UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-Q

(Mark One)

 

 

For the Quarterly Period ended March 31, 2016

 

Commission File No. 001-31446

 

CIMAREX ENERGY CO.

 

1700 Lincoln Street, Suite 3700

Denver, Colorado 80203

(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 ☒  No ☐

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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 ☒  No ☐

 

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 ☐  No ☒.

 

The number of shares of Cimarex Energy Co. common stock outstanding as of March 31, 2016 was 94,815,010.

 

 

CIMAREX ENERGY CO.

 

Table of Contents

 

 

 

 

 

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

MMBbl/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 working interest percentage

Net Production—Gross production multiplied by net revenue interest

NGL or NGLs—Natural gas liquids

Tcf—Trillion cubic feet

Tcfe—Trillion cubic feet equivalent

 

Energy equivalent is determined using the ratio of one barrel of crude oil, condensate or NGL to 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, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended.  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, gas, and NGLs 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, full cost ceiling impairments to the carrying values of our oil and gas properties, reductions in the quantity of oil and gas sold due to decreased industry-wide demand and/or curtailments in production from specific properties or areas due to mechanical, transportation, marketing, weather 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 economic, 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.

 

 

PART I

 ITEM 1 - Financial Statements

 CIMAREX ENERGY CO.

Condensed Consolidated Balance Sheets

(Unaudited)

 

 See accompanying notes to consolidated financial statements.

CIMAREX ENERGY CO.

Consolidated Statements of Operations and Comprehensive Income (Loss)

(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.

 

 

 

 The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex,” “we” or “us”) 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 Annual Report on Form 10-K for the year ended December 31, 2015.

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 and as of the dates shown.  We have evaluated subsequent events through the date of this filing.

Use of Estimates

Areas of significance requiring the use of management’s judgments relate to the estimation of proved oil and gas reserves, the use of proved reserves in calculating depletion, depreciation and amortization (DD&A), 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 also are required in determining allowance for bad debt, impairments of undeveloped properties and other assets, purchase price allocation, valuation of deferred tax assets, fair value measurements and contingencies.

Oil and Gas Well Equipment and Supplies

Our oil and gas well equipment and supplies are valued at the lower of cost or net realizable value, where net realizable value is a defined estimated selling price.  An analysis of our oil and gas well equipment and supplies was performed and no impairment was required.   However, the continued industry-wide decline in drilling operations has put downward pressure on the price of oil and gas well equipment and supplies.  Further declines in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.

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.   If the net capitalized cost of our oil and gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess is 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.  Estimated future net cash flows are determined by commodity prices and proved reserve quantities.

At March 31, 2016, the carrying value of our oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation, and we recognized an impairment of $230.1 million ($146.2 million, net of tax).   This impairment resulted primarily from the continued impact of decreases in the 12-month average trailing prices for oil, natural gas and NGLs utilized in determining the future net cash flows from proved reserves.   If pricing conditions stay at current levels or decline further, or if there is a negative impact on one or more of the other components of the calculation, we will incur full cost ceiling impairments in future quarters.  The ceiling calculation is not intended to be indicative of the fair market value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income (loss) and various components of our balance sheet.   Any recorded impairment of oil and gas properties is not reversible at a later date.

 

Accounts Receivable, Accounts Payable and Accrued Liabilities

 

The components of our accounts receivable, accounts payable and accrued liabilities are shown below:

 

 

 

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606).  In July 2015, the FASB deferred the effective date by one year to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but not before the original effective date of reporting periods beginning after December 15, 2016.  We do not intend to early adopt this standard.  At this time we do not expect that the adoption of this standard will have a material effect on our consolidated financial statements and related disclosures.

In February 2016, the FASB issued ASU 2016-02, which requires lease assets and lease liabilities for most leases to be recognized on the balance sheet and disclosing key information about leasing arrangements.  The standard is effective for reporting periods beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the impact of this new guidance on our consolidated financial statements and related disclosures.  We anticipate that we will not early adopt this standard.

In March 2016, the FASB issued ASU 2016-09, which will change how companies account for certain aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The standard is effective for reporting periods beginning after December 15, 2016. Early adoption is permitted but all of the guidance must be adopted in the same period.  We are currently evaluating the impact of this new guidance on our consolidated financial statements and related disclosures.  We anticipate that we will not early adopt this standard.

 

2.Long-Term Debt

 

Debt at March 31, 2016 and December 31, 2015 consisted of the following:

 

 

 

All of our long-term debt is senior unsecured debt and is, therefore, pari passu with other unsecured debt with respect to the payment of both principal and interest.

Bank Debt

We have a senior unsecured revolving credit facility (Credit Facility) that matures October 16, 2020.  The Credit Facility has aggregate commitments of $1.0 billion, with our option to increase aggregate commitments to $1.25 billion at any time.  There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility.  As of March 31, 2016, there were no borrowings outstanding under the Credit Facility.  We had letters of credit outstanding under the Credit Facility of $2.5 million, leaving an unused borrowing availability of $997.5 million.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.125 – 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 – 1.0%, based on the credit rating for our senior unsecured long-term debt.  Unused borrowings are subject to a commitment fee of 0.125 – 0.35%, based on the credit rating for our senior unsecured long-term debt.

The Credit Facility contains representations, warranties, covenants and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a total debt-to-capital ratio of no greater than 65%.  As of March 31, 2016, we were in compliance with all of the financial and non-financial covenants.

At March 31, 2016 and December 31, 2015, we had $5.4 million and $5.7 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as deferred assets and included in Other assets, net in our balance sheet.  These costs are being amortized to interest expense ratably over the life of the Credit Facility.

Senior Notes

Each of our senior notes is governed by an indenture containing certain covenants, events of default and other restrictive provisions with which we were in compliance as of March 31, 2016.  Interest on each of the senior notes is payable semi-annually.  The effective interest rate on the 4.375% notes and the 5.875% notes, including the debt issuance cost, is 4.50% and 6.04%, respectively.

 

3.Derivative Instruments/Hedging

We periodically use derivative instruments to mitigate volatility in commodity prices. 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. 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.

The following tables summarize our outstanding derivative contracts as of March 31, 2016:

 

 

 

A three-way collar is a combination of three options: lower floor (sold put), upper floor (bought put) and ceiling (sold call).  If the published index price is below the lower floor, we receive the difference between the two floors.  If the index price is between the two floors, we receive the difference between the upper floor and the index price.  If the index price is between the upper floor and the ceiling, we do not receive or pay any amounts.  If the index price is above the ceiling, we pay the excess over the ceiling price.

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 price 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 the ceiling price.

We have elected not to account for our derivatives as cash flow hedges.  Therefore, we recognize settlements and changes in the assets or liabilities relating to our open derivative contracts in earnings.  Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. 

The following table presents the aggregate net (gain) loss from settlements and changes in fair value of our derivative contracts and the (gains) losses only from settlements during the periods shown below.

 

 

Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to enforceable master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty. Our policy is to not offset asset and liability positions in our accompanying balance sheets.

The following tables present the amounts and classifications of our derivative assets and liabilities as of March 31, 2016 and December 31, 2015, as well as the potential effect of netting arrangements on contracts with the same counterparty.

 

 

We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. We mitigate our exposure to any single counterparty by contracting with a number of financial institutions, each of which have 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. Because some of the member banks have discontinued hedging activities, in the future we may hedge with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

4.Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  The 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 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly.  Level 3 are unobservable inputs for an asset or liability.

The following table provides fair value measurement information for certain assets and liabilities as of March 31, 2016 and December 31, 2015:

 

 

 

 

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 fair value (Level 1) of our 4.375% and 5.875% fixed rate notes was based on their last traded value before period end. The fair value of our derivative instruments (Level 2) was estimated using option pricing models. These models use certain variables including forward price and volatility curves and the strike prices for the instruments.  The fair value estimates are adjusted relative to non-performance risk as appropriate.  See Note 3 for further information on the fair value of our derivative instruments.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, 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.

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.

We routinely assess the recoverability of all material accounts receivable to determine their collectability.  We accrue a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated.  At March 31, 2016 and December 31, 2015, the allowance for doubtful accounts was $1.6 million and $1.8 million, respectively.

 

5.Capital Stock

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock.  At March 31, 2016, there were no shares of preferred stock outstanding.  A summary of our common stock activity for the three months ended March 31, 2016 follows:

 

 

Dividends

In February 2016, the Board of Directors declared a cash dividend of $0.08 per share, a decrease from the last dividend declared of $0.16 per share.  The dividend is payable on June 1, 2016, to stockholders of record on May 13, 2016.  Future dividend payments will depend on our level of earnings, financing requirements, and other factors considered relevant by the Board of Directors.

 

6.Stock-based Compensation

We have recognized stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.  During the second quarter of 2016, we accepted volunteers to participate in an early retirement incentive program, which includes accelerated vesting of certain service-based stock awards and stock option awards.  At this time, the effect of the accelerated vesting on our total stock compensation cost for the second quarter of 2016 is not determinable.

 

 

7.Asset Retirement Obligations

We recognize the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated.  The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.  This liability includes costs related to the plugging and abandonment of wells, the removal of facilities and equipment, and site restorations.  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 included as a component of the DD&A calculations.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the three months ended March 31, 2016:

 

 

 

 

8.Earnings (loss) per Share

The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below:

 

 

9.Income Taxes

The components of our provision for income taxes are as follows:

 

 

At December 31, 2015, we had a U.S. net tax operating loss carryforward of approximately $907.5 million, which would expire in tax years 2031 through 2035.  We believe that the carryforward will be utilized before it expires.  The amount of U.S. net tax operating loss carryforward that will be recorded to equity when utilized to reduce taxes payable is $77.2 million. We also had an alternative minimum tax credit carryforward of approximately $6.0 million.

At March 31, 2016, we had no unrecognized tax benefits that would impact our effective tax rate and have made no provisions for interest or penalties related to uncertain tax positions.  The tax years 2012 through 2014 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 to examination for tax years 2011 through 2014.

Our provision for income taxes differed from the U.S. statutory rate of 35% primarily due to state income taxes and non-deductible expenses.

 

10.Commitments and Contingencies

Commitments

We have commitments of $245.4 million to finish drilling and completing wells in progress at March 31, 2016.  We also have various commitments for drilling rigs.  The total minimum expenditure commitments under these agreements are $11.4 million.

At March 31, 2016, we had firm sales contracts to deliver approximately 65.1 Bcf of natural gas over the next 31 months.  If this gas is not delivered, our financial commitment would be approximately $101.1 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 proved reserves and production levels from which we can fulfill these obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next ten years.  If no gas is delivered, the maximum amount that would be payable under these commitments would be approximately $196.4 million.  However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these obligations.

We have minimum volume delivery commitments in connection with agreements to reimburse connection costs to various pipelines.  The maximum amount that would be payable if no gas is delivered would be approximately $12.9 million.  Of this total, we have accrued a liability of $10.6 million.  Due to reduced drilling activity in 2015 and projected for 2016, we may have additional liabilities associated with these delivery commitments in the future.

We have other various transportation, delivery and facilities commitments in the normal course of business, which approximate $39.1 million.  We anticipate meeting these obligations.

We have various commitments for office space and equipment under operating lease arrangements totaling $94.3 million. 

All of the noted commitments were routine and made in the ordinary course of our business.

Litigation

We have various litigation matters related to the ordinary course of our business.  We assess the probability of estimable amounts related to those matters in accordance with guidance established by the FASB and adjust our accruals accordingly.  Though some of the related claims may be significant, we believe the resolution of them, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals.

 

11.Supplemental Disclosure of Cash Flow Information

 

 

 

 

 

 

 

 

 

 

 

 

 

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 and New Mexico.  Currently our operations are focused in two main areas: the Permian Basin and the Mid-Continent region.  Our Permian Basin region encompasses west Texas and southeast New Mexico.  Our Mid-Continent region consists of Oklahoma and the Texas Panhandle.

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

We believe that detailed technical analysis, operational focus and a disciplined capital investment process mitigates risk and positions us to continue to achieve increases in proved reserves and production.  Our drilling inventory and limited long-term commitments provide the flexibility to respond quickly to industry volatility.

Our investments are generally funded with cash flow provided by operating activities together with bank borrowings, sales of non-strategic assets and occasional public financing.  Conservative use of leverage has long been a part of our financial strategy.  We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand low prices.

Market Conditions

The oil and gas industry is cyclical and commodity prices can be volatile.  In the second half of 2014, oil prices began a rapid and significant decline as global supply began to outpace demand.  During 2015, global oil supply continued to outpace demand resulting in further deterioration in realized oil prices.  Thus far in 2016, oil prices have been erratic and it is likely that they will remain erratic due to the ongoing global supply and demand imbalance, growing inventories and geopolitical factors.

Prices for domestic natural gas and NGLs began to decline during the third quarter of 2014 and continued to be weak in 2015 and thus far in 2016.  The declines in these prices are primarily due to an imbalance between supply and demand across North America, which could result in further declines.

Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production.  Compared to the first quarter of 2015, our first quarter 2016 realized oil price fell 34% to $28.02/Bbl.  Similarly, our realized natural gas price dropped 31% to $1.92/Mcf and our realized price for NGL declined 37% to $9.84/Bbl.

The U.S. oil and gas industry continues to confront weak commodity prices, which has adverse effects on our business and financial position.  Our ability to access capital markets may be restricted, which could have an impact on our flexibility to react to changing economic and business conditions.  Further, the global oversupply situation could have an adverse impact on our business partners, customers and lenders, potentially causing them to fail to meet their obligations to us.

Based on current economic conditions, our 2016 exploration and development expenditures are projected to range from $650-$700 million.  Investments in gathering and processing infrastructure and other fixed assets are expected to approximate an additional $50 million.

See “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2015, for a discussion of risk factors that affect our business, financial condition and results of operations.  Also see CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in this report for important information about these types of statements.

First quarter 2016 summary of operating and financial results compared to the first quarter of 2015:

 

 

In response to continued weak commodity prices we significantly reduced our 2016 exploration and development expenditures to $147.0 million compared to $285.5 million in 2015.

Total debt at March 31, 2016 consisted of $1.5 billion of senior notes, with $750 million maturing in 2022 and $750 million maturing in 2024, unchanged from total debt at December 31, 2015.

Revenues

Almost all of our revenues are derived from sales of our oil, natural gas and NGL production.  Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive.  Prices are market driven and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors.

Oil sales contributed 51% of our total production revenue for the first quarter of 2016. Gas sales accounted for 35% and NGL sales contributed 14%. A $1.00 per barrel change in our realized oil price would have resulted in a $4.2 million change in revenues. A $0.10 per Mcf change in our realized gas price would have resulted in a $4.3 million change in our gas revenues. A $1.00 per barrel change in NGL prices would have changed revenues by $3.4 million.

The following table presents our average realized commodity prices and certain major U.S. index prices.  Our average realized prices do not include settlements of commodity derivative contracts. 

 

 

During the first quarter of 2016 and 2015, approximately 79% and 84%, respectively, of our oil production was in the Permian Basin, the sale of which is tied to the WTI Midland benchmark price.  The majority of the remaining oil production is from our Mid-Continent region.  The impact of changes in realized prices is discussed below under RESULTS OF OPERATIONS.

Operating costs and expenses

Costs associated with producing oil and natural 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. 

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.  If the net capitalized cost of our oil and gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess is 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.  Estimated future net cash flows are determined by proved reserve quantities and commodity prices net of operating costs and capital expenditures.  We recognized ceiling test impairments in each quarter of 2015, totaling $3.7 billion for the year.

At March 31, 2016, the carrying value of our oil and gas properties subject to the ceiling test exceeded the calculated value of the ceiling limitation, resulting in an impairment of $230.1 million ($146.2 million, net of tax).  The impairment resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas and NGLs utilized in determining the estimated future net cash flows from proved reserves. If pricing conditions stay at current levels or decline further, we will incur full cost ceiling impairments in future quarters, the magnitude of which will be affected by one or more of the other components of the ceiling test calculations, until prices stabilize or improve over a twelve-month period.

Commodity prices used in the March 31, 2016 ceiling calculation, based on the required trailing 12-month average prices, were $2.40 per Mcf of gas and $46.26 per barrel of oil.  To demonstrate the impact of commodity prices on the ceiling calculation, had average prices of $2.23 per Mcf of gas and $41.34 per barrel of oil been used instead, our pre-tax ceiling test impairment would have been approximately $777.6 million, an increase of $547.5 million for the first quarter of 2016.  The lower commodity prices for this assumption were calculated based on a 12-month simple average of the commodity prices on the first day of the month for the 10 months ended April 2016 and the prices for April 2016 were used for the remaining two months in the 12-month average.

The above calculation of the impact of lower commodity prices was prepared based on the assumption that all other inputs and assumptions are held constant with the exception of oil and natural gas prices.  Therefore, this calculation strictly isolates the potential impact of commodity prices on our ceiling test limitation.  An amount of any future impairment is difficult to reasonably predict and will depend upon not only commodity prices but also other factors that include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, and all related tax effects.  There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods and the estimate described above should not be construed as indicative of our development plans or future results.

The ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income (loss) and various components of our balance sheet.  Any recorded impairment of oil and gas properties is not reversible at a later date.

Depletion, depreciation 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 realized sales price for future 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, reclassifications of properties from unproved to proved and impairments of oil and gas properties will also impact depletion expense.  DD&A is calculated quarterly before the ceiling test impairment calculation.  The

impairments of our oil and gas properties in 2015 resulted in lower DD&A rates in each quarter following the impairment.

Production expense generally consists of costs for labor, equipment, maintenance, salt water disposal, compression, power, treating and miscellaneous other costs.  Production expense also includes well workover activity necessary to maintain production from existing wells.

Transportation, processing and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, together with gas processing costs and costs to transport production to a specified sales point.  These costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees and changes in fuel and compression costs.

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.

A discussion of changes in operating costs and expenses is included in RESULTS OF OPERATIONS, below.

RESULTS OF OPERATIONS

Three Months Ended March 31, 2016 vs. March 31, 2015

In the first quarter of 2016, we had a net loss of $186.1 million ($2.00 per diluted share) compared to a net loss of $414.9 million ($4.84 per diluted share) for the same period of 2015.  Both 2016 and 2015 periods were adversely affected by low realized commodity prices, which also brought about impairments of our oil and gas properties.  Although the first quarter of 2016 had lower production revenue than the same period of 2015, this decrease was more than offset by lower impairment and other operating costs in 2016.  Quarter-over-quarter changes are discussed further in the analysis that follows.