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Resource Play Delineation and Development Results in Record Production and Increase in Year-End Proved Reserve Estimates. Our estimated proved reserves increased 40 percent to 1,760.6 BCFE (293.4 MMBOE) at December 31, 2012, from 1,259.2 BCFE (209.9 MMBOE) at December 31, 2011. We added 900.2 BCFE through drilling activity during the year, which was primarily led by our efforts in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We achieved record levels of production in 2012. Our average daily production was composed of 28.3 MBbl of oil, 328.0 MMcf of gas, and 16.7 MBbl of NGLs for an average equivalent production rate of 598.2 MMCFE per day, which was an increase of 29 percent from 465.0 MMCFE per day in 2011. Costs incurred in 2012 for drilling and exploration activities and acquisitions increased nine percent, to $1.7 billion, compared with $1.6 billion in 2011 due mainly to increased activity in plays with significant oil and NGL-rich gas components, such as our Eagle Ford shale and Bakken/Three Forks programs. Please refer to Core Operational Areas below for additional discussion concerning our 2012 estimated proved reserves, production, and capital investment.

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Impairments. We recorded impairment of proved properties expense of $208.9 million for the year ended December 31, 2012. During the fourth quarter of 2012, we recorded proved property impairment expense of $170.4 million. This non-cash charge was driven by downward engineering revisions that resulted in the write-down of Wolfberry assets in our Permian region. We also recorded proved property impairment expense of $38.5 million in the second quarter of 2012 related to our Haynesville shale assets in our Mid-Continent region due to low natural gas prices.

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Volatility and Decline in Commodity Prices. Our financial condition and the results of our operations are significantly affected by the prices we receive for oil, natural gas, and NGLs, which can fluctuate dramatically. Oil prices were volatile throughout 2012, reaching their peak for the year in February when the spot price for NYMEX crude oil hit a high of $109.49 per Bbl. The spot price for NYMEX crude oil during 2012 was at its lowest of $77.69 per Bbl in June. The average spot price for oil during 2012 was $94.10 per Bbl, down slightly from the $95.05 per Bbl average NYMEX price in 2011. In 2012, oil prices were impacted by concerns over international supply disruptions, rising U.S. oil production, and changes in global economic growth expectations throughout the year.

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(1)	Totals may not sum or recalculate due to rounding.

(2)	The standardized measure PV-10 calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown in the Reserves section below.

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(1)	Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations, but has been included only as developed acreage in the presentation above.

(2)	Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.

(3)	Includes interests in Arkansas, Colorado, Kansas, Illinois, Mississippi, Nebraska, New Mexico, and Utah.

(4)	As of the filing date of this report, we had approximately 63,368, 79,048, and 162,422 net acres scheduled to expire by December 31, 2013, 2014, and 2015, respectively, if production is not established or we take no other action to extend the terms of the applicable lease or leases.

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•	require the acquisition of various permits before drilling commences;

•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities;

•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and

•	require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

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•	the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;

•	the drilling of wells and other exploration and development activities and plans, as well as possible future acquisitions;

•	the possible divestiture or farm-down of, or joint venture relating to, certain properties;

•	proved reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those proved reserve estimates;

•	future oil, gas, and NGL production estimates;

•	our outlook on future oil, gas, and NGL prices, well costs, and service costs;

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•	cash flows, anticipated liquidity, and the future repayment of debt;

•	business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, and our outlook on our future financial condition or results of operations; and

•	other similar matters such as those discussed in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in Item 7 of this report.

•	the volatility of oil, gas, and NGL prices, and the effect it may have on our profitability, financial condition, cash flows, access to capital, and ability to grow production volumes and/or proved reserves;

•	the continued weakness in economic conditions and uncertainty in financial markets;

•	our ability to replace reserves in order to sustain production;

•	our ability to raise the substantial amount of capital that is required to replace our reserves;

•	our ability to compete against competitors that have greater financial, technical, and human resources;

•	our ability to attract and retain key personnel;

•	the imprecise estimations of our actual quantities and present value of proved oil, gas, and NGL reserves;

•	the uncertainty in evaluating recoverable reserves and estimating expected benefits or liabilities;

•	the possibility that exploration and development drilling may not result in commercially producible reserves;

•	our limited control over activities on non-operated properties;

•	our reliance on the skill and expertise of third-party service providers on our operated properties;

•	the possibility that title to properties in which we have an interest may be defective;

•	the possibility that our planned drilling in existing or emerging resource plays using some of the latest available horizontal drilling and completion techniques is subject to drilling and completion risks and may not meet our expectations for reserves or production;

•	the uncertainties associated with divestitures, joint ventures, farm-downs, farm-outs and similar transactions with respect to certain assets, including whether such transactions will be consummated or completed in the form or timing and for the value that we anticipate;

•	the uncertainties associated with enhanced recovery methods;

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•	our commodity derivative contracts may result in financial losses or may limit the prices that we receive for oil, gas, and NGL sales;

•	the inability of one or more of our vendors, customers, or contractual counterparties to meet their obligations;

•	price declines or unsuccessful exploration efforts resulting in write-downs of our asset carrying values;

•	the impact that lower oil, gas, or NGL prices could have on the amount we are able to borrow under our credit facility;

•	the possibility that our amount of debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt;

•	operating and environmental risks and hazards that could result in substantial losses;

•	complex laws and regulations, including environmental regulations, that result in substantial costs and other risks;

•	the availability and capacity of gathering, transportation, processing, and/or refining facilities;

•	our ability to sell and/or receive market prices for our oil, gas, and NGLs;

•	new technologies may cause our current exploration and drilling methods to become obsolete;

•	the possibility of security threats, including terrorist attacks and cybersecurity breaches, against, or otherwise impacting, our facilities and systems; and

•	litigation, environmental matters, the potential impact of government regulations, and the use of management estimates regarding such matters.

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•	global and domestic supplies of crude oil, natural gas, and NGLs, and the productive capacity of the industry as a whole;

•	the level of consumer demand for crude oil, natural gas, and NGLs;

•	overall global and domestic economic conditions;

•	weather conditions;

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

•	liquefied natural gas deliveries to and from the United States;

•	the price and level of foreign imports of crude oil, refined petroleum products, and liquefied natural gas;

•	the price and availability of alternative fuels;

•	technological advances and regulations affecting energy consumption and conservation;

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

•	political instability or armed conflict in crude oil or natural gas producing regions;

•	strengthening and weakening of the United States dollar relative to other currencies; and

•	governmental regulations and taxes.

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•	the demand for crude oil, natural gas, and NGLs in the United States has declined and may remain at low levels or further decline if economic conditions remain weak, and continue to negatively impact our revenues, margins, profitability, operating cash flows, liquidity, and financial condition;

•	natural gas prices have recently been lower than at various times in the last decade because of increased supply resulting from, among other things, increased drilling in unconventional reservoirs, and reduced demand in connection with the recent recession, which sustained low prices could affect our financial condition and results of operations;

•	the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

•	the liquidity available under our credit facility could be reduced if any lender is unable to fund its commitment;

•	our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration and/or development of our reserves;

•	our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and

•	variable interest rate spread levels, including for LIBOR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our credit facility.

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•	amount and timing of actual production;

•	supply and demand for crude oil, natural gas, and NGLs;

•	curtailments or increases in consumption by oil purchasers and natural gas pipelines; and

•	changes in government regulations or taxes, including severance and excise taxes.

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•	unexpected drilling conditions;

•	title problems;

•	disputes with owners or holders of surface interests on or near areas where we operate;

•	pressure or geologic irregularities in formations;

•	engineering and construction delays;

•	equipment failures or accidents;

•	hurricanes or other adverse weather conditions;

•	compliance with environmental and other governmental requirements; and

•	shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.

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•	our production is less than expected;

•	one or more counterparties to our commodity derivative contracts default on their contractual obligations; or

•	there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.

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•	making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;

•	requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments;

•	limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends;

•	placing us at a competitive disadvantage compared to our competitors that have less debt; and

•	making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

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•	incur additional debt;

•	make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock;

•	sell assets, including capital stock of our subsidiaries;

•	restrict dividends or other payments of our subsidiaries;

•	create liens that secure debt;

•	enter into transactions with affiliates; and

•	merge or consolidate with another company.

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•	the repeal of the percentage depletion allowance for oil and natural gas properties;

•	the elimination of current deductions for intangible drilling and development costs;

•	the elimination of the deduction for certain domestic production activities; and

•	an extension of the amortization period for certain geological and geophysical expenditures.

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•	changes in crude oil, natural gas, or NGL prices;

•	variations in drilling, recompletion, and operating activity;

•	changes in financial estimates by securities analysts;

•	changes in market valuations of comparable companies;

•	additions or departures of key personnel;

•	future sales of our common stock; and

•	changes in the national and global economic outlook.

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ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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(1)	All shares purchased in 2012 were to offset tax withholding obligations that occur upon the delivery of outstanding shares underlying RSUs and PSUs delivered under the terms of grants under the Equity Plan.

(2)

In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our credit facility, the indentures governing our Senior Notes and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flow, or borrowings under our credit facility. The stock repurchase program may be suspended or discontinued at any time. Please refer to Dividends above for a description of our dividend limitations.

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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At year-end 2012, we had estimated proved reserves of 1,760.6 BCFE (293.4 MMBOE), of which 53 percent were liquids (oil and NGLs) and 57 percent was characterized as proved developed. We added 900.2 BCFE from our drilling program, the majority of which related to our activity in the Eagle Ford shale in South Texas and the Bakken/Three Forks plays in North Dakota. We had negative price revisions that decreased our estimated proved reserves by 72.7 BCFE primarily due to gas weighted projects in our South Texas & Gulf Coast and Mid-Continent regions that do not generate positive cash flow utilizing historical 12-month average benchmark pricing required by the SEC. The prices used in the calculation of proved reserve estimates as of December 31, 2012, were $94.71 per Bbl, $2.76 per MMBtu, and $45.65 per Bbl, for oil, gas, and NGLs, respectively. These prices were two percent, 33 percent, and 23 percent lower for oil, gas, and NGLs, respectively, than the prices used at year-end 2011. We had downward engineering revisions of 49.2 BCFE related primarily to Eagle Ford shale proved undeveloped locations as well as downward engineering revisions of Wolfberry assets in our Permian region. Additionally, we removed 42.7 BCFE of proved undeveloped reserves primarily in the Woodford shale due to low natural gas prices and as a result of the five-year limitation on the number of years proved undeveloped reserves may remain on the books without being developed. Please refer to the caption Proved Undeveloped Reserves under the section Reserves included in Part I, Items 1 and 2 of this report for additional discussion. We had immaterial acquisitions of 1.6 BCFE, and we divested of 16.9 BCFE of proved reserves during the year related to non-core assets located primarily in our Rocky Mountain and Mid-Continent regions.

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The PV-10 value of our estimated proved reserves was $3.8 billion as of December 31, 2012, compared with $3.5 billion as of December 31, 2011. The after tax value, represented by the standardized measure calculation, was $3.0 billion as of December 31, 2012 compared with $2.6 billion as of December 31, 2011. The standardized measure calculation is presented in the Supplemental Oil and Gas Information section located in Part II, Item 8 of this report. A reconciliation between the PV-10 reserve value and the after tax value is shown under Reserves in Part I, Items 1 and 2 of this report.

•	We had record production in 2012. Our average daily production in 2012 was 28.3 MBbl of oil, 328.0 MMcf of gas, and 16.7 MBbl of NGLs, for an average equivalent production rate of 598.2 MMCFE, compared with 465.0 MMCFE in 2011, an increase of 29 percent year-over-year. Please refer to the caption Production Results below for additional discussion.

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We recorded a net loss of $54.2 million, or a loss of $0.83 per diluted share, for the year ended December 31, 2012, due to an impairment of proved properties. This compares with net income of $215.4 million, or $3.19 per diluted share, for the year ended December 31, 2011. Please refer to the caption Comparison of Financial Results and Trends Between 2012 and 2011 below for additional discussion regarding the components of net income (loss) and 2012 Highlights for additional discussion on impairment of proved properties.

•	We had record cash flow provided by operating activities of $922.0 million for the year ended December 31, 2012, compared with $760.5 million for the year ended December 31, 2011, which was an increase of 21 percent year-over-year. Please refer to Analysis of cash flow changes between 2012 and 2011 below for additional discussion.

•	Costs incurred for oil and gas producing activities for the year ended December 31, 2012, were $1.7 billion, compared with $1.6 billion for the same period in 2011. Please refer to the caption Costs Incurred in Oil and Gas Producing Activities below for additional discussion.

•	EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2012, was $1.0 billion, compared with $886.6 million for the same period in 2011. Please refer to the caption Non-GAAP Financial Measures below for additional discussion, including our definition of EBITDAX and reconciliations of our GAAP net income (loss) and net cash provided by operating activities to EBITDAX.

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(6)

Amount shown represents estimated future discounted abandonment costs. These obligations are recorded as liabilities on our December 31, 2012, accompanying balance sheets. The ultimate settlement of these obligations is unknown and can be impacted by federal and state regulations, as well as economic factors and therefore the actual timing of abandonment costs may vary significantly. Please refer to Note 9 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion regarding our asset retirement obligations.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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Eagle Ford Shale Divestiture. In August 2011, the Company divested of certain operated Eagle Ford shale assets located in its South Texas & Gulf Coast region. This divestiture was comprised of the Company’s entire operated acreage in LaSalle County, Texas, as well as an immaterial adjacent block of its operated acreage in Dimmit County, Texas. Total divestiture proceeds were $230.7 million. The final gain on this divestiture was $193.8 million. Please refer to Note 12 - Acquisition and Development Agreement and Carry and Earning Agreement for information on additional Eagle Ford activity in 2011.

•	Mid-Continent Divestiture. In June 2011, the Company divested of certain non-strategic assets located in its Mid-Continent region. Total divestiture proceeds were $35.8 million. The final gain on this divestiture was $28.5 million.

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•	Rocky Mountain Divestiture. In January 2011, the Company divested of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $45.5 million. The final gain on this divestiture was $27.2 million.

•	Permian Divestiture. In December 2010, the Company completed the divestiture of certain non-strategic assets located in its Permian region. Total divestiture proceeds were $54.7 million. The final gain on this divestiture was $18.4 million.

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Sequel Divestiture. In March 2010, the Company completed the divestiture of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $129.1 million. The final gain on this divestiture was $53.1 million. A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”).

•	Legacy Divestiture. In February 2010, the Company completed the divestiture of certain non-strategic assets located in its Rocky Mountain region. Total divestiture proceeds were $125.3 million. The final gain on this divestiture was $66.7 million. A portion of the transaction was structured to qualify as a like-kind exchange under Section 1031 of the Internal Revenue Code.

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(1)	The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending on the ending three-year performance multiplier, which ranges from zero to two.

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(1)	Equity securities of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand.

(2)	International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations.

(3)	High-yield bonds consist of non-investment grade fixed income securities. The investment objective is to obtain high current income. Due to the increased level of default risk, security selection focuses on credit-risk analysis.

(4)	The objective is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay's Capital Aggregate Bond Index with a modest amount of variability in duration around the index.

(5)	Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates.

(6)	Investments with exposure to commodity price movements, primarily through the use of futures, swaps and other commodity-linked securities.

(7)	The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity.

(8)	The hedge fund portfolio includes an investment in an actively traded global mutual fund that focuses on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.

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(1)	Certain amounts have been reclassified to conform to current-year presentation.

(2)	United States equities are invested in companies that trade on active exchanges within the United States and are well diversified by industry sector and equity style, such as growth and value strategies, and passive management strategies are employed.

(3)	International equities are invested in companies that trade on active exchanges outside the United States and are well diversified among more developed markets. Active and passive strategies are employed.

(4)	Intermediate term bonds seek total return. At least 80% of this fund is invested in a diversified portfolio of bonds, which include all types of securities. It invests primarily in bonds of corporate and governmental issues located in the United States and foreign countries, including emerging markets, all of which trade on active exchanges.

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•	Level 1 – quoted prices in active markets for identical assets or liabilities

•	Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

•	Level 3 – significant inputs to the valuation model are unobservable

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(1)	Net changes in the Net Profits Plan liability are shown in the Change in Net Profits Plan liability line item of the accompanying statements of operations.

(2)	Settlements represent cash payments made or accrued under the Net Profits Plan. The amounts in the table include cash payments made or accrued under the Net Profits Plan of $2.3 million, $6.3 million, and $26.1 million relating to divestiture proceeds for the years ended December 31, 2012, 2011, and 2010 respectively.

(3)	During 2011, the Company elected to cash out several Net Profits Plan pools with a $2.6 million direct payment. As a result, the Company reduced its Net Profits Plan liability by that amount.  There was no impact on the accompanying statements of operations for the period ended December 31, 2011, related to these settlements.

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(1)	Includes facility costs of $62.2 million, $112.4 million, and $80.3 million for the years ended December 31, 2012, 2011, and 2010, respectively.

(2)	Includes $3.4 million of unproved properties acquired for the year ended December 31, 2012. The remaining balance relates to leasing activity.

(3)	Includes capitalized interest of $12.1 million, $10.8 million, and $4.3 million for the years ended December 31, 2012, 2011, and 2010, respectively.

(4)	Includes amounts relating to estimated asset retirement obligations of $30.6 million, $19.3 million, and $5.8 million for the years ended December 31, 2012, 2011, and 2010, respectively.

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(1)	Please refer to Part I, Items 1 and 2 and Part II, Item 7 for current year reserve discussion.

(2)

For the year ended December 31, 2011, of the 11.5 BCFE upward revision of a previous estimate, (25.3) BCFE and 36.8 BCFE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2011, were $96.19 per Bbl and $4.12 per MMBtu, for oil and natural gas respectively. These prices were 21 percent higher and six percent lower, respectively, than the prices used in 2010. The per Bbl price used to estimate proved NGL reserves as of December 31, 2011 was $59.37. There is no 2010 comparative price as 2010 NGL production volumes, revenues, and prices have not been reclassified to conform with current presentation given the immateriality of NGL volumes in that period. Performance revisions in 2011 resulted in a net 36.8 BCFE increase in our estimate of proved reserves. This increase includes the impact of the Company's conversion to three stream production, which is partially offset by downward engineering revisions due primarily to the failure of Woodford shale wells in the Company's Mid-Continent region to satisfy internal economic hurdles. The Company added 526.1 BCFE from its drilling program, the majority of which related to activity in the Eagle Ford shale in South Texas. These additions are included in discoveries and extensions and infill reserves.

(3)

For the year ended December 31, 2010, of the 24.7 BCFE upward revision of a previous estimate, 42.6 BCFE and (17.9) BCFE relate to price and performance revisions, respectively. The prices used in the calculation of proved reserve estimates as of December 31, 2010, were $79.43 per Bbl and $4.38 per MMBtu for oil and natural gas, respectively. These prices were 30 percent and 13 percent higher, respectively, than the prices used in 2009.

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(4)	The Company divested of certain non-core assets during 2012, 2011, and 2010. Please refer to Note 3 - Divestitures and Assets Held for Sale for additional information.

(5)	For the years ended December 31, 2012, 2011, and 2010, amounts included approximately 299, 175, and 356 MMcf respectively, representing the Company’s net underproduced gas balancing position.

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(1)	The fourth quarter of 2012 and 2011 included $170.4 million and $170.5 million, respectively, of impairment of proved properties expense. Please refer to the caption Impairment of Proved and Unproved Properties included in Note 1 - Summary of Significant Accounting Policies for additional discussion.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

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(i)	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

(ii)	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

(iii)	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements.

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

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(1)

In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of SM Energy or any affiliate of SM Energy. The Equity Plan serves as the successor to the St. Mary Land & Exploration Company Stock Option Plan, the St. Mary Land & Exploration Company Incentive Stock Option Plan, the SM Energy Company Restricted Stock Plan, and the SM Energy Company Non-Employee Director Stock Compensation Plan (collectively referred to as the “Predecessor Plans”). All grants of equity are now made under the Equity Plan, and no further grants will be made under the Predecessor Plans. Each outstanding award under a Predecessor Plan immediately prior to the effective date of the Equity Plan continues to be governed solely by the terms and conditions of the instruments evidencing such grants or issuances. Our Board of Directors approved amendments to the Equity Plan in 2009 and 2010 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The awards granted in 2012, 2011, and 2010 under the Equity Plan were 724,671, 386,802, and 540,774, respectively.

(2)

Under the SM Energy Company ESPP, eligible employees may purchase shares of our common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on the first or last day of the six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code. Shares issued under the ESPP totaled 66,485, 41,358, and 52,948 in 2012, 2011, and 2010, respectively.

(3)

RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per share fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per share fair value for the outstanding RSUs and PSUs was $51.81 and $63.08, respectively. Please refer to Note 7 - Compensation Plan for additional discussion.

(4)	The number of awards vested assumes a one multiplier. The final number of shares issued upon settlement may vary depending on the three-year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two.

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ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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***	Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934.

****	Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of

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†	Exhibit constitutes a management contract or compensatory plan or agreement.

s	Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the recent change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document.

+	Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on November 9, 2010, in order to make technical revisions to ensure compliance with Section 409A of the Internal Revenue Code. There were no material changes to the substantive terms and conditions in this document.

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