The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in Item 8 of this report and also with "Certain Risks" in Item 1A of this report. Certain amounts in prior years' financial statements have been reclassified to conform to the 2012 financial statement presentation. This discussion also includes forward-looking statements. Please refer to "Cautionary Information about Forward-Looking Statements" in Part I of this report for important information about these types of statements.

OVERVIEW

Cimarex is an independent oil and gas exploration and production company. Our operations are entirely located in the United States, mainly in Oklahoma, Texas, New Mexico, and Kansas.

Our principal business objective is to profitably grow proved reserves and production for the long-term benefit of our shareholders through a diversified drilling portfolio. Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development. We occasionally consider property acquisitions and mergers to enhance our competitive position.

In order to achieve a consistent rate of growth and mitigate risk, we have historically maintained a blended portfolio of low, moderate, and higher risk exploration and development projects. We seek geologic and geographic diversification by operating in multiple basins. In recent years, we have shifted our capital expenditures to oil and liquids-rich gas projects because of strong oil prices relative to gas prices. We deal with volatility in commodity prices by maintaining flexibility in our capital investment program.

Our operations are currently focused in two main areas: the Mid-Continent region and the Permian Basin. The Mid-Continent region consists of Oklahoma, the Texas Panhandle, and southwest Kansas. Our Permian Basin region encompasses west Texas and southeast New Mexico. We also have operations in the Gulf Coast area, primarily in southeast Texas.

Growth is generally funded with cash flow provided by operating activities together with bank borrowings, sale of non-strategic assets and occasional public financing. Conservative use of leverage and maintaining a strong balance sheet have long been a part of our financial strategy. We have a long track record of profitable growth.

Our revenue, profitability, and future growth are highly dependent on the commodity prices we receive. Prices impact the amount of cash flow available for capital expenditures, our ability to raise additional capital and the fair market value of our assets. We use the full cost method of accounting for oil and gas activities. An extended decline in oil and/or gas prices could have an adverse effect on our financial position and results of operations, including the determination of full cost accounting ceiling test writedowns.

The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that impact reported results of operations and the amount of reported assets, liabilities, equity and proved reserves.

2012 Summary:

º •
º Average daily production increased by 6% to 627 MMcfe/d compared to 592 MMcfe/d in 2011.

º •
º Our combined Permian Basin and Mid-Continent production grew 20% to an all-time high of 586 MMcfe/d, compared to 487 MMcfe/d in 2011.

º •
º We added 757.3 Bcfe of proved reserves from extensions and discoveries, replacing 330% of production.

º •
º Proved reserves increased 10% to 2.26 Tcfe. Adjusted for property sales, proved reserves increased 13%.

º •
º Exploration and development expenditures totaled $1.6 billion.

º •
º Cash flow provided by operating activities totaled $1.2 billion.

º •
º Net income was $353.8 million, or $4.07 per diluted share. This compares to 2011 net income of $529.9 million, or $6.15 per diluted share.

º •
º We issued $750 million of 5.875% senior notes at par and retired our 7.125% senior notes.

º •
º Total debt increased by $345 million to $750 million compared to $405 million at year-end 2011.

º •
º We sold $305.9 million of non-strategic assets and used the proceeds for general corporate purposes, including repayment of outstanding bank debt.

Drilling activities were focused almost exclusively in the Permian Basin and Mid-Continent regions. During 2012, we drilled and completed 352 gross (192 net) wells. Of total wells drilled, 182 gross (122 net) were in the Permian Basin and 167 gross (69 net) were in the Mid-Continent.

We continue to evaluate and expand our acreage position in key long-term future drilling projects. During 2012, we invested $152.8 million in land and seismic.

In July 2012, aggregate commitments on our senior unsecured revolving credit facility were increased from $800 million to $1 billion. The credit facility provides for a borrowing base of $2 billion and will mature on July 14, 2016. We did not have any bank debt outstanding at December 31, 2012. At December 31, 2011, our outstanding bank debt was $55 million.

Proved Reserves

Year-end 2012 proved reserves grew 10% to 2.26 Tcfe, up from 2.05 Tcfe at year-end 2011. The increase in 2012 proved reserves is net of production of
229.3 Bcfe and sales of 57.3 Bcfe. Proved reserves were 80% developed at year-end 2012 compared to 82% at year-end 2011. Overall, approximately 68% of proved reserves were in our Mid-Continent region and 31% in the Permian Basin.

Reserves added from extensions and discoveries totaled 757.3 Bcfe, replacing 330% of production. In our western Oklahoma Cana-Woodford shale area, we added
202.5 Bcfe from infill wells drilled and 315.9 Bcfe of proved undeveloped (PUD) reserves. Development drilling in the Permian Basin added 229.2 Bcfe. In total, reserve additions were comprised of 51% oil and NGLs and 49% gas. With continued focus on oil and liquids-rich gas projects, the amount of proved reserves comprised of oil and NGLs increased to 45% as compared to 41% at year-end 2011.

Approximately 72 Bcfe of the 257.3 Bcfe net negative revisions during 2012 relate to production performance of certain wells recently drilled in our Cana-Woodford shale project. PUD reserve additions in extensions and discoveries for 2012 now reflect revised expectations of future production performance. The remainder of the net negative revision primarily resulted from decreases in prices (91 Bcfe), increases in operating expenses (21 Bcfe) which shortened the economic lives, adjustments to previously booked PUD reserves (25 Bcfe) and the removal of PUD locations due to altered future drilling plans (42 Bcfe).

The process of estimating quantities of oil, gas and NGL reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, contractual arrangements and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time.

Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. See Note 15 to the Consolidated Financial Statements of this report for further discussion regarding our proved reserves.

Revenues

Most of our revenues are derived from sales of oil, gas and NGL production. While revenues are a function of both production and prices, wide swings in commodity prices have had the greatest impact on our results of operations. Compared to 2011, our 2012 average realized gas price decreased by 35% and our average realized NGL price decreased by 28%. Our average oil price decreased 4%. Prices we receive are determined by prevailing market conditions. Regional and worldwide economic and geopolitical activity, weather and other variable factors influence market conditions, which often result in significant volatility in commodity prices.

The following table presents our average realized commodity prices. Realized prices do not include settlements of our commodity hedging contracts.

                                                          Years Ended
                                                         December 31,
                                                   2012      2011      2010
           Gas Prices:
           Average Henry Hub price ($/Mcf)        $  2.79   $  4.04   $  4.39
           Average realized sales price ($/Mcf)   $  2.88   $  4.42   $  4.92
           Oil Prices:
           Average WTI Cushing price ($/Bbl)      $ 94.20   $ 95.14   $ 79.54
           Average realized sales price ($/Bbl)   $ 89.25   $ 93.00   $ 76.76
           NGL Prices:
           Average realized sales price ($/Bbl)   $ 30.66   $ 42.31   $ 34.91

On an energy equivalent basis, 52% of our 2012 aggregate production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in a $12 million change in our gas revenues. Similarly, 48% of our production was crude oil and NGLs. A $1.00 per barrel change in our average realized sales prices would have resulted in an $18 million change in our oil and NGL revenues.

See RESULTS OF OPERATIONS below for a discussion of the impact changes in realized prices had on our 2012 revenues.

Production and other operating expenses

Costs associated with finding and producing oil and gas are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production and others are a function of the number of wells we own. At the end of 2012, we owned interests in 13,127 gross wells.

Production expense generally consists of the cost of water disposal, power and fuel, direct labor, third-party field services, compression and certain maintenance activity (workovers) necessary to produce oil and gas from existing wells.

Transportation expense is comprised of costs paid to move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which is net of transportation costs, and in other instances we pay separately for transportation. If costs are netted in the proceeds received, both the gross revenues and gross costs are shown in sales and expenses, respectively.

Depreciation, depletion, and amortization (DD&A) of our producing properties is computed using the units-of-production method. The economic life of each producing well depends upon the assumed price for future sales of production. Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves which reduces depletion expense. Lower prices generally have the effect of decreasing reserves which increases depletion expense. The costs of replacing production also impact our DD&A rate. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, and reclassifications from unproved properties to proved properties will impact depletion expense.

We use the full cost method of accounting for our oil and gas operations. Accounting rules require us to perform a quarterly "ceiling test" calculation to test our oil and gas properties for possible impairment. The primary components impacting this analysis are commodity prices, reserve quantities added and produced, overall exploration and development costs, and depletion expense. If the net capitalized cost of our oil and gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess would be expensed. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized,

the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects.

At December 31, 2012, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary. However, the amount of the excess has declined approximately 87% since December 31, 2011. As of December 31, 2012, a decline of 3% or more in the value of the ceiling limitation would have resulted in an impairment. If negative trends continue we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

General and administrative (G&A) expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our offices and not directly associated with exploration, development or production activities. Our G&A expense is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting.

See RESULTS OF OPERATIONS below for a discussion of changes in production and other operating expenses.

Derivative Instruments/Hedging

We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in oil and/or gas prices and the corresponding negative impact on cash flow available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes.

For 2012, we hedged about half of our anticipated oil production. We did not hedge any of our gas or NGL production. All of the oil contracts expired during 2012 without any cash settlements.

In 2011 we had approximately 40 to 45% of our anticipated oil production and 5 to 6% of projected gas production hedged. Those contracts were settled in 2011 for a net gain of $6.7 million. During 2010 we had approximately 40% of our anticipated 2010 oil and gas production hedged. Those contracts settled in 2010 for a net gain of $52.1 million.

As of December 31, 2012, we did not have any hedges in place. Subsequent to December 31, 2012 we entered into oil contracts as follows:

                                                               Weighted Average Price
      Period             Type      Volume/Day    Index(1)    Floor     Ceiling     Swap
      Feb 13 - Dec 13   Collars     6,000 Bbls   WTI         $ 85.00   $ 102.31         -
      Feb 13 - Dec 13    Swaps      6,000 Bbls   WTI               -          -   $ 96.13


--------------------------------------------------------------------------------
   º (1)

Depending on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our hedging positions.

We have chosen not to apply hedge accounting treatment to any of the derivative contracts we have entered into since 2009. Therefore, settlements on our derivative contracts do not impact our realized commodity prices during the periods they cover. Instead, any settlements on the contracts are shown as a component of operating costs and expenses as either a net gain or loss on derivative instruments. See Item 7A and Note 2 to the Consolidated Financial Statements of this report for additional information regarding our derivative instruments.

RESULTS OF OPERATIONS

2012 compared to 2011

Net income for the year ended December 31, 2012, was $353.8 million, or $4.07 per diluted share. For 2011, we had net income of $529.9 million, or $6.15 per diluted share. Decreased revenues from lower realized commodity prices and higher DD&A expense were the primary factors for the decrease in 2012 net income. These changes are discussed further in the analysis that follows.

                                                 Percent
                       For the Years Ended        Change
                          December 31,           Between            Price / Volume Change
Commodity Sales        2012          2011       2012/2011      Price       Volume       Total
(in thousands or
as indicated)
Gas sales           $   340,744   $   530,334          -36 % $ (182,482 ) $  (7,108 ) $ (189,590 )
Oil sales             1,027,757       909,344           13 %    (43,185 )   161,598      118,413
NGL sales               213,149       263,842          -19 %    (80,991 )    30,298      (50,693 )

Total commodity
sales               $ 1,581,650   $ 1,703,520           -7 % $ (306,658 ) $ 184,788   $ (121,870 )

Total gas
volume-MMcf             118,495       120,113           -1 %
Gas volume-MMcf
per day                   323.8         329.1
Average gas
price-per Mcf       $      2.88   $      4.42          -35 %
Total oil
volume-thousand
barrels                  11,516         9,778           18 %
Oil
volume-barrels
per day                  31,463        26,789
Average oil
price-per barrel    $     89.25   $     93.00           -4 %
Total NGL
volume-thousand
barrels                   6,952         6,236           11 %
NGL
volume-barrels
per day                  18,994        17,086
Average NGL
price-per barrel    $     30.66   $     42.31          -28 %
Total equivalent
production
volumes-MMcfe per
day                       626.5         592.3            6 %

Commodity sales totaled $1.6 billion in 2012, compared to $1.7 billion last year. The 7% year-over-year decline was attributable to a $307 million decrease from lower prices, which was partially offset by $185 million from higher oil and NGL production.

In 2012, our aggregate production volumes were 626.5 MMcfe per day, up 6% from 592.3 Mcfe per day in 2011. In the fourth quarter of 2012, our production volumes averaged a record 676.7 MMcfe per day, or 13% above 601.4 MMcfe per day in the fourth quarter 2011. The period-over-period increases in volumes were a result of our successful drilling programs in the Permian Basin and Mid-Continent region.

Our 2012 gas production averaged 323.8 MMcf per day, compared to 329.1 MMcf per day for 2011. The 1% decline in year-over-year gas production resulted in a decrease in revenue of $7.1 million. During the fourth quarter of 2012, our daily gas production averaged 333.4 MMcf per day, down slightly from 334.2 MMcf per day, for the same period of 2011. The decline in fourth quarter 2012 gas production resulted in $0.5 million less revenue in the fourth quarter of 2012 compared to the same period of 2011.

Oil production for 2012 averaged 31,463 barrels per day, up 18% from 26,789 barrels per day for in 2011. The increase in 2012 production provided an additional $161.6 million of oil revenue. Our fourth quarter 2012 oil production averaged 35,099 barrels per day, an increase of 28% compared to 27,431 barrels per day for the fourth quarter 2011. The higher production in the fourth quarter of 2012 increased oil sales by $65.4 million.

In 2012, our average daily NGL production volume was 18,994 barrels per day compared to 17,086 barrels per day for 2011. The 11% higher volumes contributed $30.3 million of additional revenue. During the fourth quarter of 2012, our average NGL production was 22,118 barrels per day, up 29% from 17,107 barrels per day during the fourth quarter 2011. Higher production provided an additional $18.6 million of revenue in the fourth quarter.

The increases in our 2012 oil and NGL production reflect our continued focus on drilling oil and liquids-rich gas wells in the Permian Basin and the Cana-Woodford shale.

Our average realized gas price for 2012 fell to $2.88 per Mcf, compared to $4.42 per Mcf in 2011. The 35% decrease in gas prices resulted in $182.5 million lower revenues compared to 2011. During the fourth quarter of 2012, our average realized gas price decreased by 14% to $3.35 per Mcf. For the same period of 2011 we realized an average price of $3.90 per Mcf. The decrease in realized prices in the fourth quarter caused our gas sales to be $16.9 million lower than the same period of 2011.

Realized oil prices during 2012 averaged $89.25 per barrel, a decrease of 4% from the average price received in 2011 of $93.00 per barrel. This decrease resulted in lower oil revenue of $43.2 million compared to 2011. For the fourth quarter of 2012 our average realized oil price was $83.04 per barrel versus $92.76 per barrel received in the fourth quarter of 2011. The decrease in fourth quarter 2012 oil sales due to the 10% decrease in oil prices totaled $31.4 million.

During 2012 our average realized price for NGLs was $30.66 per barrel, which was 28% lower than the average realized price of $42.31 per barrel received in 2011. The decrease in realized price resulted in lower NGL sales in 2012 of $81.0 million. In the fourth quarter of 2012 our average realized price for NGLs was $28.99 per barrel compared to an average realized price of $40.29 per barrel received in the fourth quarter of 2011. The 28% decrease in the fourth quarter 2012 NGL realized price resulted in lower NGL sales of $23.0 million compared to the 2011 fourth quarter.

The changes in realized commodity prices were the result of overall market conditions.

We sometimes transport, process and market third-party gas that is associated with our gas. The table below reflects our pre-tax operating margin (revenues less direct expenses) for third party gas gathering and processing as well as the marketing margin (revenues less purchases) for marketing third party gas.

                                                                For the Years
                                                              Ended December 31,
                                                               2012        2011
  Gas Gathering, Processing and Marketing (in thousands):
  Gas gathering, processing and other revenues               $  43,042   $  53,640
  Gas gathering and processing costs                           (21,965 )   (23,327 )

  Gas gathering and processing margin                        $  21,077   $  30,313

  Gas marketing revenues, net of related costs               $    (754 ) $     729

The lower net margins from gas gathering and processing and gas marketing activities are primarily the result of lower volumes and prices associated with third party gas in 2012 versus 2011.

In 2012, our total operating costs and expenses (not including gas gathering, processing and marketing and processing costs, or income tax expense) increased to $1.031 billion compared to $896 million in 2011. Analyses of the year-over-year differences are discussed below:

                                         For the Years Ended
                                            December 31,          Variance       Per Mcfe
                                                                  Between
                                          2012         2011      2012/2011     2012     2011
Operating costs and expenses (in
thousands):
Depreciation, depletion and
amortization (DD&A)                    $   513,916   $ 390,461    $ 123,455   $ 2.24   $ 1.81
Asset retirement obligation                 13,019      11,451        1,568   $ 0.06   $ 0.05
Production                                 258,584     247,048       11,536   $ 1.13   $ 1.14
Transportation                              57,354      56,711          643   $ 0.25   $ 0.26
Taxes other than income                     86,994     126,468      (39,474 ) $ 0.38   $ 0.59
General and administrative                  54,428      45,256        9,172   $ 0.24   $ 0.21
Stock compensation                          21,919      18,949        2,970   $ 0.10   $ 0.09
Gain on derivative instruments, net           (245 )   (10,322 )     10,077      N/A      N/A
Other operating, net                        24,961      10,263       14,698      N/A      N/A

                                       $ 1,030,930   $ 896,285    $ 134,645

Our 2012 DD&A expense increased 32% to $513.9 million, compared to $390.5 million in 2011. The $123.5 million increase accounted for 92% of the aggregate increase in operating costs and expenses. DD&A per Mcfe increased by 24% to $2.24 from $1.81. The higher DD&A rate is primarily from increasing costs of reserves added and the effect of lower prices resulting in negative reserve revisions. We expect the average DD&A rate to increase modestly during 2013.

Asset retirement obligation expense increased by 14% to $13.0 million in 2012. The increase resulted from higher estimated plugging and abandonment costs in the Permian Basin and Gulf of Mexico.

Our production costs consist of lease operating expense and workover expense as follows:

                                     For the Years
                                   Ended December 31,      Variance        Per Mcfe
                                                            Between
       (in thousands)               2012        2011       2012/2011     2012     2011
       Lease operating expense    $ 217,891   $ 208,097    $    9,794   $ 0.95   $ 0.96
       Workover expense              40,693      38,951         1,742   $ 0.18   $ 0.18

                                  $ 258,584   $ 247,048    $   11,536   $ 1.13   $ 1.14

Lease operating expense in 2012 increased by 5% compared to 2011. Higher costs were associated with compressor rentals and field employees. The lower rate per Mcfe was primarily a function of increased production volumes and efficiencies of horizontal well operations for 2012 compared to 2011.

Workover expense for 2012 was slightly higher than 2011. Such costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.

Our 2012 transportation costs were relatively flat compared to 2011. Transportation costs will vary based on increases or decreases in sales volumes, compression charges and fuel cost.

Taxes other than income are assessed by state and local taxing authorities on production, revenues or the value of properties. Revenue based severance taxes are the largest component of these taxes. Our 2012 taxes decreased due to lower gas and NGL prices, a reduced tax rate on Oklahoma horizontal deep wells and a refund for taxes in prior years.

. . .