| • 10-Q • EX-31.1 • EX-31.2 • EX-32.1 • EX-32.2 • XBRL INSTANCE DOCUMENT • XBRL TAXONOMY EXTENSION SCHEMA DOCUMENT • XBRL TAXONOMY EXTENSION CALCULATION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION LABELS LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION DEFINITION LINKBASE DOCUMENT | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
(Mark One)
x Quarterly Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934
o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period ended June 30, 2012
Commission File No. 001-31446
CIMAREX ENERGY CO. 1700 Lincoln Street, Suite 1800 Denver, Colorado 80203-4518 (303) 295-3995
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 x No o
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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x Noo
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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x.
The number of shares of Cimarex Energy Co. common stock outstanding as of June 30, 2012 was 85,987,555.
CIMAREX ENERGY CO.
GLOSSARY
Bbl/d—Barrels (of oil or natural gas liquids) per day Bbls—Barrels (of oil or natural gas liquids) Bcf—Billion cubic feet Bcfe—Billion cubic feet equivalent Btu—British thermal unit MBbls—Thousand barrels Mcf—Thousand cubic feet (of natural gas) Mcfe—Thousand cubic feet equivalent MMBbls—Million barrels MMBtu—Million British Thermal Units MMcf—Million cubic feet MMcf/d—Million cubic feet per day MMcfe—Million cubic feet equivalent MMcfe/d—Million cubic feet equivalent per day Net Acres—Gross acreage multiplied by Cimarex’s working interest percentage Net Production—Gross production multiplied by Cimarex’s net revenue interest NGL—Natural gas liquids Tcf—Trillion cubic feet Tcfe—Trillion cubic feet equivalent WTI—West Texas Intermediate
One barrel of oil or NGL is the energy equivalent of six Mcf of natural gas
CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS
Throughout this Form 10-Q, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. These forward-looking statements include, among others, statements concerning our outlook with regard to timing and amount of future production of oil and gas, price realizations, amounts, nature and timing of capital expenditures for exploration and development, plans for funding operations and capital expenditures, drilling of wells, operating costs and other expenses, marketing of oil and gas and other statements of expectations, beliefs, future plans and strategies, anticipated events or trends, and similar expressions concerning matters that are not historical facts. The forward-looking statements in this report are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by the statements.
These risks and uncertainties include, but are not limited to, fluctuations in the price we receive for our oil and gas production, reductions in the quantity of oil and gas sold due to decreased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated, and increased financing costs due to a significant increase in interest rates. In addition, exploration and development opportunities that we pursue may not result in productive oil and gas properties. There are also numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. These and other risks and uncertainties affecting us are discussed in greater detail in this report and in our other filings with the Securities and Exchange Commission.
CIMAREX ENERGY CO. Condensed Consolidated Balance Sheets
See accompanying notes to consolidated financial statements.
CIMAREX ENERGY CO. Consolidated Comprehensive Statements of Operations (Unaudited)
See accompanying notes to consolidated financial statements.
CIMAREX ENERGY CO. Condensed Consolidated Statements of Cash Flows (Unaudited)
See accompanying notes to consolidated financial statements.
CIMAREX ENERGY GO. Notes to Consolidated Financial Statements June 30, 2012 (Unaudited)
1. Basis of Presentation
The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in annual reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our 2011 Annual Report on Form 10-K.
In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods shown. Certain amounts in prior years’ financial statements have been reclassified to conform to the 2012 financial statement presentation. We have evaluated subsequent events through the date of this filing.
Oil and Gas Properties
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 calculation 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 charged to expense. 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 June 30, 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, a decline of 10% or more in the value of the ceiling limitation would have resulted in an impairment.
If prices decrease significantly, we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.
Use of Estimates
The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved oil and gas reserves, the use of these oil and gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations and estimates of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments are also required in determining reserves for bad debt, impairments of undeveloped properties and other assets, purchase price allocation, valuation of deferred tax assets, fair value measurements and commitments and contingencies.
Accounts Receivable, Accounts Payable, and Accrued Liabilities
The components of our receivable accounts, accounts payable, and accrued liabilities are shown below.
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
Recently Issued Accounting Standards
No significant accounting standards applicable to Cimarex have been issued during the quarter ended June 30, 2012.
2. Derivative Instruments/Hedging
We periodically enter into derivative instruments to mitigate a portion of our potential exposure to a decline in commodity 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 and 2013, management has been authorized to hedge up to 50% of our anticipated equivalent oil and gas production. 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 current hedging positions.
At June 30, 2012, we had the following outstanding contracts relative to our future production. We have elected not to account for these derivatives as cash flow hedges.
(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.
We have hedged about half of our anticipated oil production for 2012. We have not hedged any of our 2012 gas or NGL production.
Under a collar agreement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.
Our derivative contracts are carried at their fair value on our balance sheet. We estimate the fair value using internal risk adjusted discounted cash flow calculations. Cash flows are based on published forward commodity price curves for the underlying commodity as of the date of the estimate. For collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms.
The fair value of our derivative instruments in an asset position includes a measure of counterparty credit risk, and the fair value of instruments in a liability position includes a measure of our own nonperformance risk. These credit risks are based on current published credit default swap rates.
Due to the volatility of commodity prices, the estimated fair value of our derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. The following table presents the estimated fair value of our oil contracts as of June 30, 2012 and December 31, 2011.
Because we have elected not to account for our current derivative contracts as cash flow hedges, we recognize all realized settlements and unrealized changes in fair value in earnings. Cash settlements of our derivative contracts are included in cash flows from operating activities in our statements of cash flows.
The following table summarizes the realized and unrealized gains and losses from settlements and changes in fair value of our derivative contracts as presented in our accompanying financial statements.
We are exposed to financial risks associated with these contracts from nonperformance by our counterparties. Counterparty risk is also a component of our estimated fair value calculations. We have mitigated our exposure to any single counterparty by contracting with a number of financial institutions,
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
each of which has a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our hedge liability positions.
3. Fair Value Measurements
The Financial Accounting Standards Board (“FASB”) has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for an asset or liability.
The following tables provide fair value measurement information for certain assets and liabilities as of June 30, 2012 and December 31, 2011.
Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above.
Debt
The fair value of our bank debt at December 31, 2011 was estimated to approximate the carrying amount because the floating rate interest paid on such debt was set for periods of three months or less.
The fair value for our 5.875% and 7.125% fixed rate notes was based on their last traded value before period end.
Derivative Instruments (Level 2)
The fair value of our derivative instruments was estimated using internal discounted cash flow calculations. Cash flows are based on the stated contract prices and current and published forward commodity price curves, adjusted for volatility. The cash flows are risk adjusted relative to nonperformance for both our counterparties and our liability positions. Please see Note 2 for further information on the fair value of our derivative instruments.
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
Other Financial Instruments
The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. At both June 30, 2012 and December 31, 2011, the aggregate allowance for doubtful accounts for trade, oil and gas sales, and gas gathering, processing, and marketing receivables was $6.4 million.
Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry.
4. Capital Stock
A summary of our common stock activity for the six months ended June 30, 2012 follows (in thousands):
Dividends
In May 2012, the Board of Directors declared a cash dividend of $0.12 per share on our common stock. The dividend is payable on September 4, 2012 to stockholders of record on August 15, 2012. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other factors considered relevant by the Board of Directors.
5. Stock-based Compensation
Our 2011 Equity Incentive Plan (the “2011 Plan”) was approved by stockholders in May 2011. The 2011 Plan replaces the 2002 Stock Incentive Plan (the “2002 Plan”). No new grants will be made under the 2002 Plan. The 2011 Plan provides for the grant of stock options, restricted stock, restricted stock units, performance stock and performance stock units to officers, other eligible employees and nonemployee directors. A total of 5.3 million shares of common stock may be issued under the 2011 Plan.
We have recognized non-cash stock-based compensation cost as follows (in thousands):
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
Historical amounts may not be representative of future amounts as additional awards may be granted.
Restricted Stock and Units
In May 2012, 238,770 performance-based stock awards were granted to certain executive officers with an aggregate grant-date fair value of $12.4 million. The following tables provide information about restricted stock awards granted during the three and six months ended June 30, 2012 and 2011.
Performance-based awards are subject to market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance. After three years of continued service, an executive will be entitled to vest in 50% to 100% of the award. In accordance with Internal Revenue Code Section 162(m), certain of the amounts awarded may not be deductible for tax purposes. The material terms of performance goals applicable to these awards were approved by stockholders in May 2010. The other restricted shares granted in 2012 have service-based vesting schedules of five years.
A restricted unit represents a right to an unrestricted share of common stock upon satisfaction of defined vesting and holding conditions. Restricted units have a five-year vesting schedule and an additional three-year holding period following vesting, prior to payment in common stock.
Compensation cost for the performance-based stock awards is based on the grant date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for the service-based vesting restricted shares and units is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period.
The following table reflects the non-cash compensation cost related to our restricted stock and units (in thousands):
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
Unamortized compensation cost related to unvested restricted shares and units at June 30, 2012 was $63 million, which we expect to recognize over a weighted average period of approximately 1.9 years.
The following table provides information on restricted stock and unit activity as of June 30, 2012 and changes during the year:
Stock Options
Options granted under our 2011 and 2002 plans expire seven to ten years from the grant date and have service-based vesting schedules of three to five years. The plans provide that all grants have an exercise price of the average of the high and low prices of our common stock as reported by the New York Stock Exchange on the date of grant. No options were granted during the six months ended June 30, 2012 and 2011.
Compensation cost related to stock options is based on the grant date fair value of the award, recognized ratably over the applicable vesting period. We estimate the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the historical volatility of our common stock. We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.
Non-cash compensation cost related to our stock options is reflected in the following table (in thousands):
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
As of June 30, 2012, there was $3.9 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost pro rata over a weighted-average period of approximately 1.9 years.
Information about outstanding stock options is summarized below:
The following table provides information regarding the options exercised (dollars in thousands):
(1) No tax benefit is recorded until the benefit reduces current taxes payable.
The following summary reflects the status of non-vested stock options as of June 30, 2012 and changes during the year:
6. Asset Retirement Obligations
We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made, and the associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and gas producing companies incur this liability which includes costs related to the plugging of wells, the removal of facilities and equipment, and site restorations, upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are depleted as a component of the full cost pool.
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the six months ended June 30, 2012 (in thousands):
7. Long-Term Debt
Debt at June 30, 2012 and December 31, 2011 consisted of the following (in thousands):
Bank Debt
We have a five-year senior unsecured revolving credit facility (“Credit Facility”) which matures July 14, 2016. The Credit Facility provides for a borrowing base of $2 billion. At June 30, 2012 we had aggregate commitments of $800 million from our lenders. Our aggregate commitments were subsequently raised to $1 billion in July 2012.
The borrowing base under the Credit Facility is determined at the discretion of lenders based on the value of our proved reserves. Our borrowing base of $2 billion was reaffirmed by the lenders in April, 2012. The next regular annual redetermination date is on April 15, 2013.
As of June 30, 2012, we had no bank debt outstanding. We had letters of credit outstanding under the Credit Facility of $2.5 million.
At Cimarex’s option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.75-2.5%, based on our leverage ratio, or (b) the higher of (i) a prime rate, (ii) the federal funds effective rate plus 0.50%, or (iii) adjusted one-month LIBOR plus 1.0% plus, in each case, an additional 0.75-1.5%, based on our leverage ratio.
The Credit Facility also has financial covenants that include the maintenance of current assets (including unused bank commitments) to current liabilities of greater than 1.0 to 1.0. We also must maintain a leverage ratio of total debt to earnings before interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test write-downs, and goodwill impairments) of not more than 3.5 to 1.0. Other covenants could limit our ability to: incur additional indebtedness, pay dividends, repurchase our common stock, or sell assets. As of June 30, 2012, we were in compliance with all of the financial and nonfinancial covenants.
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
5.875% Notes due 2022
In April, 2012 we issued $750 million of 5.875% senior notes due May 1, 2022, with interest payable semiannually in May and November. The notes were sold to the public at par. The notes are governed by an indenture containing certain covenants, events of default and other restrictive provisions. We may redeem the notes in whole or in part, at any time on or after May 1, 2017, at redemption prices of 102.938% of the principal amount as of May 1, 2017, declining to 100% on May 1, 2020 and thereafter.
Net proceeds from the offering approximated $737 million, after deducting underwriting discounts, commissions and estimated expenses of the offering. We used a portion of the net proceeds to retire our 7.125% senior notes. The remaining net proceeds were used for general corporate purposes, including repayment of $232 million outstanding under our Credit Facility.
7.125% Notes due 2017
In May, 2007, we issued $350 million of 7.125% senior unsecured notes at par that were scheduled to mature May 1, 2017. On March 22, 2012 we commenced a cash tender offer (the “Tender Offer”) to purchase all of the outstanding 7.125% senior notes.
Under the terms of the Tender Offer, holders who tendered their notes on or prior to April 4, 2012 received (i) $1,035.63 per $1,000.00 in principal amount of notes tendered plus (ii) a consent payment of $3.75 per $1,000.00 in principal amount of notes tendered. Holders tendering their notes after April 4, 2012 but prior to expiration of the Tender Offer on April 18, 2012 were not eligible for the consent payment. Through April 18, 2012 a total of $300,163,000 of notes had been redeemed. In May 2012, the remaining notes were redeemed at 103.563% of the principal amount. We recognized a $16.2 million loss on early extinguishment of debt during the second quarter of 2012.
In connection with the Tender Offer, holders who tendered their notes were deemed to consent to proposed amendments to eliminate or modify certain covenants and events of default and other provisions contained in the indenture governing the 7.125% senior notes.
8. Income Taxes
The components of our provision for income taxes are as follows (in thousands):
At December 31, 2011 the company had a U.S. net tax operating carryforward of approximately $107 million which would expire in 2031. We believe that the carryforward will be utilized before it expires. We also had an alternative minimum tax credit carryfoward of approximately $2.9 million.
At June 30, 2012 we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2008-2011 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for tax years 2005-2011 for examination.
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
Our provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and nondeductible expenses. The effective income tax rates for the six months ended June 30, 2012 and June 30, 2011 were 37.2% and 36.9%, respectively.
9. Supplemental Disclosure of Cash Flow Information (in thousands):
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
10. Earnings per Share
The calculations of basic and diluted net earnings per common share under the two-class method are presented below (in thousands, except per share data):
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
The following table presents the amounts of outstanding stock options, restricted stock and units as follows:
Certain stock options considered to be anti-dilutive for the three months ended June 30, 2012 and 2011 were 249,303 and 2,832, respectively. For the six months ended June 30, 2012 and 2011, certain stock options considered to be anti-dilutive were 259,133 and 12,895, respectively.
11. Commitments and Contingencies
Litigation
H.B. Krug, et al versus H&P
In January 2009, the Tulsa County District Court issued a judgment totaling $119.6 million in the H.B. Krug, et al versus Helmerich & Payne, Inc. (“H&P”) case. This lawsuit was originally filed in 1998 and addressed H&P’s conduct pertaining to a 1989 take-or-pay settlement, along with potential drainage issues and other related matters. Pursuant to the 2002 spin-off transaction to shareholders of H&P by which Cimarex became a publicly-traded entity, Cimarex assumed the assets and liabilities of H&P’s exploration and production business. In 2008 we recorded litigation expense of $119.6 million for this lawsuit. We have accrued additional expense for associated post-judgment interest and costs that have accrued during the appeal of the District Court’s judgments.
On August 18, 2011, the Oklahoma Court of Appeals issued an Opinion regarding the Krug litigation. The Oklahoma Court of Appeals reversed and remanded the $112.7 million disgorgement of profits award, finding the District Court erred in failing to make the required findings of fact and conclusions of law. In all other respects, the Court of Appeals affirmed the judgment, including damages of $6.845 million. On October 27, 2011, Cimarex filed a petition with the Oklahoma Supreme Court requesting review of the affirmed portion of the judgment. This case is subject to further appeal and the final outcome cannot be determined at this time. If the District Court’s original judgment is ultimately affirmed in its entirety, the $119.6 million, plus the then determined amount of post-judgment interest and costs would become payable.
The following table reflects the change in the accrued liability for this lawsuit for the six months ended June 30, 2012 (in thousands):
Other litigation
In the normal course of business, we have other various litigation related matters. We assess the probability of estimable amounts related to litigation matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, the resolution of them we believe, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations.
CIMAREX ENERGY CO. Notes to Consolidated Financial Statements (Continued) June 30, 2012 (Unaudited)
Other
We have drilling commitments of approximately $306.6 million consisting of obligations to finish drilling and completing wells in progress at June 30, 2012. We also have various commitments for drilling rigs as well as certain service contracts. The total minimum expenditure commitments under these agreements are $21.4 million to secure the use of drilling rigs and $14.8 million to secure certain dedicated services associated with completion activities.
We have projects in Oklahoma, New Mexico, and Texas where we are constructing gathering facilities and pipelines. At June 30, 2012, we had commitments of $13.9 million relating to this construction.
At June 30, 2012, we had firm sales contracts to deliver approximately 34.1 Bcf of natural gas over the next 22 months. If this gas is not delivered, our financial commitment would be approximately $81.6 million. This commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current reserves and production levels.
We have other various transportation and delivery commitments in the normal course of business, which approximate $7.4 million.
All of the noted commitments were routine and were made in the normal course of our business.
12. Property Sales and Acquisitions
There were no significant property sales during the first half of 2012. Subsequent to June 30, 2012, we sold various interests in oil and gas properties for $11 million. We had property acquisitions of approximately $7 million during the first half of 2012.
During the first half of 2011, we sold various interests in oil and gas properties for approximately $20.3 million and we had property acquisitions of approximately $21.2 million. Of our total acquisitions, $18 million was in our western Oklahoma Cana-Woodford shale play and $3 million was in the Permian basin.
We intend to continue to actively evaluate acquisitions and dispositions relative to our property holdings, particularly in our core areas of operation.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
We are an independent oil and gas exploration and production company. Our operations are entirely located in the United States, mainly in Oklahoma, New Mexico, Texas and Kansas.
Our principle business objective is to achieve profitable growth in proved reserves and production for the long-term benefit of our shareholders, primarily through exploration and development. Our strategy centers on maximizing cash flow from our producing properties and profitably reinvesting that cash flow in exploration and development drilling.
To supplement our growth and to provide for new drilling opportunities, we also consider property acquisitions and mergers that allow us to enhance our competitive position in existing core areas or to add new areas. 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. To further mitigate risk, we have chosen to seek geologic and geographic diversification by operating in multiple basins. We intend to deal with volatility in the current commodity price environment by maintaining flexibility in our planned capital investment program for 2012.
Our operations are currently focused in two main areas: the Mid-Continent region and the Permian Basin. The Mid-Continent region consists of Oklahoma, northern Texas 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.
Our growth is generally funded with cash flow provided by our operating activities together with bank borrowings, sales of non-strategic assets and occasional institutional financing. Conservative use of leverage has long been a part of our financial strategy.
Our revenue, profitability and future growth are highly dependent on the commodity prices we receive. Oil and gas prices affect 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. Any extended decline in oil and 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 affect our reported results of operations and the amount of our reported assets, liabilities, equity and proved reserves.
Second quarter 2012 summary of financial and operating results:
· Second quarter production volumes averaged 590.1 MMcfe per day, compared to 585.7 MMcfe per day for the second quarter of 2011.
· Oil, gas and NGL sales for the second quarter of 2012 were $343.2 million, compared to $452.3 million a year earlier.
· Our average realized oil price decreased 12% to $87.81 per barrel compared to $100.12 per barrel in 2011.
· Our average realized gas price decreased 49% to $2.42 per Mcf versus $4.75 per Mcf in 2011.
· Our average realized NGL price decreased 36% to $29.02 per barrel compared to $45.06 per barrel in 2011.
· Our second quarter cash flow provided by operating activities was $323.0 million versus $373.8 million in the prior year.
· Net income of $64.3 million ($0.74 per diluted share) declined from net income of $166.7 million ($1.94 per diluted share) in 2011.
· Total debt increased by $345 million to $750 million compared to $405 million at year-end 2011.
· We drilled 87 gross (51 net) wells during the second quarter of 2012, completing 97% as producers. In the second quarter of 2011 we drilled 95 gross (55 net) wells completing 96% as producers.
Revenues
Our revenues are derived from the sale of our oil, gas and NGL production and do not include the effects of the settlements of our commodity hedging contracts. While our 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 42% and our average realized NGL price decreased by 23%. The average price we have received for oil in 2012 has decreased by 2%. The 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 for the second quarter and first six months of 2012 versus the same periods of 2011. The realized prices do not include settlements of our commodity hedging contracts.
On an energy equivalent basis, 53% of our aggregate 2012 production was natural gas. A $0.10 per Mcf change in our average realized gas sales price would have resulted in approximately a $5.8 million change in our gas revenues. Similarly, 47% of our production was crude oil and NGLs. A $1.00 per barrel change in our average realized sales price would have resulted in approximately an $8.4 million change in our combined oil and NGL 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 some are a function of the number of wells we own. At the end of 2011, we owned interests in 12,701 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 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 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. 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 charged to expense. 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 June 30, 2012, although 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, the amount of the excess has declined approximately 47% since December 31, 2011. As of June 30, 2012, a decline of 10% 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 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. While we expect these costs to increase with our growth, we also expect such increases to be proportionately smaller than our production growth.
Production taxes are assessed by state and local taxing authorities pertaining to production, revenues or the value of properties. These typically include production severance, ad valorem and excise taxes.
Stock compensation expense consists of noncash charges resulting from the issuance of restricted stock, restricted stock units and stock options. In accordance with our stock incentive plan, such grants are periodically made to nonemployee directors, officers and other eligible employees.
The net gain or loss on derivative instruments is the net realized and unrealized gain or loss on derivative contracts, to which we did not apply hedge accounting treatment. That amount will fluctuate based on changes in the fair value of the underlying commodities.
Hedging
From time to time, we attempt to mitigate a portion of our price risk through the use of hedging transactions. Management has been authorized to hedge up to 50% of our anticipated 2012 and 2013 equivalent production.
For 2012, we hedged about half of our anticipated oil production. We do not have any of our gas or NGL production hedged. We have had no cash settlements on these contracts in the first six months of 2012.
We entered into oil and gas contracts relative to our 2011 production which approximated 40 to 45% of our anticipated 2011 oil production and 5 to 6% of projected gas production. Those contracts had net cash settlements in the first six months of 2011 of $2.1 million.
We had the following contracts outstanding at June 30, 2012:
(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.
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 current hedging positions. While the use of such instruments limits the downside risk of adverse price changes, this use may also limit future income from favorable price changes.
We have chosen not to apply hedge accounting treatment to the derivative contracts we entered into. 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 Note 2 to the Consolidated Financial Statements and Item 3 of this report for additional information regarding our derivative instruments.
RESULTS OF OPERATIONS
Three Months and Six Months Ended June 30, 2012 vs. June 30, 2011
Net income for the second quarter of 2012 was $64.3 million, or $0.74 per diluted share. This compares to $166.7 million, or $1.94 per diluted share, for the second quarter of 2011. For the six months ended June 30, 2012 net income was $170.4 million, or $1.97 per diluted share, down from net income of $284.9 million, or $3.31 per diluted share, for the first six months of 2011.
Lower net income in both of the 2012 periods resulted from decreased revenues due to lower realized commodity prices, higher operating expenses and a loss on early extinguishment of debt.
These changes are discussed further in the analysis that follows.
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