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XEC > SEC Filings for XEC > Form 10-Q on 6-Nov-2013All Recent SEC Filings

Show all filings for CIMAREX ENERGY CO

Form 10-Q for CIMAREX ENERGY CO


6-Nov-2013

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Our operations are currently focused in two main areas: the Permian Basin and the Mid-Continent region. Our Permian Basin region encompasses west Texas and southeast New Mexico. The Mid-Continent region consists of Oklahoma, the Texas Panhandle, and southwest Kansas. 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 part of our financial strategy.

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 write-downs.

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.

Third quarter 2013 summary of operating and financial results:

Net income increased 64% to $138.4 million, or $1.59 per diluted share.

Oil, gas and NGL sales for the third quarter of 2013 were $549.6 million, 38% higher than a year earlier.

Our overall production volumes increased 13% to a record 716.8 MMcfe per day.

Oil production grew 21%, to a record 39,292 barrels per day.

NGL volumes increased by 16% and gas volumes were up 7%.


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Year-to-date cash flow provided by operating activities was $940.7 million versus $836.1 million for the same period of 2012.

Year-to-date exploration and development expenditures totaled $1.187 billion.

Total debt at September 30, 2013 was $900 million, up $150 million from year-end 2012.

Revenues

Most of our revenues are derived from the 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. 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, which are financial instruments.

                                            Three Months               Nine Months
                                         Ended September 30,       Ended September 30,
                                           2013         2012        2013          2012
Oil Prices:
Average WTI Cushing price ($/Bbl)      $     105.81    $ 92.22   $     98.14    $  96.21
Average realized sales price ($/Bbl)   $     102.88    $ 88.18   $     93.81    $  91.67

Gas Prices:
Average Henry Hub price ($/Mcf)        $       3.58    $  2.80   $      3.67    $   2.58
Average realized sales price ($/Mcf)   $       3.72    $  2.79   $      3.73    $   2.71

NGL Prices:
Average realized sales price ($/Bbl)   $      28.63    $ 28.55   $     28.57    $  31.35

On an energy equivalent basis, 51% of our aggregate 2013 production was crude oil and NGLs. A $1.00 per barrel change in our average realized sales price would have resulted in a $15.8 million change in our combined oil and NGL revenues. Similarly, 49% of our production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in a $9.3 million change in our gas revenues.

See RESULTS OF OPERATIONS below for a discussion of the impact changes in realized prices had on our 2013 revenues.

Production and other operating expenses

Costs associated with producing oil and gas are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production and some 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 and other operating costs include expenditures to prepare and move oil and gas from the wellhead to a specified sales point. In some cases we receive a payment from purchasers which


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is net of these costs, and in other instances we separately pay 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 estimated proved reserves for that well which in turn depend 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. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our DD&A rate. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, and reclassifications of properties from unproved to proved 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, depletion expense, and tax effects. 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 (a) the present value discounted at 10% of estimated future net cash flows from proved reserves, (b) the cost of properties not being amortized, (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and (d) all related tax effects.

At September 30, 2013, 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. Our ceiling limitation has improved since December 31, 2012. However, a decline of 5% in the value of the ceiling limitation would have resulted in an impairment. If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur a full cost ceiling impairment related to our oil and gas properties in future quarters.

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 to us by working interest owners of the oil and gas properties we operate 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 and we did not have any hedges in place at year-end.

In the first nine months of 2013, we hedged approximately 32% of our anticipated 2013 oil production, and 23% of our anticipated gas production. We have also hedged a portion of our 2014 oil


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and gas production. For contracts that have settled through September 30, 2013, we have paid net cash settlements of $5.5 million on oil contracts and received $1.2 million of cash settlements on our gas contracts.

The following tables summarize our outstanding contracts as of September 30, 2013:

                                 Oil Contracts



                                                       Weighted Average Price
Period             Type     Volume/Day   Index(1)    Floor     Ceiling     Swap
Oct 13 - Dec 13   Collars   6,000 Bbls     WTI      $  85.00   $ 102.31       N/A
Oct 13 - Dec 13    Swaps    6,000 Bbls     WTI           N/A        N/A   $ 96.13
Jan 14 - Dec 14   Collars   6,000 Bbls     WTI      $  85.00   $ 105.68       N/A



(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

Gas Contacts

Weighted Average
Price
Period Type Volume/Day Index(1) Floor Ceiling Oct 13 - Dec 14 Collars 80,000 MMBtu PEPL $ 3.51 $ 4.57



(1) PEPL refers to Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index as quoted in Platt's Inside FERC.

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.

Since 2009, we have chosen not to apply hedge accounting treatment to our derivative contracts. As a result, 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 the discussion of our net gain/loss on hedging activities below, in RESULTS OF OPERATIONS. Also, see Note 2 to the Consolidated Financial Statements and Item 3 of this report for additional information regarding our derivative instruments.

RESULTS OF OPERATIONS

Third Quarter and Nine Months Ended September 30, 2013 vs. September 30, 2012

Net income for the third quarter of 2013 was $138.4 million ($1.59 per diluted share), up 64% from $84.3 million ($0.97 per diluted share) for the same period of 2012. For the first nine months of 2013, net income of $357.9 million ($4.12 per diluted share) was 41% higher than net income of $254.7 million ($2.93 per diluted share) for 2012. The increases in net income for the 2013 periods were primarily a result of higher revenues from increased production volumes and higher realized commodity prices, which were partially offset by higher operating expenses. In addition, the first nine months of 2012 included a loss on early extinguishment of debt. These changes are discussed further in the analysis that follows.


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                                                              Percent
                                                              Change
Commodity Sales                                               Between          Price/Volume Change
(in thousands or as indicated)      2013          2012       2013/2012    Price      Volume       Total
For the Three Months Ended
September 30,
Oil sales                        $   371,881   $   263,315          41 % $ 53,141   $  55,425   $ 108,566
Gas sales                            118,824        83,208          43 %   29,674       5,942      35,616
NGL sales                             58,922        50,860          16 %      165       7,897       8,062
                                 $   549,627   $   397,383               $ 82,980   $  69,264   $ 152,244

For the Nine Months Ended
September 30,
Oil sales                        $   933,879   $   759,609          23 % $ 21,304   $ 152,966   $ 174,270
Gas sales                            346,492       238,102          46 %   94,772      13,618     108,390
NGL sales                            168,106       154,160           9 %  (16,355 )    30,301      13,946
                                 $ 1,448,477   $ 1,151,871               $ 99,721   $ 196,885   $ 296,606




                                                       Percent                                Percent
                            For the Three Months       Change       For the Nine Months       Change
                             Ended September 30,       Between      Ended September 30,       Between
                              2013          2012      2013/2012      2013          2012      2013/2012
Total oil volume -
thousand barrels                 3,615        2,986          21 %       9,955        8,287          20 %
Oil volume - barrels
per day                         39,292       32,456          21 %      36,464       30,243          21 %
Average oil price - per
barrel                    $     102.88    $   88.18          17 % $     93.81    $   91.67           2 %

Total gas volume - MMcf         31,908       29,831           7 %      92,914       87,825           6 %
Gas volume - MMcf per
day                              346.8        324.2           7 %       340.3        320.5           6 %
Average gas price - per
Mcf                       $       3.72    $    2.79          33 % $      3.73    $    2.71          38 %

Total NGL volume -
thousand barrels                 2,058        1,781          16 %       5,883        4,917          20 %
NGL volume - barrels
per day                         22,373       19,360          16 %      21,550       17,944          20 %
Average NGL price - per
barrel                    $      28.63    $   28.55           -   $     28.57    $   31.35          -9 %
Total equivalent
production volumes -
MMcfe per day                    716.8        635.1          13 %       688.4        609.6          13 %

Third quarter 2013 commodity sales of $549.6 million were 38% higher than year-earlier sales of $397.4 million. Most of the $152.2 million increase in sales resulted from higher oil production and prices.

For the first nine months of 2013, commodity sales totaled $1.448 billion, up 26% from $1.152 billion for the same period of 2012. The $296.6 million increase was attributable to increases in production volumes for each of the commodities and higher realized sales prices for oil and gas.

Our third-quarter 2013 aggregate average production volumes reached a record
716.8 MMcfe per day, up 13% from 635.1 MMcfe per day for the same period in 2012. Average production volumes for the first nine months of 2013 were
688.4 MMcfe per day, up 13% from 609.6 MMcfe per day for the comparable 2012 period. The period-over-period increases in production were a result of our drilling programs in the Permian Basin and western Oklahoma.

Oil production during the third quarter of 2013 grew 21% to a record 39,292 barrels per day, compared to 32,456 barrels per day in 2012. This increase resulted in an additional $55.4 million of oil sales revenue. During the first nine months of 2013, our oil production averaged 36,464 barrels per day, up from 30,243 barrels per day in the 2012 period. The 21% increase contributed $153.0 million of additional revenue for the first nine months of 2013.

Third-quarter 2013 gas production averaged 346.8 MMcf per day, compared to
324.2 MMcf per day in the second quarter of 2012. This 7% increase resulted in an additional $5.9 million of gas revenue for the third quarter of 2013. During the first nine months of 2013 our gas production averaged 340.3 MMcf per day, up 6% from the first nine months of 2012 average of 320.5 MMcf per day.


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Increased gas production contributed additional revenue of $13.6 million for the first nine months of 2013.

NGL production volumes in the third quarter of 2013 increased 16% to 22,373 barrels per day compared to 19,360 barrels per day in the 2012 period, which resulted in additional revenue of $7.9 million. During the first nine months of 2013, NGL production averaged 21,550 barrels per day, compared to 17,944 barrels per day in the 2012 period. The 20% increase in production provided an additional $30.3 million of revenue in 2013.

Our average realized oil price of $102.88 per barrel received in the third quarter of 2013 was 17% higher than the 2012 average price of $88.18. The increase in price contributed an additional $53.1 million in revenue. In the first nine months of 2013, our average realized oil price was $93.81 per barrel, which was 2% higher than the average price of $91.67 for the same period of 2012. The increase in price accounted for $21.3 million of higher oil revenue during the first nine months of 2013.

In the third quarter of 2013, we realized an average gas price of $3.72 per Mcf, up from $2.79 per Mcf in the third quarter of 2012, or an increase of 33%, which contributed $29.7 million of additional gas revenue. Our average realized gas price of $3.73 per Mcf for the first nine months of 2013 was 38% higher than an average realized price of $2.71 for the same period of 2012. The higher price received in 2013 resulted in increased gas revenues of $94.8 million.

The average NGL price we received in the third quarter of 2013 of $28.63 per barrel was flat compared to $28.55 per barrel in the third quarter of 2012. In the first nine months of 2013, we received an average NGL price of $28.57 per barrel, which was 9% lower than the 2012 average price of $31.35 and resulted in $16.4 million of lower NGL revenue in 2013.

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 Three Months          For the Nine Months
                                      Ended September 30,           Ended September 30,
                                      2013           2012           2013           2012
Gas Gathering, Processing,
Marketing and Other (in
thousands):
Gas gathering, processing and
other revenues                     $    11,380    $    10,054    $    32,951    $   31,940
Gas gathering and processing
costs                                   (6,970 )       (5,496 )      (18,310 )     (15,302 )
Gas gathering, processing and
other margin                       $     4,410    $     4,558    $    14,641    $   16,638

Gas marketing revenues, net of
related costs                      $       329    $      (525 )  $        21    $     (741 )

Changes in net margins from gas gathering, processing, marketing and other activities result from volumetric changes and overall market conditions.

In the third quarter of 2013, our total operating costs and expenses (not including gas gathering, processing and marketing costs, or income tax expense) were $329.8 million, up 22% compared to $271.4 million in the third quarter of 2012. For the first nine months of 2013, operating costs were $889.9 million, or an increase of 18% over the same period of 2012. Analyses of the year-over-year differences are discussed below.


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                                   For the Three Months        Variance
                                    Ended September 30,        Between            Per Mcfe
                                     2013          2012       2013/2012       2013        2012
Operating costs and expenses
(in thousands):
Depreciation, depletion and
amortization                     $    159,182    $ 135,987    $   23,195    $   2.41    $   2.33
Asset retirement obligation             1,797        3,512        (1,715 )  $   0.03    $   0.06
Production                             76,166       62,699        13,467    $   1.16    $   1.07
Transportation and other
operating                              25,838       14,481        11,357    $   0.39    $   0.25
Taxes other than income                31,104       24,095         7,009    $   0.47    $   0.41
General and administrative             19,003       14,742         4,261    $   0.29    $   0.25
Stock compensation                      3,347        8,301        (4,954 )  $   0.05    $   0.14
(Gain) loss on derivative
instruments, net                       10,824        5,329         5,495         N/A         N/A
Other operating, net                    2,507        2,236           271         N/A         N/A
                                 $    329,768    $ 271,382    $   58,386




                                For the Nine Months        Variance
                                Ended September 30,        Between             Per Mcfe
                                 2013          2012       2013/2012       2013         2012
Operating costs and
expenses (in thousands):
Depreciation, depletion
and amortization              $   442,851    $ 375,486    $   67,365    $    2.36    $    2.25
Asset retirement
obligation                          7,080        9,478        (2,398 )  $    0.04    $    0.06
Production                        214,985      192,818        22,167    $    1.15    $    1.15
Transportation and other
operating                          66,494       40,966        25,528    $    0.35    $    0.25
Taxes other than income            84,039       72,738        11,301    $    0.45    $    0.44
General and administrative         57,416       41,523        15,893    $    0.31    $    0.25
Stock compensation                 10,459       17,519        (7,060 )  $    0.06    $    0.11
(Gain) loss on derivative
instruments, net                   (1,233 )       (661 )        (572 )        N/A          N/A
Other operating, net                7,804        7,295           509          N/A          N/A
                              $   889,895    $ 757,162    $  132,733

Our third quarter 2013 DD&A expense of $159.2 million was 17% higher than during the same period of 2012 and accounted for 40% of the total quarter-over-quarter increase in costs and expenses. On a unit of production basis, third-quarter 2013 DD&A increased by $0.08 to $2.41 per Mcfe. For the first nine months of 2013, DD&A was $442.9 million, up 18% compared to the same period of 2012. This increase was 51% of the aggregate year-over-year variance. DD&A per Mcfe for the first nine months of 2013 increased by $0.11 to $2.36 per Mcfe. About two-thirds of the increases in DD&A in the 2013 periods were attributable to our higher production volumes. The rest of the increase was a result of a higher DD&A rate. Our DD&A rate has increased because the per unit cost of adding new proved reserves has exceeded the net remaining book basis of proved reserves added in prior years.

Production costs consist of lease operating expense and workover expense as follows:

                            For the Three Months      Variance
                            Ended September 30,       Between        Per Mcfe
(in thousands)               2013          2012      2013/2012     2013     2012
Lease operating expense   $    60,364    $  52,100   $    8,264   $ 0.92   $ 0.89
Workover expense               15,802       10,599        5,203     0.24     0.18
                          $    76,166    $  62,699   $   13,467   $ 1.16   $ 1.07




                            For the Nine Months      Variance
                            Ended September 30,      Between        Per Mcfe
(in thousands)               2013         2012      2013/2012     2013     2012
Lease operating expense   $   166,995   $ 163,076   $    3,919   $ 0.89   $ 0.98
Workover expense               47,990      29,742       18,248     0.26     0.17
                          $   214,985   $ 192,818   $   22,167   $ 1.15   $ 1.15

Our third quarter 2013 lease operating expense (LOE) of $60.4 million increased 16% from $52.1 million during the same period of 2012. In 2013, increased costs due to new well activity were


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partially offset by decreased costs related to property divestitures which occurred subsequent to the third quarter of 2012.

LOE for the first nine months of 2013 increased by 2% to $167.0 million compared to $163.1 million in 2012. In 2013, increased costs due to new well activity were largely offset by decreased costs from property divestitures and decreased salt water disposal costs.

Our workover expenses for the third quarter and first nine months of 2013 were considerably higher than costs incurred for the same periods of 2012. Workover costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.

. . .

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