Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in a lower DD&A rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of

41

available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected with ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 of $2.76 per MMBtu, $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.71 per barrel, $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2011 or 2010.

Asset Retirement Obligation.    The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties. FASB ASC Topic 410, Asset Retirement and Environmental Obligations (“FASB ASC 410”) requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements; the credit-adjusted, risk-free rate to be used; inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through DD&A.

Entitlements Method of Accounting for Oil and Natural Gas Sales.    The Company generally sells natural gas and condensate under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue.

Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances.

Valuation of Deferred Tax Assets.    The Company uses the asset and liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial statement carrying values and their respective income tax basis (temporary differences).

To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences

42

become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

As a result of the tax effect of the ceiling test and other impairments recorded during the year ended December 31, 2012, the Company’s previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $449.8 million as of December 31, 2012. This valuation allowance may be reversed in future periods against future taxable income.

Derivative Instruments and Hedging Activities.    The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives.

Fair Value Measurements.    The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”). Under FASB ASC 820, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). At December 31, 2012, the Company did not have any open commodity derivative contracts. See Note 8 for additional information.

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These facilities are included in Property, Plant and Equipment in the Consolidated Balance Sheets and were impaired to a fair value of $82.6 million based on the income approach, estimated using Level 3 fair value inputs.

Legal, Environmental and Other Contingencies.    A provision for legal, environmental and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes the subjective judgment of management. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company’s management closely monitors known and potential legal, environmental and other contingencies and periodically determines when the Company should record losses for these items based on information available to the Company.

Share-Based Payment Arrangements.    The Company follows FASB ASC Topic 718, Compensation – Stock Compensation (“FASB ASC 718”) which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized under FASB ASC 718 for the years ended December 31, 2012, 2011 and 2010 was $10.8 million, $13.9 million and $12.9 million, respectively. See Note 6 for additional information.

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Conversion of Barrels of Oil to Mcfe of Gas.    The Company converts Bbls of oil and other liquid hydrocarbons to Mcfe at a ratio of one Bbl of oil or liquids to six Mcfe. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or other liquids to an Mcf of natural gas. The sales price of one Bbl of oil or liquids has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to a Bbl of oil or other liquids.

Recent Accounting Pronouncements.    In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC 820. The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company’s consolidated financial statements.

Results of Operations — Year Ended December 31, 2012 vs. Year Ended December 31, 2011

During the year ended December 31, 2012, production increased on a gas equivalent basis to 257.0 Bcfe from 245.3 Bcfe for the same period in 2011 as a result of wells put on production in 2012. Realized natural gas prices, including realized gain and loss on commodity derivatives, decreased to $4.01 per Mcf during the year ended December 31, 2012 as compared to $5.05 per Mcf during 2011. During the year ended December 31, 2012, the Company’s average price for natural gas was $2.79 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.15 per Mcf for the same period in 2011. The decrease in average natural gas prices largely contributed to a 26% decrease in revenues for the year ended December 31, 2012 to $810.0 million as compared to $1.1 billion in 2011.

Lease operating expenses (“LOE”) increased to $64.5 million for the year ended December 31, 2012 compared to $51.8 million during the same period in 2011 primarily due to increased well counts resulting from the Company’s drilling program. On a unit of production basis, LOE costs increased to $0.25 per Mcfe at December 31, 2012 compared to $0.21 per Mcfe at December 31, 2011 as a result of higher lease operating expense on non-operated wells in Pennsylvania.

During the year ended December 31, 2012, production taxes were $60.8 million compared to $97.1 million during the same period in 2011, or $0.24 per Mcfe, compared to $0.40 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 7.5% of revenues for the year ended 2012 and 8.8% for the same period in 2011. In addition, the year ended December 31, 2012 includes charges related to Pennsylvania impact fees totaling $5.6 million while the period ended December 31, 2011 did not include any charges related to impact fees in Pennsylvania. The decrease in per unit taxes is primarily attributable to decreased sales revenues as a result of decreased natural gas prices, excluding the effects of commodity derivatives, during the year December 31, 2012 as compared to the same period in 2011.

Gathering fees increased to $59.0 million for the year ended December 31, 2012 compared to $56.5 million during the same period in 2011 largely due to increased production volumes. On a per unit basis, gathering fees remained flat at $0.23 per Mcfe for the year ended December 31, 2012 and 2011.

The Company incurred firm transportation charges totaling $84.5 million for the period ended December 31, 2012 as compared to $64.2 million for the same period in 2011 in association with REX pipeline charges. On a per unit basis, transportation charges increased to $0.33 per Mcfe (on total company volumes) for the period ended December 31, 2012 as compared to $0.26 for the same period in 2011 primarily due to demand charges associated with the additional capacity of 50 MMMBtu per day secured on the REX pipeline system beginning in January 2012.

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DD&A expenses increased to $389.0 million during the period ended December 31, 2012 from $346.4 million for the same period in 2011, attributable primarily to increased production volumes and a higher depletion rate. On a unit of production basis, DD&A increased to $1.51 per Mcfe at December 31, 2012 from $1.41 at December 31, 2011 primarily as a result of increased costs in Pennsylvania.

The Company recorded a $2.9 billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the period ended December 31, 2012 as a result of ceiling test limitations, which is reflected as ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 of $2.76 per MMBtu, $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.71 per barrel, $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The write-down reduced earnings in the period and will result in a lower DD&A rate in future periods. The Company did not have any write-downs related to the full cost ceiling limitation during the prior year period ended December 31, 2011. See Note 1(e). In addition, the Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets. (See Note 8 for additional information on fair value).

General and administrative expenses decreased slightly to $25.1 million for the period ended December 31, 2012 compared to $26.0 million for the same period in 2011. On a per unit basis, general and administrative expenses decreased to $0.10 per Mcfe for the year ended December 31, 2012 compared with $0.11 per Mcfe in 2011 as a result of increased production volumes during 2012.

Interest expense increased to $88.2 million during the period ended December 31, 2012 compared to $63.2 million during the same period in 2011 primarily as a result of higher average borrowings outstanding during the year ended December 31, 2012 and lower amounts of capitalized interest related to unevaluated oil and gas properties that are excluded from amortization. For the years ended December 31, 2012 and 2011, the Company capitalized $15.0 million and $30.7 million, respectively, in interest associated with unevaluated oil and gas properties that are excluded from amortization and actively being evaluated as well as work in process relating to gathering systems that are not currently in service. At December 31, 2012, all costs related to unevaluated properties that were previously excluded from capitalized costs being amortized have been impaired and transferred to the capitalized costs being amortized in the full cost pool.

During the year ended December 31, 2012, the Company recognized contract cancellation expenses of $15.5 million. In response to low natural gas prices, the Company reduced its drilling rig count to two operated rigs, down from six at December 31, 2011.

During the year ended December 31, 2012, the Company recognized $304.0 million related to realized gain on commodity derivatives as compared to $213.3 million during the year ended December 31, 2011. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts.

At December 31, 2012, the Company recognized $230.4 million related to unrealized loss on commodity derivatives as compared to $100.4 million related to unrealized gain on commodity derivatives at December 31, 2011. The unrealized gain or loss on commodity derivatives represents the non-cash change in the fair value of these derivative instruments.

The Company recognized a loss before income taxes of $2.9 billion for the year ended December 31, 2012 compared with income before income taxes of $710.9 million for the same period in 2011. The decrease in earnings is primarily related to the non-cash ceiling test and other impairments and decreased natural gas prices partially offset by increased production during 2012.

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As a result of the tax effect of the non-cash ceiling test and other impairments, the Company’s previously recorded net deferred tax liability fully reversed into a net deferred tax asset during the quarter ended June 30, 2012. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $449.8 million as of December 31, 2012. This valuation allowance may be reversed in future periods against future taxable income. The income tax benefit recognized for the year ended December 31, 2012 was $700.2 million compared with an income tax provision of $257.7 million for the year ended December 31, 2011.

For the year ended December 31, 2012, the Company recognized net loss of $2.2 billion or ($14.24) per diluted share as compared with net income of $453.2 million or $2.94 per diluted share for the same period in 2011. The decrease in earnings is primarily related to the non-cash ceiling test and other impairments and decreased natural gas prices partially offset by increased production during 2012.

Results of Operations — Year Ended December 31, 2011 vs. Year Ended December 31, 2010

During the year ended December 31, 2011, production increased on a gas equivalent basis to 245.3 Bcfe from 213.6 Bcfe for the same period in 2010 attributable to the Company’s successful drilling activities during 2011. Realized natural gas prices, including realized gain and loss on commodity derivatives, increased to $5.05 per Mcf during the year ended December 31, 2011 as compared to $4.88 per Mcf during 2010. During the year ended December 31, 2011, the Company’s average price for natural gas was $4.15 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.31 per Mcf for the same period in 2010. The increase in production largely contributed to a 12% increase in revenues for the year ended December 31, 2011 to $1.1 billion as compared to $979.4 million in 2010.

Lease operating expenses (“LOE”) increased to $51.8 million for the year ended December 31, 2011 compared to $45.9 million during the same period in 2010 due primarily to increased well counts resulting from the Company’s drilling program. On a unit of production basis, LOE costs decreased to $0.21 per Mcfe at December 31, 2011 compared to $0.22 per Mcfe at December 31, 2010 as a result of increased production volumes.

During the year ended December 31, 2011, production taxes were $97.1 million compared to $95.9 million during the same period in 2010, or $0.40 per Mcfe, compared to $0.45 per Mcfe. Production taxes are calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 8.8% of revenues for the year ended 2011 and 9.8% for the same period in 2010. The decrease in per unit taxes is primarily attributable to increased production in Pennsylvania, which is not subject to production taxes, as well as the decrease in average natural gas prices, excluding the effects of commodity derivatives, during the year ended December 31, 2011 as compared to the same period in 2010.

Gathering fees increased to $56.5 million for the year ended December 31, 2011 compared to $50.1 million during the same period in 2010 largely due to increased production volumes. On a per unit basis, gathering fees remained flat at $0.23 per Mcfe for the years ended December 31, 2011 and 2010.

To secure pipeline infrastructure providing sufficient capacity to transport a portion of the Company’s natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas, the Company incurred firm transportation charges totaling $64.2 million for the period ended December 31, 2011 as compared to $65.0 million for the same period in 2010 in association with REX Pipeline transportation charges. On a per unit basis, transportation charges decreased to $0.26 per Mcfe (on total company volumes) for the period ended December 31, 2011 as compared to $0.30 for the same period in 2010 due to the increase in total company production volumes during the period ended December 31, 2011.

DD&A increased to $346.4 million during the period ended December 31, 2011 from $241.8 million for the same period in 2010, attributable to increased production volumes and a higher depletion rate. On a unit of production basis, DD&A increased to $1.41 per Mcfe at December 31, 2011 from $1.13 at December 31, 2010 largely as a result of increased well costs in Pennsylvania.

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General and administrative expenses increased to $26.0 million for the period ended December 31, 2011 compared to $24.4 million for the same period in 2010. The increase in general and administrative expenses is primarily attributable to increased headcount and related compensation. On a per unit basis, general and administrative expenses remained flat at $0.11 per Mcfe for the years ended December 31, 2011 and 2010.

Interest expense increased to $63.2 million during the period ended December 31, 2011 compared to $49.0 million during the same period in 2010 as a result of increased borrowings outstanding during the period ended December 31, 2011. For the years ended December 31, 2011 and 2010, the Company capitalized $30.7 million and $21.2 million, respectively, in interest associated with unevaluated oil and gas properties that are excluded from amortization and actively being evaluated as well as work in process relating to gathering systems that are not currently in service. At December 31, 2011, the Company had $1.9 billion in borrowings outstanding.

During the year ended December 31, 2010, the Company recognized litigation expenses of $9.9 million related to the resolution of litigation matters.

During the year ended December 31, 2011, the Company recognized $213.3 million related to realized gain on commodity derivatives as compared to $116.8 million during the year ended December 31, 2010. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts.

At December 31, 2011, the Company recognized $100.4 million related to unrealized gain on commodity derivatives as compared to $208.6 million related to unrealized gain on commodity derivatives at December 31, 2010. The unrealized gain or loss on commodity derivatives represents the non-cash change in the fair value of these derivative instruments.

The Company recognized income before income taxes of $710.9 million for the year ended December 31, 2011 compared with $723.1 million for the same period in 2010. The decrease in earnings is primarily a result of increased DD&A expense during 2011 and partially offset by increased revenues during 2011.

The income tax provision recognized for the year ended December 31, 2011 was $257.7 million compared with an income tax provision of $258.6 million for the year ended December 31, 2010.

For the year ended December 31, 2011, the Company recognized net income of $453.2 million or $2.94 per diluted share as compared with net income of $464.5 million or $3.01 per diluted share for the same period in 2010. The decrease is primarily attributable to increased DD&A expense during 2011 and partially offset by increased revenues during 2011.

The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. GAAP. In addition, application of generally accepted accounting principles requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changes in these estimates, judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated.

LIQUIDITY AND CAPITAL RESOURCES

During the year ended December 31, 2012, the Company relied on cash provided by operations along with borrowings under the Credit Agreement (defined below) to finance its capital expenditures. The Company participated in 178 wells that were drilled to total depth and cased during 2012. For the year ended December 31, 2012, total capital expenditures were $839.4 million ($708.0 million related to oil and gas exploration and development expenditures, $127.1 million related to gathering system expenditures and $4.3 million related to other property costs). During December 2012, the Company entered into a Purchase and Sale Agreement (the

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“PSA”) to sell its system of pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The net cash proceeds received for the assets were $203.0 million and additional consideration of $23.0 million in the form of marketable securities which were sold during December 2012 for net cash proceeds of $21.2 million. The proceeds from the sale of the Company’s LGS were used to repay amounts outstanding under the Company’s Credit Agreement (defined below).

At December 31, 2012, the Company reported a cash position of $12.9 million compared to $11.3 million at December 31, 2011. Working capital deficit at December 31, 2012 was $388.2 million compared to a deficit of $251.1 million at December 31, 2011. At December 31, 2012, the Company had $277.0 million in outstanding borrowings and $723.0 million of available borrowing capacity under the Credit Agreement (defined below). In addition, the Company had $1.6 billion outstanding in senior notes (See Note 5). Other long-term obligations of $76.0 million at December 31, 2012 is comprised of items payable in more than one year, primarily related to production taxes and asset retirement obligations.

The Company’s positive cash provided by operating activities, along with availability under the senior credit facility, are projected to be sufficient to fund the Company’s budgeted capital investment program for 2013, which is currently projected to be approximately $415.0 million. Of the $415.0 million budget, the Company plans to allocate approximately 90% to exploration and development related expenditures and the remainder to gathering and infrastructure and other.

Bank indebtedness.    The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the borrower and with the lenders’ consent, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016 (which term may be extended for up to two successive one-year periods at the Borrower’s request and with the lenders’ consent). At December 31, 2012, the Company had $277.0 million in outstanding borrowings and $723.0 million of available borrowing capacity under the Credit Agreement.

Loans under the Credit Agreement are unsecured and bear interest, at the Borrower’s option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 100 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrower’s consolidated leverage ratio (200 basis points per annum as of December 31, 2012). The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio.

The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive covenants requiring the Borrower to maintain a consolidated leverage ratio of no greater than three and one half times to one and, as long as the Company’s debt rating is below investment grade, the maintenance of an annual ratio of the

net present value of the Company’s oil and gas properties to total funded debt of no less than one and one half times to one. At December 31, 2012, the Company was in compliance with all of its debt covenants under the Credit Agreement. (See Note 5).

Senior Notes:    The Company’s Senior Notes rank pari passu with the Company’s Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At December 31, 2012, the Company was in compliance with all of its debt covenants under the Senior Notes. (See Note 5).

Operating Activities.    During the year ended December 31, 2012, net cash provided by operating activities was $654.8 million, a 37% decrease from $1.0 billion for the same period in 2011. The decrease in net cash

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provided by operating activities was largely attributable to decreased revenues resulting from decreased natural gas prices during the year ended December 31, 2012 as compared to the same period in 2011.

Investing Activities.    During the year ended December 31, 2012, net cash used in investing activities was $577.2 million as compared to $1.4 billion for the same period in 2011. The decrease in net cash used in investing activities is largely related to decreased capital investments associated with the Company’s drilling activities in 2012 as compared to 2011 and proceeds from the sale of the LGS during December 2012.

Financing Activities.    During the year ended December 31, 2012, net cash used in financing activities was $76.0 million as compared to net cash provided by financing activities of $316.0 million for the same period in 2011. The change in cash used in net financing activities is primarily due to decreased borrowings during 2012 as compared to 2011.

Outlook

We believe we are well positioned for the current economic environment because of our status as a low cost operator in the industry combined with our financial flexibility. In 2012, the Company established new production records while maintaining a low cost structure. The Company’s low cost structure contributes to the Company’s long-term favorable returns and growth profile.

Although our net cash provided by operating activities was negatively affected by continued low natural gas prices, and although we have not hedged any of our 2013 production because we expect natural gas prices to improve over the next two years, we believe that we will continue to generate positive cash flow from operations, which, along with our available cash, will provide sufficient liquidity to fund our capital investments and operations over the next twelve months. We continue to monitor and evaluate the impact of reduced commodity prices in order to determine the appropriate size and nature of our capital investment program.

We expect to rely on our available cash, our existing credit facility and the cash generated from operations to meet our obligations. While we continue to monitor the overall health of the credit markets, a renewed, long-term disruption in the credit markets could make financing more expensive or unavailable, which could have a material adverse effect on our operations.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of December 31, 2012.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2012:

	Payments Due by period:
	Total		Less than 1 year		1 to 3 years		3 to 5 years		More than 5 years
	(Amounts in thousands of U.S. dollars)
Long-term debt (See Note 5)	$	1,837,000	$	—	$	100,000	$	455,000	$	1,282,000
Interest payments		644,319		93,918		183,267		154,745		212,389
Transportation contract (REX)(1)		673,027		103,295		201,845		202,122		165,765
Operating lease		299,397		20,000		40,000		40,000		199,397
Drilling contracts		21,487		14,973		6,514		—		—
Office space lease		1,540		876		664		—		—
Total contractual obligations	$	3,476,770	$	233,062	$	532,290	$	851,867	$	1,859,551

(1) The Company’s average net interest in payments related to REX transportation charges is approximately 80%.

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Transportation contract.    The Company is an anchor shipper on REX securing pipeline infrastructure providing sufficient capacity to transport a portion of its natural gas production away from its properties and to provide for reasonable basis differentials for its natural gas in the future. REX begins at the Opal Processing Plant in southwest Wyoming and traverses Wyoming and several other states to an ultimate terminus in eastern Ohio. The Company’s commitment involves a capacity of 200 MMMBtu per day of natural gas for a term of 10 years commencing in November 2009. During the first quarter of 2009, the Company entered into agreements to secure an additional capacity of 50 MMMBtu per day on the REX pipeline system, beginning in January 2012 through December 2018. The Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper. The Company has the right, but not the obligation, to deliver its natural gas production into the REX pipeline, but must pay its reservation charges in either event. The Company continuously assesses its best available market options when determining the appropriate level of utilization of its REX capacity.

Operating lease.    During December 2012, the Company entered into a Purchase and Sale Agreement (the “LGS PSA”) to sell its system of pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The net cash proceeds received for the assets were $203.0 million and additional consideration of $23.0 million in the form of marketable securities which were sold during December 2012 for net cash proceeds of $21.2 million.

Pursuant to the LGS PSA, the Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the LGS at the sole discretion of the Company. Annual rent for the initial term under the Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The Company’s sale leaseback transaction was treated as a “normal leaseback” under the provisions of FASB ASC Topic 840, Leases and qualified for sales recognition. The lease is classified as an operating lease.

All of the Company’s lease obligations are related to leases that are classified as operating leases. These leases contain certain provisions that could result in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in its lease classification analysis and has determined that the default provisions do not impact classification of any the Company’s operating leases.

Drilling contracts.    As of December 31, 2012, the Company had committed to drilling obligations that will continue into 2014. The drilling rigs were contracted to fulfill the 2013-2014 drilling program initiatives in Wyoming.

Office space lease.    The Company maintains office space in Colorado, Texas, Wyoming and Pennsylvania with total remaining commitments for office leases of $1.5 million at December 31, 2012 ($0.9 million in 2013 and $0.7 million in 2014 to 2015).

50

Item 7A. — Quantitative and Qualitative Disclosures About Market Risk

Objectives and Strategy:    The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue.

Historically, the Company has entered into various types of derivative transactions to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s capital investment program. A significant portion of our revenues during 2010, 2011 and 2012 was attributable to these derivative transactions. Because forward natural gas prices for 2013 production were very low during 2012, the Company has not hedged any of its forecast 2013 natural gas production. As a result of the Company not having hedged any of its 2013 production, its earnings and cash flow may be more volatile during 2013 than in prior years.

The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise.

Fair Value of Commodity Derivatives:    FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the balance sheet and the associated unrealized gains and losses are recorded as current expense or income in the income statement. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement.

The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010:

	For the Year Ended December 31,
Natural Gas Commodity Derivatives:	2012			2011		2010
Realized gain on commodity derivatives(1)	$	303,966		$	213,349	$	116,827
Unrealized (loss) gain on commodity derivatives(1)		(230,385	)		100,383		208,625
Total gain on commodity derivatives	$	73,581		$	313,732	$	325,452

(1) Included in gain on commodity derivatives in the Consolidated Statements of Operations.

51

Item 8. Financial Statements and Supplementary Data.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for the preparation and integrity of all information contained in this Annual Report. The accompanying financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. The financial statements include amounts that are management’s best estimates and judgments.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2012.

The effectiveness of our internal control over financial reporting has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

52

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Ultra Petroleum Corp.

We have audited the accompanying consolidated balance sheets of Ultra Petroleum Corp. as of December 31, 2012 and 2011, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Ultra Petroleum Corp. at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Ultra Petroleum Corp.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2013 expressed an unqualified opinion thereon.

/s/    Ernst & Young LLP

Houston, Texas

February 20, 2013

53

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Ultra Petroleum Corp.

We have audited Ultra Petroleum Corp.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Ultra Petroleum Corp.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the 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.

In our opinion, Ultra Petroleum Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Ultra Petroleum Corp. as of December 31, 2012 and 2011, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012 of Ultra Petroleum Corp. and our report dated February 20, 2013 expressed an unqualified opinion thereon.

/s/    Ernst & Young LLP

Houston, Texas

February 20, 2013

54

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2012			2011			2010
	(Amounts in thousands of U.S. dollars, except per share data)
Revenues:
Natural gas sales	$	695,733		$	982,413		$	886,396
Oil sales		114,241			119,383			92,990
Total operating revenues		809,974			1,101,796			979,386
Expenses:
Lease operating expenses		64,468			51,758			45,938
Production taxes		60,757			97,094			95,914
Gathering fees		59,004			56,511			50,126
Transportation charges		84,470			64,243			64,965
Depletion, depreciation and amortization		388,985			346,394			241,796
Ceiling test and other impairments		2,972,464			—			—
General and administrative		25,104			26,032			24,351
Total operating expenses		3,655,252			642,032			523,090
Operating (loss) income		(2,845,278	)		459,764			456,296
Other income (expense), net:
Interest expense		(88,180	)		(63,156	)		(49,032	)
Gain on commodity derivatives		73,581			313,732			325,452
Contract cancellation fees		(15,469	)		—			—
Litigation expense		—			—			(9,902	)
Other (expense) income, net		(1,765	)		532			260
Total other (expense) income, net		(31,833	)		251,108			266,778
(Loss) income before income tax (benefit) provision		(2,877,111	)		710,872			723,074
Income tax (benefit) provision		(700,213	)		257,670			258,615
Net (loss) income	$	(2,176,898	)	$	453,202		$	464,459
Basic (Loss) Earnings per Share:
Net (loss) income per common share — basic	$	(14.24	)	$	2.97		$	3.05
Fully Diluted (Loss) Earnings per Share:
Net (loss) income per common share — fully diluted	$	(14.24	)	$	2.94		$	3.01
Weighted average common shares outstanding — basic		152,845			152,754			152,346
Weighted average common shares outstanding — fully diluted		152,845			154,336			154,253

Approved on behalf of the Board:
/s/ Michael D. Watford	/s/ Michael J. Keeffe
Chairman of the Board, Chief Executive Officer and President	Director

See accompanying notes to consolidated financial statements.

55

ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS

	December 31, 2012			December 31, 2011
	(Amounts in thousands of U. S. dollars, except share data)
ASSETS
Current Assets:
Cash and cash equivalents	$	12,921		$	11,307
Restricted cash		121			121
Oil and gas revenue receivable		81,143			88,243
Joint interest billing and other receivables		26,712			82,370
Derivative assets		—			230,385
Prepaid drilling costs and other current assets		4,951			7,494
Total current assets		125,848			419,920
Oil and gas properties, net, using the full cost method of accounting:
Proven		1,657,500			3,651,622
Unproven properties not being amortized		—			537,526
Property, plant and equipment		212,372			246,586
Deferred financing costs and other		11,625			14,051
Total assets	$	2,007,345		$	4,869,705
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	67,489		$	105,453
Accrued liabilities		121,124			190,420
Production taxes payable		47,745			62,117
Interest payable		30,093			30,306
Deferred tax liabilities		—			73,380
Capital cost accrual		247,641			209,303
Total current liabilities		514,092			670,979
Long-term debt		1,837,000			1,903,000
Deferred income tax liabilities		—			635,009
Deferred gain on sale of liquids gathering system		158,082			—
Other long-term obligations		76,038			67,008
Commitments and contingencies (Note 11)
Shareholders’ equity:
Common stock — no par value; authorized — unlimited; issued and outstanding — 152,929,907 and 152,476,564, at December 31, 2012 and 2011, respectively		474,016			463,221
Treasury stock		(13	)		(14,951	)
Retained (loss) earnings		(1,051,870	)		1,145,439
Total shareholders’ (deficit) equity		(577,867	)		1,593,709
Total liabilities and shareholders’ equity	$	2,007,345		$	4,869,705

See accompanying notes to consolidated financial statements.

56

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(Amounts in thousands of U.S. dollars, except share data)

	Shares Issued and Outstanding			Common Stock			Retained Earnings			Treasury Stock			Total Shareholders’ Equity
Balances at December 31, 2009		151,759		$	377,339		$	281,383		$	(10,525	)	$	648,197
Stock options exercised		1,206			6,561			—			—			6,561
Employee stock plan grants		105			4,841			—			—			4,841
Shares re-issued from treasury		—			(587	)		(9,938	)		10,525			—
Net share settlements		(502	)		—			(23,707	)		—			(23,707	)
Fair value of employee stock plan grants		—			21,103			—			—			21,103
Excess tax benefit on stock based compensation		—			17,522			—			—			17,522
Net income					—			464,459			—			464,459
Balances at December 31, 2010		152,568		$	426,779		$	712,197		$	—		$	1,138,976
Stock options exercised		672			9,928			—			—			9,928
Employee stock plan grants		150			—			—			700			700
Shares repurchased		(588	)		—			—			(20,868	)		(20,868	)
Shares re-issued from treasury		—			(686	)		(4,531	)		5,217			—
Net share settlements		(325	)		—			(15,429	)		—			(15,429	)
Fair value of employee stock plan grants		—			20,988			—			—			20,988
Excess tax benefit on stock based compensation		—			6,212			—			—			6,212
Net income		—			—			453,202			—			453,202
Balances at December 31, 2011		152,477		$	463,221		$	1,145,439		$	(14,951	)	$	1,593,709
Stock options exercised		34			632			—			—			632
Employee stock plan grants		708			613			—			—			613
Shares repurchased		(50	)		—			—			(1,100	)		(1,100	)
Shares re-issued from treasury		—			(1,245	)		(14,793	)		16,038			—
Net share settlements		(239	)		—			(5,618	)		—			(5,618	)
Fair value of employee stock plan grants		—			15,222			—			—			15,222
(Reduction in) tax benefit on stock based compensation		—			(4,427	)		—			—			(4,427	)
Net (loss)		—			—			(2,176,898	)		—			(2,176,898	)
Balances at December 31, 2012		152,930		$	474,016		$	(1,051,870	)	$	(13	)	$	(577,867	)

See accompanying notes to consolidated financial statements.

57

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2012			2011			2010
Cash provided by (used in):	(Amounts in thousands of U.S. dollars)
Operating activities:
Net (loss) income for the period	$	(2,176,898	)	$	453,202		$	464,459
Adjustments to reconcile net (loss) income to cash provided by operating activities:
Depletion, depreciation and amortization		388,985			346,394			241,796
Ceiling test and other impairments		2,972,464			—			—
Deferred and current non-cash income taxes		(712,576	)		251,206			253,926
Unrealized loss (gain) on commodity derivatives		230,385			(100,383	)		(208,625	)
Reduction in/(excess) tax benefit from stock based compensation		4,427			(6,212	)		(17,522	)
Stock compensation		10,756			13,919			12,944
Other		3,667			1,495			734
Net changes in operating assets and liabilities:
Restricted cash		—			(23	)		1,583
Accounts receivable		62,758			(26,910	)		(31,966	)
Prepaid expenses and other		2,066			(1,274	)		(229	)
Other non-current assets		284			—			(1,176	)
Accounts payable and accrued liabilities		(115,597	)		86,079			91,982
Production taxes payable		(14,372	)		8,735			(7,439	)
Interest payable		(213	)		3,428			14,867
Other long-term obligations		(9,031	)		433			6,035
Current taxes payable		7,720			3,203			3,359
Net cash provided by operating activities		654,825			1,033,292			824,728
Investing Activities:
Acquisition of oil and gas properties		—			—			(403,806	)
Oil and gas property expenditures		(708,017	)		(1,435,611	)		(1,164,389	)
Gathering system expenditures		(127,149	)		(83,996	)		(76,703	)
Proceeds from sale of oil and gas properties		—			5,821			68,420
Proceeds from sale of liquids gathering system (See Note 4)		203,046			—			—
Proceeds from sale of marketable securities (See Note 4)		21,235			—			—
Change in capital cost accrual		38,338			125,261			19,826
Restricted cash		—			—			28,257
Inventory		(374	)		1,595			1,738
Purchase of property, plant and equipment		(4,302	)		(21,865	)		(2,442	)
Net cash used in investing activities		(577,223	)		(1,408,795	)		(1,529,099	)
Financing activities:
Borrowings on long-term debt		852,000			1,257,000			1,000,000
Payments on long-term debt		(918,000	)		(914,000	)		(1,260,000	)
Proceeds from issuance of Senior Notes		—			—			1,025,000
Deferred financing costs		—			(6,866	)		(4,425	)
Repurchased shares/net share settlements		(6,718	)		(36,298	)		(23,707	)
(Reduction in)/excess tax benefit from stock based compensation		(4,427	)		6,212			17,522
Proceeds from exercise of options		1,157			9,928			6,561
Net cash (used in) provided by financing activities		(75,988	)		315,976			760,951
Increase (decrease) in cash during the period		1,614			(59,527	)		56,580
Cash and cash equivalents, beginning of period		11,307			70,834			14,254
Cash and cash equivalents, end of period	$	12,921		$	11,307		$	70,834
SUPPLEMENTAL INFORMATION:
Cash paid for:
Interest	$	101,237		$	88,964		$	53,291
Income taxes	$	4,379		$	7,260		$	2,537

See accompanying notes to consolidated financial statements.

58

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts in this Report on Form 10-K are expressed in thousands of U.S. dollars (except per share data), unless otherwise noted).

Ultra Petroleum Corp. (the “Company”) is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil and natural gas properties. The Company is incorporated under the laws of the Yukon Territory, Canada. The Company’s principal business activities are in the Green River Basin of southwest Wyoming and the north-central Pennsylvania area of the Appalachian Basin.

1.    SIGNIFICANT ACCOUNTING POLICIES:

(a) Basis of presentation and principles of consolidation:    The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation.

(b) Cash and cash equivalents:    The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(c) Restricted cash:    Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. Wyoming law requires that these funds be held in a federally insured bank in Wyoming.

(d) Property, plant and equipment:    Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life. Gathering system expenditures are recorded at cost and depreciated using the straight-line method based on a 30-year useful life. The gathering system assets which are downstream of the Company’s well pads are depreciated separately from proven oil and gas properties because they are expected to be used to transport oil and gas not currently included in the Company’s proved reserves, including production expected from probable and possible reserves, as well as from third parties.

The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets.

(e) Oil and natural gas properties:    The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Separate cost centers are maintained for each country in which the Company incurs costs. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

59

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the proved reserves as determined by independent petroleum engineers. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement obligations are included in the base costs for calculating depletion.

Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 of $2.76 per MMBtu, $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.71 per barrel, $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2011 or 2010.

(f) Inventories:    Materials and supplies inventories are carried at lower of cost or market. Inventory costs include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. The Company uses the weighted average method of recording its inventory. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. At December 31, 2012, inventory of $1.5 million primarily includes the cost of pipe and production equipment that will be utilized during the 2013 drilling program.

(g) Derivative instruments and hedging activities:    The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7).

60

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(h) Income taxes:    Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

As a result of the tax effect of the ceiling test and other impairments recorded during the year ended December 31, 2012, the Company’s previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $449.8 million as of December 31, 2012. This valuation allowance may be reversed in future periods against future taxable income.

(i) Earnings per share:    Basic (loss) earnings per share is computed by dividing net (loss) earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted (loss) earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.

The following table provides a reconciliation of components of basic and diluted net (loss) income per common share:

	December 31,
	2012			2011		2010
Net (loss) income	$	(2,176,898	)	$	453,202	$	464,459
Weighted average common shares outstanding during the period		152,845			152,754		152,346
Effect of dilutive instruments		—	(1)		1,582		1,907
Weighted average common shares outstanding during the period including the effects of dilutive instruments		152,845			154,336		154,253
Net (loss) income per common share — basic	$	(14.24	)	$	2.97	$	3.05
Net (loss) income per common share — fully diluted	$	(14.24	)	$	2.94	$	3.01
Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares		—	(1)		1,030		1,214

(1) Due to the net loss for the year ended December 31, 2012, 1.9 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of loss per share.

(j) Use of estimates:    Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities,

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the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(k) Accounting for share-based compensation:    The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.

(l) Fair value accounting:    The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information.

(m) Asset retirement obligation:    The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

(n) Revenue recognition:    The Company generally sells natural gas and condensate under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2012 and 2011, the Company had a net natural gas imbalance liability of $2.1 million and $1.3 million, respectively.

Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances.

(o) Capitalized interest:    Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any, as well as on work in process relating to gathering systems that are not currently in service.

(p) Capital cost accrual:    The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.

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(q) Reclassifications:    Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.

(r) Recent accounting pronouncements:    In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC 820. The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company’s consolidated financial statements.

2.    ASSET RETIREMENT OBLIGATIONS:

The Company is required to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The following table summarizes the activities for the Company’s asset retirement obligations for the years ended:

	December 31,
	2012			2011
Asset retirement obligations at beginning of period	$	42,052		$	28,052
Accretion expense		4,922			3,088
Liabilities incurred		13,638			10,878
Liabilities settled		(1,182	)		(3	)
Revisions of estimated liabilities		1,384			37
Asset retirement obligations at end of period		60,814			42,052
Less: current asset retirement obligations		(702	)		—
Long-term asset retirement obligations	$	60,112		$	42,052

3.    OIL AND GAS PROPERTIES:

	December 31,			December 31,
	2012			2011
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	7,235,765		$	5,974,604
Less: Accumulated depletion, depreciation and amortization(1)		(5,578,265	)		(2,322,982	)
		1,657,500			3,651,622
Unproven Properties:
Acquisition and exploration costs not being amortized(2)		—			537,526
Net capitalized costs — oil and gas properties	$	1,657,500		$	4,189,148

On a unit basis, DD&A from continuing operations was $1.51, $1.41 and $1.13 per Mcfe for the years ended December 31, 2012, 2011 and 2010, respectively.

(1) During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within

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ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 of $2.76 per MMBtu, $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.71 per barrel, $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2011.

(2) Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as on work in process relating to gathering systems that are not currently in service. For the years ended December 31, 2012 and 2011, total interest on outstanding debt was $103.2 million and $93.9 million, respectively, of which $15.0 million and $30.7 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and work in process relating to gathering systems that are not currently in service.

At December 31, 2012, all costs related to unevaluated properties that were previously excluded from capitalized costs being amortized have been impaired and transferred to the capitalized costs being amortized in the full cost pool.

	Total		2012			2011		2010		Prior
Acquisition costs	$	—	$	(481,689	)	$	24,583	$	411,326	$	45,780
Exploration costs		—		(9,962	)		198		—		9,764
Capitalized interest		—		(45,875	)		26,498		19,377		—
Unproven properties	$	—	$	(537,526	)	$	51,279	$	430,703	$	55,544

4.    PROPERTY, PLANT AND EQUIPMENT:

	December 31,
	2012							2011
	Cost		Accumulated Depreciation			Net Book Value		Net Book Value
Gathering systems(1),(2)	$	282,879	$	(99,312	)	$	183,567	$	219,011
Computer equipment		2,510		(1,510	)		1,000		1,025
Office equipment		454		(374	)		80		109
Leasehold improvements		450		(251	)		199		307
Land		22,359		—			22,359		22,150
Other		11,358		(6,191	)		5,167		3,984
Property, Plant and Equipment, Net	$	320,010	$	(107,638	)	$	212,372	$	246,586

(1) The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices.

(2) During December 2012, the Company sold its system of pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The net cash proceeds received for the assets were $203.0 million and additional consideration of $23.0 million in the form of marketable securities which were sold during December 2012 for net cash proceeds of

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$21.2 million. The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the LGS at the sole discretion of the Company. Annual rent for the initial term under the Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The Company’s sale leaseback transaction was treated as a “normal leaseback” under the provisions of FASB ASC Topic 840, Leases (“FASB ASC Topic 840”) and qualified for sales recognition. The lease is classified as an operating lease.

In Pennsylvania, the Company and its partners continue constructing gas gathering pipelines and facilities, compression facilities and pipeline delivery stations to gather production from its newly completed natural gas wells. These facilities are gathering systems and related infrastructure, and their construction is expected to continue until the Company’s properties in Pennsylvania are fully developed. To date, none of the Company’s natural gas production in Pennsylvania has required processing, treating or blending in order to remove natural gas liquids or other impurities and it is anticipated that facilities of this type will not be required in the future to accommodate the Company’s production.

5.    LONG-TERM LIABILITIES:

	December 31, 2012		December 31, 2011
Bank indebtedness	$	277,000	$	343,000
Senior notes		1,560,000		1,560,000
Other long-term obligations		76,038		67,008
	$	1,913,038	$	1,970,008

Aggregate maturities of debt at December 31, 2012:
2013	2014		2015		2016		2017		Beyond 5 years		Total
$—	$	—	$	100,000	$	339,000	$	116,000	$	1,282,000	$	1,837,000

Bank indebtedness.    The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the borrower and with the lenders’ consent, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016 (which term may be extended for up to two successive one-year periods at the Borrower’s request and with the lenders’ consent). At December 31, 2012, the Company had $277.0 million in outstanding borrowings and $723.0 million of available borrowing capacity under the Credit Agreement.

Loans under the Credit Agreement are unsecured and bear interest, at the Borrower’s option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 100 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrower’s consolidated leverage ratio (200 basis points per annum as of December 31, 2012). The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio.

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The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive covenants requiring the Borrower to maintain a consolidated leverage ratio of no greater than three and one half times to one and, as long as the Company’s debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Company’s oil and gas properties to total funded debt of no less than one and one half times to one. At December 31, 2012, the Company was in compliance with all of its debt covenants under the Credit Agreement.

Senior Notes:    The Company’s Senior Notes rank pari passu with the Company’s Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At December 31, 2012, the Company was in compliance with all of its debt covenants under the Senior Notes.

Other long-term obligations:    These costs primarily relate to the long-term portion of production taxes payable and our asset retirement obligations.

6.    SHARE BASED COMPENSATION:

The Company sponsors a share based compensation plan: the 2005 Stock Incentive Plan (the “2005 Plan”). The plan is administered by the Compensation Committee of the Board of Directors (the “Committee”). The share based compensation plan is an important component of the total compensation package offered to the Company’s key service providers, and reflects the importance that the Company places on motivating and rewarding superior results.

The 2005 Plan was adopted by the Company’s Board of Directors on January 1, 2005 and approved by the Company’s shareholders on April 29, 2005. The purpose of the 2005 Plan is to foster and promote the long-term financial success of the Company and to increase shareholder value by attracting, motivating and retaining key employees, consultants, and outside directors, and providing such participants with a program for obtaining an ownership interest in the Company that links and aligns their personal interests with those of the Company’s shareholders, and thus, enabling such participants to share in the long-term growth and success of the Company. To accomplish these goals, the 2005 Plan permits the granting of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock, and other stock-based awards, some of which may require the satisfaction of performance-based criteria in order to be payable to participants. The Committee determines the terms and conditions of the awards, including, any vesting requirements and vesting restrictions or forfeitures that may occur. The Committee may grant awards under the 2005 Plan until December 31, 2014, unless terminated sooner by the Board of Directors.

Valuation and Expense Information

	Year Ended December 31,
	2012		2011		2010
Total cost of share-based payment plans	$	15,835	$	21,688	$	21,805
Amounts capitalized in fixed assets	$	5,079	$	7,769	$	8,861
Amounts charged against income, before income tax benefit	$	10,756	$	13,919	$	12,944
Amount of related income tax benefit recognized in income	$	4,463	$	4,997	$	4,595

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Securities Authorized for Issuance Under Equity Compensation Plans

As of December 31, 2012, the Company had the following securities issuable pursuant to outstanding award agreements or reserved for issuance under the Company’s previously approved stock incentive plans. Upon exercise, shares issued will be newly issued shares or shares issued from treasury.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options		Weighted Average Exercise Price of Outstanding Options		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in the First Column)
Equity compensation plans approved by security holders		1,357	$	49.03		3,075
Equity compensation plans not approved by security holders		n/a		n/a		n/a
Total		1,357	$	49.03		3,075

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the three year period ended December 31, 2012:

	Number of Options			Weighted Average Exercise Price (US$)
Balance, December 31, 2009		3,504		$	1.49	to	$	98.87
Forfeited		(68	)	$	51.60	to	$	76.01
Exercised		(1,206	)	$	1.49	to	$	45.95
Balance, December 31, 2010		2,230		$	3.91	to	$	98.87
Forfeited		(99	)	$	51.60	to	$	75.18
Exercised		(672	)	$	3.91	to	$	33.57
Balance, December 31, 2011		1,459		$	16.97	to	$	98.87
Forfeited		(68	)	$	25.08	to	$	75.18
Exercised		(34	)	$	16.97	to	$	19.18
Balance, December 31, 2012		1,357		$	16.97	to	$	98.87

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The following table summarizes information about the stock options outstanding and exercisable at December 31, 2012:

	Options Outstanding and Exercisable
Range of Exercise Price	Number Outstanding		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Aggregate Intrinsic Value
			(Years)
$16.97 - $16.97		40		1.32	$	16.97	$	46
$25.68 - $55.58		604		2.61	$	39.21	$	—
$46.05 - $65.04		166		3.53	$	56.44	$	—
$49.05 - $65.94		362		4.31	$	54.66	$	—
$51.14 - $98.87		185		5.42	$	70.24	$	—

The aggregate intrinsic value in the preceding tables represents the total pre-tax intrinsic value, based on the Company’s closing stock price of $18.13 on December 31, 2012, which would have been received by the option holders had all option holders exercised their options as of that date. The total number of in-the-money options exercisable as of December 31, 2012 was 40,000 options.

The following table summarizes information about the weighted-average grant-date fair value of share options:

	2012		2011		2010
Non-vested share options at beginning of year	$	—	$	30.72	$	26.28
Non-vested share options at end of year	$	—	$	—	$	30.72
Options vested during the year	$	—	$	30.73	$	23.86
Options forfeited during the year	$	27.05	$	25.80	$	28.36

The fair value of stock options that vested during the years ended December 31, 2011 and 2010 was $6.4 million and $9.8 million, respectively. As of December 31, 2011, all options fully vested; therefore, no options vested during the year ended December 31, 2012. The total intrinsic value of stock options exercised during the years ended December 31, 2012, 2011 and 2010 was $0.3 million, $21.5 million and $50.7 million, respectively.

At December 31, 2012, there was no unrecognized compensation cost related to non-vested, employee stock options as all options fully vested as of December 31, 2011.

PERFORMANCE SHARE PLANS:

Long Term Incentive Plans.    The Company offers a Long Term Incentive Plan (“LTIP”) in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. Each LTIP covers a performance period of three years. In 2010, 2011 and 2012, the Compensation Committee (the “Committee”) approved an award consisting of performance-based restricted stock units to be awarded to each participant.

For each LTIP award, the Committee establishes performance measures at the beginning of each performance period. Under each LTIP, the Committee establishes a percentage of base salary for each participant which is multiplied by the participant’s base salary to derive a Long Term Incentive Value as a “target” value

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which corresponds to the number of shares of the Company’s common stock the participant is eligible to receive if the target level for all performance measures is met. In addition, each participant is assigned threshold and maximum award levels in the event that actual performance is below or above target levels. For the 2010, 2011 and 2012 LTIP awards, the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth.

For the year ended December 31, 2012, the Company recognized $7.9 million in pre-tax compensation expense related to the 2010, 2011 and 2012 LTIP awards of restricted stock units. For the year ended December 31, 2011, the Company recognized $10.7 million in pre-tax compensation expense related to the 2009, 2010 and 2011 LTIP awards of restricted stock units. For the year ended December 31, 2010, the Company recognized $8.6 million in pre-tax compensation expense related to the 2008, 2009 and 2010 LTIP awards of restricted stock units. The amounts recognized during the year ended December 31, 2012 assumes that maximum performance objectives are attained under each plan. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at December 31, 2012, for each of the three year performance periods is expected to be approximately $11.7 million, $11.9 million, and $12.1 million related to the 2010, 2011 and 2012 LTIP awards of restricted stock units, respectively. The 2009 LTIP Common Stock Award was paid in shares of the Company’s stock to employees during the first quarter of 2012 and totaled $24.1 million (409,160 net shares).

7.    DERIVATIVE FINANCIAL INSTRUMENTS:

Objectives and Strategy:    The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue.

Historically, the Company has entered into various types of derivative instrument transactions to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s capital investment program. Because forward natural gas prices for 2013 production were low in 2012, the Company did not hedge any of its forecast 2013 natural gas production. As a result of the Company not having hedged any of its 2013 production, its earnings and cash flows may be more volatile during 2013 than in prior years.

The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise.

Fair Value of Commodity Derivatives:    FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the balance sheet and the associated unrealized gains and losses are recorded as current expense or income in the income statement. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement.

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The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010:

	For the Year Ended December 31,
	2012			2011		2010
Natural Gas Commodity Derivatives:
Realized gain on commodity derivatives(1)	$	303,966		$	213,349	$	116,827
Unrealized (loss) gain on commodity derivatives(1)		(230,385	)		100,383		208,625
Total gain on commodity derivatives	$	73,581		$	313,732	$	325,452

(1) Included in gain on commodity derivatives in the Consolidated Statements of Operations.

8.    FAIR VALUE MEASUREMENTS:

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

As required by FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:

Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

Level 2: Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.

Level 3: Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). At December 31, 2012, the Company did not have any open commodity derivative contracts.

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At December 31, 2012, the Company did not have any open commodity derivative contracts.

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Fair Value of Long-Lived Assets

The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These facilities are included in Property, Plant and Equipment in the Consolidated Balance Sheets and were impaired to a fair value of $82.6 million based on the income approach, estimated using Level 3 fair value inputs.

Fair Value of Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. We use available market data and valuation methodologies to estimate the fair value of our fixed rate debt. The inputs utilized to estimate the fair value of the Company’s fixed rate debt are considered Level 2 fair value inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact our financial position, results of operations or cash flows.

	December 31, 2012				December 31, 2011
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
Long-Term Debt:
5.45% Notes due 2015, issued 2008	$	100,000	$	107,801	$	100,000	$	111,475
7.31% Notes due 2016, issued 2009		62,000		72,046		62,000		74,817
4.98% Notes due 2017, issued 2010		116,000		127,109		116,000		128,570
5.92% Notes due 2018, issued 2008		200,000		230,062		200,000		231,091
7.77% Notes due 2019, issued 2009		173,000		219,045		173,000		219,552
5.50% Notes due 2020, issued 2010		207,000		234,552		207,000		229,423
4.51% Notes due 2020, issued 2010		315,000		331,329		315,000		318,925
5.60% Notes due 2022, issued 2010		87,000		98,526		87,000		94,165
4.66% Notes due 2022, issued 2010		35,000		36,361		35,000		34,631
5.85% Notes due 2025, issued 2010		90,000		102,096		90,000		99,022
4.91% Notes due 2025, issued 2010		175,000		179,677		175,000		173,835
Credit Facility		277,000		277,000		343,000		343,000
	$	1,837,000	$	2,015,604	$	1,903,000	$	2,058,506

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9.    INCOME TAXES:

The consolidated income tax (benefit) provision is comprised of the following:

	Year Ended December 31,
	2012			2011		2010
Current	$	12,363		$	6,464	$	4,763
(Reduction in) current tax benefit on stock based compensation		(4,427	)		6,212		17,522
Total current tax		7,936			12,676		22,285
Deferred		(708,149	)		244,994		236,330
Total income tax (benefit) provision	$	(700,213	)	$	257,670	$	258,615

The income tax provision (benefit) for continuing operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 35% to pretax income as a result of the following:

	Year Ended December 31,
	2012			2011			2010
Income tax (benefit) provision computed at the U.S. statutory rate	$	(1,006,989	)	$	248,805		$	253,076
State income tax provision (benefit) net of federal benefit		(136,112	)		6,329			3,608
Valuation allowance		446,148			—			(677	)
Tax effect of rate change		1,358			4,228			1,939
Other, net		(4,618	)		(1,692	)		669
	$	(700,213	)	$	257,670		$	258,615

The tax effects of temporary differences that give rise to significant components of the Company’s deferred tax assets and liabilities for continuing operations are as follows:

	Year Ended December 31,
	2012			2011
Deferred tax assets — current:
Incentive compensation/other, net		6,468			9,329
Valuation allowance		(6,468	)		—
Net deferred tax assets — current	$	—		$	9,329
Deferred tax liabilities — current:
Derivative instruments, net	$	—		$	82,709
Net deferred tax liabilities — current	$	—		$	82,709
Net deferred tax liability — current	$	—		$	73,380

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Year Ended December 31,
	2012			2011
Deferred tax assets — non-current:
Property and equipment		350,978			—
Deferred gain		55,329			—
U.S. Federal tax credit carryforwards		4,870			13,280
Capital loss carryforwards		—			1,929
Net operating loss carryforwards		17,755			150
Incentive compensation/other, net		15,104			12,880
		444,036			28,239
Valuation allowance		(443,300	)		(3,621	)
Net deferred tax assets — non-current	$	736		$	24,618
Deferred tax liabilities — non-current:
Property and equipment		—			659,040
Other		736			587
Net non-current tax liabilities	$	736		$	659,627
Net non-current tax liability	$	—		$	635,009

In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, management considers the scheduled reversal of deferred tax liabilities, historical taxable income, projected future taxable income, and available tax planning strategies.

As a result of the ceiling test and other impairments recorded during the year ended December 31, 2012, the Company’s previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $449.8 million as of December 31, 2012. This valuation allowance may be reversed in future periods against future taxable income.

As of December 31, 2012, the Company had approximately $3.2 million of U.S. federal alternative minimum tax (AMT) credits available to offset regular U.S. Federal income taxes. These AMT credits do not expire and can be carried forward indefinitely. In addition, the Company has $1.7 million of foreign tax credit carryforwards, none of which expire prior to 2017. The Company has U.S. State tax net operating loss carryforwards of $273.1 million which will expire between 2031 and 2032.

The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations as a result of implementing the standard related to accounting for uncertain tax positions. The amount of unrecognized tax benefits did not change as of December 31, 2012.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statements of Operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.

The Company files a consolidated federal income tax return in the United States federal jurisdiction and various combined, consolidated, unitary, and separate filings in several states, and international jurisdictions. The income tax years 2009 and 2010 have been audited by the Internal Revenue Service resulting in no material

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

changes to the Company’s taxes. With certain exceptions, including previous audited tax years, the income tax years 2009 through 2012 remain open to examination by the major taxing jurisdictions in which the Company has business activity.

The undistributed earnings of the Company’s U.S. subsidiaries are considered to be indefinitely invested outside of Canada. Accordingly, no provision for Canadian income taxes and/or withholding taxes has been provided thereon.

10.    EMPLOYEE BENEFITS:

The Company sponsors a qualified, tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for its employees. Employees may defer 100% of their compensation, subject to limitations. The Company matches 100% of the employee’s contribution up to 5% of compensation, as defined by the plan, along with an employer discretionary contribution of 8%. The expense associated with the Company’s contribution was $1.8 million, $1.4 million and $1.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

11.    COMMITMENTS AND CONTINGENCIES:

Transportation contract.    The Company is an anchor shipper on REX securing pipeline infrastructure providing sufficient capacity to transport a portion of its natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas in the future. REX begins at the Opal Processing Plant in southwest Wyoming and traverses Wyoming and several other states to an ultimate terminus in eastern Ohio. The Company’s commitment involves a capacity of 200 MMMBtu per day of natural gas through November 2019, and the Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper.

Subsequently, the Company entered into agreements to secure an additional capacity of 50 MMMBtu per day on the REX pipeline system, beginning in January 2012 through December 2018. This additional capacity will provide the Company with the ability to move additional volumes from its producing wells in Wyoming to markets in the eastern U.S.

The Company currently projects that demand charges related to the remaining term of the contract will total approximately $673.0 million.

Operating lease.    During December 2012, the Company sold its system of pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The net cash proceeds received for the assets were $203.0 million and additional consideration of $23.0 million in the form of marketable securities which were sold during December 2012 for net cash proceeds of $21.2 million.

The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the LGS at the sole discretion of the Company. Annual rent for the initial term under the Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The Company’s sale leaseback transaction was treated as a “normal leaseback” under the provisions of FASB ASC Topic 840 and qualified for sales recognition. The lease is classified as an operating lease. The Company currently projects that lease payments related to the Lease Agreement will total approximately $299.4 million.

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

All of the Company’s lease obligations are related to leases that are classified as operating leases. These leases contain certain provisions that could result in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in its lease classification analysis and has determined that the default provisions do not impact classification of any the Company’s operating leases.

Drilling contracts.    As of December 31, 2012, the Company had committed to drilling obligations totaling $21.5 million ($15.0 million due in 2013, $6.5 million due in 2014). The commitments expire in 2014 and were entered into to fulfill the Company’s drilling program initiatives in Wyoming.

Office space lease.    The Company’s maintains office space in Colorado, Texas, Wyoming and Pennsylvania with total remaining commitments for office leases of $1.5 million at December 31, 2012 ($0.9 million in 2013, $0.7 million in 2014 to 2015).

During the years ended December 31, 2012, 2011 and 2010, the Company recognized expense associated with its office leases in the amount of $1.0 million, $0.9 million, and $0.8 million, respectively.

Other.    The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, management, after consultation with legal counsel, is of the opinion that the final resolution of all such currently pending or threatened litigation is not likely to have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company.

12.    CONCENTRATION OF CREDIT RISK:

The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and commodity derivative contracts associated with the Company’s hedging program. The Company’s revenues related to natural gas sales are derived principally from a diverse group of companies, including major energy companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financial institutions and end-users in various industries.

Concentrations of credit risk with respect to receivables is limited due to the large number of customers and their dispersion across geographic areas. Commodity-based contracts may expose the Company to the credit risk of nonperformance by the counterparty to these contracts. This credit exposure to the Company is diversified primarily among as many as ten major investment grade institutions and will only be present if the reference price of natural gas established in those contracts is less than the prevailing market price of natural gas, from time to time. At December 31, 2012, the Company did not have any open commodity derivative contracts.

The Company maintains credit policies intended to monitor and mitigate the risk of uncollectible accounts receivable related to the sale of natural gas, condensate as well as its commodity derivative positions. The Company performs a credit analysis of each of its customers and counterparties prior to making any sales to new customers or extending additional credit to existing customers. Based upon this credit analysis, the Company may require a standby letter of credit or a financial guarantee. The Company did not have any outstanding, uncollectible accounts for its natural gas or condensate sales, nor derivative settlements sales at December 31, 2012.

A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2012, the Company had no single customer that represented 10% or more of its total revenues.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

13.    SUBSEQUENT EVENTS:

FASB ASC Topic 855, Subsequent Events (“FASB ASC 855”), sets forth principles and requirements to be applied to the accounting for and disclosure of subsequent events. FASB ASC 855 sets forth the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which events or transactions occurring after the balance sheet date shall be recognized in the financial statements and the required disclosures about events or transactions that occurred after the balance sheet date. The FASB issued ASU No. 2010-09, Subsequent Events (FASB ASC 855), Amendments to Certain Recognition and Disclosure Requirements, on February 24, 2010, in an effort to remove some contradictions between the requirements of U.S. GAAP and the SEC’s filing rules. The amendments remove the requirement that public companies disclose the date through which their financial statements are evaluated for subsequent events in both issued and revised financial statements. The Company has evaluated the period subsequent to December 31, 2012 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading.

14.    SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):

	2012
	1st Quarter		2nd Quarter			3rd Quarter			4th Quarter			Total
Revenues from continuing operations	$	226,143	$	170,270		$	196,375		$	217,186		$	809,974
Gain (loss) on commodity derivatives		120,283		(33,287	)		(9,896	)		(3,519	)		73,581
Expenses from continuing operations		193,539		186,064			156,503			146,682			682,788
Ceiling test and other impairments		—		1,869,136			606,827			496,501			2,972,464
Interest expense		18,298		18,748			25,369			25,765			88,180
Contract cancellation fees		4,846		4,666			(291	)		6,248			15,469
Other income (expense), net		8		7			(42	)		(1,738	)		(1,765	)
Income (loss) before income tax provision		129,751		(1,941,624	)		(601,971	)		(463,267	)		(2,877,111	)
Income tax provision (benefit)		45,489		(754,642	)		175			8,765			(700,213	)
Net income (loss)	$	84,262	$	(1,186,982	)	$	(602,146	)	$	(472,032	)	$	(2,176,898	)
Net income (loss) per common share — basic	$	0.55	$	(7.76	)	$	(3.94	)	$	(3.09	)	$	(14.24	)
Net income (loss) per common share — fully diluted	$	0.55	$	(7.76	)	$	(3.94	)	$	(3.09	)	$	(14.24	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	2011
	1st Quarter		2nd Quarter			3rd Quarter			4th Quarter		Total
Revenues from continuing operations	$	257,290	$	280,567		$	293,141		$	270,798	$	1,101,796
Gain on commodity derivatives		15,635		47,606			114,166			136,325		313,732
Expenses from continuing operations		145,666		151,365			160,543			184,458		642,032
Interest expense		14,590		15,590			15,902			17,074		63,156
Other income (expense), net		20		(4	)		(3	)		519		532
Income before income tax provision		112,689		161,214			230,859			206,110		710,872
Income tax provision		43,969		57,709			81,713			74,279		257,670
Net income	$	68,720	$	103,505		$	149,146		$	131,831	$	453,202
Net income per common share — basic	$	0.45	$	0.68		$	0.98		$	0.86	$	2.97
Net income per common share — fully diluted	$	0.44	$	0.67		$	0.97		$	0.86	$	2.94

15.    DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

The following information about the Company’s oil and natural gas producing activities is presented in accordance with FASB ASC Topic 932, Oil and Gas Reserve Estimation and Disclosures:

A.    OIL AND GAS RESERVES:

The determination of oil and natural gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. From time to time, the Company may adjust the inventory and schedule of its proved undeveloped locations in response to changes in capital budget, economics, new opportunities in the portfolio or resource availability. The Company has not scheduled any proved undeveloped reserves beyond five years nor does it have any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years.

In estimating proved reserves and future revenue as of December 31, 2012, the Company’s independent reserve engineer, Netherland, Sewell & Associates, Inc., used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and guidelines, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, Netherland, Sewell & Associates, Inc.’s conclusions necessarily represent only informed professional judgment.

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

SEC’s regulations and GAAP. The Vice President — Reservoir Engineering & Development is primarily responsible for overseeing the preparation of the Company’s reserve estimates by our independent engineers, Netherland, Sewell & Associates, Inc. The Vice President — Reservoir Engineering & Development has a Bachelor and Master of Science degree in Petroleum Engineering and is a licensed Professional Engineer with over 18 years of experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

All of the information regarding reserves in this annual report is derived from the report of Netherland, Sewell & Associates, Inc. The report of Netherland, Sewell & Associates, Inc. is included as an Exhibit to this annual report. The principal engineer at Netherland, Sewell & Associates, Inc. responsible for preparing our reserve estimates has a Bachelor of Science degree in Mechanical Engineering and is a licensed Professional Engineer with 30 years of experience, including significant experience throughout the Rocky Mountain basins.

Since January 1, 2012, 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 and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA.

The following unaudited tables as of December 31, 2012, 2011, and 2010 are based upon estimates prepared by Netherland, Sewell & Associates, Inc. in reports dated February 11, 2013, February 1, 2012, and January 31, 2011, respectively. These are estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2012, 2011 and 2010. All such reserves are located in the Green River Basin in Wyoming and the Appalachian Basin of Pennsylvania.

B.    ANALYSES OF CHANGES IN PROVEN RESERVES:

	United States
	Oil (MBbls)			Natural Gas (MMcf)
Reserves, December 31, 2009		29,185			3,736,601
Extensions, discoveries and additions		8,496			1,195,829
Production		(1,334	)		(205,613	)
Revisions		(4,663	)		(526,662	)
Reserves, December 31, 2010		31,684			4,200,155
Extensions, discoveries and additions		7,425			1,452,122
Production		(1,408	)		(236,832	)
Revisions		(4,620	)		(636,891	)
Reserves, December 31, 2011		33,081			4,778,554
Extensions, discoveries and additions		5,435			819,896
Production		(1,282	)		(249,310	)
Revisions(1)		(19,097	)		(2,382,695	)
Reserves, December 31, 2012		18,137			2,966,445

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	United States
	Oil (MBbls)		Natural Gas (MMcf)
Proved:
Developed		11,627		1,541,813
Undeveloped		17,558		2,194,788
Total Proved — 2009		29,185		3,736,601
Developed		11,013		1,678,697
Undeveloped		20,671		2,521,458
Total Proved — 2010		31,684		4,200,155
Developed		11,794		1,973,391
Undeveloped		21,287		2,805,163
Total Proved — 2011		33,081		4,778,554
Developed		10,531		1,820,994
Undeveloped		7,606		1,145,451
Total Proved — 2012		18,137		2,966,445

(1) The net downward revision is primarily due to lower natural gas prices utilized in the preparation of the December 31, 2012 reserve estimation as compared to the price used in the previous year’s estimate impacting the economic limit of reserves and the corresponding reduction in capital investment associated with the transfer of proved undeveloped reserves to the unproven category. The calculated weighted average natural gas sales prices utilized for the purposes of estimating the Company’s proved reserves and future net revenues at December 31, 2012 and 2011 were $2.63 per Mcf and $4.04 per Mcf, respectively.

During 2012, substantially all of our extensions and discoveries in the proved developed category were attributable to wells drilled in 2012, and substantially all of our extensions and discoveries in the proved undeveloped category were attributable to our ongoing drilling activities and its associated effect on our proved undeveloped reserves estimates.

C.    STANDARDIZED MEASURE:

The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s proved natural gas reserves. Natural gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company’s proved reserves and future net revenues at December 31, 2012, 2011 and 2010 was $2.63, $4.04 and $4.05 per Mcf, respectively, for natural gas and $87.85, $88.19 and $68.93 per barrel, respectively, for condensate, based upon the average of the price in effect on the first day of the month for the preceding twelve month period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available operating loss carryovers.

	As of December 31,
	2012			2011			2010
Future cash inflows	$	9,380,970		$	22,196,913		$	19,186,072
Future production costs		(3,217,771	)		(6,113,282	)		(5,253,509	)
Future development costs		(1,661,394	)		(4,294,375	)		(3,052,843	)
Future income taxes		(733,855	)		(3,340,516	)		(3,198,413	)
Future net cash flows		3,767,950			8,448,740			7,681,307
Discount at 10%		(1,873,633	)		(4,652,684	)		(4,155,739	)
Standardized measure of discounted future net cash flows	$	1,894,317		$	3,796,056		$	3,525,568

The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses.

D.    SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE         NET CASH FLOWS:

	December 31,
	2012			2011			2010
Standardized measure, beginning	$	3,796,056		$	3,525,568		$	2,026,700
Net revisions of previous quantity estimates		(2,516,159	)		(964,987	)		(807,877	)
Extensions, discoveries and other changes		858,951			2,173,103			1,816,073
Changes in future development costs		952,067			(741,658	)		(606,449	)
Sales of oil and gas, net of production costs		(625,745	)		(896,434	)		(787,409	)
Net change in prices and production costs		(2,912,698	)		108,108			1,501,041
Development costs incurred during the period that reduce future development costs		316,394			464,880			404,402
Accretion of discount		529,696			499,358			288,713
Net changes in production rates and other		363,788			(338,982	)		297,957
Net change in income taxes		1,131,967			(32,900	)		(607,583	)
Aggregate changes		(1,901,739	)		270,488			1,498,868
Standardized measure, ending	$	1,894,317		$	3,796,056		$	3,525,568

There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and natural gas prices have fluctuated widely.

E.    COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES:

	Years Ended December 31,
	2012		2011		2010
United States
Property Acquisitions:
Unproved	$	47,979	$	91,983	$	472,339
Proved		—		—		—
Exploration*		199,569		746,085		634,503
Development		587,618		675,718		469,636
Total	$	835,166	$	1,513,786	$	1,576,478

* Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field.

F.    RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES:

	Years Ended December 31,
	2012			2011			2010
United States
Oil and gas revenue	$	809,974		$	1,101,796		$	979,386
Production expenses		(184,229	)		(205,363	)		(191,978	)
Depletion and depreciation		(388,985	)		(346,394	)		(241,796	)
Ceiling test and other impairments		(2,972,464	)		—			—
Income taxes		662,698			(197,464	)		(193,692	)
Total	$	(2,073,006	)	$	352,575		$	351,920

G.    CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:

	December 31,
	2012			2011
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	7,235,765		$	5,974,604
Less: accumulated depletion, depreciation and amortization		(5,578,265	)		(2,322,982	)
		1,657,500			3,651,622
Unproven Properties:
Acquisition and exploration costs not being amortized		—			537,526
	$	1,657,500		$	4,189,148

81

Item 9.    Change in and Disagreements with Accountants on Accounting and Financial Disclosures.

None.

Item 9A.    Controls and Procedures.

Management’s Report on Internal Control Over Financial Reporting

Management’s Report on Internal Control Over Financial Reporting is included on page 42 of this form 10-K.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Evaluation of Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we evaluated the effectiveness of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Exchange Act. Based on that evaluation, our chief executive officer and our chief financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2012. The evaluation considered the procedures designed to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and communicated to our management as appropriate to allow timely decisions regarding required disclosure.

Item 9B.    Other Information.

None.

82

Part III

Item 10.    Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not later than 120 days after December 31, 2012.

The Company has adopted a code of ethics that applies to the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics is posted on the Company’s website at www.ultrapetroleum.com, and is available free of charge in print to any shareholder who requests it. Requests for copies should be addressed to the Secretary at 400 North Sam Houston Parkway East, Suite 1200, Houston, Texas 77060.

Item 11.    Executive Compensation.

The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not later than 120 days after December 31, 2012.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not later than 120 days after December  31, 2012.

Item 13.    Certain Relationships and Related Transactions, and Director Independence.

The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not later than 120 days after December 31, 2012.

Item 14.    Principal Accounting Fees and Services.

The information required by this item is incorporated herein by reference to the Company’s definitive proxy statement, which will be filed not later than 120 days after December 31, 2012.

83

Part IV

Item 15.    Exhibits, Financial Statement Schedules.

The following documents are filed as part of this report:

1. Financial Statements:     See Item 8.

2. Financial Statement Schedules:     None.

3. Exhibits.     The following Exhibits are filed herewith pursuant to Rule 601 of the Regulation S-K or are incorporated by reference to previous filings.

Exhibit Number	Description
3.1	Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001).
3.2	By-Laws of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001).
3.3	Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005)
4.1	Specimen Common Share Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001).
4.2	Form 8-A filed with the Securities and Exchange Commission on July 23, 2007.
10.1	Credit Agreement dated as of October 6, 2011 among Ultra Resources, Inc., JPMorgan Chase Bank, N.A. as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on October 11, 2011).
10.2	Share Purchase Agreement dated September 26, 2007 between UP Energy Corporation and SPC E&P (China) Pte. Ltd. (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on September 26, 2007).
10.3	Precedent Agreement between Rockies Express Pipeline LLC and Ultra Resources, Inc. dated December 19, 2005 (incorporated by reference to Exhibit 10.1 of the Company’s Report of Form 8-K filed on February 9, 2006).
10.4	Precedent Agreement between Rockies Express Pipeline LLC, Entrega Gas Pipeline LLC and Ultra Resources, Inc. dated December 19, 2005 (incorporated by reference to Exhibit 10.2 of the Company’s Report on Form 8-K filed on February 9, 2006).
10.5	Ultra Petroleum Corp. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-132443), filed with the SEC on March 15, 2006).
10.6	Ultra Petroleum Corp. 2000 Stock Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-13278), filed with the SEC on March 15, 2001).
10.7	Ultra Petroleum Corp. 1998 Stock Option Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-13342) filed with the SEC on April 2, 2001).
10.8	Employment Agreement between Ultra Petroleum Corp. and Michael D. Watford dated August 6, 2007 (incorporated by reference from Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2007).
10.9	Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on March 6, 2008).
10.10	First Supplement dated March 5, 2009 to Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on March 5, 2009).

84

Exhibit Number	Description
10.11	Second Supplement dated January 28, 2010 to Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on January 28, 2010).
10.12	Third Supplement dated October 12, 2010 to Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on October 12, 2010).
10.13	Sale and Purchase Agreement dated December 18, 2009 between Ultra Resources, Inc. and NCL Appalachian Partners, L.P., Locin Oil Corporation, Lyons Petroleum Reserves, Inc., MC Reserves, Inc., (incorporated by reference to Exhibit 1.1 of the Company’s Report on Form 8-K filed on December 23, 2009).
*10.14	Sale and Purchase Agreement dated December 7, 2012 between Ultra Wyoming, Inc. and Pinedale Corridor, LP and First Amendment to Sale and Purchase Agreement dated December 12, 2012 between Ultra Wyoming, Inc. and Pinedale Corridor, LP.
*21.1	Subsidiaries of the Company.
*23.1	Consent of Netherland, Sewell & Associates, Inc.
*23.2	Consent of Ernst & Young LLP.
*31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*99.1	Reserve Report Summary prepared by Netherland, Sewell & Associates, Inc. as of December 31, 2012.
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema Document
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
*101.LAB	XBRL Taxonomy Extension Label Linkbase Document
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
*101.DEF	XBRL Taxonomy Extension Definition

* Filed herewith.

85

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ULTRA PETROLEUM CORP.
By:	/s/    Michael D. Watford
	Name:   Michael D. Watford
	Title:     Chairman of the Board,
	Chief Executive Officer, and President

Date: February 20, 2013

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/    Michael D. Watford Michael D. Watford	Chairman of the Board, Chief Executive Officer, and President (principal executive officer)	February 20, 2013
/s/    Marshall D. Smith Marshall D. Smith	Senior Vice President and Chief Financial Officer (principal financial officer)	February 20, 2013
/s/    Garland R. Shaw Garland R. Shaw	Corporate Controller (principal accounting officer)	February 20, 2013
/s/    W. Charles Helton W. Charles Helton	Director	February 20, 2013
/s/    Stephen J. McDaniel Stephen J. McDaniel	Director	February 20, 2013
/s/    Roger A. Brown Roger A. Brown	Director	February 20, 2013
/s/    Michael J. Keeffe Michael J. Keeffe	Director	February 20, 2013

86

EXHIBIT INDEX

Exhibit Number	Description
3.1	Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001).
3.2	By-Laws of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001).
3.3	Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005)
4.1	Specimen Common Share Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001).
4.2	Form 8-A filed with the Securities and Exchange Commission on July 23, 2007.
10.1	Credit Agreement dated as of October 6, 2011 among Ultra Resources, Inc., JPMorgan Chase Bank, N.A. as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on October 11, 2011).
10.2	Share Purchase Agreement dated September 26, 2007 between UP Energy Corporation and SPC E&P (China) Pte. Ltd. (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on September 26, 2007).
10.3	Precedent Agreement between Rockies Express Pipeline LLC and Ultra Resources, Inc. dated December 19, 2005 (incorporated by reference to Exhibit 10.1 of the Company’s Report of Form 8-K filed on February 9, 2006).
10.4	Precedent Agreement between Rockies Express Pipeline LLC, Entrega Gas Pipeline LLC and Ultra Resources, Inc. dated December 19, 2005 (incorporated by reference to Exhibit 10.2 of the Company’s Report on Form 8-K filed on February 9, 2006).
10.5	Ultra Petroleum Corp. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-132443), filed with the SEC on March 15, 2006).
10.6	Ultra Petroleum Corp. 2000 Stock Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-13278), filed with the SEC on March 15, 2001).
10.7	Ultra Petroleum Corp. 1998 Stock Option Plan (incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form S-8 (Reg. No. 333-13342) filed with the SEC on April 2, 2001).
10.8	Employment Agreement between Ultra Petroleum Corp. and Michael D. Watford dated August 6, 2007 (incorporated by reference from Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2007).
10.9	Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on March 6, 2008).
10.10	First Supplement dated March 5, 2009 to Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on March 5, 2009).
10.11	Second Supplement dated January 28, 2010 to Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on January 28, 2010).
10.12	Third Supplement dated October 12, 2010 to Master Note Purchase Agreement dated March 6, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on October 12, 2010).

Exhibit Number	Description
10.13	Sale and Purchase Agreement dated December 18, 2009 between Ultra Resources, Inc. and NCL Appalachian Partners, L.P., Locin Oil Corporation, Lyons Petroleum Reserves, Inc., MC Reserves, Inc., (incorporated by reference to Exhibit 1.1 of the Company’s Report on Form 8-K filed on December 23, 2009).
*10.14	Sale and Purchase Agreement dated December 7, 2012 between Ultra Wyoming, Inc. and Pinedale Corridor, LP and First Amendment to Sale and Purchase Agreement dated December 12, 2012 between Ultra Wyoming, Inc. and Pinedale Corridor, LP..
*21.1	Subsidiaries of the Company.
*23.1	Consent of Netherland, Sewell & Associates, Inc.
*23.2	Consent of Ernst & Young LLP.
*31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*99.1	Reserve Report Summary prepared by Netherland, Sewell & Associates, Inc. as of December 31, 2012.
*101.INS	XBRL Instance Document
*101.SCH	XBRL Taxonomy Extension Schema Document
*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
*101.LAB	XBRL Taxonomy Extension Label Linkbase Document
*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
*101.DEF	XBRL Taxonomy Extension Definition

* Filed herewith.

EX-10.14

Exhibit 10.14

LIQUIDS GATHERING SYSTEM

SUBLETTE COUNTY, WYOMING

PURCHASE AND SALE AGREEMENT

BETWEEN

ULTRA WYOMING, INC.

AS SELLER

AND

PINEDALE CORRIDOR, LP

AS BUYER

AND

DATED DECEMBER 7, 2012

TABLE OF CONTENTS

		Page
ARTICLE I DEFINITIONS			1
	Definitions		1
	Certain Interpretive Provisions		11
ARTICLE II PURCHASE AND SALE			11
	Purchase and Sale		11
	Nonrefundable Consideration		11
ARTICLE III PURCHASE PRICE			12
	Purchase Price		12
ARTICLE IV BUYER’S INSPECTION			12
	Access to Records, Insurance Policies and Services Agreement		12
	Disclaimer		12
	Access to the Assets		12
ARTICLE V TITLE MATTERS; CASUALTY; CONSENTS			13
	Title		13
	Casualty Loss		13
	Consents		14
	Nerd Farm Mortgage and Nerd Farm Judgment		15
ARTICLE VI CONFIDENTIALITY			15
	No Disclosure or Use of Confidential Information		15
6.2	Compelled and Anticipated Disclosure		16
	Ownership and Return		16
	Standstill		16
	Attorneys’ Fees		17
	Announcements		17
	Injunctive Relief		17
	Survival		17
ARTICLE VII SELLER’S REPRESENTATIONS			17
	Incorporation/Qualification		17
	Power and Authority		17
	Authorization and Enforceability		18
	Liability for Brokers’ Fees		18
	No Bankruptcy		18
	Litigation		18
	Environmental Condition of Assets		18
	Assets		18
	Taxes		19

ii

	Records, Insurance Policies, Services Agreement and Easements	19
	Compliance with Laws	20
	Governmental Authorizations	20
	Bonds, Letters of Credit, Guarantees	20
	Ownership	20
	Consents	20
	Preferential Rights	21
	Material Agreements	21
	Sufficiency of the Assets	21
	Adverse Change	21
	Disclaimers	21
	Survival	22
ARTICLE VIII BUYER’S REPRESENTATIONS		22
	Incorporation and Qualification	22
	Power and Authority	22
	Authorization and Enforceability	22
	Liability for Brokers’ Fees	22
	No Bankruptcy	23
	Litigation	23
	Buyer’s Evaluation	23
	Loan Documents and Ownership Documents and Information	23
	No Buyer Factual Default Under the Lease or Equity Investment Agreement	23
	Survival	24
ARTICLE IX COVENANTS AND AGREEMENTS		24
	Conduct of Business	24
	Insurance	25
	Loan Documents, Ownership Documents and Information, Financial Resources	25
	Further Assurances	25
	Fees and Expenses	26
	PSA Guaranties	26
	Survival	26
ARTICLE X TAX MATTERS		26
	Apportionment of Property Tax Liability	26
	Property Tax Reports and Returns	27
	Sales Taxes	27
	Federal Tax Reporting	27
	Like Kind Exchange	27
ARTICLE XI CONDITIONS PRECEDENT TO CLOSING		28
	Seller’s Conditions Precedent	28
	Buyer’s Conditions Precedent	28
ARTICLE XII RIGHT OF TERMINATION		29
	Termination	29

iii

ARTICLE XIII CLOSING		30
	Date of Closing	30
	Time and Place of Closing	30
	Closing Obligations	30
ARTICLE XIV ASSUMPTION AND RETENTION OF OBLIGATIONS AND INDEMNIFICATION		31
	Seller’s Retention of Liabilities and Obligations	31
	Environmental Indemnification	31
	Indemnification	31
	Survival	32
	Procedure	33
	No Insurance; Subrogation	34
	Reservation as to Non-Parties	34
	Consequential Damages	34
	No Derivative Liability	34
	Attorneys’ Fees	34
ARTICLE XV MISCELLANEOUS		34
	Expenses	34
	Notices	35
	Amendments	36
	Assignment	36
	Counterparts/PDF and Fax Signatures	36
	GOVERNING LAW; JURISDICTION, VENUE; JURY WAIVER	36
	Entire Agreement	36
	Binding Effect	37
	No Third-Party Beneficiaries	37
	Time of the Essence	37
	Business Day	37
	No Recordation of Agreement	37
	No Waiver	37
	Waiver of Trial by Jury	37
	Further Assurances	37

iv

SCHEDULES

Schedule 7.13:	Bonds, Letters of Credit and Guarantees
Schedule 7.19	Adverse Change

EXHIBITS

Exhibit A:	Partial Assignment of Jensen Easements to Buyer
Exhibit B:	BLM Request for Consent to Assignment to Buyer
Exhibit C:	List of BLM Easements
Exhibit D:	BLM Easements Assignment to Buyer/ BLM Filing
Exhibit E:	BLM Easements Assignment to Buyer/ County Filing
Exhibit F:	Map of Pipelines and Gathering Facilities
Exhibit G:	Bill of Sale
Exhibit H:	Resources Guaranty
Exhibit I:	Buyer PSA Guaranty
Exhibit J:	Equity Investors Agreement
Exhibit K:	SNDA
Exhibit L:	Lease
Exhibit M:	Lessee Lease Guaranty
Exhibit N:	Lessor Lease Guaranty
Exhibit O:	Memorandum of Lease
Exhibit P:	Nerd Farm Easement
Exhibit Q:	Non-Foreign Affidavit
Exhibit R:	Seller PSA Guaranty
Exhibit S:	List of Well Pads/ LGS Pipeline Riser Exhibit
Exhibit T:	Improvements Exhibit
Exhibit U:	Central Gathering Facility Exhibit
Exhibit V:	Photo of Inlet Flange/ Liquids Gathering System Exhibit

v

DEFINED TERMS

Certain terms are defined in Section 1.1 of this Agreement. In addition, other terms are defined on the pages indicated below:

Additional Required Consent	15
Agreement	1
Authorizations	20
Buyer	1
Buyer Warranties	24
Buyer’s Conditions	28
Casualty Loss	13
Claim	33
Claim Notice	33
Closing	30
Closing Date	30
Controlling and Controlled	4
Effective Date	1
Improvements	2
Indemnified Party	33
Indemnifying Party	33
Independent Contract Consideration	11
Loan Documents	23
Loss or Losses	31
Major Casualty Loss	14

Major Casualty Notice	14
Material Agreements	21
Non-Assignable Assets	15
Notice	35
Other BLM Matters	14
Ownership Documents and Information	23
Party	1
Purchase Price	12
Real Estate Records	30
Recorded Documents	30
Restoration Operations	13
Restricted Period	24
Retained Liabilities	31
Seller	1
Seller’s Conditions	28
Seller’s Warranties	21
Taxes	19
Transaction	12
Transaction Documents	1

vi

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (this “Agreement”), is made as of December 7, 2012 (“Effective Date”), by and between ULTRA WYOMING, INC., a Wyoming corporation (“Seller”) whose address is 400 N. Sam Houston Parkway E., Suite 1200, Houston, Texas 77060, and PINEDALE CORRIDOR, LP, a Delaware limited partnership (“Buyer”) whose address is 4200 W. 115^th Street, Suite 210, Leawood, Kansas 66211. Seller and Buyer may be referred to individually as a “Party” or collectively as the “Parties.”

RECITALS

Seller owns certain rights in and to the Assets (as defined in this Agreement) located in the Pinedale Anticline in Sublette County, Wyoming, as more fully described in this Agreement.

Buyer desires to purchase, and Seller desires to sell and convey, the Assets pursuant to and in accordance with the terms and conditions of this Agreement.

As a condition to Closing (as defined in this Agreement) of the purchase and sale of the Assets, Seller and Buyer will enter into the Lease described herein (this Agreement, the Lease and the other Closing Deliveries (as defined in this Agreement) to be collectively referred to as the “Transaction Documents”).

Concurrently with the execution of this Agreement by the Parties, Seller Guarantor (as defined in this Agreement) has executed and delivered to Buyer the Seller PSA Guaranty (as defined in this Agreement), and the Buyer Guarantor (as defined in this Agreement) has executed and delivered to Seller the Buyer PSA Guaranty (as defined in this Agreement).

AGREEMENT

In consideration of the mutual promises, covenants and warranties contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Buyer and Seller agree as follows:

ARTICLE I

DEFINITIONS

1.1 Definitions The following terms shall have the meanings set forth below:

Actual Daily Product Volume: the average daily volume (expressed in Bbls per day) of Condensate and water physically transported through the Liquids Gathering System.

Affiliate: With respect to a specified Person, (a) any Subsidiary of that Person, and (b) any Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with, the specified Person.

Assets: The Liquids Gathering System and the Personal Property.

Bill of Sale: The Bill of Sale executed by Seller and Buyer in the form attached to this Agreement as Exhibit G.

BLM: The United States Department of the Interior Bureau of Land Management, Wyoming State Office.

BLM Consent: The consent of BLM to the BLM Easement Assignments to Buyer, in response to the BLM Request for Consent to Assignment to Buyer.

BLM Easements Assignment to Buyer: The assignment by Seller to Buyer of all of Seller’s right, title and interest under the BLM Easements pursuant to (a) the Application for Transportation and Utility Systems and Facilities on Federal Lands to be executed by Seller and Buyer, in the form attached to this Agreement as Exhibit D, and (b) the Assignment of Easements and Transfer of Improvements (LGS) [BLM Easements] to be executed by Seller and Buyer and with their signatures acknowledged, in the form attached to this Agreement as Exhibit E.

BLM and Jensen Easements Assignment to Seller: The assignment by Ultra Resources to Seller of all of Ultra Resources’ right, title and interest under the BLM Easements by (a) the Application for Transportation and Utility Systems and Facilities on Federal Lands dated June 29, 2012, and (b) the Assignment and Bill of Sale (LGS) dated effective as of January 1, 2012, and recorded in the Real Estate Records.

BLM Easements: The easements, rights of way and agreements listed in Exhibit C, which shall be assigned to Seller pursuant to the BLM Easements Assignment to Seller.

BLM Request for Consent to Assignment to Buyer: The form of request for BLM’s consent to the BLM Easements Assignment to Buyer, a copy of which request is attached to this Agreement as Exhibit B.

Business Day: Any day other than a Saturday, Sunday or any day that is a national banking holiday in the United States.

Buyer Closing Deliveries: The Equity Investors Agreement executed by Buyer, Ross Avenue Investments, LLC, Pinedale GP, Inc. and CorEnergy, the Lease executed by Buyer, the Memo of Lease executed by Buyer and with its signature acknowledged, the BLM Easements Assignment to Buyer executed by Buyer and with its signature acknowledged, the BLM Request for Consent to Assignment to Buyer executed by Buyer, the Partial Assignment of Jensen Easements to Buyer executed by Buyer and with its signature acknowledged, the Nerd Farm Easement executed by Buyer and with its signature acknowledged, the Lessor Lease Guaranty executed by CorEnergy, the Bill of Sale executed by Buyer, the SNDA executed by Buyer, CorEnergy and KeyBank, National Association, and with their signatures acknowledged, and true, correct and complete copies of the executed Loan Documents and the executed Ownership Documents and Information.

Buyer Closing Payments: The Purchase Price in Current Funds, and to the extent payable at Closing, any Taxes that Buyer is required to pay as a result of Closing under Section 10.3 of this Agreement, any recording fees or costs to record the Recorded Documents in the Real Estate Records or to file with BLM the BLM Assignment to Buyer.

2

Buyer PSA Guaranty: The Guaranty of certain obligations of Buyer under this Agreement, in the form attached hereto as Exhibit I, executed by CorEnergy.

Central Gathering Facility or CGF: The four locations within the Liquids Gathering System at which condensate, produced water, and associated natural gas is collected and separated for sale and transport off the subject location or alternatively, in the case of associated natural gas, used for fuel or flared on the subject location. A legal description of each of CGF#1, CGF#2, CGF#3, and CGF#4 is set out on the attached Exhibit U.

CGF#1: means the Central Gathering Facility identified in the “Identification” header on Exhibit U attached hereto as “Central Gathering Facility #1”.

CGF#2: means the Central Gathering Facility identified in the “Identification” header on Exhibit U attached hereto as “Central Gathering Facility #2”.

CGF#3: means the Central Gathering Facility identified in the “Identification” header on Exhibit U attached hereto as “Central Gathering Facility #3”.

CGF#4: means the Central Gathering Facility identified in the “Identification” header on Exhibit U attached hereto as “Central Gathering Facility #4”.

Closing Deliveries: The Seller Closing Deliveries and the Buyer Closing Deliveries.

Code: the Internal Revenue Code of 1986, as amended. All references to the Code, Treasury Regulations or other governmental pronouncements shall be deemed to include references to any applicable successor regulations or amending pronouncements.

Condensate: Liquid hydrocarbons.

Condensate Loading Point: The condensate loading coupling off each condensate storage tank located on a Central Gathering Facility on the Effective Date, as the Condensate Loading Points may be modified consistent with the terms of this Agreement on or prior to the Closing Date.

Condensate Terminus Point: The (a) inlet flange for each LACT Unit Facility and (b) each Condensate Loading Point.

Confidentiality Agreement: The Confidentiality and Nondisclosure Agreement dated as of December 1, 2011, between Corridor Energy, LLC, and Ultra Resources.

Confidential Information: (i) all Proprietary Information, and (ii) all other information furnished to Buyer by or on behalf of Seller, Ultra Resources or any of their respective Affiliates and designated as confidential. Notwithstanding the foregoing, Confidential Information shall not include information that is publicly available other than as a result of actions in violation of Article VI hereof.

3

Confidentiality Provisions: The terms, conditions and requirements of Article VI of this Agreement.

Control: The possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. “Controlling” and “Controlled” have meanings correlative thereto.

CorEnergy: CorEnergy Infrastructure Trust, Inc., a Maryland corporation, formerly known as Tortoise Capital Resources Corporation.

Current Funds: Wire transfers of immediately available funds to Seller.

Diligence Commencement Date: February 1, 2012.

Disclosing Party: The Party disclosing Confidential Information to the Recipient Party.

Easement Rights: Collectively, the right, title and interest in the BLM Easements conveyed to Buyer under the BLM Easements Assignment to Buyer, the right, title and interest in the Jensen Easements conveyed to Buyer under the Partial Assignment of Jensen Easements to Buyer, and the Nerd Farm Easement (but exclusive of the Improvements transferred pursuant to the Nerd Farm Easement).

Easements: The BLM Easements, the Jensen Easements and the Nerd Farm Easement.

Environmental Laws: All federal, state, and local laws, statutes, rules, regulations, orders, judgments, ordinances, codes, injunctions, decrees, and other legally enforceable requirements relating to (i) pollution or protection of the environment or natural resources, (ii) any actual or threatened depositing, spilling, leaking, pumping, pouring, placing, emitting, discarding, abandoning, emptying, discharging, migrating, injecting, escaping, leaching, dumping or disposing into the environment of, or any exposure to, any Hazardous Substances or (iii) the generation, manufacture, processing, distribution, use, treatment, storage, transport, disposal or handling of any Hazardous Substances; including the federal Comprehensive Environmental Response, Compensation and Liability Act, the Superfund Amendments and Reauthorization Act, the Resource Conservation and Recovery Act, the Clean Air Act, the Clean Water Act, the Safe Drinking Water Act, the Toxic Substances Control Act, the Oil Pollution Act of 1990, the Federal Hazardous Materials Transportation Law, the Marine Mammal Protection Act, the Endangered Species Act, and the National Environmental Policy Act, each as amended through the Closing Date.

Environmental Permit: Any permit, approval, identification number, license, registration, certification, consent, exemption, variance or other authorization required under or issued pursuant to any applicable Environmental Law.

Equity Investors Agreement: The Equity Investors Agreement in the form attached to this Agreement as Exhibit J, executed by Buyer, Seller, CorEnergy, Pinedale GP, Inc. and Ross Avenue Investments, LLC.

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Flash Gas Terminus Point: means: (a) with respect to CGF#1, CGF #3, and CGF #4, the gas outlet flange on the Effective Date to each dehydrator located on each such Central Gathering Facility; and (b) with respect to CGF #2, the gas outlet flange on the Effective Date on (i) each three-phase heated separator located on CGF #2, (ii) each condensate storage tank located on CGF #2, and (iii) each water storage tank located on CGF #2, in each case, as the Flash Gas Terminus Points may be modified consistent with the terms of this Agreement on or prior to the Closing Date.

Flow and Volume Information: any Actual Daily Product Volume information or similar flow and volume information furnished or made available by Seller or Ultra Resources.

GAAP: means generally accepted accounting principles in effect in the United States of America from time to time or at a specific time if so specified in this Agreement.

Hazardous Substance: (a) Any substance that is designated as a hazardous waste, solid waste, hazardous material, pollutant, contaminant or toxic or hazardous substance, as those terms are used in the Comprehensive Environmental Response, Compensation, and Liability Act, (b) any petroleum, petroleum hydrocarbons, petroleum products, petrochemical products and any components, fractions or derivatives thereof, any oil or gas exploration or production waste, and any natural gas, synthetic gas, and any mixtures thereof, and (c) radioactive materials or polychlorinated biphenyls.

Improvements: All of the improvements and fixtures used directly in connection with the Liquids Gathering System, including, without limitation, any and all surface and/or subsurface pipelines, surface and/or subsurface machinery and equipment, line pipe, pipe connections, fittings, flanges, welds, or other interconnections, valves, control and monitoring equipment, cathodic or electrical protection units, by-passes, regulators, drips, treating equipment, dehydration equipment, separation equipment, processing equipment, condensate and water storage tanks and other storage facilities, generators, gas compressors, vapor recovery units, combustors, flares, storage sheds, towers, gas and electric fixtures, radiators and heaters, in each case that are downstream of the inlet flange to each LGS Pipeline Riser and that are upstream of each LGS Terminus Point, including any of the foregoing described on the attached Exhibit T, but specifically excluding (i) any of the facilities, improvements and fixtures located upstream of the inlet flange to each LGS Pipeline Riser (an example of such an inlet flange is shown, for the Parties’ convenience, on the photograph on the attached Exhibit V) and (ii) any of the facilities, improvements or fixtures located downstream of each LGS Terminus Point, except in each case to the extent explicitly described on Exhibit T. The term “Improvements” includes all of the improvements and fixtures which are a part of the Liquids Gathering System as described herein, regardless of whether they are included or properly described in Exhibit T.

Indebtedness: With respect to a Person, such Person’s (a) liabilities for borrowed money, (b) liabilities for the deferred purchase price of property acquired by it (excluding accounts payable arising in the ordinary course of businesses), (c) obligations that are required to be accounted for as capital leases on a balance sheet under GAAP (and the amount of such obligations shall be the capitalized amount thereof determined in accordance with GAAP), and (d) guaranty obligations with respect to liabilities of another Person of the type described in the preceding subsections (a)-(c).

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Insurance Policies: The material policies of general liability, workers’ compensation and other insurance held as of the Effective Date by Seller or its Affiliates with respect to the Assets.

Jensen Easements: The following easements: (a) that certain Grant of Pipeline Easements dated June 24, 2010, recorded in Book 95, Page 423 of the Records of the Sublette County Clerk’s Office, Sublette County, Wyoming, from Mary Kay Jensen, as grantor, to Ultra Resources, as grantee, and (b) that certain Grant of Pipeline Easements dated June 24, 2010, in Book 95, Page 418 of the Records of the Sublette County Clerk’s Office, Sublette County, Wyoming, from Mary Kay Jensen, as personal representative of the Estate of John Wayne Jensen, individually, as grantor, to Ultra Resources, as grantee, as both such easements were assigned by Ultra Resources to Seller pursuant to the BLM and Jensen Easements Assignment to Seller.

LACT Unit Facilities: The condensate pump, meter and sales point as well as the associated equipment downstream of the inlet risers to any Lease Automated Custody Transfer Unit located on a Central Gathering Facility.

Land: The land underlying, subject to and covered by the Easement Rights.

Lease: The Lease of the Assets from Buyer to Lessee, in the form attached hereto as Exhibit L, executed by Lessee, as lessee, and Buyer, as lessor, provided however, if Lessee determines that its deemed incremental borrowing rate for this transaction has declined materially after the Effective Date, then at any time on or before the Closing Date, Lessee may request that the Specified Discount Rate set forth in Section 23.2(a)(i) of the Lease be reduced to the amount that is specified by Lessee as its deemed incremental borrowing rate for this transaction. If Lessee makes such request, then the Specified Discount Rate set forth in Section 23.2(a)(i) of the Lease shall be the amount specified by Lessee in such request. As used in this definition, “this transaction” means the transactions pursuant to this Agreement.

Lessee: Ultra Wyoming LGS, LLC, a Delaware limited liability company.

Lessee Lease Guaranty: The Guaranty of certain obligations of Lessee under the Lease, in the form attached hereto as Exhibit M, executed by Ultra Petroleum.

Lessor Lease Guaranty: The Guaranty of certain obligations of Buyer under the Lease, in the form attached hereto as Exhibit N, executed by CorEnergy.

LGS Pipeline Riser: The pipeline riser downstream of the liquids legs of the production separators located on each of the producing well pads described on the attached Exhibit S, as each is in existence on the Effective Date, as they may have been modified consistent with the terms of this Agreement on or prior to the Closing Date.

LGS Terminus Point: Each Flash Gas Terminus Point, each Condensate Terminus Point and each Produced Water Terminus Point.

Lien: Any mortgage lien, deed of trust lien, vendor’s lien, security interest, mechanic’s or materialman’s lien, or other lien.

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Liquids Gathering System: Generally, the system of pipelines and central gathering facilities highlighted on the map attached as Exhibit F, together with the related equipment that is capable of gathering, separating, collecting, and delivering for sale or transport, condensate and water, together with associated natural gas, produced from natural gas and oil wells that are operated by Ultra Resources and are located in the Pinedale Anticline Field in Sublette County, Wyoming, including, specifically, the Easement Rights and the Improvements, which Liquids Gathering System begins at the inlet flange to each LGS Pipeline Riser (an example of such an inlet flange is shown, for the Parties’ convenience, on the photograph on the attached Exhibit V), extends through an interconnected system of pipelines to the production and separation equipment and storage tanks located at the Central Gathering Facilities, and terminates at each LGS Terminus Point.

Material Adverse Effect: Any circumstance, change, or effect that is materially adverse to the ownership, operation, or financial condition of the Assets, taken as a whole.

Material Adverse Effect for Closing Conditions: Any circumstance, change, or effect that is materially adverse to the ownership, operation, or financial condition of the Assets, taken as a whole, but excluding any circumstance, change, or effect resulting or arising from: (a) any general change in conditions in the industries or markets in which Seller operates; (b) seasonal reductions in revenues and/or earnings of Seller in the conduct of its business with respect to the Assets in the ordinary course; (c) any adverse change, event, or effect on the global, national, or regional energy industry as a whole, including those impacting energy prices or the value of gathering assets and properties or other commodities, goods, or services, or the availability or costs of hedges; (d) national or international political conditions, including any engagement in hostilities, whether or not pursuant to declaration of a national emergency or war, or the occurrence of any military or terrorist attack; (e) changes in law or generally accepted accounting procedures, or the interpretation thereof; (f) the entry into or announcement of this Agreement, actions contemplated by this Agreement, or the consummation of the transactions contemplated hereby; (g) any failure to meet internal or third party projections or forecasts or revenue or earnings or reserve predictions; (h) changes or developments in financial or securities markets or the economy in general; (i) effects of weather, meteorological events, natural disasters, or other acts of God; or (j) fire or other casualty.

Memo of Lease: The Memorandum of Lease in the form attached to this Agreement as Exhibit O.

Nerd Farm Easement: The Easement Agreement and Transfer of Improvements in the form attached to this Agreement as Exhibit P.

Nerd Farm Judgment: Judgment dated December 8, 2010, recorded January 6, 2011, in Book 96, Page 421 of the Miscellaneous Records of Sublette County, Wyoming, against Questar Exploration and Production Company et al and in favor of Doyle Hartman et al.

Nerd Farm Mortgage: Mortgage recorded April 30, 1997, recorded in Book 68, Page 75 of the Mortgage Records of Sublette County, Wyoming, from Nerd Enterprises, Inc., to George P. Westman.

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Nerd Farm Title Policy: An Owner Policy of Title Insurance issued by a title insurer acceptable to Buyer, to be procured by Buyer at Buyer’s expense, insuring the easement estate of Buyer in the Nerd Farm Easement.

Non-Foreign Affidavit: The Non-Foreign Affidavit (Federal) in the form attached to this Agreement as Exhibit Q, executed by Seller, and equivalent forms, if any, required by the State of Wyoming.

Outside Closing Date: December 21, 2012, or such other date as may be mutually agreed in writing by Buyer and Seller, in either case as such date may be automatically extended upon a Major Casualty Loss if Buyer and Seller fail to terminate this Agreement, but only as and to the extent expressly provided in Section 5.2.

Partial Assignment of Jensen Easements to Buyer: The Partial Assignment of Easements and Transfer of Improvements (LGS) [Jensen Easements] to be executed by Seller and Buyer and with their signatures acknowledged, in the form attached to this Agreement as Exhibit A.

Person: Any individual, firm, corporation, partnership, limited liability company, incorporated or unincorporated association, joint venture, governmental authority or any other entity of any kind.

Personal Property: (a) The monitoring equipment located in or on the Liquids Gathering System, (b) the computer hardware located in the centralized monitoring building for each CGF constituting a portion of the Liquids Gathering System to which such monitoring equipment connects, (c) the wires and other connectors for such monitoring equipment between such computer hardware and such monitoring equipment, (d) all office furniture in each centralized monitoring building for each Central Gathering Facility, (e) engineering drawings and plans and specifications in Seller’s possession for the Liquids Gathering System except to the extent assignment thereof is prohibited by contract or applicable law, (f) as-built drawings and surveys of the Liquids Gathering System in Seller’s possession, and (g) to the extent assignable, the other Records.

Produced Water Terminus Point: Each outlet flange to the water pump facility or facilities, as the case may be, on each Central Gathering Facility that is directly upstream of each water meter and through which the produced water flows after it is separated from the condensate and the associated natural gas, as in existence on the Effective Date, as they may be modified consistent with the terms of this Agreement on or prior to the Closing Date.

Proprietary Information: (a) the business concept, operating techniques, marketing methods, financial information, plans, site and system renderings, schedules, itemized costs, development plans and all related trade secrets or confidential or proprietary information treated as such by Seller, whether by course of conduct, by letter or report or by use of any appropriate proprietary stamp of legend designating such information item to be confidential or proprietary, by communication to such effect made prior to or at the time any such Proprietary Information is disclosed to Buyer, or otherwise, (b) all financial statements and financial information relating to the Liquids Gathering System delivered to Buyer by Seller and Ultra Resources pursuant to Article IV, and (c) all Flow and Volume Information. Notwithstanding the foregoing, Proprietary Information shall not include information that is publicly available other than as a result of actions in violation of Article VI hereof.

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Recipient Party: The Party receiving, directly or by delivery to its Representatives, Confidential Information disclosed by or on behalf of the other Party hereto.

Records: The following information, to the extent in Seller’s Possession: all engineering drawings or plans of or covering the Liquids Gathering System or any component thereof, site assessments and environmental reports regarding or covering the Liquids Gathering System or any component thereof, manuals relating to the operation of the Assets, and “as-built” surveys of the pipelines and drawings of the Liquids Gathering System.

Representatives: Those Persons including, without limitation, officers, directors, employees, accountants, attorneys consultants, independent contractors, agents, stockholders, members, partners, actual or potential financing sources, investment advisers, and investment bankers, with a need to know the Confidential Information in order to evaluate the Transaction.

Resources Guaranty: The Limited Guaranty of Collection, in the form attached hereto as Exhibit H, executed by Ultra Resources.

Seller Closing Deliveries: The Equity Investors Agreement executed by Seller, the Lease executed by Lessee, the Memo of Lease executed by Lessee and with its signature acknowledged, the BLM Easements Assignment to Buyer, executed by Seller and with its signature acknowledged, the BLM Request for Consent to Assignment to Buyer executed by Seller, the Partial Assignment of Jensen Easements to Buyer executed by Seller and with its signature acknowledged, the Nerd Farm Easement executed by Seller and with its signature acknowledged, the Bill of Sale, executed by Seller, the SNDA executed by Lessee, Ultra Petroleum and Ultra Resources and with their signatures acknowledged, the Non-Foreign Affidavit executed by Seller, the Lessee Lease Guaranty executed by Ultra Petroleum and the Resources Guaranty executed by Ultra Resources.

Seller PSA Guaranty: The Guaranty of certain obligations of Seller under this Agreement, in the form attached hereto as Exhibit R, executed by Ultra Petroleum.

Seller’s Knowledge: As of any date, the then current actual knowledge of Seller’s Representatives as of such date, and not any implied, imputed or constructive knowledge of such individuals, and without any independent investigation or inquiry having been made or any implied duty to investigate, make any inquiries or review any information. The foregoing qualification of Seller’s Knowledge shall in no event give rise to any personal liability on the part of any Seller’s Representative or any other officer or employee of Seller or its Affiliates on account of any breach of any representation or warranty made by Seller herein. No broker, agent or Person other than Seller is authorized to make any representation or warranty for or on behalf of Seller.

Seller’s Possession: With respect to information, records and materials, only such information, records and materials as may be in the actual possession or control of Seller or its Affiliates, and without including any information or materials in the possession or control of a third Person or any other agent of Seller or its Affiliates.

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Seller’s Representatives: As of any date, the Chief Executive Officer, the Senior Vice President of Operations and the Chief Financial Officer of Ultra Resources.

Services Agreement: The Services Agreement dated as of January 1, 2012, between Ultra Resources, as Services Provider, and Seller.

SNDA: The Subordination, Non-Disturbance and Attornment Agreement (Liquids Gathering System, Sublette County, Wyoming) to be executed by KeyBank, N.A., Lessee and Buyer, in the form attached hereto as Exhibit K.

Subsidiary: With respect to any Person (the “parent”) at any date, any corporation, limited liability company, partnership, association or other entity the accounts of which would be consolidated with those of the parent in the parent’s consolidated financial statements if such financial statements were prepared in accordance with generally accepted accounting principles as of such date, as well as any other corporation, limited liability company, partnership, association or other entity (a) of which securities or other ownership interests representing more than fifty percent (50%) of the equity or more than fifty percent (50%) of the ordinary voting power or, in the case of a partnership, more than fifty percent (50%) of the general partnership interests are, as of such date, owned, controlled or held, or (b) that is, as of such date, otherwise Controlled, by the parent or one or more subsidiaries of the parent or by the parent and one or more subsidiaries of the parent.

Survival Period: The period beginning on the Closing Date and ending twelve (12) months following the Closing Date.

Tax or Taxes: (a) all federal, state, local or foreign income, gross receipts, license, payroll, employment, excise, severance, stamp, occupation, premium, windfall profits, environmental (including taxes under Section 59A of the Code), customs, duties, capital stock, franchise, profits, withholding, social security (or similar), unemployment, disability, real property, personal property, sales, use, transfer, escheat, registration, value added, alternative or add-on minimum, estimated or any other taxes, unclaimed property liabilities, any payments in lieu of taxes or other similar payments, charges, fees, levies, imposts, customs or duties of any kind whatsoever, that are imposed by a Taxing Authority, including any interest, penalty, or addition thereto, whether disputed or not and including any obligations to indemnify or otherwise assume or succeed to the tax liability of any other Person or (b) any liability for the payment of any taxes, interest, penalty, addition to tax or like additional amount resulting from the application of Treasury Regulation Section 1.1502-6 or comparable federal, state or local laws.

Tax Return: any return, declaration, report, claim for refund, property rendition or information return or statement relating to Taxes, including any schedule or attachment thereto and including any amendment thereof.

Taxing Authority: a governmental entity having jurisdiction over the assessment, determination, collection, or other imposition of any Tax.

Treasury Regulations: the regulations promulgated by the United States Treasury Department under the Code.

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Ultra Petroleum: Ultra Petroleum Corp., a Yukon Territory of Canada corporation.

Ultra Resources: Ultra Resources, Inc., a Wyoming corporation.

1.2 Certain Interpretive Provisions. As used in this Agreement: (a) the word “or” is not exclusive and the word “including” is not limiting, (b) references to a law include any rule or regulation issued under the law and any amendment to the law, rule or regulation, (c) whenever the words “include,” “includes,” or “including” appear, they shall be deemed to be followed by the words “without limitation,” (d) personal pronouns shall be deemed to include the other genders and the singular shall include the plural and vice versa, and (e) the words “herein,” “hereof’ and “hereunder” and other words of similar import refer to this Agreement as a whole and not to any particular Article, Section or other subdivision. Wherever a period of time is stated in this Lease as commencing or ending on specified dates, such period of time shall be deemed (i) inclusive of such stated commencement and ending dates, and (ii) to commence at 12:00 A.M. Central Time on such stated commencement date and to end at 11:59 P.M. Central Time on such stated ending date. Unless the context otherwise requires, (A) any definition or reference to any agreement, instrument or other document shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (B) subject to restrictions on assignment set forth herein, any reference herein to any Person shall be construed to include such Person’s successor and assigns, and (C) any reference to any law shall include all statutory and regulation provisions consolidating, amending, replacing or interpreting such law and reference to any law or regulation shall, unless otherwise specified, refer to such law or regulation as amended, modified or supplemented from time to time. Section headings herein are included for convenience of reference only and shall not affect the interpretation of this Agreement or any other document executed in connection herewith.

ARTICLE II

PURCHASE AND SALE

2.1 Purchase and Sale. Seller agrees to sell the Assets to Buyer, and Buyer agrees to purchase the Assets from Seller, pursuant to, and subject to the terms and conditions of, this Agreement.

2.2 Nonrefundable Consideration Contemporaneously with the execution and delivery of this Agreement, Buyer has delivered to Seller, and Seller herby acknowledges the receipt of, a check in the amount of $100.00 (the “Independent Contract Consideration”), which amount the Parties bargained for and agreed to as consideration for Buyer’s right to inspect and purchase the Assets pursuant to this Agreement, and for Seller’s execution, delivery and performance of this Agreement. The Independent Contract Consideration is in addition to and independent of any other consideration or payment provided in this Agreement, is nonrefundable, and is fully earned and shall be retained by Seller notwithstanding any other provision of this Agreement.

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ARTICLE III

PURCHASE PRICE

3.1 Purchase Price. The purchase price for the Assets shall be Two Hundred Twenty-five Million U.S. Dollars (U.S. $225,000,000) (the “Purchase Price”). If the transaction contemplated by the Transaction Documents (“Transaction”) closes, Buyer agrees to pay to Seller the Purchase Price at Closing in Current Funds.

ARTICLE IV

BUYER’S INSPECTION

4.1 Access to Records, Insurance Policies and Services Agreement. Prior to the Effective Date and pursuant to the Confidentiality Agreement, Seller has provided Buyer and its Affiliates and Representatives with access to the Liquids Gathering System and to certain information about the Liquids Gathering System, and has made available to Buyer and such Persons certain of Seller’s officers, employee, agents and others for question and answer sessions related to the Liquids Gathering System, including during two field tours of the Liquids Gathering System, all of which inspections and information shall for all purposes be deemed to have been made pursuant to, and shall in all respects be subject to, this Agreement. From and after the Effective Date until Closing, and subject to the Confidentiality Provisions, upon reasonable advance notice and compliance with applicable law governing the access to or use of such Confidential Information, Seller will make originals or copies of the Records and the Insurance Policies, in each case only to the extent such documents and information are in Seller’s Possession, and the Services Agreement, available to Buyer and its Representatives for inspection and review during normal business hours to permit Buyer to perform its due diligence review. Subject to the consent and cooperation of third parties and subject to the Confidentiality Provisions, Seller will assist Buyer in Buyer’s efforts to obtain, at Buyer’s expense, such additional information from third parties as Buyer may reasonably request in writing, for the purposes of Buyer’s due diligence review.

4.2 Disclaimer. Except for Seller’s Warranties, Seller makes no warranty or representation of any kind as to the Records or the Insurance Policies or any other information provided by or on behalf of Seller or its Affiliates to Buyer or its Affiliates or Representatives in connection with Buyer’s review of the Assets or the Transaction.

4.3 Access to the Assets. Subject to the Confidentiality Provisions, Seller agrees to grant Buyer access to the Assets during reasonable business hours and after prior reasonable written notice, with Seller’s representative present and Buyer complying with Seller’s rules and regulations, including safety, so Buyer may, at its sole risk and expense, (a) conduct non-invasive on-site inspections and environmental assessments of the Assets and (b) conduct inspections of the operation of the Assets and prepare to assume ownership of the Assets after Closing. Buyer acknowledges and agrees that: (1) Seller owns oil and gas wells, leases, and other related properties in and around the Assets separate and apart from the Liquids Gathering System and the Personal Property; (2) Ultra Resources operates such oil and gas wells, leases, and other related properties and may itself own rights and property in and around the Assets

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separate and apart from the Liquids Gathering System and the Personal Property; (3) after the Closing, Seller intends to continue to own such oil and gas wells, leases, and other related properties; (4) after the Closing, Ultra Resources intends to continue to operate such oil and gas wells, leases, and other related properties, to own its other rights and property in and around the Assets, and to co-use the Jensen Easements as contemplated in the Partial Assignment of Jensen Easements to Buyer; and (5) nothing in this Agreement or otherwise gives Buyer or any of its Representatives any right to make inspections or investigations with respect to such operations, oil and gas wells, leases, and other related properties. If Buyer or its agents prepares an environmental assessment of any Asset, Buyer agrees to keep such assessment confidential (unless legally required to disclose) and to furnish copies thereof to Seller. In connection with any on-site inspections, Buyer (a) agrees not to interfere with the normal operation of the Assets, (b) agrees to comply with Seller’s requirements of the operators of the Assets and (c) represents that it is adequately insured. Buyer waives, releases and agrees to indemnify, defend and hold harmless Seller and its Affiliates, and each of their directors, officers, shareholders, members, employees, agents and representatives against all claims, liabilities and obligations, including without limitation, personal injury, death and/or property damage, arising from Buyer’s activities or inspection of the Assets, the Records, the Insurance Policies or any other related information prior to Closing, except to the extent such liabilities or damages are caused by Seller’s gross negligence or willful misconduct, and such indemnification shall survive Closing and termination of this Agreement. The provisions of this Section 4.3 shall survive termination of this Agreement for a period of twelve (12) months after such termination and shall survive Closing until the expiration of the Survival Period.

ARTICLE V

TITLE MATTERS; CASUALTY; CONSENTS

5.1 Title. Except for Seller’s Warranties, neither Seller nor any of its Affiliates makes any representation or warranty, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets, except by, through and under Seller and its Affiliates, but not otherwise, and Buyer hereby acknowledges and agrees that Buyer has no claim or remedy against Seller or its Affiliates, or their respective successors or assigns, for any defect of title relating to the Assets, including but not limited to any lien, encumbrance, claim, defect in or object to real property title, and the existence or non-existence of any leases, easements or rights-of-way, except those claims or rights against the Assets that arise by, through and under Seller and its Affiliates, but not otherwise.

5.2 Casualty Loss. If (a) a portion of the Assets is damaged or destroyed by fire or other casualty prior to Closing (“Casualty Loss”) and such Casualty Loss is not a Major Casualty Loss, or (b) such Casualty Loss is a Major Casualty Loss but neither Seller nor Buyer elect to terminate this Agreement as permitted in this Section 5.2, then (i) this Agreement will remain in full force and effect and the Parties shall proceed to close the Transaction, without adjustment or reduction to the Purchase Price, (ii) the insurance proceeds shall be paid to Seller to be used and applied as provided in the Lease, and (iii) Seller will commence to repair, restore and/or replace the Assets or part thereof damaged or destroyed by such fire or other casualty as soon as reasonably practicable to substantially the same condition as immediately prior to the Casualty Loss and in a manner consistent with the applicable provisions of the Lease (the “Restoration Operations”), (iv) if the Restoration Operations cannot be completed prior to the

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Closing Date but can be completed prior to the Outside Closing Date, the Closing Date shall be automatically extended until the Restoration Operations are complete (but not beyond the Outside Closing Date), and (v) if the Major Casualty Notice indicates that the Restoration Operations cannot be completed by the Outside Closing Date and neither Seller or Buyer terminates the Agreement pursuant to this Section 5.2, then the Outside Closing Date shall be automatically extended until the estimated completion date for the Restoration Operations as set forth in the Major Casualty Notice. If Seller determines in good faith that either (A) the Casualty Loss is greater than Ten Million Dollars ($10,000,000), or (B) the casualty cannot be repaired, restored or replaced prior to the Outside Closing Date (each, a “Major Casualty Loss”), Seller shall so notify Buyer in writing (“Major Casualty Notice”), and either Seller or Buyer may elect to terminate this Agreement by giving written notice of termination to the other Party within five (5) Business Days following the date of Seller’s Major Casualty Notice. Upon any such termination, neither Seller nor Buyer shall have any further rights or obligations hereunder except those which expressly survive termination. Seller shall consult with Buyer regarding any Casualty Loss in excess of Two Million ($2,000,000.00) and consider in good faith any input from Buyer as to whether such Casualty Loss is a Major Casualty Loss prior to making any determination in respect thereof.

5.3 Consents.

(a) Buyer and Seller acknowledge that BLM consent to the assignment of a right of way or easement from BLM is customarily not requested or obtained until after the closing of the actual assignment of such right of way or easement. Buyer and Seller shall use commercially reasonable efforts after Closing to obtain the BLM Consent, through submission of the BLM Request for Consent to Assignment to Buyer in the form attached hereto as Exhibit B, with such changes to such form as may be required by changes in applicable law or regulations after the Effective Date. Buyer shall pay any costs or expenses assessed by BLM in connection with such BLM Request for Consent to Assignment to Buyer.

(b) Prior to Closing, Seller shall request of the BLM that the BLM Easement issued under the Federal Land Policy Management Act be converted to a right-of-way under the Mineral Leasing Act of 1920 (or issue a new right-of-way under the Mineral Leasing Act of 1920 covering the same lands for the same purposes). If such conversion (or new issuance) is not completed by September 1, 2013, Seller shall, as expeditiously as possible, either (i) obtain the written approval of the BLM to Lessee’s use of such BLM Easement pursuant to the Lease, or (ii) obtain an amendment to such BLM Easement to allow such use and the sublease thereof. Such September 1, 2013, date may be extended by Buyer if Seller has demonstrated to Buyer’s reasonable satisfaction that the conversion (or new issuance) is imminent. Seller shall, as expeditiously as possible, take all action the BLM deems necessary or appropriate (including making any such filings, providing such information, materials and documentation and obtaining such approvals, consents and other action as is necessary or appropriate) in connection with the transfer of the BLM Easements to Buyer, the lease of the BLM Easements by Lessee pursuant to the Lease, and the use of such BLM Easements by Lessee pursuant thereto. For purposes of this Agreement, the term “Other BLM Matters” means the issues, matters and obligations under this Section 5.3(b).

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(c) Except for the BLM Consent and the Other BLM Matters, if prior to Closing Seller or Buyer discovers a consent necessary for the valid assignment of the Assets, or a portion thereof, required by either (a) the contract or agreement granting or creating Seller’s rights in an Asset component (other than a consent to assignment of the Records or any part of the Records, which shall not be considered an Additional Required Consent) or (b) a law applicable to the transfer of an Asset component from Seller to Buyer hereunder (other than the BLM Request for Consent to Assignment to Buyer) (each, and except for the BLM Consent and the Other BLM Matters (which are governed by subsections (a) and (b), above), an “Additional Required Consent”) such Party shall promptly notify the other of the need for such Additional Required Consent, the Seller shall use commercially reasonable efforts to obtain such Additional Required Consent, and Buyer shall cooperate (without any obligation on Buyer’s part to make any payments or incur any liabilities) with Seller in a commercially reasonable manner. In connection with Seller’s efforts to acquire any Additional Required Consent, “commercially reasonable efforts” may include the payment of reasonable costs and expenses in connection therewith. Unless and until any such Additional Required Consent is obtained, to the extent permitted by applicable law, the Parties will cooperate in good faith to establish an arrangement reasonably satisfactory to Buyer and Seller under which Buyer would obtain the claims, rights and benefits associated with the Assets (or portion thereof) affected by such Additional Required Consents (the “Non-Assignable Assets”) and under which Seller would enforce for the benefit of Buyer any and all claims, rights and benefits of Seller associated with the Non-Assignable Assets against a third party thereto. Nothing in this Section 5.3 shall be deemed to constitute an agreement by Buyer to exclude from the Assets any of the Non-Assignable Assets. Seller will convey such Non-Assignable Assets to Buyer promptly upon receipt of the requisite Additional Required Consents with the Closing Date for such Non-Assignable Assets being adjusted appropriately, but subject in all other respects to the terms and conditions of this Agreement. Buyer and Seller agree, upon the request and at the expense of Buyer, to use commercially reasonable efforts to acquire consent to the assignment of any of the Records for which consent to assignment is required.

5.4 Nerd Farm Mortgage and Nerd Farm Judgment. For each of the Nerd Farm Mortgage and the Nerd Farm Judgment, Seller shall use commercially reasonable efforts to obtain prior to Closing either (a) a subordination to the Nerd Farm Easement, (b) a release, or (c) agreement of the Title Company to issue to Buyer the Nerd Farm Title Policy without exception for the Nerd Farm Mortgage and Nerd Farm Judgment. Upon receipt of any release or subordination, Seller shall cause such releases and subordinations to be recorded in the applicable public records of Sublette County, Wyoming.

ARTICLE VI

CONFIDENTIALITY

6.1 No Disclosure or Use of Confidential Information. Except as permitted in this Agreement, each Party agrees not to disclose the Confidential Information to any other Person not having a need to know such Confidential Information in connection with the evaluation of the Transaction, and to use all reasonable efforts to protect the confidentiality of such Confidential Information. Notwithstanding the foregoing, each Party may disclose Confidential Information to its Representatives; provided that each Party shall obtain an agreement from such Representatives to abide by the Confidentiality Provisions.

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6.2 Compelled and Anticipated Disclosure.

(a) If the Recipient Party is requested, through legal or administrative process, to disclose any Confidential Information, the Recipient Party must (a) disclose only that portion of the Confidential Information that the Recipient Party’s legal counsel advises is required to be disclosed, (b) use its reasonable efforts to ensure that the Confidential Information is treated confidentially, (c) notify the Disclosing Party as promptly as possible of the request for disclosure and the items of Confidential Information to be disclosed; and (d) if requested by Disclosing Party, reasonably cooperate with the Disclosing Party, at the Disclosing Party’s expense, in the Disclosing Party’s efforts to limit disclosure of such Confidential Information.

(b) The Parties acknowledge: (i) that Tortoise Capital Resources Corporation changed its name to CorEnergy and CorEnergy will conduct a public offering of its common stock to partially finance the Transaction and (ii) that the public offering will require or make appropriate the public disclosure of certain Confidential Information. In addition, the Parties acknowledge that CorEnergy is subject to the reporting obligations of the Securities Exchange Act of 1934 (the “34 Act”) and, as a result, it will be required or appropriate that CorEnergy make public disclosure of certain Confidential Information on a periodic basis. Further, the Parties acknowledge that the partners of Buyer will be entitled, under state partnership law and Buyer’s partnership agreement, to access to certain Confidential Information. Notwithstanding the foregoing, the Parties agree that neither Buyer nor CorEnergy shall, under any circumstance contemplated in this subparagraph (b), disclose any Proprietary Information in any securities law filing or to any Person who is a Disqualified Person as that term is defined in the Lease.

6.3 Ownership and Return. All Confidential Information will remain the property of the Disclosing Party, and no right or license is granted to the Recipient Party with respect to any Confidential Information. Except as explicitly noted in Section 13.3(f), nothing in this Agreement creates an agency or partnership relationship between the Parties. Upon the request of the Disclosing Party, the Recipient Party agrees to (a) immediately return to the Disclosing Party or destroy all Confidential Information, including copies of the same, and (b) destroy any memoranda, summaries, reports, documents or analyses created by the Recipient Party that contain or are based in any way on the Confidential Information. Upon the Disclosing Party’s request, the fact of any such destruction must be certified in writing to the Disclosing Party by an officer of the Recipient Party. Notwithstanding the foregoing, in the event the Recipient Party is required by federal securities laws to retain certain records, nothing herein shall prevent the Recipient Party from complying with its ordinary records retention policy, and each Recipient Party may retain Confidential Information contained or reflected in materials presented to its board of directors, to the extent required by law, or which would be unreasonably burdensome for it to destroy (such as archived computer records).

6.4 Standstill. The Recipient Party agrees that while it is in possession of material nonpublic information concerning the Disclosing Party, it will not purchase, sell or otherwise engage in any transaction in or related to the securities of: (a) the Disclosing Party, or (b) any entity in which the Disclosing Party has invested or advises and that is the subject of any of the Confidential Information. Each Party confirms that it is familiar with federal and state securities laws concerning material non-public information. Each Party hereby confirms that it will not use the Confidential Information in any manner inconsistent with those laws.

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6.5 Attorneys’ Fees. Notwithstanding anything set forth in this Agreement to the contrary, if the Disclosing Party commences a lawsuit or other proceeding against the Recipient Party under this Article VI and successfully enforces any of the provisions of this Article VI or on account of any damages sustained by the Disclosing Party by reason of the Recipient Party’s proven violation of any provisions of this Article VI, the Recipient Party agrees that it will pay, in addition to other costs and damages, the Disclosing Party’s reasonable attorneys’ fees.

6.6 Announcements. Seller and Buyer shall consult with each other with regard to, and shall jointly review prior to issuance, all press releases and other announcements issued on or after the Effective Date concerning this Agreement or the transactions contemplated hereby so as to ensure consistency of description of the Transaction.

6.7 Injunctive Relief. Notwithstanding anything set forth in this Agreement to the contrary, the Recipient Party agrees that if it breaches any provision of this Article VI, the Disclosing Party may suffer irreparable damages and its remedy at law may be inadequate. Therefore, if the Recipient Party breaches this Agreement, the Disclosing Party will be entitled, in addition to the damages provided for in Section 6.5, above, and all other remedies available to it at law or in equity, to seek equitable relief, including specific performance and injunctive relief to enforce any provision hereof and to restrain the Recipient Party from using or disclosing, in whole or in part, directly or indirectly, any Confidential Information.

6.8 Survival. The Parties shall comply with this Article VI until Closing. The actions of the Parties with respect to Confidential Information after Closing shall be governed by the provisions of the Lease. Notwithstanding the foregoing, the rights of the Parties to enforce the provisions of this Article VI for actions taken prior to Closing shall survive Closing. If, for any reason, this Agreement is terminated and Closing does not occur, the provisions of this Article VI shall survive termination of this Agreement for a period of twelve (12) months following the date of such termination.

ARTICLE VII

SELLER’S REPRESENTATIONS

Seller represents and warrants to Buyer as of the Effective Date and as of the Closing Date the following:

7.1 Incorporation/Qualification. Seller is a Wyoming corporation, duly organized, validly existing and in good standing under the laws of the State of Wyoming and is qualified to conduct business in Wyoming.

7.2 Power and Authority. Seller has all requisite power and authority to own the Assets and to carry on its business as presently conducted and to execute and deliver this Agreement and perform its respective obligations under this Agreement. The execution and delivery of this Agreement and consummation of the Transaction and the fulfillment of and compliance with the terms and conditions hereof will not violate, or be in conflict with, any material provision of its governing documents or any material provision of any agreement or instrument to which it is a party or by which it is bound or, to Seller’s Knowledge, any judgment, decree, order, statute, rule or regulation applicable to it.

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7.3 Authorization and Enforceability. The execution, delivery and performance of this Agreement and the Transaction have been duly and validly authorized by all requisite corporate action on behalf of Seller. This Agreement constitutes Seller’s legal, valid and binding obligation, enforceable in accordance with its terms, subject however, to the effects of bankruptcy, insolvency, reorganization, moratorium and similar laws for the protection of creditors, as well as to general principles of equity, regardless whether such enforceability is considered in a proceeding in equity or at law.

7.4 Liability for Brokers’ Fees. Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the Transaction for which Buyer shall have any responsibility whatsoever.

7.5 No Bankruptcy. Seller is solvent and will be solvent immediately before and after the Closing. There are no bankruptcy proceedings pending, being contemplated by or, to Seller’s Knowledge, threatened in writing against Seller.

7.6 Litigation. There are no actions, suits, or proceedings pending against Seller or any of the Assets in any court or by or before any federal, state, municipal or other governmental agency that would affect Seller’s ability to consummate the Transaction or have a Material Adverse Effect. To Seller’s Knowledge, (a) there are no ongoing governmental investigations or written governmental inquiries pending or threatened in writing against the Assets that would affect Seller’s ability to consummate the Transaction, and (b) there are no actions, suits or proceedings threatened in writing against Seller or any of the Assets that would affect Seller’s ability to consummate the Transaction. Neither Seller nor any of its Affiliates are subject to any outstanding injunction, judgment, settlement, order, decree, ruling or charge that would reasonably be expected to have a Material Adverse Effect.

7.7 Environmental Condition of Assets. To Seller’s Knowledge: (a) the Assets are and have been operated by Seller in material compliance with all Environmental Laws, and all material Environmental Permits have been procured; (b) there are no pending proceedings, and Seller has not received written notice of any threatened proceedings, asserting a violation of Environmental Laws or noncompliance with Environmental Permits against Seller with respect to the Assets or the operation of the Assets by Seller or its Affiliates, and (c) there has been no material release of any Hazardous Substances by Seller or its Affiliates, or by any other Person, on or about the Assets.

7.8 Assets. Ultra Resources operates the Liquids Gathering System for Seller pursuant to the Services Agreement. The Improvements and Personal Property are and have been maintained by Seller or its Affiliates consistent with the standards of a reasonably prudent operator in the area where such Assets are located except to the extent the failure to do so would not have a Material Adverse Effect. Neither Ultra Resources nor Seller has assigned or pledged, in whole or in part, its right, title or interest under any BLM Easement or either Jensen Easement, other than the assignment of such rights from Ultra Resources to Seller. The copies of the BLM Easements and the Jensen Easements furnished or made available to Buyer by Seller are true, correct and complete in all material respects. The BLM Easements and the Jensen Easements are in full force and effect. No material default exists under any of the BLM Easements or either of the Jensen Easements, and to Seller’s Knowledge, no events or conditions exist which, with or

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without notice or lapse of time or both, would constitute a material default thereunder or result in a termination of any such Easement except to the extent the grantor of any BLM Easement or the Jensen Easements has terminations rights unrelated to any default by the holder or beneficiary of such easement under applicable law or regulations or the express terms of the BLM Easements or the Jensen Easements. No part of the Liquids Gathering System was acquired by Seller or any of its Affiliates using eminent domain proceedings.

7.9 Taxes. To Seller’s Knowledge,

(a) Seller has (i) duly and timely filed or caused to be filed all Tax Returns required to be filed by or with respect to Seller or with respect to the Assets with the appropriate Taxing Authority, and each such Tax Return is complete and correct in all material respects and (ii) paid all Taxes due or claimed to be due by a Taxing Authority (whether or not shown as due on a filed Tax Return) from or with respect to Seller which, in the case of clauses (i) and (ii) above, if unpaid would result in the filing of a lien against the Assets for a material amount of Taxes.

(b) There are not pending any, and Seller has received no written notice of any currently proposed, material adjustments by any Taxing Authority in connection with any Tax Returns relating to the Assets which if unpaid would result in the filing of a lien against the Assets for a material amount of Taxes and no waiver or extension of any statute of limitations as to any federal, state, local or foreign Tax matter relating to the Assets has been given by or requested from Seller with respect to any Tax year.

(c) There are no liens for material Taxes upon any of the Assets except liens for Taxes not yet due and payable.

(d) Seller does not have any liability for any unpaid Taxes of any other Person under Treasury Regulation Section 1.1502-6 (or any similar provision of United States state, local, or foreign Law), as a result of being a member of a consolidated or combined group (other than a consolidated or combined group with a common parent with Seller), as a transferee, by contract, or otherwise.

7.10 Records, Insurance Policies, Services Agreement and Easements. To Seller’s Knowledge, the copies of the Records, the Insurance Policies, the BLM Easements and the Jensen Easements furnished or made available to Buyer are true, correct and complete. To Seller’s Knowledge: (a) no events or conditions exist which, with or without notice or lapse of time, or both, would constitute a default under the Services Agreement, the BLM Easements or the Jensen Easements, (b) neither Seller nor Ultra Resources has canceled, terminated, or modified, or threatened to cancel, terminate, or modify, the Services Agreement, (c) neither the grantor nor Seller nor Ultra Resources has canceled or terminated any of the BLM Easements or the Jensen Easements, (d) neither Seller nor Ultra Resources has threatened to cancel, terminate or modify any of the BLM Easements or the Jensen Easements (except as and to the extent set forth in the Closing Deliveries), (e) BLM has not threatened to cancel, terminate or modify the BLM Easements, and (f) the grantors of the Jensen Easements have not threatened to cancel, terminate or modify the Jensen Easements.

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7.11 Compliance with Laws. To Seller’s Knowledge: (a) Seller and its Affiliates are in compliance in all material respects with all applicable laws with respect to ownership, use and operation of the Assets by Seller and its Affiliates, and (b) Seller and its Affiliates have not received written notice from any governmental authority or any other Person alleging a material violation of, or material failure to comply with, any legal requirement applicable to the use, operation and ownership of the Assets by Seller and its Affiliates.

7.12 Governmental Authorizations. To Seller’s Knowledge: (a) Seller or its applicable Affiliates have obtained all material federal, state and local governmental licenses, permits, orders, exemptions, waivers, authorizations, certificates, consents and applications (collectively, “Authorizations”) that are presently necessary or required for the ownership and operation of the Assets, (b) Seller or its applicable Affiliates are in material compliance with all such Authorizations that are presently necessary or required for the ownership and operation of the Assets, and (c) all such Authorizations are in full force and there are no proceedings pending or threatened before any governmental authority that seek the revocation, cancellation, suspension, or adverse modification thereof.

7.13 Bonds, Letters of Credit, Guarantees. To Seller’s Knowledge, Schedule 7.13 identifies the bonds, letters of credit, guarantees, and security deposits posted (or supported) by Seller or any of its Affiliates with respect to the ownership of the Assets.

7.14 Ownership. Neither Seller nor Ultra Resources has transferred, assigned, pledged or conveyed its rights as “grantee” or “holder” under the BLM Easements or the Jensen Easements, other than pursuant to the BLM and Jensen Easements Assignment to Seller. Seller owns the Improvements and Personal Property free and clear of all Liens which secure Indebtedness (other than the Nerd Farm Mortgage and Nerd Farm Judgment) and no Improvements or Personal Property are held under a lease or installment sale contract. To Seller’s Knowledge, there are no condemnation proceedings pending or threatened in writing against any of the Assets. To Seller’s Knowledge, no portion of the Liquids Gathering System is located upon land other than the Land. As noted in Section 4.3, above, (a) Seller owns oil and gas wells, leases, and other related properties in and around the Assets separate and apart from the Liquids Gathering System and the Personal Property; (b) Ultra Resources operates such oil and gas wells, leases, and other related properties and may itself own rights and property in and around the Assets separate and apart from the Liquids Gathering System and the Personal Property; (c) after the Closing, Seller intends to continue to own such oil and gas wells, leases, and other related properties; (d) after the Closing, Ultra Resources intends to continue to operate such oil and gas wells, leases, and other related properties and owns its other rights and property in and around the Assets; and (e) nothing in this Agreement or otherwise gives Buyer or any of its Representatives any right to make inspections or investigations with respect to such operations, oil and gas wells, leases, and other related properties.

7.15 Consents. To Seller’s Knowledge, except for (a) the BLM Consent, (b) the Other BLM Matters (which shall be governed by Section 5.3(b)), and (c) any Additional Required Consent that may be discovered after the Effective Date, the consent of a third party to the transfer or assignment of such Asset component from Seller to Buyer hereunder is not required under any (i) contract or agreement granting or creating Seller’s rights in an Asset component or (ii) law applicable to the transfer of an Asset component from Seller to Buyer hereunder.

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7.16 Preferential Rights. To Seller’s Knowledge, no third party holds a preferential purchase right to purchase any Asset.

7.17 Material Agreements. There are no Material Agreements which cover, relate to or are otherwise associated with the ownership or operation of the Assets. For the purposes hereof, “Material Agreements” means any agreements binding on Seller or Ultra Resources, with respect to the ownership or operation of the Liquids Gathering System for which alternative agreements could not be readily procured and which, if terminated, would (i) impair the ability of an operator to operate the Liquids Gathering System or (ii) have an adverse economic impact on Buyer, but in any case “Material Agreements” shall exclude agreements related to the material or product that flows into or flows out of the Liquids Gathering System including, without limitation, leases, operating agreements, and sales or delivery agreements.

7.18 Sufficiency of the Assets. The Assets constitute all of the property and assets that comprise and are necessary for the ownership and operation of the Liquids Gathering System immediately prior to the Effective Date, assuming the existence of (i) the equipment and fixtures attached or connected to the Liquids Gathering System upstream of the inlet flange to each LGS Pipeline Riser and downstream of each LGS Terminus Point and (ii) the material or product that flows into or flows out of the Liquids Gathering System.

7.19 Adverse Change. Except as disclosed on Schedule 7.19, from and including June 30, 2012 through the Effective Date, (i) there has not been any circumstance, condition, event, or state of facts (either singly or in the aggregate) which has had, or reasonably would be expected to have, a Material Adverse Effect for Closing Conditions, and (ii) except for matters relating to the transactions contemplated by this Agreement or described in schedules to this Agreement, the Assets have been operated in the ordinary course of business consistent with past practices of Seller and Ultra Resources. Notwithstanding the foregoing provisions of this Section 7.19, the representation in clause (i) preceding is given only as of the Effective Date and is not made or deemed re-made as of the Closing Date.

7.20 Disclaimers. THE EXPRESS REPRESENTATIONS AND WARRANTIES OF SELLER CONTAINED IN THIS AGREEMENT (COLLECTIVELY “Seller’s Warranties”) ARE EXCLUSIVE AND ARE IN LIEU OF ALL OTHER REPRESENTATIONS AND WARRANTIES, EXPRESS, IMPLIED, STATUTORY OR OTHERWISE. SELLER EXPRESSLY DISCLAIMS ANY AND ALL SUCH OTHER REPRESENTATIONS AND WARRANTIES. WITHOUT LIMITATION OF THE FOREGOING AND, EXCEPT FOR SELLER’S WARRANTIES, THE INTEREST IN THE ASSETS TO BE CONVEYED TO BUYER SHALL BE CONVEYED PURSUANT HERETO WITHOUT (i) ANY WARRANTY, COVENANT OR REPRESENTATION WHETHER EXPRESS, IMPLIED, STATUTORY OR OTHERWISE RELATING TO TITLE TO THE ASSETS (OTHER THAN BY, THROUGH OR UNDER SELLER), THE CONDITION, QUANTITY, QUALITY, EXISTENCE OF DEFECTS, FITNESS FOR A PARTICULAR PURPOSE, CONFORMITY TO THE MODELS OR SAMPLES OF MATERIALS OR MERCHANTABILITY OF ANY EQUIPMENT OR PROPERTY OR ITS FITNESS FOR ANY PURPOSE OR (ii) ANY OTHER EXPRESS, IMPLIED, STATUTORY OR OTHER WARRANTY OR REPRESENTATION WHATSOEVER. BUYER IS RELYING SOLELY UPON ITS OWN INSPECTION OF THE ASSETS, AND, SUBJECT TO BUYER’S EXPRESS RIGHTS UNDER THIS AGREEMENT AND THE OTHER TRANSACTION DOCUMENTS, BUYER SHALL ACCEPT ALL OF THE SAME IN THEIR “AS IS”, “WHERE IS” CONDITION, “WITH ALL FAULTS”.

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7.21 Survival. Seller’s Warranties (a) are made as of the Effective Date, (b) are remade as of the Closing Date (except for the representation in Section 7.19(i)), (c) shall not be deemed to be merged into or waived by the Closing Deliveries, and (d) shall survive Closing only for the Survival Period. If Buyer first learns of a breach of Seller’s Warranties prior to Closing, Buyer’s remedies shall be governed solely and exclusively by Section 11.2. Notwithstanding anything to the contrary in this Agreement, if Buyer elects to proceed to Closing notwithstanding Buyer’s knowledge of the existence of a breach by Seller with respect to any Seller Warranty, Buyer shall be deemed to have waived each such breach and any and all rights and remedies in connection therewith. Seller shall have no liability or obligation to Buyer with respect to the breach of any representation or warranty of which Buyer first learns after Closing unless Buyer delivers written notice to Seller of the alleged breach prior to the end of the Survival Period, which notice must include the information described in clauses (i), (ii) and (iii) of Subsection 14.5(a).

ARTICLE VIII

BUYER’S REPRESENTATIONS

Buyer represents and warrants to Seller as of the Effective Date and as of the Closing Date the following:

8.1 Incorporation and Qualification. Buyer is a Delaware limited liability company, duly organized, validly existing and in good standing under the laws of the State of Delaware and on the Closing Date will be qualified to conduct business in Wyoming.

8.2 Power and Authority. Buyer has all requisite power and authority to execute and deliver this Agreement and perform its obligations under this Agreement. The execution and delivery of this Agreement and consummation of the Transaction and the fulfillment of and compliance with the terms and conditions hereof will not violate, or be in conflict with, any material provision of its governing documents or any material provision of any agreement or instrument to which it is a party or by which it is bound, or, to its knowledge, any judgment, decree, order, statute, rule or regulation applicable to it.

8.3 Authorization and Enforceability. The execution, delivery and performance of this Agreement and the Transaction have been duly and validly authorized by all requisite company action on behalf of Buyer. This Agreement constitutes Buyer’s legal, valid and binding obligation, enforceable in accordance with its terms, subject, however, to the effects of bankruptcy, insolvency, reorganization, moratorium and similar laws for the protection of creditors, as well as to general principles of equity, regardless whether such enforceability is considered in a proceeding in equity or at law.

8.4 Liability for Brokers’ Fees. Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the Transaction for which Seller shall have any responsibility whatsoever.

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8.5 No Bankruptcy. There are no bankruptcy proceedings pending, being contemplated by or, to Buyer’s knowledge, threatened against Buyer.

8.6 Litigation. There is no action, suit, proceeding, claim or investigation by any person, entity, administrative agency or governmental body pending or, to Buyer’s knowledge, threatened against it before any governmental authority that impedes or is likely to impede its ability (a) to consummate the Transaction or (b) to assume the obligations and liabilities to be assumed by it under this Agreement.

8.7 Buyer’s Evaluation. Buyer has made a complete and thorough investigation and examination of the Assets and the Transaction, employing the levels of due diligence as Buyer has elected to perform in its sole and absolute discretion. To the extent Buyer does not currently have available its own employees who are competent to conduct such examinations and inspections, Buyer has retained such consultants, independent contractors and other professional advisors as necessary to enable it to complete its due diligence and investigation of the Assets and the Transaction as Buyer determines is necessary in its sole and absolute discretion. Except for the Seller Warranties, Buyer acknowledges and agrees that Seller has not made any other representations or warranties, express or implied, written or oral, as to the accuracy or completeness of the information supplied by Seller or any other information relating to the Assets or the Transaction furnished or to be furnished to Buyer or its representatives by or on behalf of Seller, including without limitation any estimate of the value of the Assets or reserves or any projections as to future events. Buyer acknowledges and affirms that it has relied on and will rely solely on the terms of this Agreement and upon its own independent analysis, evaluation and investigation of, and judgment with respect to, the business, economic, legal, tax or other consequences of this Transaction including, without limitation, its estimate and appraisal of the extent, condition and value of the Assets. Buyer and its Representatives have been given opportunities to examine the Assets and the books and records relating to the ownership of the Assets.

8.8 Loan Documents and Ownership Documents and Information. Prior to the Effective Date, Buyer has furnished to Seller (a) true, correct and complete copies of the documents which will be executed in connection with the Closing to evidence and secure the loan to be made to finance a portion of Buyer’s acquisition of the Property (collectively, the “Loan Documents”), (b) true, correct and complete copies of the organizational documents for Buyer (including, without limitation, the Amended and Restated Limited Partnership Agreement of Pinedale Corridor, LP, of even date herewith and the Certificate of Limited Partnership for Pinedale Corridor, LP, executed on November 30, 2012 and filed with the Delaware Secretary of State on December 3, 2012, and for the general partner of Buyer, and (c) the identity of each partner of Buyer at Closing as well as information regarding the financial contribution of each partner of Buyer at Closing (collectively, the “Ownership Documents and Information”).

8.9 No Buyer Factual Default Under the Lease or Equity Investment Agreement. There are no facts in existence with respect to Buyer, CorEnergy, the Loan Documents or the Ownership Documents and Information which would result in a material breach, default or failure of performance under the Lease or the Equity Investors Agreement, upon execution of such documents at Closing.

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8.10 Survival. Buyer’s representations and warranties under this Agreement (collectively, the “Buyer Warranties”) (a) are made as of the Effective Date, (b) are remade as of the Closing Date, (c) shall not be deemed to be merged into or waived by the Closing Deliveries, and (d) shall survive Closing only for the Survival Period. If Seller first learns of the breach prior to Closing, Seller’s remedies shall be governed solely and exclusively by Section 11.2. Notwithstanding anything to the contrary in this Agreement, in the event Seller elects to proceed to Closing notwithstanding Seller’s knowledge of the existence of a breach by Buyer with respect to any Buyer Warranties, Seller shall be deemed to have waived each such breach and any and all rights and remedies in connection therewith. Buyer shall have no liability or obligation to Seller with respect to the breach of any representation or warranty of which Seller first learns after Closing unless Seller delivers written notice to Buyer of the alleged breach prior to the end of the Survival Period, which notice must include the information described in clauses (i), (ii) and (iii) of Subsection 14.5(a).

ARTICLE IX

COVENANTS AND AGREEMENTS

9.1 Conduct of Business.

(a) Operations before Closing. Except as provided in this Agreement, during the period from and including the Effective Date until the Closing Date (the “Interim Period”), Seller shall, in all material respects: (i) operate or cause its Affiliates to operate the Assets in the ordinary course and in a manner substantially consistent with past practices; (ii) use commercially reasonable efforts to preserve or cause its Affiliates to preserve intact the Assets in a manner consistent with past practices, except for fire or other casualty; (iii) use commercially reasonable efforts to operate its business and maintain the Assets in accordance with all applicable laws; and (iv) use commercially reasonable efforts to manage its relationships with agents, vendors, lessors, contractors, suppliers, and customers in a manner which would reasonably be expected to result in operations of the Assets by Seller and its Affiliates in the ordinary course and in a manner substantially consistent with past practices. During the period following the Effective Date and until Closing, upon Seller’s Knowledge thereof, Seller shall promptly notify Buyer of any events or circumstances which would cause any of Seller’s Warranties to be untrue or inaccurate in any material respect.

(b) Activities During Interim Period. As noted in Section 4.3 hereof, Seller and Ultra Resources are engaged in oil and gas development activities in and around the Assets. Those oil and gas development activities will continue during the Interim Period, and Buyer agrees and acknowledges that nothing in this Agreement, including in this Article IX, limits or is intended to limit Seller and/or Ultra Resources from engaging in these oil and gas development activities to the extent either Seller or Ultra Resources or both of them deem beneficial to Seller and/or Ultra Resources. Without limiting the generality of the foregoing, however, Seller agrees that, during the Interim Period, without the prior written consent of Buyer, Seller shall:

(i) Not sell, transfer, lease, encumber, or create a Lien on, exchange, or otherwise dispose of any of the Assets (other than the sale of worn-out or obsolete equipment, spare parts, or minor or insignificant Assets) in a manner which would cause Seller’s Warranties under Section 7.14 hereof to be untrue or incorrect;

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(ii) manage and maintain all Authorizations with respect to the ownership and operation of the Assets in the ordinary course and in a manner consistent with past practices;

(iii) not grant in favor of any Person a preferential purchase right to purchase any Assets;

(iv) not remove from the Liquids Gathering System any material portion of the Liquids Gathering System except for replacement, substitution or upgrades of the Liquids Gathering System in the ordinary course of Seller’s operations and except such as would not diminish the operational capability of the Liquids Gathering System as it existed on the Effective Date; or

(v) not agree, whether in writing or otherwise, to do any of the foregoing.

9.2 Insurance. During the Interim Period, Seller shall maintain liability insurance generally similar to that under the Insurance Policies in effect on the Effective Date and in accordance with the corporate practices of Ultra Resources and its Affiliates and will maintain worker’s compensation insurance in substantial compliance with applicable law.

9.3 Loan Documents, Ownership Documents and Information, Financial Resources, Buyer’s Warranties. Buyer shall use commercially reasonable efforts to secure the financial resources to close the Transaction as and when required by this Agreement, to make the Buyer Closing Payments at Closing and to perform its obligations under this Agreement and the Buyer Closing Deliveries on the Closing Date. Buyer shall not revise, amend, terminate, restate, or supplement, or permit the revision, amendment, termination, restatement or supplement, in any material respect of, (a) the Loan Documents the forms of which were delivered to Seller prior to the Effective Date or (b) any of the Ownership Documents and Information, the forms of which were delivered to Seller prior to the Effective Date. Buyer shall not take or refrain from taking any action, or permit its Affiliates to take or refrain from taking any action, which would result in a material breach, default or failure of performance under the Lease or the Equity Investors Agreement with respect to Buyer or its direct or indirect owners or its Affiliates upon execution of the Lease and the Equity Investors Agreement at Closing. During the Interim Period, upon acquiring knowledge thereof, Buyer shall promptly notify Seller of any events or circumstances which would cause any of Buyer’s Warranties to be untrue or inaccurate in any material respect.

9.4 Further Assurances. Subject to the terms and conditions of this Agreement, during the Interim Period, each Party will use commercially reasonable efforts to take, or cause to be taken, and cause its applicable Affiliates to take and cause to be taken, all actions and to do, or cause to be done, all things necessary or desirable, under applicable law or otherwise, to consummate the Transaction. The Parties agree to execute and deliver such other documents, certificates, agreements, and other writings and to take such other actions as may be necessary or desirable in order to consummate or implement expeditiously the Transaction hereof, in a manner consistent with the terms of this Agreement.

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9.5 Fees and Expenses. Except as otherwise provided in this Agreement, all fees and expenses, including fees and expenses of counsel, financial advisors, investment and equity advisors, real estate and other brokers and agents, and accountants, incurred in connection with this Agreement and the Transactions shall be paid by the Party (or their applicable Affiliate) incurring such fee or expense. The provisions of this Section 9.5 shall survive termination of this Agreement and Closing.

9.6 PSA Guaranties. Contemporaneous with execution of this Agreement by the Parties (a) Seller shall cause Ultra Petroleum to execute and deliver to Buyer the Seller PSA Guaranty, and (b) Buyer shall cause CorEnergy to execute and deliver to Seller the Buyer PSA Guaranty.

9.7 Survival The covenants and agreements of the Parties under Sections 9.1 and 9.2 shall survive Closing only for the Survival Period. If Buyer first learns of a breach by Seller of these covenants and agreements prior to Closing, Buyer’s remedies shall be governed solely and exclusively by Section 11.2. Notwithstanding anything to the contrary in this Agreement, if Buyer elects to proceed to Closing notwithstanding Buyer’s knowledge of the existence of a breach by Seller with respect to any of such covenants and agreements, Buyer shall be deemed to have waived each such breach and any and all rights and remedies in connection therewith. If Seller first learns of the breach prior to Closing, Seller’s remedies shall be governed solely and exclusively by Section 11.1. Notwithstanding anything to the contrary in this Agreement, in the event Seller elects to proceed to Closing notwithstanding Seller’s knowledge of the existence of a breach by Buyer with respect to any such covenant or agreement, Seller shall be deemed to have waived each such breach and any and all rights and remedies in connection therewith. All liability or obligation of any Party with respect to the breach of any covenant or agreement under this Article IX shall lapse and be of no further force or effect with respect to any matters not described in a written notice delivered to such Party by the other Party on or prior to the end of the Survival Period, which notice must include the information described in clauses (i), (ii) and (iii) of Subsection 14.5(a). Notwithstanding anything to the contrary in this Agreement, (a) the obligations of Seller under Section 9.4 shall survive so long as Lessee or any of its Affiliates is the lessee under the Lease, and (b) the obligations of Buyer under Section 9.4 shall survive so long as Buyer or any of its Affiliates is the lessor under the Lease.

ARTICLE X

TAX MATTERS

10.1 Apportionment of Property Tax Liability. “Property Taxes” means all ad valorem and property taxes and obligations assessed by a Taxing Authority against the Assets or based upon the ownership of the Assets, but excluding income, franchise or similar taxes. All Property Taxes assessed against the Assets shall be prorated between Buyer and Seller as of the end of the Closing Date for all taxable periods that include the Closing Date. Accordingly, (a) Buyer shall be responsible for all Property Taxes assessed against the Assets that are attributable to the period of time after the Closing Date and (b) Seller shall be responsible for all Property Taxes assessed against the Assets that are attributable to the period of time prior to and ending on the Closing Date. Such proration shall, initially, be based on the most recent Property Tax statements received by Seller or available from the applicable taxing authority as of the Closing Date. Following the Closing Date, each Party shall, upon request of the other Party, immediately reimburse the other Party for any such Property Taxes for which said Party is responsible but have been paid by the other Party.

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10.2 Property Tax Reports and Returns. Seller agrees to file all Tax Returns required to be filed by Seller, applicable to the ownership of the Assets, for all Property Taxes related to the Assets attributable to the period of time before the Closing Date. Buyer agrees to file all Tax Returns applicable to ownership of the Assets for all Property Taxes related to the period of time on and after the Closing Date. The Parties will cooperate with each other after the Closing Date in connection with audits and other proceedings with respect to Property Taxes relating to the ownership of the Assets.

10.3 Sales Taxes. Buyer shall be liable for and shall indemnify Seller for, any sales and use taxes, conveyance, transfer and recording fees and real estate transfer stamps or taxes (including any related interest, penalties or legal costs) that may be imposed on any transfer of the Assets pursuant to this Agreement. If required by applicable law, Seller shall, in accordance with applicable law, calculate and remit any sales or similar taxes that are required to be paid as a result of the transfer of the Assets to Buyer and Buyer shall promptly reimburse Seller therefor. If Seller receives notice that any sales and/or use taxes are due, Seller shall promptly forward such notice to Buyer for handling.

10.4 Federal Tax Reporting. Buyer and Seller will comply, to the extent required pursuant to the procedural requirements of Section 1060 of the Code and the Treasury Regulations promulgated thereunder, with respect to the allocation of the Purchase Price among the Assets. Buyer and Seller agree that they will not take any Tax position inconsistent with allocations made in this Agreement, if any; provided, however, that (a) Buyer’s cost for the Assets may differ from the total amount allocated thereunder to reflect Buyer’s capitalized transaction costs so allocated, and (b) Seller’s amount realized on the sale of the Assets may differ from the total amount so allocated to reflect Seller’s transaction costs that reduce the amount realized. The Parties will promptly inform one another of any challenge by any Taxing Authority to any allocation made pursuant to this Section 10.4 and agree to consult and keep one another informed with respect to the status of, and any discussion, proposal or submission with respect to, such challenge.

10.5 Like Kind Exchange. Seller may desire to have its transfer of one or more of the Assets to Buyer qualify as a deferred like kind exchange within the meaning of Section 1031 of the Internal Revenue Code of 1986, as amended. Further, either Seller or Buyer may desire to effectuate a deferred like kind exchange through the use of an intermediary in the manner described in Treas. Reg. Section 1.031(k)1(g)(8), example 4 or other applicable provisions. Each party shall reasonably cooperate with the other Party in effectuating such a deferred like kind exchange through the use of such an intermediary, including consenting to an assignment of any or all of the exchanging Party’s rights under this Agreement to an intermediary. Such other Party, however, shall have no obligation to locate, contract for or take title to any property that the exchanging Party may wish to buy or to incur any cost, expense, indebtedness, liability or other obligation of any kind as a part of such other Party’s agreement to reasonably cooperate.

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ARTICLE XI

CONDITIONS PRECEDENT TO CLOSING

11.1 Seller’s Conditions Precedent. The obligations of Seller at the Closing are subject to the satisfaction or waiver at or prior to the Closing of the following conditions precedent (collectively, the “Seller’s Conditions”):

(a) (i) The representations and warranties of Buyer made in this Agreement will be true and correct in all material respects as of the Closing Date, as if remade on the Closing Date (without duplication of any materiality qualifiers within the representations and warranties themselves); and (ii) Buyer shall have performed or complied in all material respects with all of the covenants and agreements required of Buyer or its Affiliates under this Agreement to be performed at or prior to Closing;

(b) No order has been entered by any court or governmental agency having jurisdiction over the Parties or the subject matter of this Agreement that restrains or prohibits the Transaction and that remains in effect at the time of Closing;

(c) No Additional Required Consent, which has not been obtained, would cause Closing of the Transaction to be in violation of applicable law which would result in (i) criminal liability to Buyer or Seller or (ii) a material civil fine or penalty to Buyer or Seller;

(d) Buyer shall have delivered at Closing all Buyer Closing Deliveries and have paid all Buyer Closing Payments unless Buyer’s failure to deliver the Buyer Closing Deliveries and pay the Buyer Closing Payments results from Buyer’s termination of this Agreement as a result of its termination rights under Section 11.2 below as a result of a failure of Buyer’s Conditions; and

(e) There shall not have occurred any event or circumstance giving rise to a Material Adverse Effect for Closing Conditions which event or circumstance first occurred after the Effective Date.

Notwithstanding anything set forth in this Agreement to the contrary, if any Seller’s Condition has not been satisfied by the Closing Date, then Seller may, as Seller’s sole and exclusive remedy with respect to such Seller’s Condition, either (1) terminate this Agreement, in which case the Parties shall have no further rights or obligations hereunder except those which expressly survive termination, or (2) proceed to Closing, in which case such Seller’s Condition shall be deemed to be waived for all purposes, or (3) with respect to a failure of Seller’s Condition set forth in subsection (c), above, bring suit for specific performance.

11.2 Buyer’s Conditions Precedent. The obligations of Buyer at the Closing are subject to the satisfaction or waiver at or prior to the Closing of the following conditions precedent (collectively, the “Buyer’s Conditions”):

(a) (i) The representations and warranties of Seller made in this Agreement will be true and correct in all material respects as of the Closing Date, as if remade on the Closing Date (without duplication of any “materiality” qualifiers in the representations and warranties themselves); and (ii) Seller shall have performed or complied in all material respects with all of the covenants and agreements required of Seller or its Affiliates under this Agreement to be performed at or prior to Closing;

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(b) No order has been entered by any court or governmental agency having jurisdiction over the Parties or the subject matter of this Agreement that restrains or prohibits the Transaction and that remains in effect at the time of Closing;

(c) No Additional Required Consent, which has not been obtained, would cause Closing of the Transaction to be in violation of applicable law which would result in (i) criminal liability to Buyer or Seller or (ii) a material civil fine or penalty to Buyer or Seller.

(d) Buyer shall have received funds sufficient to enable it to pay the Purchase Price through the combination of capital contributions to the Buyer by one or more of its equity investors, debt financing, and the completion of an equity offering by the parent of the general partner of the Buyer unless such failure results from a failure of performance by Buyer of Section 9.3 of this Agreement;

(e) Seller shall have delivered at Closing all Seller Closing Deliveries unless Seller’s failure to deliver the Seller Closing Deliveries results from Seller’s termination of this Agreement as a result of its termination rights under Section 11.1 above as a result of a failure of Seller’s Conditions; and

(f) There shall not have occurred any event or circumstance giving rise to a Material Adverse Effect for Closing Conditions which event or circumstance first occurred after the Effective Date.

Notwithstanding anything set forth in this Agreement to the contrary, if any Buyer’s Condition has not been satisfied by the Closing Date, then Buyer may, as Buyer’s sole and exclusive remedy with respect to such Buyer’s Condition, either (1) terminate this Agreement, in which case the Parties shall have no further rights or obligations hereunder except those which expressly survive termination, or (2) proceed to Closing, in which case such Buyer’s Condition shall be deemed to be waived for all purposes or (3) with respect to a failure of Buyer’s Condition set forth in subsection (d), above, bring suit for specific performance.

ARTICLE XII

RIGHT OF TERMINATION

12.1 Termination. This Agreement may be terminated in accordance with the following provisions:

(a) by mutual written consent of Seller and Buyer, in which case this Agreement shall terminate and the Parties shall have no further rights or obligations hereunder except those which expressly survive termination;

(b) as otherwise expressly provided in this Agreement including Section 5.2 and Article XI hereof; or

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(c) if the Closing has not occurred by the Outside Closing Date and neither Buyer nor Seller is entitled to enforce specific performance of this Agreement pursuant to the terms of Article XI hereof, in which case this Agreement shall terminate and the Parties shall have no further rights or obligations hereunder except those which expressly survive termination.

ARTICLE XIII

CLOSING

13.1 Date of Closing. The “Closing” will be held on December 14, 2012, or on such other date as Buyer and Seller mutually agree in writing, but in any event on or before the Outside Closing Date (the “Closing Date”).

13.2 Time and Place of Closing. The Closing shall be held at the offices of Seller’s counsel in Houston, Texas beginning at 9:00 a.m. Central Standard Time, or at such other time and place as Buyer and Seller may agree in writing.

13.3 Closing Obligations. At Closing, the following events shall occur, each being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a) Seller shall execute and deliver, or cause to be executed and delivered, to Buyer the Seller Closing Deliveries;

(b) Buyer shall deliver the Purchase Price to the account at a bank designated by Seller in Current Funds, or by such other method as agreed to by the Parties, and Buyer shall pay the Taxes required to be paid by Buyer in connection with the Closing under Section 10.3 of this Agreement and Buyer shall pay the other Buyer Closing Payments as required hereby;

(c) Buyer shall execute and deliver, or cause to be executed and delivered, to Seller the Buyer Closing Deliveries and pay the Buyer Closing Payments;

(d) Seller shall deliver to Buyer copies of all additional consents obtained prior to Closing pursuant to Section 5.3 of this Agreement;

(e) Seller and Buyer shall cause the following documents (collectively, the “Recorded Documents”) to be recorded in the applicable real estate records of Sublette County, Wyoming (the “Real Estate Records”), in the following order: the BLM Easement Assignment to Buyer to be recorded in the Real Estate Records, the Partial Assignment of Jensen Easements to Buyer, the Nerd Farm Easement, the Memo of Lease, and any Loan Documents required to be recorded in the Real Estate Records, and Buyer shall pay all fees and costs for such recording;

(f) Seller, as agent for Buyer for this limited purpose, shall deliver to BLM and provide to Buyer (i) the BLM Easement Assignment to Buyer which is not a Recorded Document and (ii) the BLM Request for Consent to Assignment to Buyer, and Buyer shall pay all fees and costs for such filing; and

(g) Seller and Buyer shall take such other actions and deliver such other documents as are contemplated by this Agreement.

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ARTICLE XIV

ASSUMPTION AND RETENTION OF OBLIGATIONS AND INDEMNIFICATION

14.1 Seller’s Retention of Liabilities and Obligations. Upon Closing Seller retains all claims, costs, expenses, liabilities and obligations accruing or relating to (a) the failure or inability of the Parties to obtain any Additional Required Consent prior to Closing and the implementation of the arrangements in lieu thereof contemplated by Section 5.3 (excluding costs to Buyer allocated to Buyer under this Agreement), (b) any injury or death attributable to or occurring on the Assets prior to the Closing Date; (c) any Tax liability or lien resulting therefrom in connection with the Assets with respect to any period prior to the Closing Date, and (d) any other Losses that arise, accrue in respect of are otherwise attributable to the Assets prior to the Closing Date (collectively, the “Retained Liabilities”). This Section 14.1 is for the sole benefit of Buyer and no other party shall be entitled to rely hereon. Specifically, and without limitation, Seller’s retention of any Retained Liabilities hereunder is not intended to and shall not be deemed to be an admission of liability to any third party by Seller. The provisions of this Section 14.1 are independent of, and are not intended to cover, liability with respect to Hazardous Substances and with respect to or arising under Environmental Laws, which is the subject solely of Section 14.2.

14.2 Environmental Indemnification. Subject to Sections 14.4, 14.5, 14.6, 14.7 and 14.8 of this Agreement, Seller shall indemnify, save and hold harmless Buyer, its officers, directors, employees and agents, from and against Losses for violations of Environmental Laws and releases of Hazardous Substances associated with Seller’s and its Affiliates operations of the Assets prior to the Closing Date where such use was not in conformance with Environmental Laws at the time the environmental conditions arose provided, however, Buyer shall not affirmatively cause a third party to issue a claim unless required to do so under applicable law. The provisions of this Section 14.2 are independent of the provisions of Section 14.1 and Section 14.3(a). The provisions of this Section 14.2 are the only provisions of this Article XIV that address Hazardous Substances and Environmental Laws.

14.3 Indemnification. For the purposes of this Article XIV, “Loss” or “Losses” means (i) any actual losses, costs, expenses (including court costs, reasonable fees and expenses of attorneys, technical experts and expert witnesses and the cost of investigation), liabilities, damages, demands, suits, claims, and sanctions of every kind and character (including civil fines) arising from, related directly or indirectly or reasonably incident to matters indemnified against, excluding however any special, consequential, punitive or exemplary damages, loss of profits, any Loss incurred as a result of the indemnified party indemnifying a third party, or diminution in value of the Assets unless caused directly and exclusively by Seller or an Affiliate of Seller and (ii) in respect of the Buyer, any amounts that the Buyer receives for such matters under the Lease. After the Closing, the Parties shall indemnify each other as follows:

(a) Seller’s Indemnification of Buyer. Seller assumes all risk, liability, obligation and Losses in connection with, and shall indemnify, save and hold harmless Buyer, its officers, directors, employees and agents, from and against all Losses which arise from or in connection with (i) the Retained Liabilities, (ii) claims asserted against Buyer or the Assets under the Nerd Farm Mortgage or the Nerd Farm Judgment as to either or both if included as an exception to title in the Nerd Farm Title Policy, (iii) any matter for which Seller has agreed to indemnify

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Buyer under this Agreement, and (iv) any breach of representations, warranties, covenants, or agreements by Seller under this Agreement which are not waived or deemed waived under Sections 5.1, 7.20, 7.21, or 11.2 of this Agreement or this Article XIV of this Agreement. The provisions of this Section 14.3(a) are independent of, and are not intended to cover, liability with respect to Hazardous Substances and with respect to or arising under Environmental Laws, which is the subject solely of Section 14.2. The Seller’s obligations under this Section 14.3(a) are limited as provided in Section 14.4.

(b) Buyer’s Indemnification of Seller. Buyer assumes all risk, liability, obligation and Losses in connection with, and Buyer shall indemnify, save and hold harmless Seller, its officers, directors, employees and agents, from and against all Losses which arise from or in connection with (i) any matter for which Buyer has agreed to indemnify Seller under this Agreement, and (ii) any breach of representations, warranties, covenants, or agreements by Buyer under this Agreement which are not deemed waived or deemed waived under Sections 8.10 and 11.1 of this Agreement or this Article XIV of this Agreement. The Buyer’s obligations under this Section 14.3(b) are limited as provided in Section 14.4.

(c) Release. Buyer shall be deemed to have released Seller at the Closing from any Losses for which Buyer has agreed to indemnify Seller hereunder, and Seller shall be deemed to have released Buyer at the Closing from any Losses for which Seller has agreed to indemnify Buyer hereunder.

(d) Express Negligence. Buyer understands and agrees that Buyer’s indemnity obligations under this Article XIV include and cover indemnification for certain claims arising from its indemnitee’s negligence, as and to the extent provided herein. Seller understands and agrees that Seller’s indemnity obligations under this Article XIV include and cover indemnification for certain claims arising from its indemnitee’s negligence, as and to the extent provided herein.

14.4 Survival.

(a) The indemnity and other obligations of the Parties contained in Sections 14.1 (a), (b) and (d), and 14.3(a)(i), (iii) and (iv) and (b) of this Agreement shall survive Closing only for the Survival Period.

(b) The indemnity and other obligations of the Parties contained in Section 14.1(c) of this Agreement shall survive Closing until the statute of limitations for such matters expires.

(c) The indemnity and other obligations of the Parties contained in Section 14.2 of this Agreement shall survive Closing until the fourth anniversary of the termination of the Lease.

(d) All liability or obligation of any Party with respect to any indemnity or other obligation contained in Sections 14.1, 14.2, or 14.3(a)(i), (iii) or (iv) or (b) of this Agreement shall lapse and be of no further force or effect with respect to any matters not described in reasonable detail in a Claim Notice delivered to such Party by the other Party on or prior to the end of the applicable period described in Sections 14.4(a), (b) or (c).

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(e) The provisions of Sections 14.3(a)(ii), (c) and (d), 14.4, 14.5, 14.6, 14.7, 14.8, 14.9 and 14.10 shall survive termination of this Agreement and Closing without limitation.

14.5 Procedure. The indemnifications contained in this Article XIV shall be implemented as follows:

(a) Claim Notice. The Party seeking indemnification under the terms of this Agreement (“Indemnified Party”) shall submit a written “Claim Notice” to the other Party (“Indemnifying Party”) which, to be effective, must state: (i) the amount of each payment claimed by an Indemnified Party to be owing, (ii) the basis for such claim, with supporting documentation, and (iii) a list identifying to the extent reasonably possible each separate item of Loss for which payment is so claimed. The amount claimed shall be paid by the Indemnifying Party to the extent required herein within 30 days after receipt of the Claim Notice, or after the amount of such payment has been finally established, whichever last occurs; provided, however, that any objection to the Claim Notice by the Indemnifying Party must be provided to the Indemnified Party within 15 days of receipt of the Claim Notice and any undisputed portion of the Claim paid within 30 days of receipt of the Claim Notice, or the Indemnifying Party waives its right to protest the Claim.

(b) Information. Within 60 days after the Indemnified Party receives notice of a claim or legal action that may result in a Loss for which indemnification may be sought under this Agreement (a “Claim”), the Indemnified Party shall give written notice of such Claim to the Indemnifying Party. If the Indemnifying Party or its counsel so requests, the Indemnified Party shall furnish the Indemnifying Party with copies of all pleadings and other information with respect to such Claim. At the election of the Indemnifying Party made within 60 days after receipt of such notice, the Indemnified Party shall permit the Indemnifying Party to assume control of such Claim (to the extent only that such Claim, legal action or other matter relates to a Loss for which the Indemnifying Party is liable), including the determination of all appropriate actions, the negotiation of settlements on behalf of the Indemnified Party, and the conduct of litigation through attorneys of the Indemnifying Party’s choice. No settlement of a Claim can result in any liability or cost to the Indemnified Party for which it is entitled to be indemnified hereunder without its consent. If the Indemnifying Party elects to assume control, (i) any expense incurred by the Indemnifying Party thereafter for investigation or defense of the matter shall be borne by the Indemnifying Party, and (ii) the Indemnified Party shall give all reasonable information and assistance, other than pecuniary, that the Indemnifying Party shall deem necessary to the proper defense of such Claim, legal action, or other matter. In the absence of such an election to assume control by the Indemnifying Party, the Indemnified Party will use commercially reasonable efforts to defend, at the Indemnifying Party’s expense, any claim, legal action or other matter to which such other Party’s indemnification under this Article XIV applies until the Indemnifying Party assumes such defense, and, if the Indemnifying Party fails to assume such defense within the time period provided above, settle the same in the Indemnified Party’s reasonable discretion at the Indemnifying Party’s expense. If such a Claim requires immediate action, the Parties agree to cooperate in good faith to take appropriate action so as not to jeopardize defense of such Claim or either Party’s position with respect to such Claim.

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14.6 No Insurance; Subrogation. The indemnifications provided in this Agreement shall not be construed as a form of insurance. Buyer and Seller hereby waive for themselves, their successors or assigns including, without limitation, any insurers, any rights to subrogation for Losses for which each of them is respectively liable or against which each respectively indemnifies the other, and, if required by applicable policies, Buyer and Seller shall obtain waiver of such subrogation from their respective insurers.

14.7 Reservation as to Non-Parties. Nothing herein is intended to limit or otherwise waive any recourse Buyer or Seller may have against any Person not a Party to this Agreement for any obligations or liabilities that may be incurred with respect to the Assets. For purposes of this Section 14.7 only, Ultra Resources and CorEnergy shall be deemed to be Parties to this Agreement.

14.8 Consequential Damages. Notwithstanding anything set forth in this Agreement, Buyer and Seller, on behalf of themselves and their respective Affiliates, expressly waive any and all rights to consequential, special, incidental, punitive, or exemplary damages and loss of profits resulting from a breach of this Agreement, including under or with respect to any indemnifications required hereby, and agree that the indemnifications set forth herein shall not include or cover any consequential, special, incidental, punitive, or exemplary damages or loss of profits. Nothing in this Section 14.8 shall constitute a waiver by any Party to a claim under this Article XIV with respect to diminution in value to the extent diminution in value is expressly included in the definition of the “Losses” covered by the Section of this Article under which the claim is made.

14.9 No Derivative Liability. Notwithstanding anything set forth in this Agreement, the Closing Deliveries or otherwise, no direct or indirect (through tiered ownership or otherwise) advisor, trustee, director, officer, employee, beneficiary, shareholder, participant, partner, member, owner, investor, representative or agent of a Party or its applicable Affiliates shall have any personal liability, directly or indirectly, under or in connection with this Agreement or any Closing Deliveries or any amendment or amendments to any of the foregoing made at any time or times, heretofore or hereafter, and the other Party and its successors and assigns and, without limitation, all other persons and entities, shall look solely to the assets of such Party (or, if expressly applicable, the assets of such Party’s Affiliate) for the payment of any claim or for any performance, and each other Party, on behalf of itself and its successors and assigns, hereby waive any and all such personal liability. Nothing in this Section 14.9 is intended or shall be deemed to impair or limit the liability of any Person under the Seller PSA Guaranty, the Buyer PSA Guaranty, the Lessee Lease Guaranty, the Resources Guaranty or the Lessor Lease Guaranty.

14.10 Attorneys’ Fees. If it shall be necessary for any Party to this Agreement to employ an attorney to enforce its rights pursuant to this Agreement, the non-prevailing Party shall reimburse the prevailing Party for its reasonable attorneys’ fees and the reasonable attorneys’ fees of the prevailing Party’s applicable Affiliates, if any, in such proceeding.

ARTICLE XV

MISCELLANEOUS

15.1 Expenses. Except as otherwise specifically provided, all fees, costs and expenses incurred by Buyer or Seller in negotiating this Agreement or in consummating the Transaction shall be paid by the Party incurring the same, including without limitation, engineering, land, title, legal and accounting fees, costs and expenses. This Section 15.1 shall survive termination of this Agreement and Closing.

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15.2 Notices. All notices and communications required or permitted under this Agreement (a “Notice”) shall be in writing and addressed as set forth below. Any Notice shall be deemed to have been duly made and the receiving Party charged with notice (a) if personally delivered, or sent by registered or certified Mail, or nationally recognized overnight courier, when received; (b) if sent by facsimile, upon receipt by the sending party of an acknowledgment or transmission report generated by the machine from which the facsimile was sent indicating that the facsimile was sent in its entirety to the addressee’s facsimile number; and (c) if the addressee rejects or otherwise refuses to accept the Notice, or if the Notice cannot be delivered because of a change in address for which no Notice was given, then upon the rejection, refusal, or inability to deliver the Notice; provided, however, that if a Notice is sent by facsimile, the party sending the Notice also must send, on the date that the facsimile is sent, a confirmation copy of the Notice (including the acknowledgement/transmission report described above) by one of the other methods set forth in this Section. All Notices shall be addressed as follows:

If to Seller:

Ultra Wyoming, Inc.

400 N. Sam Houston Parkway E. Suite 1200

Houston, Texas, 77060

Attention: Marshall D. Smith, Senior Vice President and Chief Financial Officer

Telecopy No.: 281-876-2831

With a copy to:

Ultra Wyoming, Inc.

400 North Sam Houston Parkway East, Suite 1200

Houston TX 77060

Attention: Legal Department

Telecopy No.: 281-876-2831

If to Buyer:

Pinedale Corridor, LP

4200 W. 115^th Street, Suite 210

Leawood, KS 66211

With a copy to:

Husch Blackwell LLP

4801 Main Street, Ste. 1000

Kansas City, MO 64112

Attn: Steven F. Carman

Telecopy No.: 816-983-8080

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Any Party may, by written notice so delivered to the other Party, change the address or individual to which delivery shall thereafter be made.

15.3 Amendments. This Agreement may not be amended nor any rights hereunder waived except by an instrument in writing signed by the Party to be charged with such amendment or waiver and delivered by such Party to the Party claiming the benefit of such amendment or waiver.

15.4 Assignment. Neither Party may assign all or any portion of its rights or delegate all or any portion of its duties hereunder without the prior written consent of the other Party. Any assignment or delegation made in violation of this Section 15.4 shall be null and void. In the event a Party consents in writing to the other Party’s assignment or delegation of its rights or duties hereunder, the assigning or delegating Party shall not be released from any of its liabilities or obligations hereunder, and no such assignment or delegation shall increase the burden on the non-assigning or non-delegating Party, and the non-assigning or non-delegating Party may continue to look to the assigning or delegating Party for all purposes under this Agreement.

15.5 Counterparts/PDF and Fax Signatures. This Agreement may be executed by Buyer and Seller in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute but one and the same instrument. PDF and facsimile signatures shall be considered binding. The Parties agree to exchange originally executed counterparts of this Agreement within three (3) Business Days of the request of a Party hereto.

15.6 GOVERNING LAW; JURISDICTION, VENUE; JURY WAIVER. THIS AGREEMENT AND THE OTHER TRANSACTION AGREEMENTS AND ANY DISPUTE RESOLUTION CONDUCTED PURSUANT HERETO AND THERETO SHALL BE CONSTRUED IN ACCORDANCE WITH, AND GOVERNED BY, THE LAWS OF THE STATE OF TEXAS EXCEPT AS MAY OTHERWISE BE REQUIRED FOR REAL PROPERTY ISSUES UNDER THE CONFLICT OF LAWS PRINCIPLES OF WYOMING. THE PARTIES IRREVOCABLY AGREE THAT ANY LEGAL ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT SHALL BE BROUGHT IN THE COURTS OF THE STATE OF TEXAS OR OF THE UNITED STATES OF AMERICA LOCATED IN HOUSTON, HARRIS COUNTY, TEXAS. BY THE EXECUTION AND DELIVERY OF THIS AGREEMENT, THE PARTIES IRREVOCABLY SUBMIT TO THE EXCLUSIVE JURISDICTION OF ANY SUCH COURT IN ANY SUCH ACTION, SUIT OR PROCEEDING. EACH PARTY HERETO WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT.

15.7 Entire Agreement. Except for the Confidentiality Agreement, this Agreement constitutes the entire understanding between the Parties with respect to the subject matter hereof, superseding all negotiations, prior discussions and prior agreements and understandings relating to such subject matter.

36

15.8 Binding Effect. This Agreement shall be binding upon, and shall inure to the benefit of the Parties hereto and their respective successors and assigns.

15.9 No Third-Party Beneficiaries. This Agreement is intended to benefit only the Parties hereto and their respective permitted successors and assigns. This Section 15.9 shall survive termination of this Agreement and Closing.

15.10 Time of the Essence. It is expressly agreed by the Parties hereto that time is of the essence with respect to this Agreement and the obligations and duties of the Parties hereunder.

15.11 Business Day. In the event that any event hereunder is to occur, or a time period is to expire, on a date which is not a Business Day, such event shall occur or such time period shall expire on the next succeeding Business Day.

15.12 No Recordation of Agreement. In no event shall this Agreement or any memorandum hereof be recorded in the public records of any place in which all or any part of the Property is situated, and any such recordation or attempted recordation shall constitute a material breach of this Agreement by the Party responsible for such recordation or attempted recordation. The provisions of this Section 15.12 shall survive termination of this Agreement and Closing.

15.13 No Waiver. Except as and to the extent expressly provided herein, (a) the failure of any Party hereto to enforce at any time any of the provisions of this Agreement shall in no way be construed as a waiver of any of such provisions, or the right of any party thereafter to enforce each and every such provision, and (b) no waiver of any breach of this Agreement shall be held to be a waiver of any other or subsequent breach.

15.14 Waiver of Trial by Jury. NEITHER SELLER NOR BUYER SHALL HAVE THE RIGHT TO SEEK A TRIAL BY JURY OF ANY ISSUE TRIABLE OF RIGHT BY JURY, AND EACH WAIVES TO THE EXTENT PERMITTED BY APPLICABLE LAW ANY RIGHT TO TRIAL BY JURY FULLY TO THE EXTENT THAT ANY SUCH RIGHT SHALL NOW OR HEREAFTER EXIST WITH REGARD TO THE TERMS OF THIS AGREEMENT OR ANY CLOSING DELIVERY, THE TRANSACTION CONTEMPLATED HEREBY, OR ANY CLAIM, COUNTERCLAIM OR OTHER ACTION ARISING IN CONNECTION THEREWITH. THIS WAIVER OF RIGHT TO TRIAL BY JURY IS GIVEN KNOWINGLY AND VOLUNTARILY BY EACH PARTY, AND IS INTENDED TO ENCOMPASS INDIVIDUALLY EACH INSTANCE AND EACH ISSUE AS TO WHICH THE RIGHT TO A TRIAL BY JURY WOULD OTHERWISE ACCRUE. ANY PARTY IS HEREBY AUTHORIZED TO FILE A COPY OF THIS SECTION IN ANY PROCEEDING AS CONCLUSIVE EVIDENCE OF THIS WAIVER BY EACH PARTY HERETO. This Section 15.14 shall survive termination of this Agreement and Closing.

15.15 Further Assurances. In furtherance of the provisions of this Agreement, Buyer agrees to take and cause its Affiliates to take, and Seller agrees to take and cause its Affiliates to take, such commercially reasonable further actions and to execute, deliver and file such further reasonable documents and instruments as may be reasonably necessary to consummate the transactions contemplated by this Agreement, but only if such actions and documents are

37

consistent with the terms of this Agreement and do not expand or otherwise vary from the obligations and liabilities of such Persons under this Agreement and the Closing Deliveries. Any and all such documents and instruments shall be prepared by, or at the direction of, the requesting Party, at the requesting Party’s sole cost and expense, and shall be in form and substance reasonably acceptable to the other Party. This Section 15.15 shall survive Closing.

[Remainder of Page Intentionally Blank Signature Pages Follow]

38

Executed as of the Effective Date.

SELLER:
ULTRA WYOMING, INC., a Wyoming corporation
By:	/s/ Marshall D. Smith
	Marshall D. Smith, Senior Vice President and Chief Financial Officer

BUYER:
PINEDALE CORRIDOR, LP,
a Delaware limited partnership
By:	PINEDALE GP, INC.,
	a Delaware corporation,
	its sole general partner
	By:	/s/ Richard C. Green
		Richard C. Green, Chairman

FIRST AMENDMENT TO

LIQUIDS GATHERING SYSTEM

SUBLETTE COUNTY, WYOMING

PURCHASE AND SALE AGREEMENT

This First Amendment to Liquids Gathering System Sublette County, Wyoming Purchase and Sale Agreement (this “Amendment”) is made as of December 12, 2012 (“Effective Date”), by and between ULTRA WYOMING, INC., a Wyoming corporation (“Seller”) whose address is 400 N. Sam Houston Parkway E., Suite 1200, Houston, Texas 77060, and PINEDALE CORRIDOR, LP, a Delaware limited partnership (“Buyer”) whose address is 4200 W. 115^th Street, Suite 210, Leawood, Kansas 66211. Seller and Buyer may be referred to individually as a “Party” or collectively as the “Parties.”

RECITALS

The Parties have entered into a Liquids Gathering System Sublette County, Wyoming Purchase and Sale Agreement dated as of December 7, 2012 (the “Agreement”) pursuant to which Buyer agreed to purchase, and Seller agreed to sell and convey, the Assets.

Section 3.1 of the Agreement provides that Buyer agrees to pay to Seller the Purchase Price at Closing in Current Funds.

The Parties desire to amend Section 3.1 of the Agreement and make certain additional representations and warranties and agreements, as set forth herein.

AGREEMENT

In consideration of the mutual promises, covenants and warranties contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Buyer and Seller agree as follows.

1. The Second Sentence of Section 3.1 of the Agreement shall be deleted and replaced with the following: “If the transaction contemplated by the Transaction Documents (“Transaction”) closes, Buyer agrees to pay to Seller the Purchase Price at Closing as follows: (i) $205,000,000 in Current Funds; and (ii) the transfer to Seller of 1,050,420 common units of NGL Energy Partners, LP (the “Units”) currently held by Buyer, free of any Liens or encumbrances.

2. Seller acknowledges that the Units are “restricted securities” under the federal securities law and are, as a result, currently subject to limitations on transfer. Seller further acknowledges that the Units are currently held in book entry form and, when certificated, will bear a legend reflecting the foregoing restrictions on transfer.

3. Buyer is the sole record and beneficial owner of the Units, and owns the Units free and clear of all Liens and encumbrances. Upon delivery of certificates representing the Units, duly endorsed for transfer to Seller as contemplated by Section 4 of this Amendment, Seller will become the owner of the Units, free and clear of any Liens and encumbrances created by Buyer. Buyer acquired the Units on June 19, 2012, in a transaction not involving a public

1

offering (as defined in the Securities Act), and paid the full consideration for the Units on June 19, 2012. Buyer is not an affiliate (as used in Rule 144 under the Securities Act) of the issuer of the Units. Buyer has not entered into, and is not bound by, any contractual provisions or agreements which limit or otherwise restrict or condition the right of Buyer to sell, assign or transfer the Units, except for restrictions imposed by the Securities Act.

4. At and prior to the closing, Buyer and Seller cooperate in good faith and shall take such steps as are necessary to transfer ownership of the Units from Seller to Buyer.

5. Section 13.1 is amended to provide that the “Closing Date” shall be December 20, 2012, or on such other date as Buyer and Seller mutually agree in writing.

6. Unless otherwise defined herein, all capitalized terms used in this Amendment shall have the same meanings as set forth in the Agreement.

7. Except as modified and amended by this Amendment, the Agreement shall remain in full force and effect and its terms are hereby ratified and confirmed.

Executed as of the Effective Date.

SELLER:
ULTRA WYOMING, INC., a Wyoming corporation
By:	/s/ Marshall D. Smith
	Marshall D. Smith, Senior Vice President and Chief Financial Officer

2

BUYER:
PINEDALE CORRIDOR, LP,
a Delaware limited partnership
By:	PINEDALE GP, INC.,
	a Delaware corporation,
	its sole general partner
	By:	/s/ Richard C. Green
		Richard C. Green, Chairman

3

EX-21.1

Exhibit 21.1

LIST OF MATERIAL SUBSIDIARIES OF ULTRA PETROLEUM CORP.

Entity	Jurisdiction of Organization
UP Energy Corporation	Nevada
Ultra Resources, Inc.	Wyoming
Ultra Wyoming, Inc.	Wyoming
Ultra Wyoming LGS, LLC	Delaware

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

Netherland, Sewell & Associates, Inc. has issued a report, as of December 31, 2012, of the “Estimate of Reserves and Future Revenue to the Ultra Petroleum Corporation Interest in certain oil and gas properties prepared in accordance with Securities and Exchange Commission guidelines” for Ultra Petroleum Corp. Netherland, Sewell & Associates, Inc. consents to the reference in Form 10-K to Netherland, Sewell & Associates, Inc.’s reserve reported dated February 11, 2013, and to the incorporation by reference of our Firm’s name and report into Ultra’s previously filed Registration Statements on Form S-8 (File Nos. 333-132443; 333-13342; 333-13278 and Form S-3 (File Nos. 333-89522; 333-162062)).

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Thomas J. Tella II
	Thomas J. Tella II
	Senior Vice President

Dallas, Texas

February 20, 2013

EX-23.2

Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-8 No. 333-13342) pertaining to the Ultra Petroleum Corp. 1998 Stock Option Plan,

(2) Registration Statement (Form S-8 No. 333-13278) pertaining to the Ultra Petroleum Corp. 2000 Stock Incentive Plan, and

(3) Registration Statement (Form S-8 No. 333-132443) pertaining to the Ultra Petroleum Corp. 2005 Stock Incentive Plan;

of our reports dated February 20, 2013, with respect to the consolidated financial statements of Ultra Petroleum Corp. and the effectiveness of internal control over financial reporting of Ultra Petroleum Corp. included in this Annual Report (Form 10-K) of Ultra Petroleum Corp. for the year ended December 31, 2012.

/s/ Ernst & Young LLP

Houston, Texas

February 20, 2013

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Michael D. Watford, certify that:

1. I have reviewed this Annual Report on Form 10-K of Ultra Petroleum Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

/s/ Michael D. Watford

Michael D. Watford,

Chairman, President and Chief Executive Officer (Principal Executive Officer)

Date: February 20, 2013

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Marshall D. Smith, certify that:

1. I have reviewed this Annual Report on Form 10-K of Ultra Petroleum Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

/s/  Marshall D. Smith        

Marshall D. Smith,

Senior Vice President and Chief Financial Officer (Principal Financial Officer)

Date: February 20, 2013

EX-32.1

EXHIBIT 32.1

SECTION 906 CERTIFICATION PURSUANT OF PRINCIPAL EXECUTIVE OFFICER

ULTRA PETROLEUM CORP.

In connection with the Annual Report of Ultra Petroleum Corp. (the “Company”) on Form 10-K for the fiscal year ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael D. Watford, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/  Michael D. Watford        

Michael D. Watford,

Chairman, President and Chief Executive Officer

(Principal Executive Officer)

Dated: February 20, 2013

This certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, will not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This certification will not be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference.

EX-32.2

Exhibit 32.2

SECTION 906 CERTIFICATION PURSUANT OF PRINCIPAL FINANCIAL OFFICER

ULTRA PETROLEUM CORP.

In connection with the Annual Report of Ultra Petroleum Corp. (the “Company”) on Form 10-K for the fiscal year ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Marshall D. Smith, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/  Marshall D. Smith        

Marshall D. Smith,

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Dated: February 20, 2013

This certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, will not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This certification will not be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference.

EX-99.1

Exhibit 99.1

February 11, 2013

Mr. Brad Johnson

Ultra Petroleum Corporation

304 Inverness Way South, Suite 295

Englewood, Colorado 80112

Dear Mr. Johnson:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2012, to the Ultra Petroleum Corporation (Ultra) interest in certain gas properties located in Pennsylvania and Wyoming. We completed our evaluation on or about February 4, 2013. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Ultra. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Ultra’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Ultra interest in these properties, as of December 31, 2012, to be:

	Net Reserves				Future Net Revenue (M$)
	Gas		Condensate				Present Worth
Category	(MMCF)		(MBBL)		Total		at 10%
Proved Developed Producing		1,694,635		10,015		2,955,789		1,853,764
Proved Developed Non-Producing		126,359		516		211,755		121,867
Proved Undeveloped		1,145,451		7,606		1,334,261		287,629
Total Proved		2,966,445		18,137		4,501,804		2,263,259

Totals may not add because of rounding.

Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. Condensate volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons.

The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties have not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Ultra’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Ultra’s share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2012. For gas volumes for the Pennsylvania properties, the average Dominion (South Point) spot price of $2.753 per MMBTU is adjusted for energy content and fees for gathering and processing. For gas volumes for the Wyoming properties, the average Kern River (Opal plant) spot price of $2.668 per MMBTU is adjusted by lease for energy content, fuel usage, and fees for gathering and processing. For condensate volumes, the average West Texas Intermediate spot price of $94.71 per barrel is reduced by $6.86 for quality and fees for gathering and treating. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $2.625 per MCF of gas and $87.85 per barrel of condensate. By state, these average adjusted prices are $2.802 per MCF of gas for the Pennsylvania properties and $2.583 per MCF of gas and $87.85 per barrel of condensate for the Wyoming properties.

Operating costs used in this report are based on operating expense records of Ultra. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Ultra are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are held constant throughout the lives of the properties.

Capital costs used in this report were provided by Ultra and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Ultra’s estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are held constant to the date of expenditure.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Ultra interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Ultra receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property

ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Ultra, other interest owners, various operators of the properties, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

	Sincerely,
	NETHERLAND, SEWELL & ASSOCIATES, INC.
	Texas Registered Engineering Firm F-2699
	By: /s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer
By: /s/ Robert C. Barg	By: /s/ Philip R. Hodgson
Robert C. Barg, P.E. 71658	Philip R. Hodgson, P.G. 1314
Senior Vice President	Vice President
Date Signed: February 11, 2013	Date Signed: February 11, 2013

RCB:LMS

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

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

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

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

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

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

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

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

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

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

Definitions - Page 2 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

Definitions - Page 3 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

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

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

Definitions - Page 4 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

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

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90%

Definitions - Page 5 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

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

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

    a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

    b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

    a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

    b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

    c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

    d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

    e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

    f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Definitions - Page 6 of 7

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

• The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

• The company’s historical record at completing development of comparable long-term projects;

• The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

• The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

• The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 7 of 7

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Share Based Compensation (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Valuation And Expense Information [Abstract]
Total Cost Of Share Based Payment Plans	$ 15,835	$ 21,688	$ 21,805
Amounts capitalized in fixed costs	5,079	7,769	8,861
Amounts charged against income, before income tax benefit	10,756	13,919	12,944
Amount of related income tax benefit recognized in income	$ 4,463	$ 4,997	$ 4,595

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Share Based Compensation (Details 3) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$ 16.97	$ 16.97	$ 3.91	$ 1.49
Exercise Price, Upper Range Limit	$ 98.87	$ 98.87	$ 98.87	$ 98.87
Range 3 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$ 16.97
Exercise Price, Upper Range Limit	$ 16.97
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Number Outstanding	40
Weighted Average Remaining Contractual Life	1 year 3 months 25 days
Weighted Average Exercise Price	$ 16.97
Aggregate Intrinsic Value	$ 46
Range 4 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$ 25.68
Exercise Price, Upper Range Limit	$ 55.58
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Number Outstanding	604
Weighted Average Remaining Contractual Life	2 years 7 months 10 days
Weighted Average Exercise Price	$ 39.21
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Range 5 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$ 46.05
Exercise Price, Upper Range Limit	$ 65.04
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Number Outstanding	166
Weighted Average Remaining Contractual Life	3 years 6 months 11 days
Weighted Average Exercise Price	$ 56.44
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Range 6 [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit	$ 49.05
Exercise Price, Upper Range Limit	$ 65.94
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Number Outstanding	362
Weighted Average Remaining Contractual Life	4 years 3 months 22 days
Weighted Average Exercise Price	$ 54.66
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Stock Options Outstanding Summary [Line Items]
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Exercise Price, Upper Range Limit	$ 98.87
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest [Abstract]
Number Outstanding	185
Weighted Average Remaining Contractual Life	5 years 5 months 1 day
Weighted Average Exercise Price	$ 70.24
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Oil and Gas Properties (Details Textuals) (USD $)	3 Months Ended			12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
[OilAndGasPropertyAbstract]
DD&A per Mcfe	1.51			1.51	1.41	1.13
Ceiling test limitation				$ 2,900,000,000
Natural Gas Market Price Full Cost Ceiling Test	2.76	2.83	3.15
Crude Oil Market Price Full Cost Ceiling Test	94.71	94.97	95.67
Total interest on outstanding debt				103,200,000	93,900,000
Capitalized interest detail				$ 15,000,000	$ 30,700,000

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Disclosure About Oil and Gas Producing Activities (Unaudited) (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Internal Engineer Experience	18
External engineer responsible for preparing the reserve estimate years of experience	30
Weighted Average Sales Price For Proved Reserves Textuals [Abstract]
Weighted Average Sales Price For Proved Reserves Natural Gas	$ 2.63	$ 4.04	$ 4.05
Weighted Average Sales Price For Proved Reserves Condensate	$ 87.85	$ 88.19	$ 68.93

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Share Based Compensation (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Share options granted	$ 0	$ 0	$ 0
Non-vested share options at beginning of year	$ 0	$ 30.72	$ 26.28
Non-vested share options at end of year	$ 0	$ 0	$ 30.72
Options vested during the year	$ 0	$ 30.73	$ 23.86
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Significant Accounting Policies (Details Textuals) (USD $)	3 Months Ended			12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Dec. 31, 2012	Dec. 31, 2011
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Gathering facilities impairment charges				$ 92,500,000
Ceiling test limitation				2,900,000,000
Natural Gas Market Price Full Cost Ceiling Test	2.76	2.83	3.15
Crude Oil Market Price Full Cost Ceiling Test	94.71	94.97	95.67
Inventory	1,500,000			1,500,000
Valuation allowance	449,800,000			449,800,000
Natural gas imbalance liability	$ 2,100,000			$ 2,100,000	$ 1,300,000

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Disclosures About Oil and Gas Producing Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Oil And Gas Exploration And Production Industries Disclosures [Abstract]

Analyses of changes in proven reserves

	United States
	Oil	Natural Gas
	(MBbls)	(MMcf)
Reserves, December 31, 2009	29,185	3,736,601
Extensions, discoveries and additions	8,496	1,195,829
Production	(1,334)	(205,613)
Revisions	(4,663)	(526,662)
Reserves, December 31, 2010	31,684	4,200,155
Extensions, discoveries and additions	7,425	1,452,122
Production	(1,408)	(236,832)
Revisions	(4,620)	(636,891)
Reserves, December 31, 2011	33,081	4,778,554
Extensions, discoveries and additions	5,435	819,896
Production	(1,282)	(249,310)
Revisions(1)	(19,097)	(2,382,695)
Reserves, December 31, 2012	18,137	2,966,445
	United States
	Oil	Natural Gas
	(MBbls)	(MMcf)
Proved:
Developed	11,627	1,541,813
Undeveloped	17,558	2,194,788
Total Proved - 2009	29,185	3,736,601
Developed	11,013	1,678,697
Undeveloped	20,671	2,521,458
Total Proved - 2010	31,684	4,200,155
Developed	11,794	1,973,391
Undeveloped	21,287	2,805,163
Total Proved - 2011	33,081	4,778,554
Developed	10,531	1,820,994
Undeveloped	7,606	1,145,451
Total Proved - 2012	18,137	2,966,445

Standardized measure

		As of December 31,
		2012		2011		2010
Future cash inflows	$	9,380,970	$	22,196,913	$	19,186,072
Future production costs		(3,217,771)		(6,113,282)		(5,253,509)
Future development costs		(1,661,394)		(4,294,375)		(3,052,843)
Future income taxes		(733,855)		(3,340,516)		(3,198,413)
Future net cash flows		3,767,950		8,448,740		7,681,307
Discount at 10%		(1,873,633)		(4,652,684)		(4,155,739)
Standardized measure of discounted
future net cash flows	$	1,894,317	$	3,796,056	$	3,525,568

Summary of changes in the standardized measure of discounted future net cash flows

		December 31,
		2012		2011		2010
Standardized measure, beginning	$	3,796,056	$	3,525,568	$	2,026,700
Net revisions of previous quantity estimates		(2,516,159)		(964,987)		(807,877)
Extensions, discoveries and other changes		858,951		2,173,103		1,816,073
Changes in future development costs		952,067		(741,658)		(606,449)
Sales of oil and gas, net of production costs		(625,745)		(896,434)		(787,409)
Net change in prices and production costs		(2,912,698)		108,108		1,501,041
Development costs incurred during the
period that reduce future development costs		316,394		464,880		404,402
Accretion of discount		529,696		499,358		288,713
Net changes in production rates and other		363,788		(338,982)		297,957
Net change in income taxes		1,131,967		(32,900)		(607,583)
Aggregate changes		(1,901,739)		270,488		1,498,868
Standardized measure, ending	$	1,894,317	$	3,796,056	$	3,525,568

Costs incurred in oil and gas exploration and development activities

		Years Ended December 31,
		2012		2011		2010
United States
Property Acquisitions:
Unproved	$	47,979	$	91,983	$	472,339
Proved		-		-		-
Exploration*		199,569		746,085		634,503
Development		587,618		675,718		469,636
Total	$	835,166	$	1,513,786	$	1,576,478
* Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field.

Results of operations for oil and gas producing activities

F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES:
			Years Ended December 31,
			2012		2011		2010
	United States
	Oil and gas revenue	$	809,974	$	1,101,796	$	979,386
	Production expenses		(184,229)		(205,363)		(191,978)
	Depletion and depreciation		(388,985)		(346,394)		(241,796)
	Ceiling test and other impairments		(2,972,464)		-		-
	Income taxes		662,698		(197,464)		(193,692)
	Total	$	(2,073,006)	$	352,575	$	351,920

Capitalized Costs Relating to Oil and Gas Producing Activities

		December 31,		December 31,
		2012		2011
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	7,235,765	$	5,974,604
Less: Accumulated depletion, depreciation and amortization(1)		(5,578,265)		(2,322,982)
		1,657,500		3,651,622
Unproven Properties:
Acquisition and exploration costs not being amortized (2)		-		537,526
Net capitalized costs - oil and gas properties	$	1,657,500	$	4,189,148

G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:
			December 31,
			2012		2011
	Proven Properties:
	Acquisition, equipment, exploration, drilling and
	environmental costs	$	7,235,765	$	5,974,604
	Less: accumulated depletion, depreciation and amortization		(5,578,265)		(2,322,982)
			1,657,500		3,651,622
	Unproven Properties:
	Acquisition and exploration costs not being amortized		-		537,526
		$	1,657,500	$	4,189,148

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Derivative Financial Instruments (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Natural Gas Commodity Derivatives [Abstract]
Realized (loss) gain on commodity derivatives									$ 303,966	$ 213,349	$ 116,827
Unrealized loss (gain) on commodity derivatives									(230,385)	100,383	208,625
Gain loss on commodity derivatives	$ (3,519)	$ (9,896)	$ (33,287)	$ 120,283	$ 136,325	$ 114,166	$ 47,606	$ 15,635	$ 73,581	$ 313,732	$ 325,452

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Oil and Gas Properties (Tables)

12 Months Ended

Dec. 31, 2012

Oil and Gas Properties And Equipment Tables [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities

		December 31,		December 31,
		2012		2011
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	7,235,765	$	5,974,604
Less: Accumulated depletion, depreciation and amortization(1)		(5,578,265)		(2,322,982)
		1,657,500		3,651,622
Unproven Properties:
Acquisition and exploration costs not being amortized (2)		-		537,526
Net capitalized costs - oil and gas properties	$	1,657,500	$	4,189,148

G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:
			December 31,
			2012		2011
	Proven Properties:
	Acquisition, equipment, exploration, drilling and
	environmental costs	$	7,235,765	$	5,974,604
	Less: accumulated depletion, depreciation and amortization		(5,578,265)		(2,322,982)
			1,657,500		3,651,622
	Unproven Properties:
	Acquisition and exploration costs not being amortized		-		537,526
		$	1,657,500	$	4,189,148

Schedule Of Capitalized Costs Of Unproved Properties Excluded From Amortization Text Block

At December 31, 2012, all costs related to unevaluated properties that were previously excluded from capitalized costs being amortized have been impaired and transferred to the capitalized costs being amortized in the full cost pool.

		Total		2012		2011		2010		Prior
Acquisition costs	$	-	$	(481,689)	$	24,583	$	411,326	$	45,780
Exploration costs		-		(9,962)		198		-		9,764
Capitalized interest		-		(45,875)		26,498		19,377		-
Unproven properties	$	-	$	(537,526)	$	51,279	$	430,703	$	55,544

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Long Term Liabilities (Details 1) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012
Maturities Of Long Term Debt One Year [Member]
Long Term Debt Maturities	$ 0
Maturities Of Long Term Debt 2014 [Member]
Long Term Debt Maturities	0
Maturities Of Long Term Debt 2015 [Member]
Long Term Debt Maturities	100,000
Maturities Of Long Term Debt 2016 [Member]
Long Term Debt Maturities	339,000
Maturities of Long Term Debt 2017 [Member]
Long Term Debt Maturities	116,000
Maturities Of Long Term Debt Beyond Five Years [Member]
Long Term Debt Maturities	$ 1,282,000

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Credit Risk (Details)	12 Months Ended
	Dec. 31, 2012
Schedule Of Significant Customers [Line Items]
Percentage of revenue	10.00%

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Property, Plant & Equipment (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	$ 320,010
Accumulated Depreciation	(107,638)
Property, plant and equipment	212,372	246,586
Gas Gathering Equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	282,879
Accumulated Depreciation	(99,312)
Property, plant and equipment	183,567	219,011
Computer equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	2,510
Accumulated Depreciation	(1,510)
Property, plant and equipment	1,000	1,025
Office equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	454
Accumulated Depreciation	(374)
Property, plant and equipment	80	109
Leasehold improvements [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	450
Accumulated Depreciation	(251)
Property, plant and equipment	199	307
Land [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	22,359
Accumulated Depreciation	0
Property, plant and equipment	22,359	22,150
Other [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Cost	11,358
Accumulated Depreciation	(6,191)
Property, plant and equipment	$ 5,167	$ 3,984

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Share Based Compensation (Details 1) (USD $) Share data in Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2009
Share Based Compensation Details [Abstract]
Number of Securities to be Issued Upon Exercise of Outstanding Options	1,357	1,459	3,504
Weighted Averaged Exercise Price of Outstanding Options	$ 49.03
Number Of Securities Remaining Available For Future Issuance Under Equity Compenstation Plans Excluding Securities Reflected In The First Column	3,075

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Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 4) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Acquisition costs - unproved properties	$ 47,979	$ 91,983	$ 472,339
Exploration	199,569	746,085	634,503
Development	587,618	675,718	469,636
Total	$ 835,166	$ 1,513,786	$ 1,576,478

XML

Income Taxes (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation Abstract
State income tax provision net of federal benefit									$ (136,112)	$ 6,329	$ 3,608
Other, net									(4,618)	(1,692)	669
Income tax provision (benefit) computed at the U.S. statutory rate									(1,006,989)	248,805	253,076
Tax Effect Of Rate Change									1,358	4,228	1,939
Total income tax(benefit) provision	8,765	175	(754,642)	45,489	74,279	81,713	57,709	43,969	(700,213)	257,670	258,615
Change in valuation allowance									$ 446,148	$ 0	$ (677)

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Oil and Gas Properties (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Unproven Properties:
Acquisition costs	$ 0
Interest Costs Capitalized	0
Exploration costs	0
Total	0	537,526
Acquisition costs	(481,689)	24,583	411,326	45,780
Interest Costs Capitalized	(45,875)	26,498	19,377	0
Exploration costs	(9,962)	198	0	9,764
Total	$ (537,526)	$ 51,279	$ 430,703	$ 55,544

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Oil and Gas Properties

12 Months Ended

Dec. 31, 2012

Oil and Gas Properties And Equipment Tables [Abstract]

OIL AND GAS PROPERTIES

3. OIL AND GAS PROPERTIES:

		December 31,		December 31,
		2012		2011
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	7,235,765	$	5,974,604
Less: Accumulated depletion, depreciation and amortization(1)		(5,578,265)		(2,322,982)
		1,657,500		3,651,622
Unproven Properties:
Acquisition and exploration costs not being amortized (2)		-		537,526
Net capitalized costs - oil and gas properties	$	1,657,500	$	4,189,148

On a unit basis, DD&A from continuing operations was $1.51, $1.41and $1.13 per Mcfe for the years ended December 31, 2012, 2011 and 2010, respectively.

(1)During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company's proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 of $2.76 per MMBtu, $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.71 per barrel, $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2011.

(2)Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as onwork in process relating to gathering systems that are not currently in service.For the yearsended December 31, 2012 and 2011, total interest on outstanding debt was $103.2million and $93.9 million, respectively, of which$15.0 million and $30.7 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and work in process relating to gathering systems that are not currently in service.

At December 31, 2012, all costs related to unevaluated properties that were previously excluded from capitalized costs being amortized have been impaired and transferred to the capitalized costs being amortized in the full cost pool.

		Total		2012		2011		2010		Prior
Acquisition costs	$	-	$	(481,689)	$	24,583	$	411,326	$	45,780
Exploration costs		-		(9,962)		198		-		9,764
Capitalized interest		-		(45,875)		26,498		19,377		-
Unproven properties	$	-	$	(537,526)	$	51,279	$	430,703	$	55,544

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Income Taxes (Details 2) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Deferred tax assets - current:
Incentive compensation-other, net	$ 6,468	$ 9,329
Deferred Tax Assets Valuation Allowance Net Current	(6,468)	0
Net deferred tax assets - current	0	9,329
Deferred Tax Liabilities Current [Abstract]
Derivative instruments, net	0	(82,709)
Deferred Tax Assets Liabilities Net Current	0	73,380
Deferred tax assets - non - current [Abstract]
Property and equipment	350,978	0
Deferred gain on sale	55,329	0
U.S. federal tax credit carryforwards	4,870	13,280
Capital loss carryforwards	0	1,929
Net operating loss carryforwards	17,755	150
Incentive compensation/other, net	15,104	12,880
Deferred tax assets noncurrent before valuation allowances	444,036	28,239
Valuation allowance	(443,300)	(3,621)
Net deferred tax assets - non-current	736	24,618
Deferred Tax Liabilities - non current [Abstract]
Property and equipment	0	659,040
Other	736	587
Net non-current tax liabilities	736	659,627
Net non-current tax liability	$ 0	$ 635,009

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Commitments and Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2012 Btu	Dec. 31, 2011	Dec. 31, 2010
Commitements And Contingencies Disclosure [Abstract]
Commitment capacity per day of natural gas	200
Increased commitment capacity per day of natural gas	50
Demand charges related to remaining contract	$ 673,000,000
Proceeds from sale of liquids gathering system	203,046,000	0	0
Marketable securities consideration in liquids gathering sale	23,000,000
Proceeds from sale of marketable securities	21,235,000	0	0
Liquids Gathering System Operating Lease Rental Expense	20,000,000
Lease And Rental Expense Total	299,400,000
Committed drilling obligations with rig contractors, total	21,500,000
Committed drilling obligations with rig contractors, due in one year	15,000,000
Committed drilling obligations with rig contractors, due in one to three years	6,500,000
Commitment to office leases, current	900,000
Office Space Operating Lease Total Future Minimum Payments	1,500,000
Commitment to office leases, due in three years	700,000
Office leases expense	$ 1,000,000	$ 900,000	$ 800,000
Initial Term Liquids Gathering System Lease	15
Renewal Term Liquids Gathering System Lease	5
Renewal Term Liquids Gathering System Lease Useful Life	75.00%

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Financial Instruments Tables [Abstract]

Detail Schedule of Realized and Unrealized Gains and Losses

		For the Year Ended December 31,
Natural Gas Commodity Derivatives:		2012		2011		2010
Realized gain on commodity derivatives (1)	$	303,966	$	213,349	$	116,827
Unrealized (loss) gain on commodity derivatives (1)		(230,385)		100,383		208,625
Total gain on commodity derivatives	$	73,581	$	313,732	$	325,452
(1) Included in gain on commodity derivatives in the Consolidated Statements of Operations.

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Share Based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

Share Based Compensation Tables [Abstract]

Valuation and Expense Information

Valuation and Expense Information
		Year Ended December 31,
		2012		2011		2010
Total cost of share-based payment plans	$	15,835	$	21,688	$	21,805
Amounts capitalized in fixed assets	$	5,079	$	7,769	$	8,861
Amounts charged against income, before
income tax benefit	$	10,756	$	13,919	$	12,944
Amount of related income tax benefit recognized
in income	$	4,463	$	4,997	$	4,595

Securities Authorized for Issuance Under Equity Compensation Plans

			Number of Securities
			Remaining Available
	Number of		for Future Issuance
	Securities to	Weighted	Under Equity
	be Issued	Average	Compensation Plans
	Upon Exercise of	Exercise Price of	(Excluding Securities
	Outstanding	Outstanding	Reflected in the
Plan Category	Options	Options	First Column)
Equity compensation plans approved by
security holders	1,357	$49.03	3,075
Equity compensation plans not approved
by security holders	n/a	n/a	n/a
Total	1,357	$49.03	3,075

Changes in Stock Options Outstanding

		Weighted
		Average
	Number of	Exercise Price
	Options	(US$)
Balance, December 31, 2009	3,504	$ 1.49	to	$ 98.87
Forfeited	(68)	$ 51.60	to	$ 76.01
Exercised	(1,206)	$ 1.49	to	$ 45.95
Balance, December 31, 2010	2,230	$ 3.91	to	$ 98.87
Forfeited	(99)	$ 51.60	to	$ 75.18
Exercised	(672)	$ 3.91	to	$ 33.57
Balance, December 31, 2011	1,459	$ 16.97	to	$ 98.87
Forfeited	(68)	$ 25.08	to	$ 75.18
Exercised	(34)	$ 16.97	to	$ 19.18
Balance, December 31, 2012	1,357	$ 16.97	to	$ 98.87

Share Based Compensation by Exercise Price Table

The following table summarizes information about the stock options outstanding and exercisable at December 31, 2012:
					Options Outstanding and Exercisable
						Weighted	Weighted
						Average	Average	Aggregate
					Number	Remaining	Exercise	Intrinsic
Range of Exercise Price					Outstanding	Contractual Life	Price	Value
						(Years)
$	16.97	-	$	16.97	40	1.32	$ 16.97	$ 46
$	25.68	-	$	55.58	604	2.61	$ 39.21	$ -
$	46.05	-	$	65.04	166	3.53	$ 56.44	$ -
$	49.05	-	$	65.94	362	4.31	$ 54.66	$ -
$	51.14	-	$	98.87	185	5.42	$ 70.24	$ -

Weighted Average Grant Date Fair Value of Stock Options

		2012		2011		2010
Non-vested share options at beginning of year	$	-	$	30.72	$	26.28
Non-vested share options at end of year	$	-	$	-	$	30.72
Options vested during the year	$	-	$	30.73	$	23.86
Options forfeited during the year	$	27.05	$	25.80	$	28.36

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Share Based Compensation (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share Based Compensation Details [Abstract]
Companys Closing Stock Price Last Day Of Year	$ 18.13
Number Of In The Money Options Exercisable	40,000
Fair Value Of Options Vesting In The Period	0
Total intrinsic value of stock options excercised	300,000	21,500,000	50,700,000
Long Term Incentive Program Period	7,900,000	10,700,000	8,600,000
Long Term Incentive Program Total 2010 Program	11,700,000
Long Term Incentive Program Total 2011 Program	11,900,000
Long Term Incentive Program Total 2012 Program	12,100,000
Long Term Incentive Program Total 2009 Program	$ 24,100,000
Long Term Incentive Program Total 2009 Program Shares	409,160

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Summarized Quarterly Financial Information (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Selected Quarterly Financial Information [Abstract]
Revenues from continuing operations	$ 217,186	$ 196,375	$ 170,270	$ 226,143	$ 270,798	$ 293,141	$ 280,567	$ 257,290	$ 809,974	$ 1,101,796	$ 979,386
Gain (loss) on commodity derivatives	(3,519)	(9,896)	(33,287)	120,283	136,325	114,166	47,606	15,635	73,581	313,732	325,452
Expenses from continuing operations	146,682	156,503	186,064	193,539	184,458	160,543	151,365	145,666	682,788	642,032
Ceiling test and other impairments	496,501	606,827	1,869,136	0	0	0	0	0	2,972,464	0	0
Interest expense	25,765	25,369	18,748	18,298	17,074	15,902	15,590	14,590	88,180	63,156	49,032
Contract Cancellation Fees	6,248	(291)	4,666	4,846					15,469	0	0
Litigation expense					0	0	0	0	0	0	9,902
Other (expense) income, net	(1,738)	(42)	7	8	519	(3)	(4)	20	(1,765)	532
(Loss) income from continuing operations	(463,267)	(601,971)	(1,941,624)	129,751	206,110	230,859	161,214	112,689	(2,877,111)	710,872	723,074
Income tax (benefit) provision	8,765	175	(754,642)	45,489	74,279	81,713	57,709	43,969	(700,213)	257,670	258,615
Net (loss) income	$ (472,032)	$ (602,146)	$ (1,186,982)	$ 84,262	$ 131,831	$ 149,146	$ 103,505	$ 68,720	$ (2,176,898)	$ 453,202	$ 464,459
Net (loss) income per common share - basic	$ (3.09)	$ (3.94)	$ (7.76)	$ 0.55	$ 0.86	$ 0.98	$ 0.68	$ 0.45	$ (14.24)	$ 2.97	$ 3.05
Net (loss) income per common share - fully diluted	$ (3.09)	$ (3.94)	$ (7.76)	$ 0.55	$ 0.86	$ 0.97	$ 0.67	$ 0.44	$ (14.24)	$ 2.94	$ 3.01

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Measurements Tables [Abstract]

Fair Value of Long-Term Debt

		December 31, 2012				December 31, 2011
		Carrying		Estimated		Carrying		Estimated
		Amount		Fair Value		Amount		Fair Value
Long-Term Debt:
5.45% Notes due 2015, issued 2008	$	100,000	$	107,801	$	100,000	$	111,475
7.31% Notes due 2016, issued 2009		62,000		72,046		62,000		74,817
4.98% Notes due 2017, issued 2010		116,000		127,109		116,000		128,570
5.92% Notes due 2018, issued 2008		200,000		230,062		200,000		231,091
7.77% Notes due 2019, issued 2009		173,000		219,045		173,000		219,552
5.50% Notes due 2020, issued 2010		207,000		234,552		207,000		229,423
4.51% Notes due 2020, issued 2010		315,000		331,329		315,000		318,925
5.60% Notes due 2022, issued 2010		87,000		98,526		87,000		94,165
4.66% Notes due 2022, issued 2010		35,000		36,361		35,000		34,631
5.85% Notes due 2025, issued 2010		90,000		102,096		90,000		99,022
4.91% Notes due 2025, issued 2010		175,000		179,677		175,000		173,835
Credit Facility		277,000		277,000		343,000		343,000
	$	1,837,000	$	2,015,604	$	1,903,000	$	2,058,506

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Taxes [Abstract]

Consoldiated income tax provision table

The consolidated income tax (benefit) provision is comprised of the following:
		Year Ended December 31,
		2012		2011		2010
Current	$	12,363	$	6,464	$	4,763
(Reduction in) current tax benefit on stock based compensation		(4,427)		6,212		17,522
Total current tax		7,936		12,676		22,285
Deferred		(708,149)		244,994		236,330
Total income tax (benefit) provision	$	(700,213)	$	257,670	$	258,615

Income tax expense reconciliation table

The income tax provision (benefit) for continuing operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 35% to pretax income as a result of the following:

		Year Ended December 31,
		2012		2011		2010
Income tax (benefit) provision computed at the U.S. statutory rate	$	(1,006,989)	$	248,805	$	253,076
State income tax provision (benefit) net of federal benefit		(136,112)		6,329		3,608
Valuation allowance		446,148		-		(677)
Tax effect of rate change		1,358		4,228		1,939
Other, net		(4,618)		(1,692)		669
	$	(700,213)	$	257,670	$	258,615

Consoldiated deferred tax assets and liabilities

The tax effects of temporary differences that give rise to significant components of the Company's deferred tax assets and liabilities for continuing operations are as follows:
		Year Ended December 31,
		2012		2011
Deferred tax assets - current:
Incentive compensation/other, net		6,468		9,329
Valuation allowance		(6,468)		-
Net deferred tax assets - current	$	-	$	9,329
Deferred tax liabilities - current:
Derivative instruments, net	$	-	$	82,709
Net deferred tax liabilities - current	$	-	$	82,709
Net deferred tax liability - current	$	-	$	73,380
Deferred tax assets - non-current:
Property and equipment		350,978		-
Deferred gain		55,329		-
U.S. Federal tax credit carryforwards		4,870		13,280
Capital loss carryforwards		-		1,929
Net operating loss carryforwards		17,755		150
Incentive compensation/other, net		15,104		12,880
		444,036		28,239
Valuation allowance		(443,300)		(3,621)
Net deferred tax assets - non-current	$	736	$	24,618
Deferred tax liabilities - non-current:
Property and equipment		-		659,040
Other		736		587
Net non-current tax liabilities	$	736	$	659,627
Net non-current tax liability	$	-	$	635,009

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligations Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

2. ASSET RETIREMENT OBLIGATIONS:

The Company is required to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets.The following table summarizes the activities for the Company's asset retirement obligations for the years ended:

		December 31,
		2012		2011
Asset retirement obligations at beginning of period	$	42,052	$	28,052
Accretion expense		4,922		3,088
Liabilities incurred		13,638		10,878
Liabilities settled		(1,182)		(3)
Revisions of estimated liabilities		1,384		37
Asset retirement obligations at end of period		60,814		42,052
Less: current asset retirement obligations		(702)		-
Long-term asset retirement obligations	$	60,112	$	42,052

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Summarized Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Summarized Quarterly Financial Information Disclosure [Abstract]

Schedule Of Quarterly Financial Information Table Text Block

14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):

		2012
		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total
Revenues from continuing operations	$	226,143	$	170,270	$	196,375	$	217,186	$	809,974
Gain (loss) on commodity derivatives		120,283		(33,287)		(9,896)		(3,519)		73,581
Expenses from continuing operations		193,539		186,064		156,503		146,682		682,788
Ceiling test and other impairments		-		1,869,136		606,827		496,501		2,972,464
Interest expense		18,298		18,748		25,369		25,765		88,180
Contract cancellation fees		4,846		4,666		(291)		6,248		15,469
Other income (expense), net		8		7		(42)		(1,738)		(1,765)
Income (loss) before income tax provision		129,751		(1,941,624)		(601,971)		(463,267)		(2,877,111)
Income tax provision (benefit)		45,489		(754,642)		175		8,765		(700,213)
Net income (loss)	$	84,262	$	(1,186,982)	$	(602,146)	$	(472,032)	$	(2,176,898)
Net income (loss) per common share - basic	$	0.55	$	(7.76)	$	(3.94)	$	(3.09)	$	(14.24)
Net income (loss) per common share - fully diluted	$	0.55	$	(7.76)	$	(3.94)	$	(3.09)	$	(14.24)
		2011
		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total
Revenues from continuing operations	$	257,290	$	280,567	$	293,141	$	270,798	$	1,101,796
Gain on commodity derivatives		15,635		47,606		114,166		136,325		313,732
Expenses from continuing operations		145,666		151,365		160,543		184,458		642,032
Interest expense		14,590		15,590		15,902		17,074		63,156
Other income (expense), net		20		(4)		(3)		519		532
Income before income tax provision		112,689		161,214		230,859		206,110		710,872
Income tax provision		43,969		57,709		81,713		74,279		257,670
Net income	$	68,720	$	103,505	$	149,146	$	131,831	$	453,202
Net income per common share - basic	$	0.45	$	0.68	$	0.98	$	0.86	$	2.97
Net income per common share - fully diluted	$	0.44	$	0.67	$	0.97	$	0.86	$	2.94

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Fair Value Measurments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Derivative Assets Abstract
Derivative assets	$ 0	$ 230,385
Long Term Derivative Assets	0	0
Derivative Liabilities Abstract
Derivative liabilities	0	0
Derivative Liabilities, Noncurrent	$ 0	$ 0

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Share Based Compensation (Details 2) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock Options Outstanding Summary [Line Items]
Balance,	1,459		3,504
Exercise Price, Lower Range Limit	$ 16.97	$ 16.97	$ 3.91	$ 1.49
Exercise Price, Upper Range Limit	$ 98.87	$ 98.87	$ 98.87	$ 98.87
Balance,	1,357	1,459		3,504
Number Of Options [Member]
Stock Options Outstanding Summary [Line Items]
Balance,		2,230
Granted			0
Forfeited	(68)	(99)	(68)
Exercised	(34)	(672)	(1,206)
Balance,			2,230
Weighted Average Exercise Price [Member]
Stock Options Outstanding Summary [Line Items]
Exercise Price, Lower Range Limit Granted			$ 0
Exercise Price, Upper Range Limit Granted			$ 0
Exercise Price, Lower Range Limit Forfeited	$ 25.08	$ 51.60	$ 51.60
Exercise Price, Upper Range Limit Forfeited	$ 75.18	$ 75.18	$ 76.01
Exercise Price, Lower Range Limit Exercised	$ 16.97	$ 3.91	$ 1.49
Exercise Price, Upper Range Limit Exercised	$ 19.18	$ 33.57	$ 45.95

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Consolidated Statement of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues:
Natural gas sales	$ 695,733	$ 982,413	$ 886,396
Oil sales	114,241	119,383	92,990
Total operating revenues	809,974	1,101,796	979,386
Expenses:
Lease operating expenses	64,468	51,758	45,938
Production taxes	60,757	97,094	95,914
Gathering fees	59,004	56,511	50,126
Transportation charges	84,470	64,243	64,965
Depletion and depreciation	388,985	346,394	241,796
Ceiling test and other impairments	2,972,464	0	0
General and Administrative Expense	25,104	26,032	24,351
Total operating expenses	3,655,252	642,032	523,090
Operating income (loss)	(2,845,278)	459,764	456,296
Other income (expense), net:
Interest expense	(88,180)	(63,156)	(49,032)
Gain (loss) on commodity derivatives	73,581	313,732	325,452
Contract Cancellation Fees	(15,469)	0	0
Litigation expense	0	0	(9,902)
Other income (expense) net	(1,765)	532	260
Total other income (expense), net	(31,833)	251,108	266,778
(Loss) income before income tax (benefit) provision	(2,877,111)	710,872	723,074
Income tax (benefit) provision	(700,213)	257,670	258,615
Net (loss) income	$ (2,176,898)	$ 453,202	$ 464,459
Basic (Loss) Earnings per Share:
Net (loss) income per common share - basic	$ (14.24)	$ 2.97	$ 3.05
Fully Diluted Earnings per Share:
Net (loss) income per common share - fully diluted	$ (14.24)	$ 2.94	$ 3.01
Weighted average common shares outstanding - basic	152,845	152,754	152,346
Weighted average common shares outstanding - fully diluted	152,845	154,336	154,253

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Disclosure About Oil and Gas Producing Activities (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2012 Bbl	Dec. 31, 2011 Bbl	Dec. 31, 2010 Bbl
Oil Reserves [Member]
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	33,081,000	31,684,000	29,185,000
Extensions, discoveries and additions	5,435,000	7,425,000	8,496,000
Production	(1,282,000)	(1,408,000)	(1,334,000)
Revisions	(19,097,000)	(4,620,000)	(4,663,000)
Reserves, Ending Balance	18,137,000	33,081,000	31,684,000
Natural Gas Reserves [Member]
Increase (Decrease) in Proved Developed and Undeveloped Reserves [Roll Forward]
Reserves, Beginning Balance	4,778,554,000	4,200,155,000	3,736,601,000
Extensions, discoveries and additions	819,896,000	1,452,122,000	1,195,829,000
Production	(249,310,000)	(236,832,000)	(205,613,000)
Revisions	(2,382,695,000)	(636,891,000)	(526,662,000)
Reserves, Ending Balance	2,966,445,000	4,778,554,000	4,200,155,000

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating activities:
Net Income (Loss) Attributable to Parent	$ (2,176,898)	$ 453,202	$ 464,459
Adjustments to reconcile net (Loss) income to cash provided by operating activities:
Depletion and depreciation	388,985	346,394	241,796
Ceiling test and other impairments	2,972,464	0	0
Deferred and current non-cash income taxes	(712,576)	251,206	253,926
Unrealized loss (gain) on commodity derivatives	230,385	(100,383)	(208,625)
Excess tax benefit from stock based compensation	4,427	(6,212)	(17,522)
Stock compensation	10,756	13,919	12,944
Other	3,667	1,495	734
Net changes in operating assets and liabilities:
Restricted cash	0	(23)	1,583
Accounts receivable	62,758	(26,910)	(31,966)
Prepaid expenses and other	2,066	(1,274)	(229)
Other non-current assets	284	0	(1,176)
Accounts payable and accrued liabilities	(115,597)	86,079	91,982
Production taxes payable	(14,372)	8,735	(7,439)
Interest payable	(213)	3,428	14,867
Other long-term obligations	(9,031)	433	6,035
Current taxes payable	7,720	3,203	3,359
Net cash provided by operating activities	654,825	1,033,292	824,728
Investing Activities:
Acquisition of oil and gas properties	0	0	403,806
Oil and gas property expenditures	(708,017)	(1,435,611)	(1,164,389)
Gathering system expenditures	(127,149)	(83,996)	(76,703)
Restricted Cash Non Current	0	0	28,257
Proceeds on sale of subsidiary, net of transaction costs	0	5,821	68,420
Proceeds from sale of liquids gathering system	203,046	0	0
Proceeds from sale of marketable securities	21,235	0	0
Change in capital cost accrual	38,338	125,261	19,826
Inventory	(374)	1,595	1,738
Purchase of property, plant and equipment	(4,302)	(21,865)	(2,442)
Net cash used in investing activities	(577,223)	(1,408,795)	(1,529,099)
Financing activities:
Borrowings on long-term debt	852,000	1,257,000	1,000,000
Payments on long-term debt	(918,000)	(914,000)	(1,260,000)
Proceeds from issuance of Senior Notes	0	0	1,025,000
Deferred financing costs	0	(6,866)	(4,425)
Repurchased shares/net share settlements	(6,718)	(36,298)	(23,707)
Excess tax benefit from stock based compensation	(4,427)	6,212	17,522
Proceeds from exercise of options	1,157	9,928	6,561
Net cash provided by (used in) financing activities	(75,988)	315,976	760,951
(Decrease)/increase in cash during the period	1,614	(59,527)	56,580
Cash and cash equivalents, beginning of period	11,307	70,834	14,254
Cash and cash equivalents, end of period	12,921	11,307	70,834
Cash paid for:
Interest	101,237	88,964	53,291
Income taxes	$ 4,379	$ 7,260	$ 2,537

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Fair Value Measurments (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Fair Value Measurments Details [Abstract]
Other Asset Impairment Charges	$ 92.5
Estimated Fair Value Gathering Assets	$ 82.6

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Asset Retirement Obligation (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation [Abstract]
Asset retirement obligations at beginning of period	$ 42,052	$ 28,052
Accretion expense	4,922	3,088
Liabilities incurred	13,638	10,878
Liabilities settled	(1,182)	(3)
Asset Retirement Obligation, Revision of Estimate	1,384	37
Asset retirement obligations at end of period	60,814	42,052
Less: current asset requirement obligations	(702)	0
Long-term asset retirement obligations	$ 60,112	$ 42,052

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Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Future Net Cash Flows Abstract
Future Cash Inflows	$ 9,380,970	$ 22,196,913	$ 19,186,072
Future Production Costs	(3,217,771)	(6,113,282)	(5,253,509)
Future Development Costs	(1,661,394)	(4,294,375)	(3,052,843)
Future Income Taxes	(733,855)	(3,340,516)	(3,198,413)
Future Net Cash Flows	3,767,950	8,448,740	7,681,307
Discount at 10%	(1,873,633)	(4,652,684)	(4,155,739)
Standardized measure of discounted future net cash flows	$ 1,894,317	$ 3,796,056	$ 3,525,568

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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Accounting Policies [Abstract]

Basis of presentation

(a) Basis of presentation and principles of consolidation:  The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation.

Cash and cash equivalents

(b) Cash and cash equivalents:The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted cash

(c) Restricted cash:  Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. Wyoming law requires that these funds be held in a federally insured bank in Wyoming.

Property, plant and equipment

(d) Property, plant and equipment:  Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life. Gathering system expenditures are recorded at cost and depreciated using the straight-line method based on a 30-year useful life.The gathering system assets which are downstream of the Company's well pads are depreciated separately from proven oil and gas properties because they are expected to be used to transport oil and gas not currently included in the Company's proved reserves, including production expected from probable and possible reserves, as well as from third parties.

The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets.

Oil and natural gas properties

(e) Oil and natural gas properties:The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”)Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”)Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”).Separate cost centers are maintained for each country in which the Company incurs costs. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the proved reserves as determined by independent petroleum engineers. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement obligations are included in the base costs for calculating depletion.

Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”)rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company's proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 of $2.76 per MMBtu, $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.71 per barrel, $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2011 or 2010.

Inventories

(f) Inventories:  Materials and supplies inventories are carried at lower of cost or market. Inventory costs include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. The Company uses the weighted average method of recording its inventory. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. At December 31,2012, inventory of $1.5 million primarily includes the cost of pipe and production equipment that will be utilized during the 2013 drilling program.

Derivative Instruments and hedging activities

(g) Derivative instruments and hedging activities:The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note7).

Income Taxes Policy

(h) Income taxes:  Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

As a result of the tax effect of the ceiling test and other impairments recorded during the year ended December 31, 2012, the Company's previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $449.8 million as of December 31, 2012. This valuation allowance may be reversed in future periods against future taxable income.

Earnings per share

(i) Earnings per share:  Basic (loss) earnings per share is computed by dividing net (loss) earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted (loss) earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect

The following table provides a reconciliation of components of basic and diluted net (loss) income per common share:
		December 31,
		2012		2011		2010
Net (loss) income	$	(2,176,898)	$	453,202	$	464,459
Weighted average common shares outstanding
during the period		152,845		152,754		152,346
Effect of dilutive instruments		-	(1)	1,582		1,907
Weighted average common shares outstanding during
the period including the effects of dilutive instruments		152,845		154,336		154,253
Net (loss) income per common share - basic	$	(14.24)	$	2.97	$	3.05
Net (loss) income per common share - fully diluted	$	(14.24)	$	2.94	$	3.01
Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of
the common shares		-	(1)	1,030		1,214

Use of estimates

(j) Use of estimates:  Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Accounting for share based compensation

(k) Accounting for share-based compensation:  The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.

Fair value accounting

(l) Fair value accounting:  The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information.

Asset retirement obligation

(m) Asset retirement obligation:  The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

Revenue recognition

(n) Revenue recognition:The Company generally sells natural gas and condensate under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company's ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of the Company's share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2012 and 2011, the Company had a net natural gas imbalanceliability of $2.1 million and$1.3 million, respectively.

Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances.

Capitalized interest

(o)Capitalized interest:Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortizationand actively being evaluated, if any,as well as on work in process relating to gathering systems that are not currently in service.

(2)Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as onwork in process relating to gathering systems that are not currently in service.

Reclassifications

(q) Reclassifications:  Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.

Capital Cost Accrual

(p) Capital cost accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.

Recent accounting pronouncements

(r) Recent accounting pronouncements:In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC  820. The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company's consolidated financial statements.

Derivatives and Hedging Activities Policies [Abstract]

Derivative Instruments and hedging activities

(g) Derivative instruments and hedging activities:The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note7).

Oil and Gas Properties Policies [Abstract]

Capitalized interest

(o)Capitalized interest:Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortizationand actively being evaluated, if any,as well as on work in process relating to gathering systems that are not currently in service.

(2)Interest is capitalized on the cost of unevaluated oil and natural gas properties that are excluded from amortization and actively being evaluated as well as onwork in process relating to gathering systems that are not currently in service.

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Oil and Gas Properties (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Proven Properties [Abstract]
Acquisition, equipment, exploration, drilling and evnironmental costs	$ 7,235,765	$ 5,974,604
Less: Accumulated depletion, depreciation and amortization	(5,578,265)	(2,322,982)
Proved	1,657,500	3,651,622
Unproven Properties:
Unproven properties not being amortized	0	537,526
Net capitalized costs - oil and gas properties	$ 1,657,500	$ 4,189,148

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation [Abstract]

Schedule Of Asset Retirement Obligations

		December 31,
		2012		2011
Asset retirement obligations at beginning of period	$	42,052	$	28,052
Accretion expense		4,922		3,088
Liabilities incurred		13,638		10,878
Liabilities settled		(1,182)		(3)
Revisions of estimated liabilities		1,384		37
Asset retirement obligations at end of period		60,814		42,052
Less: current asset retirement obligations		(702)		-
Long-term asset retirement obligations	$	60,112	$	42,052

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Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 5) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs) [Abstract]
Oil and gas revenue	$ 809,974	$ 1,101,796	$ 979,386
Production expenses	(184,229)	(205,363)	(191,978)
Depletion and depreciation expense	(388,985)	(346,394)	(241,796)
Write-downs of proved oil and gas properties	(2,972,464)	0	0
Income taxes	662,698	(197,464)	(193,692)
Total	$ (2,073,006)	$ 352,575	$ 351,920

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Significant Accounting Policies Disclosures [Abstract]

SIGNIFICANT ACCOUNTING POLICIES

1.  SIGNIFICANT ACCOUNTING POLICIES:

(a) Basis of presentation and principles of consolidation:  The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation.

(b) Cash and cash equivalents:The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

(c) Restricted cash:  Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. Wyoming law requires that these funds be held in a federally insured bank in Wyoming.

(d) Property, plant and equipment:  Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life. Gathering system expenditures are recorded at cost and depreciated using the straight-line method based on a 30-year useful life.The gathering system assets which are downstream of the Company's well pads are depreciated separately from proven oil and gas properties because they are expected to be used to transport oil and gas not currently included in the Company's proved reserves, including production expected from probable and possible reserves, as well as from third parties.

The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These assets are included in Property, Plant and Equipment in the Consolidated Balance Sheets.

(e) Oil and natural gas properties:The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”)Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”)Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”).Separate cost centers are maintained for each country in which the Company incurs costs. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the proved reserves as determined by independent petroleum engineers. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement obligations are included in the base costs for calculating depletion.

Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”)rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

During 2012, the Company recorded a $2.9 billion non-cash write-down of the carrying value of the Company's proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2012, September 30, 2012 and June 30, 2012 of $2.76 per MMBtu, $2.83 per MMBtu and $3.15 per MMBtu for Henry Hub natural gas, respectively, and $94.71 per barrel, $94.97 per barrel and $95.67 per barrel for West Texas Intermediate oil, respectively, adjusted for market differentials. The Company did not have any write-downs related to the full cost ceiling limitation in 2011 or 2010.

(f) Inventories:  Materials and supplies inventories are carried at lower of cost or market. Inventory costs include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. The Company uses the weighted average method of recording its inventory. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. At December 31,2012, inventory of $1.5 million primarily includes the cost of pipe and production equipment that will be utilized during the 2013 drilling program.

(g) Derivative instruments and hedging activities:The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note7).

(h) Income taxes:  Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

As a result of the tax effect of the ceiling test and other impairments recorded during the year ended December 31, 2012, the Company's previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $449.8 million as of December 31, 2012. This valuation allowance may be reversed in future periods against future taxable income.

(i) Earnings per share:  Basic (loss) earnings per share is computed by dividing net (loss) earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted (loss) earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.

The following table provides a reconciliation of components of basic and diluted net (loss) income per common share:
		December 31,
		2012		2011		2010
Net (loss) income	$	(2,176,898)	$	453,202	$	464,459
Weighted average common shares outstanding
during the period		152,845		152,754		152,346
Effect of dilutive instruments		-	(1)	1,582		1,907
Weighted average common shares outstanding during
the period including the effects of dilutive instruments		152,845		154,336		154,253
Net (loss) income per common share - basic	$	(14.24)	$	2.97	$	3.05
Net (loss) income per common share - fully diluted	$	(14.24)	$	2.94	$	3.01
Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of
the common shares		-	(1)	1,030		1,214

(1)       Due to the net loss for the yearended December 31, 2012, 1.9million shares for options and restricted stock units were anti-dilutive and excluded from the computation of loss per share.

(j) Use of estimates:  Preparation of consolidated financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(k) Accounting for share-based compensation:  The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.

(l) Fair value accounting:  The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional information.

(m) Asset retirement obligation:  The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

(n) Revenue recognition:The Company generally sells natural gas and condensate under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company's ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of the Company's share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2012 and 2011, the Company had a net natural gas imbalanceliability of $2.1 million and$1.3 million, respectively.

Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances.

(o)Capitalized interest:Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortizationand actively being evaluated, if any,as well as on work in process relating to gathering systems that are not currently in service.

(p) Capital cost accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.

(q) Reclassifications:  Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.

(r) Recent accounting pronouncements:In May 2011, the FASB issued ASU No. 2011-04, which amends FASB ASC  820. The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this amendment did not have a material impact on the Company's consolidated financial statements.

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 12,921	$ 11,307
Restricted cash	121	121
Oil and gas revenue receivable	81,143	88,243
Joint interest billing and other receivables	26,712	82,370
Derivative assets	0	230,385
Prepaid drilling costs and other current assets	4,951	7,494
Total current assets	125,848	419,920
Oil And Gas Properties, Net, Using Full Cost Method Of Accounting [Abstract]
Proven	1,657,500	3,651,622
Unproven properties not being amortized	0	537,526
Property, plant and equipment	212,372	246,586
Long Term Derivative Assets	0	0
Deferred financing costs and other	11,625	14,051
Total assets	2,007,345	4,869,705
Current liabilities:
Accounts payable	67,489	105,453
AccruedLiabilitiesCurrent	121,124	190,420
Production taxes payable	47,745	62,117
Interest Payable Current	30,093	30,306
Current deferred tax liabilities	0	73,380
Derivative liabilities	0	0
Capital cost accrual	247,641	209,303
Total current liabilities	514,092	670,979
Long-term debt	1,837,000	1,903,000
Non-current derivative liability	0	0
Deferred income tax liability	0	635,009
Deferred gain on sale of liquids gathering system	158,082	0
Other long-term obligations	76,038	67,008
CommitmentsAndContingencies
Shareholders' equity:
Common stock - no par value; authorized - unlimited; issued and outstanding - 152,476,564 and 152,567,813, respectively	474,016	463,221
Treasury stock	(13)	(14,951)
Retained earnings	(1,051,870)	1,145,439
Total Shareholders' (Deficit) Equity	(577,867)	1,593,709
Total liabilities and shareholders' equity	$ 2,007,345	$ 4,869,705

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitements And Contingencies Disclosures [Abstract]

COMMITMENTS AND CONTINGENCIES

11. COMMITMENTS AND CONTINGENCIES:

Transportation contract.The Company is an anchor shipper on REX securing pipeline infrastructure providing sufficient capacity to transport a portion of its natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas in the future. REX begins at the Opal Processing Plant in southwest Wyoming and traverses Wyoming and several other states to an ultimate terminus in eastern Ohio. The Company's commitment involves a capacity of 200 MMMBtu per day of natural gas throughNovember 2019, and the Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper.

Subsequently, the Company entered into agreements to secure an additional capacity of 50 MMMBtu per day on the REX pipeline system, beginning in January 2012 through December 2018. This additional capacity will provide the Company with the ability to move additional volumes from its producing wells in Wyoming to markets in the eastern U.S.

The Company currently projects that demand charges related to the remaining term of the contract will total approximately $673.0 million.

Operating lease.During December 2012, the Company sold its system of pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The net cash proceeds received for the assets were $203.0 million and additional consideration of $23.0 million in the form of marketable securities which were sold during December 2012 for net cash proceeds of $21.2 million.

The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the LGS at the sole discretion of the Company. Annual rent for the initial term under the Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The Company's sale leaseback transaction was treated as a “normal leaseback” under the provisions of FASB ASC Topic 840 and qualified for sales recognition. The lease is classified as an operating lease.The Company currently projects that lease payments related to the Lease Agreement will total approximately $299.4 million.

All of the Company's lease obligations are related to leases that are classified as operating leases.  These leases contain certain provisions that could result in accelerated lease payments.  The Company has considered the effect of these provisions on minimum lease payments in its lease classification analysis and has determined that the default provisions do not impact classification of any the Company's operating leases.

Drilling contracts.  As of December 31, 2012, the Company had committed to drilling obligations totaling $21.5 million ($15.0 million due in 2013, $6.5 million due in 2014). The commitments expire in 2014 and were entered into to fulfill the Company's drilling program initiatives in Wyoming.

Office space lease.  The Company's maintains office space in Colorado, Texas, Wyoming and Pennsylvania with total remaining commitments for office leases of $1.5 million at December 31, 2012 ($0.9 million in 2013, $0.7 million in 2014 to 2015).

During the years ended December 31, 2012, 2011 and 2010, the Company recognized expense associated with its office leases in the amount of $1.0 million, $0.9 million, and $0.8 million, respectively.

Other.  The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, management, after consultation with legal counsel, is of the opinion that the final resolution of all such currently pending or threatened litigation is not likely to have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Feb. 15, 2013	Jun. 30, 2012
Document And Entity Information [Abstract]
Entity Registrant Name	Ultra Petroleum Corp.
Entity Central Index Key	0001022646
Document Type	10-K
Document Period End Date	Dec. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 3,528,103,567
Entity Common Stock, Shares Outstanding (actual number)		152,929,907

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Credit Risk

12 Months Ended

Dec. 31, 2012

Credit Risk [Abstract]

CREDIT RISK

12.  CONCENTRATION OF CREDIT RISK:

The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and commodity derivative contracts associated with the Company's hedging program. The Company's revenues related to natural gas sales are derived principally from a diverse group of companies, including major energy companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financial institutions and end-users in various industries.

Concentrations of credit risk with respect to receivables islimited due to the large number of customers and their dispersion across geographic areas.Commodity-based contracts may expose the Company to the credit risk of nonperformance by the counterparty to these contracts. This credit exposure to the Company is diversified primarily among as many as ten major investment grade institutions and will only be present if the reference price of natural gas established in those contracts is less than the prevailing market price of natural gas, from time to time.At December 31, 2012, the Company did not have any open commodity derivative contracts.

The Company maintains credit policies intended to monitor and mitigate the risk of uncollectible accounts receivable related to the sale of natural gas, condensate as well as its commodity derivative positions. The Company performs a credit analysis of each of its customers and counterparties prior to making any sales to new customers or extending additional credit to existing customers. Based upon this credit analysis, the Company may require a standby letter of credit or a financial guarantee.The Company did not have any outstanding, uncollectible accounts for its natural gas or condensate sales, nor derivative settlements sales at December 31, 2012.

A significant counterparty is defined as one that individually accounts for 10% or more of the Company's total revenues during the year. In 2012, the Company hadno single customer that represented 10% or more of its total revenues.

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Consolidated Balance Sheets [Abstract]
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	unlimited	unlimited
Common stock, shares issued	152,929,907	152,476,564
Common stock, shares outstanding	152,929,907	152,476,564

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Share Based Compensation

12 Months Ended

Dec. 31, 2012

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

SHARE BASED COMPENSATION

6. SHARE BASED COMPENSATION:

The Company sponsors a share based compensation plan: the 2005 Stock Incentive Plan (the “2005 Plan”). The plan is administered by the Compensation Committee of the Board of Directors (the “Committee”). The share based compensation plan is an important component of the total compensation package offered to the Company's key service providers, and reflects the importance that the Company places on motivating and rewarding superior results.

The 2005 Plan was adopted by the Company's Board of Directors on January 1, 2005 and approved by the Company's shareholders on April 29, 2005. The purpose of the 2005 Plan is to foster and promote the long-term financial success of the Company and to increase shareholder value by attracting, motivating and retaining key employees, consultants, and outside directors, and providing such participants with a program for obtaining an ownership interest in the Company that links and aligns their personal interests with those of the Company's shareholders, and thus, enabling such participants to share in the long-term growth and success of the Company. To accomplish these goals, the 2005 Plan permits the granting of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock, and other stock-based awards, some of which may require the satisfaction of performance-based criteria in order to be payable to participants. The Committee determines the terms and conditions of the awards, including, any vesting requirements and vesting restrictions or forfeitures that may occur. The Committee may grant awards under the 2005 Plan until December 31, 2014, unless terminated sooner by the Board of Directors.

Valuation and Expense Information
		Year Ended December 31,
		2012		2011		2010
Total cost of share-based payment plans	$	15,835	$	21,688	$	21,805
Amounts capitalized in fixed assets	$	5,079	$	7,769	$	8,861
Amounts charged against income, before
income tax benefit	$	10,756	$	13,919	$	12,944
Amount of related income tax benefit recognized
in income	$	4,463	$	4,997	$	4,595

Securities Authorized for Issuance Under Equity Compensation Plans

As of December 31, 2012, the Company had the following securities issuable pursuant to outstanding award agreements or reserved for issuance under the Company's previously approved stock incentive plans. Upon exercise, shares issued will be newly issued shares or shares issued from treasury.

			Number of Securities
			Remaining Available
	Number of		for Future Issuance
	Securities to	Weighted	Under Equity
	be Issued	Average	Compensation Plans
	Upon Exercise of	Exercise Price of	(Excluding Securities
	Outstanding	Outstanding	Reflected in the
Plan Category	Options	Options	First Column)
Equity compensation plans approved by
security holders	1,357	$49.03	3,075
Equity compensation plans not approved
by security holders	n/a	n/a	n/a
Total	1,357	$49.03	3,075

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the three year period ended December 31, 2012:

		Weighted
		Average
	Number of	Exercise Price
	Options	(US$)
Balance, December 31, 2009	3,504	$ 1.49	to	$ 98.87
Forfeited	(68)	$ 51.60	to	$ 76.01
Exercised	(1,206)	$ 1.49	to	$ 45.95
Balance, December 31, 2010	2,230	$ 3.91	to	$ 98.87
Forfeited	(99)	$ 51.60	to	$ 75.18
Exercised	(672)	$ 3.91	to	$ 33.57
Balance, December 31, 2011	1,459	$ 16.97	to	$ 98.87
Forfeited	(68)	$ 25.08	to	$ 75.18
Exercised	(34)	$ 16.97	to	$ 19.18
Balance, December 31, 2012	1,357	$ 16.97	to	$ 98.87

The following table summarizes information about the stock options outstanding and exercisable at December 31, 2012:
					Options Outstanding and Exercisable
						Weighted	Weighted
						Average	Average	Aggregate
					Number	Remaining	Exercise	Intrinsic
Range of Exercise Price					Outstanding	Contractual Life	Price	Value
						(Years)
$	16.97	-	$	16.97	40	1.32	$ 16.97	$ 46
$	25.68	-	$	55.58	604	2.61	$ 39.21	$ -
$	46.05	-	$	65.04	166	3.53	$ 56.44	$ -
$	49.05	-	$	65.94	362	4.31	$ 54.66	$ -
$	51.14	-	$	98.87	185	5.42	$ 70.24	$ -

The aggregate intrinsic value in the preceding tables represents the total pre-tax intrinsic value, based on the Company's closing stock price of $18.13 on December 31, 2012, which would have been received by the option holders had all option holders exercised their options as of that date. The total number of in-the-money options exercisable as of December 31, 2012 was 40,000 options.

The following table summarizes information about the weighted-average grant-date fair value of share options:

		2012		2011		2010
Non-vested share options at beginning of year	$	-	$	30.72	$	26.28
Non-vested share options at end of year	$	-	$	-	$	30.72
Options vested during the year	$	-	$	30.73	$	23.86
Options forfeited during the year	$	27.05	$	25.80	$	28.36

The fair value of stock options that vested during the years ended December 31, 2011 and 2010 was $6.4 million and $9.8 million, respectively.As of December 31, 2011, all options fully vested; therefore, no options vested during the year ended December 31, 2012. The total intrinsic value of stock options exercised during the years ended December 31, 2012, 2011 and 2010 was $0.3 million, $21.5 million and $50.7 million, respectively.

At December 31, 2012, there was no unrecognized compensation cost related to non-vested, employee stock options as all options fully vested as of December 31, 2011.

PERFORMANCE SHARE PLANS:

Long Term Incentive Plans.  The Company offers a Long Term Incentive Plan (“LTIP”) in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. Each LTIP covers a performance period of three years. In 2010, 2011 and 2012, the Compensation Committee (the “Committee”) approved an award consisting of performance-based restricted stock units to be awarded to each participant.

For each LTIP award, the Committee establishes performance measures at the beginning of each performance period. Under each LTIP, the Committee establishes a percentage of base salary for each participant which is multiplied by the participant's base salary to derive a Long Term Incentive Value as a “target” value which corresponds to the number of shares of the Company's common stock the participant is eligible to receive if the target level for all performance measures is met. In addition, each participant is assigned threshold and maximum award levels in the event that actual performance is below or above target levels. For the 2010, 2011 and 2012 LTIP awards, the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth.

For the year ended December 31,2012, the Company recognized $7.9million in pre-tax compensation expense related to the 2010, 2011 and 2012 LTIP awards of restricted stock units. For the year ended December 31, 2011, the Company recognized $10.7 million in pre-tax compensation expense related to the 2009,2010and 2011 LTIP awards of restricted stock units. For the year ended December 31, 2010, the Company recognized $8.6 million in pre-tax compensation expense related to the 2008, 2009 and 2010 LTIP awards of restricted stock units. The amounts recognized during the year ended December 31, 2012 assumes that maximum performance objectives are attained under each plan. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at December 31, 2012, for each of the three year performance periods is expected to be approximately $11.7 million, $11.9 million, and $12.1 million related to the 2010, 2011 and 2012 LTIP awards of restricted stock units, respectively. The 2009 LTIP Common Stock Award was paid in shares of the Company's stock to employees during the first quarter of 2012 and totaled $24.1 million ( 409,160 net shares).

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Long Term Liabilities

12 Months Ended

Dec. 31, 2012

Long Term Liabilities Tables [Abstract]

LONG-TERM LIABILITIES

5. LONG-TERM LIABILITIES:

		December 31,		December 31,
		2012		2011
Bank indebtedness	$	277,000	$	343,000
Senior notes		1,560,000		1,560,000
Other long-term obligations		76,038		67,008
	$	1,913,038	$	1,970,008

Aggregate maturities of debt at December 31, 2012:
											Beyond
	2013		2014		2015		2016		2017		5 years		Total
$	-	$	-	$	100,000	$	339,000	$	116,000	$	1,282,000	$	1,837,000

Bank indebtedness.  The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the borrower and with the lenders' consent, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016 (which term may be extended for up to two successive one-year periods at the Borrower's request and with the lenders' consent). At December 31, 2012, the Company had $277.0 million in outstanding borrowings and $723.0 million of available borrowing capacity under the Credit Agreement.

Loans under the Credit Agreement are unsecured and bear interest, at the Borrower's option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 100 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrower's consolidated leverage ratio (200 basis points per annum as of December 31, 2012).The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio.

The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive covenants requiring the Borrower to maintain a consolidated leverage ratio of no greater than three and one half times to one and, as long as the Company's debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Company's oil and gas properties to total funded debt of no less than one and one half times to one. At December 31, 2012, the Company was in compliance with all of its debt covenants under the Credit Agreement.

Senior Notes:  The Company's Senior Notes rank paripassu with the Company's Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At December 31, 2012, the Company was in compliance with all of its debt covenants under the Senior Notes.

Other long-term obligations:  These costs primarily relate to the long-term portion of production taxes payableand our asset retirement obligations.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Significant Accounting Tables Policies [Abstract]

Schedule Of Earnings Per Share

The following table provides a reconciliation of components of basic and diluted net (loss) income per common share:
		December 31,
		2012		2011		2010
Net (loss) income	$	(2,176,898)	$	453,202	$	464,459
Weighted average common shares outstanding
during the period		152,845		152,754		152,346
Effect of dilutive instruments		-	(1)	1,582		1,907
Weighted average common shares outstanding during
the period including the effects of dilutive instruments		152,845		154,336		154,253
Net (loss) income per common share - basic	$	(14.24)	$	2.97	$	3.05
Net (loss) income per common share - fully diluted	$	(14.24)	$	2.94	$	3.01
Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of
the common shares		-	(1)	1,030		1,214

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Subsequent Events

12 Months Ended

Dec. 31, 2012

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

13.  SUBSEQUENT EVENTS:

FASB ASC Topic 855, Subsequent Events (“FASB ASC 855”), sets forth principles and requirements to be applied to the accounting for and disclosure of subsequent events. FASB ASC 855 sets forth the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which events or transactions occurring after the balance sheet date shall be recognized in the financial statements and the required disclosures about events or transactions that occurred after the balance sheet date. The FASB issued ASU No. 2010-09, Subsequent Events (FASB ASC 855), Amendments to Certain Recognition and Disclosure Requirements, on February 24, 2010, in an effort to remove some contradictions between the requirements of U.S. GAAP and the SEC's filing rules. The amendments remove the requirement that public companies disclose the date through which their financial statements are evaluated for subsequent events in both issued and revised financial statements. The Company has evaluated the period subsequent to December 31, 2012 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading.

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Taxes Disclosure [Abstract]

INCOME TAXES

9. INCOME TAXES:

The consolidated income tax (benefit) provision is comprised of the following:
		Year Ended December 31,
		2012		2011		2010
Current	$	12,363	$	6,464	$	4,763
(Reduction in) current tax benefit on stock based compensation		(4,427)		6,212		17,522
Total current tax		7,936		12,676		22,285
Deferred		(708,149)		244,994		236,330
Total income tax (benefit) provision	$	(700,213)	$	257,670	$	258,615

The income tax provision (benefit) for continuing operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 35% to pretax income as a result of the following:

		Year Ended December 31,
		2012		2011		2010
Income tax (benefit) provision computed at the U.S. statutory rate	$	(1,006,989)	$	248,805	$	253,076
State income tax provision (benefit) net of federal benefit		(136,112)		6,329		3,608
Valuation allowance		446,148		-		(677)
Tax effect of rate change		1,358		4,228		1,939
Other, net		(4,618)		(1,692)		669
	$	(700,213)	$	257,670	$	258,615
The tax effects of temporary differences that give rise to significant components of the Company's deferred tax assets and liabilities for continuing operations are as follows:
				Year Ended December 31,
				2012		2011
Deferred tax assets - current:
Incentive compensation/other, net				6,468		9,329
Valuation allowance				(6,468)		-
Net deferred tax assets - current			$	-	$	9,329
Deferred tax liabilities - current:
Derivative instruments, net			$	-	$	82,709
Net deferred tax liabilities - current			$	-	$	82,709
Net deferred tax liability - current			$	-	$	73,380
Deferred tax assets - non-current:
Property and equipment				350,978		-
Deferred gain				55,329		-
U.S. Federal tax credit carryforwards				4,870		13,280
Capital loss carryforwards				-		1,929
Net operating loss carryforwards				17,755		150
Incentive compensation/other, net				15,104		12,880
				444,036		28,239
Valuation allowance				(443,300)		(3,621)
Net deferred tax assets - non-current			$	736	$	24,618
Deferred tax liabilities - non-current:
Property and equipment				-		659,040
Other				736		587
Net non-current tax liabilities			$	736	$	659,627
Net non-current tax liability			$	-	$	635,009

In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, management considers the scheduled reversal of deferred tax liabilities, historical taxable income, projected future taxable income, and available tax planning strategies.

As a result of the ceiling test and other impairments recorded during the year ended December 31, 2012, the Company's previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company has recorded a full valuation allowance against its net deferred tax asset balance of $449.8 million as of December 31, 2012. This valuation allowance may be reversed in future periods against future taxable income.

As of December 31, 2012, the Company had approximately $3.2 million of U.S. federal alternative minimum tax (AMT) credits available to offset regular U.S. Federal income taxes. These AMT credits do not expire and can be carried forward indefinitely. In addition, the Company has $1.7 million of foreign tax credit carryforwards, none of which expire prior to 2017. The Company has U.S. State tax net operating loss carryforwards of $273.1 million which will expire between 2031 and 2032.

The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations as a result of implementing the standard related to accounting for uncertain tax positions. The amount of unrecognized tax benefits did not change as of December 31, 2012.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statements of Operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.

The Company files a consolidated federal income tax return in the United States federal jurisdiction and various combined, consolidated, unitary, and separate filings in several states, and international jurisdictions. The income tax years 2009 and 2010 have been audited by the Internal Revenue Service resulting in no material changes to the Company's taxes. With certain exceptions, including previous audited tax years, the income tax years 2009 through 2012 remain open to examination by the major taxing jurisdictions in which the Company has business activity.

The undistributed earnings of the Company's U.S. subsidiaries are considered to be indefinitely invested outside of Canada. Accordingly, no provision for Canadian income taxes and/or withholding taxes has been provided thereon.

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Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current:
U.S. federal and state - current									$ 12,363	$ 6,464	$ 4,763
Current tax benefit on equity compensation									(4,427)	6,212	17,522
Total current tax									7,936	12,676	22,285
Deferred:
U.S. federal and state - deferred									(708,149)	244,994	236,330
Total income tax(benefit) provision	$ 8,765	$ 175	$ (754,642)	$ 45,489	$ 74,279	$ 81,713	$ 57,709	$ 43,969	$ (700,213)	$ 257,670	$ 258,615

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2012

Derivative Financial Instruments Disclosure [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

7.  DERIVATIVE FINANCIAL INSTRUMENTS:

Objectives and Strategy: The Company's major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company's Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue.

Historically, the Company has entered into various types of derivative instrument transactions to manage its exposure to commodity price risk and to provide a level of certainty in the Company's forward cash flows supporting the Company's capital investment program. Because forward natural gas prices for 2013 production were low in 2012, the Company did not hedge any of its forecast 2013 natural gas production. As a result of the Company not having hedged any of its 2013 production, its earnings and cash flows may be more volatile during 2013 than in prior years.

The Company's hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise.

Fair Value of Commodity Derivatives:FASB ASC 815 requires that all derivatives be recognized on the balance sheet as either an asset or liability and be measured at fair value. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the balance sheet and the associated unrealized gains and losses are recorded as current expense or income in the income statement. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement.

The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010:

		For the Year Ended December 31,
Natural Gas Commodity Derivatives:		2012		2011		2010
Realized gain on commodity derivatives (1)	$	303,966	$	213,349	$	116,827
Unrealized (loss) gain on commodity derivatives (1)		(230,385)		100,383		208,625
Total gain on commodity derivatives	$	73,581	$	313,732	$	325,452
(1) Included in gain on commodity derivatives in the Consolidated Statements of Operations.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

8.  FAIR VALUE MEASUREMENTS:

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

As required by FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:

Level 1:       Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

Level 2:       Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.

Level 3:       Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).At December 31, 2012, the Company did not have any open commodity derivative contracts.

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At December 31, 2012, the Company did not have any open commodity derivative contracts.

Fair Value of Long-Lived Assets

The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. These facilities are included in Property, Plant and Equipment in the Consolidated Balance Sheets and were impaired to a fair value of $82.6 million based on the income approach, estimated using Level 3 fair value inputs.

Fair Value ofFinancial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.We use available market data and valuation methodologies to estimate the fair value of our fixed rate debt. The inputs utilized to estimate the fair value of the Company's fixed rate debt are considered Level 2 fair value inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact our financial position, results of operations or cash flows.

		December 31, 2012				December 31, 2011
		Carrying		Estimated		Carrying		Estimated
		Amount		Fair Value		Amount		Fair Value
Long-Term Debt:
5.45% Notes due 2015, issued 2008	$	100,000	$	107,801	$	100,000	$	111,475
7.31% Notes due 2016, issued 2009		62,000		72,046		62,000		74,817
4.98% Notes due 2017, issued 2010		116,000		127,109		116,000		128,570
5.92% Notes due 2018, issued 2008		200,000		230,062		200,000		231,091
7.77% Notes due 2019, issued 2009		173,000		219,045		173,000		219,552
5.50% Notes due 2020, issued 2010		207,000		234,552		207,000		229,423
4.51% Notes due 2020, issued 2010		315,000		331,329		315,000		318,925
5.60% Notes due 2022, issued 2010		87,000		98,526		87,000		94,165
4.66% Notes due 2022, issued 2010		35,000		36,361		35,000		34,631
5.85% Notes due 2025, issued 2010		90,000		102,096		90,000		99,022
4.91% Notes due 2025, issued 2010		175,000		179,677		175,000		173,835
Credit Facility		277,000		277,000		343,000		343,000
	$	1,837,000	$	2,015,604	$	1,903,000	$	2,058,506

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Employee Benefits

12 Months Ended

Dec. 31, 2012

Compensation And Retirement Disclosure [Abstract]

EMPLOYEE BENEFITS

10.  EMPLOYEE BENEFITS:

The Company sponsors a qualified, tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for its employees. Employees may defer 100% of their compensation, subject to limitations. The Company matches 100% of the employee's contribution up to 5% of compensation, as defined by the plan, along with anemployer discretionary contribution of 8%. The expense associated with the Company's contribution was $1.8 million, $1.4 million and $1.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 1)	Dec. 31, 2012 Bbl	Dec. 31, 2011 Bbl	Dec. 31, 2010 Bbl	Dec. 31, 2009 Bbl
Oil Reserves [Member]
Reserve Quantities [Line Items]
Developed	10,531,000	11,794,000	11,013,000	11,627,000
Undeveloped	7,606,000	21,287,000	20,671,000	17,558,000
Total Proved	18,137,000	33,081,000	31,684,000	29,185,000
Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Developed	1,820,994,000	1,973,391,000	1,678,697,000	1,541,813,000
Undeveloped	1,145,451,000	2,805,163,000	2,521,458,000	2,194,788,000
Total Proved	2,966,445,000	4,778,554,000	4,200,155,000	3,736,601,000

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Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized Measure, beginning	$ 3,796,056	$ 3,525,568	$ 2,026,700
Net revisions of previous quantity estimates	(2,516,159)	(964,987)	(807,877)
Extensions, discoveries and other changes	858,951	2,173,103	1,816,073
Changes in future development costs	952,067	(741,658)	(606,449)
Sales of oil and gas, net of production costs	(625,745)	(896,434)	(787,409)
Net change in prices and production costs	(2,912,698)	108,108	1,501,041
Development costs incurred during the period that reduce future development costs	316,394	464,880	404,402
Accretion of discount	529,696	499,358	288,713
Net changes in production rates and other	363,788	(338,982)	297,957
Net change in income taxes	1,131,967	(32,900)	(607,583)
Aggregrate changes	(1,901,739)	270,488	1,498,868
Standardized Measure, ending	$ 1,894,317	$ 3,796,056	$ 3,525,568

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Income Taxes (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Statement Income Taxes Details [Abstract]
Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate	35.00%
U.S. federal alternative minimum tax credits	$ 3.2
Foreign tax credit carryforward	1.7
U. S. state tax net operating loss carryforwards	273.1
Deferred Tax Assets, Valuation Allowance	$ 449.8

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Significant Accounting Policies (Details) (USD $) Share data in Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Significant Accounting Policies Details [Abstract]
Discount Rate Future Net Revenues									10.00%
Inventory, Net	$ 1,500,000								$ 1,500,000
Earnings Per Share Reconciliation
Net earnings (loss)	$ (472,032,000)	$ (602,146,000)	$ (1,186,982,000)	$ 84,262,000	$ 131,831,000	$ 149,146,000	$ 103,505,000	$ 68,720,000	$ (2,176,898,000)	$ 453,202,000	$ 464,459,000
Weighted average common shares outstanding - basic									152,845	152,754	152,346
Effect of dilutive instruments									0	1,582	1,907
Weighted average common shares outstanding - fully diluted									152,845	154,336	154,253
Net (loss) income per common share - basic	$ (3.09)	$ (3.94)	$ (7.76)	$ 0.55	$ 0.86	$ 0.98	$ 0.68	$ 0.45	$ (14.24)	$ 2.97	$ 3.05
Net (loss) income per common share - fully diluted	$ (3.09)	$ (3.94)	$ (7.76)	$ 0.55	$ 0.86	$ 0.97	$ 0.67	$ 0.44	$ (14.24)	$ 2.94	$ 3.01
Antidilutive Securities Excluded From Computation Of Earnings Per Share Amount									1,900	1,030	1,214

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Long Term Liabilities (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Senior Credit Facility Details [Abstract]
Revolving Bank Loan Comitment Value	$ 1,000,000,000
Max Revolving Bank Loan Comitment Value	1,250,000,000
Letters Of Credit Availability	250,000,000
Bank indebtedness	277,000,000	343,000,000
Available borrowing capacity	$ 723,000,000
Debt Instrument Interest Rate Terms Prime	100
Debt Instrument Interest Rate Terms Libor	200

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Disclosure About Oil and Gas Producing Activities

12 Months Ended

Dec. 31, 2012

Oil And Gas Exploration And Production Industries Disclosures [Abstract]

DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

15.  DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

The following information about the Company's oil and natural gas producing activities is presented in accordance with FASB ASC Topic 932, Oil and Gas Reserve Estimation and Disclosures:

A. OIL AND GAS RESERVES:

The determination of oil and natural gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs.From time to time, the Company may adjust the inventory and schedule of its proved undeveloped locations in response to changes in capital budget, economics, new opportunities in the portfolio or resource availability. The Company has not scheduled any proved undeveloped reserves beyond five years nor does it have any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years.

In estimating proved reserves and future revenue as of December 31, 2012, the Company's independent reserve engineer, Netherland, Sewell & Associates, Inc., used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and guidelines, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, Netherland, Sewell & Associates, Inc.'s conclusions necessarily represent only informed professional judgment.

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC's regulations and GAAP. The Vice President – Reservoir Engineering & Development is primarily responsible for overseeing the preparation of the Company's reserve estimates by our independent engineers, Netherland, Sewell & Associates, Inc. The Vice President – Reservoir Engineering & Development has a Bachelor and Master of Science degree in Petroleum Engineering and is a licensed Professional Engineer with over 18 years of experience. The Company's internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

All of the information regarding reserves in this annual report is derived from the report of Netherland, Sewell & Associates, Inc. The report of Netherland, Sewell & Associates, Inc. is included as an Exhibit to this annual report. The principal engineer at Netherland, Sewell & Associates, Inc. responsible for preparing our reserve estimates has a Bachelor of Science degree in Mechanical Engineering and is a licensed Professional Engineer with 30 years of experience, including significant experience throughout the Rocky Mountain basins.

Since January 1, 2012, 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 and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA.

The following unaudited tables as of December 31, 2012, 2011, and 2010 are based upon estimates prepared by Netherland, Sewell & Associates, Inc. in reports datedFebruary 11, 2013, February 1, 2012, and January 31, 2011, respectively. These are estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2012, 2011 and 2010. All such reserves are located in the GreenRiver Basin inWyoming and the Appalachian Basin of Pennsylvania.

B. ANALYSES OF CHANGES IN PROVEN RESERVES:

	United States
	Oil	Natural Gas
	(MBbls)	(MMcf)
Reserves, December 31, 2009	29,185	3,736,601
Extensions, discoveries and additions	8,496	1,195,829
Production	(1,334)	(205,613)
Revisions	(4,663)	(526,662)
Reserves, December 31, 2010	31,684	4,200,155
Extensions, discoveries and additions	7,425	1,452,122
Production	(1,408)	(236,832)
Revisions	(4,620)	(636,891)
Reserves, December 31, 2011	33,081	4,778,554
Extensions, discoveries and additions	5,435	819,896
Production	(1,282)	(249,310)
Revisions(1)	(19,097)	(2,382,695)
Reserves, December 31, 2012	18,137	2,966,445
	United States
	Oil	Natural Gas
	(MBbls)	(MMcf)
Proved:
Developed	11,627	1,541,813
Undeveloped	17,558	2,194,788
Total Proved - 2009	29,185	3,736,601
Developed	11,013	1,678,697
Undeveloped	20,671	2,521,458
Total Proved - 2010	31,684	4,200,155
Developed	11,794	1,973,391
Undeveloped	21,287	2,805,163
Total Proved - 2011	33,081	4,778,554
Developed	10,531	1,820,994
Undeveloped	7,606	1,145,451
Total Proved - 2012	18,137	2,966,445

(1)The net downward revision is primarily due to lower natural gas prices utilized in the preparation of the December 31, 2012 reserve estimation as compared to the price used in the previous year's estimate impacting the economic limit of reserves andthe corresponding reduction in capital investment associated with the transfer of proved undeveloped reserves to the unproven category. The calculated weighted average natural gas sales prices utilized for the purposes of estimating the Company's proved reserves and future net revenues at December 31, 2012 and 2011 were $2.63 per Mcf and $4.04 per Mcf, respectively.

C. STANDARDIZED MEASURE:

The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company's proved natural gas reserves. Natural gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company's proved reserves and future net revenues at December 31, 2012, 2011and 2010 was$2.63, $4.04 and $4.05 per Mcf, respectively, for natural gas and $87.85, $88.19 and $68.93 per barrel, respectively, for condensate, based upon the average of the price in effect on the first day of the month for the preceding twelve month period.

The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company's proved reserves and the tax basis of proved properties and available operating loss carryovers.

		As of December 31,
		2012		2011		2010
Future cash inflows	$	9,380,970	$	22,196,913	$	19,186,072
Future production costs		(3,217,771)		(6,113,282)		(5,253,509)
Future development costs		(1,661,394)		(4,294,375)		(3,052,843)
Future income taxes		(733,855)		(3,340,516)		(3,198,413)
Future net cash flows		3,767,950		8,448,740		7,681,307
Discount at 10%		(1,873,633)		(4,652,684)		(4,155,739)
Standardized measure of discounted
future net cash flows	$	1,894,317	$	3,796,056	$	3,525,568

The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses.

D. SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASHFLOWS:

		December 31,
		2012		2011		2010
Standardized measure, beginning	$	3,796,056	$	3,525,568	$	2,026,700
Net revisions of previous quantity estimates		(2,516,159)		(964,987)		(807,877)
Extensions, discoveries and other changes		858,951		2,173,103		1,816,073
Changes in future development costs		952,067		(741,658)		(606,449)
Sales of oil and gas, net of production costs		(625,745)		(896,434)		(787,409)
Net change in prices and production costs		(2,912,698)		108,108		1,501,041
Development costs incurred during the
period that reduce future development costs		316,394		464,880		404,402
Accretion of discount		529,696		499,358		288,713
Net changes in production rates and other		363,788		(338,982)		297,957
Net change in income taxes		1,131,967		(32,900)		(607,583)
Aggregate changes		(1,901,739)		270,488		1,498,868
Standardized measure, ending	$	1,894,317	$	3,796,056	$	3,525,568

There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and natural gas prices have fluctuated widely.

E. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES:

			Years Ended December 31,
			2012		2011		2010
	United States
	Property Acquisitions:
	Unproved	$	47,979	$	91,983	$	472,339
	Proved		-		-		-
	Exploration*		199,569		746,085		634,503
	Development		587,618		675,718		469,636
	Total	$	835,166	$	1,513,786	$	1,576,478
	* Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field.
F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES:
			Years Ended December 31,
			2012		2011		2010
	United States
	Oil and gas revenue	$	809,974	$	1,101,796	$	979,386
	Production expenses		(184,229)		(205,363)		(191,978)
	Depletion and depreciation		(388,985)		(346,394)		(241,796)
	Ceiling test and other impairments		(2,972,464)		-		-
	Income taxes		662,698		(197,464)		(193,692)
	Total	$	(2,073,006)	$	352,575	$	351,920
G. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:
			December 31,
			2012		2011
	Proven Properties:
	Acquisition, equipment, exploration, drilling and
	environmental costs	$	7,235,765	$	5,974,604
	Less: accumulated depletion, depreciation and amortization		(5,578,265)		(2,322,982)
			1,657,500		3,651,622
	Unproven Properties:
	Acquisition and exploration costs not being amortized		-		537,526
		$	1,657,500	$	4,189,148

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

		December 31,
		2012						2011
		Cost		Accumulated Depreciation		Net Book Value		Net Book Value
Gathering systems(1)(2)	$	282,879	$	(99,312)	$	183,567	$	219,011
Computer equipment		2,510		(1,510)		1,000		1,025
Office equipment		454		(374)		80		109
Leasehold improvements		450		(251)		199		307
Land		22,359		-		22,359		22,150
Other		11,358		(6,191)		5,167		3,984
Property, Plant and Equipment, Net	$	320,010	$	(107,638)	$	212,372	$	246,586

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Property, Plant & Equipment (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Abstract]
Gathering facilities impairment charges	$ 92,500,000
Proceeds from sale of liquids gathering system	203,046,000	0	0
Marketable securities consideration in liquids gathering sale	23,000,000
Proceeds from sale of marketable securities	21,235,000	0	0
Liquids Gathering System Operating Lease Rental Expense	$ 20,000,000
Initial Term Liquids Gathering System Lease	15
Renewal Term Liquids Gathering System Lease	5
Renewal Term Liquids Gathering System Lease Useful Life	75.00%

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Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Tax Deferred Savings Plan [Abstract]
Employee Deferral Percent for 401(k)	100.00%
Company Matching Percent for 401(k)	5.00%
Company Discretionary Contribution for 401(k)	8.00%
Pension and Other Postretirement Benefit Contributions [Abstract]
Other Postretirement Benefits Payments	$ 1.8	$ 1.4	$ 1.2

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Statement of Shareholders Equity (USD $) In Thousands, unless otherwise specified	Total	Common Stock [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Beginning Balance at Dec. 31, 2009	$ 648,197	$ 377,339	$ 281,383	$ (10,525)
Beginning Balance, Shares at Dec. 31, 2009		151,759
Stock options exercised	6,561	6,561
Stock options exercised, Shares		1,206
Employee stock plan grants	4,841	4,841
Employee stock plan grants, Shares		105
Shares re-issued from treasury	0	(587)	(9,938)	10,525
Net share settlements	(23,707)		(23,707)
Net share settlements, Shares		(502)
Fair value of employee stock plan grants	21,103	21,103
Tax benefit of stock options exercised	17,522	17,522
Comprehensive earnings:
Net earnings (loss)	464,459		464,459
Ending Balance at Dec. 31, 2010	1,138,976	426,779	712,197	0
Ending Balance, Shares at Dec. 31, 2010		152,568
Stock options exercised	9,928	9,928
Stock options exercised, Shares		672
Employee stock plan grants	700	0		700
Employee stock plan grants, Shares		150
Shares re-issued from treasury	0	(686)	(4,531)	5,217
Shares repurchased	(20,868)			(20,868)
Shares repurchased, Shares		(588)
Net share settlements	(15,429)		(15,429)
Net share settlements, Shares		(325)
Fair value of employee stock plan grants	20,988	20,988
Tax benefit of stock options exercised	6,212	6,212
Comprehensive earnings:
Net earnings (loss)	453,202		453,202
Ending Balance at Dec. 31, 2011	1,593,709	463,221	1,145,439	(14,951)
Ending Balance, Shares at Dec. 31, 2011		152,477
Stock options exercised	632	632
Stock options exercised, Shares		34
Employee stock plan grants	613	613
Employee stock plan grants, Shares		708
Shares re-issued from treasury	0	(1,245)	(14,793)	16,038
Shares repurchased	(1,100)			(1,100)
Shares repurchased, Shares		(50)
Net share settlements	(5,618)		(5,618)
Net share settlements, Shares		(239)
Fair value of employee stock plan grants	15,222	15,222
Tax benefit of stock options exercised	(4,427)	(4,427)
Comprehensive earnings:
Net earnings (loss)	(2,176,898)		(2,176,898)
Ending Balance at Dec. 31, 2012	$ (577,867)	$ 474,016	$ (1,051,870)	$ (13)
Ending Balance, Shares at Dec. 31, 2012		152,930

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2012

Property Plant And Equipment Disclosure [Abstract]

PROPERTY, PLANT AND EQUIPMENT

4. PROPERTY, PLANT AND EQUIPMENT:

		December 31,
		2012						2011
		Cost		Accumulated Depreciation		Net Book Value		Net Book Value
Gathering systems(1)(2)	$	282,879	$	(99,312)	$	183,567	$	219,011
Computer equipment		2,510		(1,510)		1,000		1,025
Office equipment		454		(374)		80		109
Leasehold improvements		450		(251)		199		307
Land		22,359		-		22,359		22,150
Other		11,358		(6,191)		5,167		3,984
Property, Plant and Equipment, Net	$	320,010	$	(107,638)	$	212,372	$	246,586

(1)The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of forecast decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices.

(2) During December 2012, the Company sold its system of pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The net cash proceeds received for the assets were$203.0 million and additional consideration of $23.0million in the form of marketable securities which were sold during December 2012 for net cash proceeds of $21.2 million.The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the LGS at the sole discretion of the Company. Annual rent for the initial term under the Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The Company's sale leaseback transaction was treated as a “normal leaseback” under the provisions of FASB ASC Topic 840, Leases (“FASB ASC Topic 840”) and qualified for sales recognition. The lease is classified as an operating lease.

In Pennsylvania, the Company and its partners continue constructing gas gathering pipelines and facilities, compression facilities and pipeline delivery stations to gather production from its newly completed natural gas wells. These facilities are gathering systems and related infrastructure, and their construction is expected to continue until the Company's properties in Pennsylvania are fully developed. To date, none of the Company's natural gas production in Pennsylvania has required processing, treating or blending in order to remove natural gas liquids or other impurities and it is anticipated that facilities of this type will not be required in the future to accommodate the Company's production.

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Fair Value Measurments (Details 1) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Carrying Amount	$ 1,837,000	$ 1,903,000
Notes Due 2015 [Member]
Debt Instrument [Line Items]
Carrying Amount	100,000	100,000
Estimated Fair Value	107,801	111,475
Private Debt Placement Instruments Interst Rates	5.45%
Notes Due 2016 [Member]
Debt Instrument [Line Items]
Carrying Amount	62,000	62,000
Estimated Fair Value	72,046	74,817
Private Debt Placement Instruments Interst Rates	7.31%
Notes Due 2017 [Member]
Debt Instrument [Line Items]
Carrying Amount	116,000	116,000
Estimated Fair Value	127,109	128,570
Private Debt Placement Instruments Interst Rates	4.98%
Notes Due 2018 [Member]
Debt Instrument [Line Items]
Carrying Amount	200,000	200,000
Estimated Fair Value	230,062	231,091
Private Debt Placement Instruments Interst Rates	5.92%
Notes Due 2019 [Member]
Debt Instrument [Line Items]
Carrying Amount	173,000	173,000
Estimated Fair Value	219,045	219,552
Private Debt Placement Instruments Interst Rates	7.77%
Notes Due January 2020 [Member]
Debt Instrument [Line Items]
Carrying Amount	207,000	207,000
Estimated Fair Value	234,552	229,423
Private Debt Placement Instruments Interst Rates	5.50%
Notes Due October 2020 [Member]
Debt Instrument [Line Items]
Carrying Amount	315,000	315,000
Estimated Fair Value	331,329	318,925
Private Debt Placement Instruments Interst Rates	4.51%
Notes Due January 2022 [Member]
Debt Instrument [Line Items]
Carrying Amount	87,000	87,000
Estimated Fair Value	98,526	94,165
Private Debt Placement Instruments Interst Rates	5.60%
Notes Due October 2022 [Member]
Debt Instrument [Line Items]
Carrying Amount	35,000	35,000
Estimated Fair Value	36,361	34,631
Private Debt Placement Instruments Interst Rates	4.66%
Notes Due January 2025 [Member]
Debt Instrument [Line Items]
Carrying Amount	90,000	90,000
Estimated Fair Value	102,096	99,022
Private Debt Placement Instruments Interst Rates	5.85%
Notes Due October 2025 [Member]
Debt Instrument [Line Items]
Carrying Amount	175,000	175,000
Estimated Fair Value	179,677	173,835
Private Debt Placement Instruments Interst Rates	4.91%
Credit Facility [Member]
Debt Instrument [Line Items]
Carrying Amount	277,000	343,000
Estimated Fair Value	$ 277,000	$ 343,000

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Disclosure About Oil and Gas Producing Activities (Unaudited) (Details 6) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Proven Properties [Abstract]
Acquisition, equipment, exploration, drilling and evnironmental costs	$ 7,235,765	$ 5,974,604
Less: Accumulated depletion, depreciation and amortization	(5,578,265)	(2,322,982)
Proved	1,657,500	3,651,622
Unproven Properties:
Oil Gas Properties Using Full Cost Method Accounting Unproved	0	537,526
Net capitalized costs - oil and gas properties	$ 1,657,500	$ 4,189,148

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Long Term Liabilities (Tables)

12 Months Ended

Dec. 31, 2012

Long Term Liabilities Tables [Abstract]

Schedule of Long-term Liabilities

		December 31,		December 31,
		2012		2011
Bank indebtedness	$	277,000	$	343,000
Senior notes		1,560,000		1,560,000
Other long-term obligations		76,038		67,008
	$	1,913,038	$	1,970,008

Maturity Schedule

Aggregate maturities of debt at December 31, 2012:
											Beyond
	2013		2014		2015		2016		2017		5 years		Total
$	-	$	-	$	100,000	$	339,000	$	116,000	$	1,282,000	$	1,837,000

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Long Term Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Long Term Liabilies Details [Abstract]
Bank indebtedness	$ 277,000	$ 343,000
Senior Notes Payable	1,560,000	1,560,000
Other long-term obligations	76,038	67,008
Total Long Term Liabilities	$ 1,913,038	$ 1,970,008

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Summarized Quarterly Financial Information

12 Months Ended

Dec. 31, 2012

Summarized Quarterly Financial Information Disclosure [Abstract]

SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):

		2012
		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total
Revenues from continuing operations	$	226,143	$	170,270	$	196,375	$	217,186	$	809,974
Gain (loss) on commodity derivatives		120,283		(33,287)		(9,896)		(3,519)		73,581
Expenses from continuing operations		193,539		186,064		156,503		146,682		682,788
Ceiling test and other impairments		-		1,869,136		606,827		496,501		2,972,464
Interest expense		18,298		18,748		25,369		25,765		88,180
Contract cancellation fees		4,846		4,666		(291)		6,248		15,469
Other income (expense), net		8		7		(42)		(1,738)		(1,765)
Income (loss) before income tax provision		129,751		(1,941,624)		(601,971)		(463,267)		(2,877,111)
Income tax provision (benefit)		45,489		(754,642)		175		8,765		(700,213)
Net income (loss)	$	84,262	$	(1,186,982)	$	(602,146)	$	(472,032)	$	(2,176,898)
Net income (loss) per common share - basic	$	0.55	$	(7.76)	$	(3.94)	$	(3.09)	$	(14.24)
Net income (loss) per common share - fully diluted	$	0.55	$	(7.76)	$	(3.94)	$	(3.09)	$	(14.24)
		2011
		1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total
Revenues from continuing operations	$	257,290	$	280,567	$	293,141	$	270,798	$	1,101,796
Gain on commodity derivatives		15,635		47,606		114,166		136,325		313,732
Expenses from continuing operations		145,666		151,365		160,543		184,458		642,032
Interest expense		14,590		15,590		15,902		17,074		63,156
Other income (expense), net		20		(4)		(3)		519		532
Income before income tax provision		112,689		161,214		230,859		206,110		710,872
Income tax provision		43,969		57,709		81,713		74,279		257,670
Net income	$	68,720	$	103,505	$	149,146	$	131,831	$	453,202
Net income per common share - basic	$	0.45	$	0.68	$	0.98	$	0.86	$	2.97
Net income per common share - fully diluted	$	0.44	$	0.67	$	0.97	$	0.86	$	2.94