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CIMXP Cimarex Energy

Filed: 6 Aug 21, 10:58am

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
FORM 10-Q
(Mark One)
Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period endedJune 30, 2021
or
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _______________ to _______________
 Commission File No. 001-31446
CIMAREX ENERGY CO.
(Exact name of registrant as specified in its charter)
Delaware 45-0466694
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification No.)
 
1700 Lincoln Street, Suite 3700DenverColorado 80203
(Address of principal executive offices) (Zip Code)
(303) 295-3995
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s)Name of each exchange on which registered
Common Stock ($0.01 par value) XECNew York Stock Exchange

    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 every Interactive Data File required to be submitted 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 such files).    Yes   No 

    Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerAccelerated filerNon-accelerated filerSmaller reporting company
Emerging growth company

    If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 July 31, 2021 was 102,813,233.


CIMAREX ENERGY CO.
Table of Contents
 



GLOSSARY

Bbls—Barrels (of oil or natural gas liquids)
Bcf—Billion cubic feet (of natural gas)
BOE—Barrels of oil equivalent
Gross Wells—The total wells in which a working interest is owned.
MBbls—Thousand barrels (of oil or natural gas liquids)
MBOE—Thousand barrels of oil equivalent
Mcf—Thousand cubic feet (of natural gas)
MMBtu—Million British thermal units
MMcf—Million cubic feet (of natural gas)
Net Wells—The sum of the fractional working interest owned in gross wells expressed in whole numbers and fractions of whole numbers.
NGL or NGLs—Natural gas liquids

Energy equivalent is determined using the ratio of one barrel of 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 and Section 21E of the Securities Exchange Act of 1934. In particular, in our Management’s Discussion and Analysis of Financial Condition and Results of Operations, we provide projections of our 2021 capital expenditures. All statements, other than statements of historical facts, that address activities, events, outcomes, and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-Q and our Form 10-K for the year ended December 31, 2020. Forward-looking statements include statements with respect to, among other things:

Fluctuations in the price we receive for our oil, gas, and NGL production, including local market price differentials, which may be exacerbated by the demand destruction resulting from the highly transmissible and pathogenic coronavirus known as severe acute respiratory syndrome coronavirus 2 (SARS-CoV-2) that causes the disease known as COVID-19;

Disruptions to the availability of workers and contractors due to illness and stay-at-home orders related to the COVID-19 pandemic;

Cost and availability of gathering, pipeline, processing, refining, transportation and other midstream and downstream activities and our ability to sell oil, gas, and NGLs, which may be negatively impacted by the COVID-19 pandemic, severe weather, and other risks, and may lead to a lack of any available markets;

Availability of supply chains and critical equipment and supplies, which may be negatively impacted by the COVID-19 pandemic and other risks;

Higher than expected costs and expenses, including the availability and cost of services and materials, which may be negatively impacted by the COVID-19 pandemic and severe weather;

Compliance with environmental and other regulations, including new regulations that may result from the recent change in federal and state administrations and legislatures;

3

Legislative or regulatory changes, including initiatives related to hydraulic fracturing, emissions, and disposal of produced water, which may be negatively impacted by the recent change in Presidential administration or legislatures;

The ability to receive drilling and other permits or approvals and rights-of-way in a timely manner (or at all), which may be negatively impacted by the impact of COVID-19 restrictions on regulatory employees who process and approve permits, other approvals and rights-of-way and which may be restricted by new Presidential and Secretarial orders and regulation and legislation;

Reductions in the quantity of oil, gas, and NGLs sold and prices received because of decreased demand and/or curtailments in production relating to mechanical, transportation, processing, storage, capacity, marketing, weather, the COVID-19 pandemic, or other problems;

Declines in the SEC PV10 value of our oil and gas properties resulting in full cost ceiling test impairments to the carrying values of our oil and gas properties;

The effectiveness of our internal control over financial reporting;

Success of the company’s risk management activities;

Availability of financing and access to capital markets;

Estimates of proved reserves, exploitation potential, or exploration prospect size;

Greater than expected production decline rates;

Timing and amount of future production of oil, gas, and NGLs;

Cybersecurity threats, technology system failures, and data security issues;

The inability to transport, process, and store oil and gas;

Hedging activities and the viability of our hedging counterparties, many of whom have been negatively impacted by the COVID-19 pandemic;

Economic and competitive conditions;

Lack of or cost of available insurance;

Cash flow and anticipated liquidity;

Continuing compliance with the financial covenant contained in our amended and restated credit agreement;

The loss of certain federal income tax deductions;

Litigation;

Environmental liabilities;

New federal regulations regarding species or habitats;

Exploration and development opportunities that we pursue may not result in economic, productive oil and gas properties;
4

Drilling of wells;

Development drilling and testing results;

Performance of acquired properties and newly drilled wells;

Ability to obtain industry partners to jointly explore certain prospects, and the willingness and ability of those partners to meet capital obligations when requested;

The expected benefits associated with the announced transaction with Cabot and the ability to achieve those expected benefits;

Ability to successfully integrate our and Cabot’s businesses;

Ability to obtain the approvals of our and Cabot’s stockholders to consummate the announced transaction with Cabot;

Timing of the announced transaction with Cabot;

Unexpected future capital expenditures;

Amount, nature, and timing of capital expenditures;

Proving up undeveloped acreage and maintaining production on leases;

Unforeseen liabilities associated with acquisitions and dispositions;

Establishing valuation allowances against our deferred tax assets;

Potential payments for failing to meet minimum oil, gas, NGL, or water delivery or sales commitments;

Increased financing costs due to a significant increase in interest rates;

Risks associated with concentration of operations in one major geographic area;

Availability and cost of capital;

Title to properties;

Ability to complete property sales or other transactions; and

Other factors discussed in the company’s reports filed with the Securities and Exchange Commission (“SEC”).

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production, and sale of oil, gas, and NGLs.

These risks include, but are not limited to, commodity price volatility, demand, capacity, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production,
5

production type curves, well spacing, timing of development expenditures, and other risks described herein. Many of these risks can be exacerbated by epidemics and pandemics including the current COVID-19 pandemic.

Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results of drilling, testing, and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered.

Risk factors related to mergers and acquisitions, including our acquisition of Resolute Energy Corporation in 2019 and our proposed transaction with Cabot in 2021, include, among others: unknown liabilities related to the acquired properties or entities; the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; the risk that the combined company may be unable to achieve synergies or other anticipated benefits of the transaction; or it may take longer than expected to achieve those synergies or benefits, and other important factors, such as expenses related to integration, that could cause actual results to differ materially from those projected.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q or in our Annual Report on Form 10-K for the year ended December 31, 2020 cause our underlying assumptions to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, express or implied, included in this Form 10-Q and attributable to Cimarex are qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-Q with the SEC, except as required by law.

6

PART I
ITEM 1. Financial Statements
CIMAREX ENERGY CO.
Condensed Consolidated Balance Sheets
(in thousands, except share and per share information)
(Unaudited)
 June 30,December 31,
 20212020
Assets  
Current assets:  
Cash and cash equivalents$799,315 $273,145 
Accounts receivable, net of allowance: 
Trade51,421 49,650 
Oil and gas sales410,327 271,141 
Gas gathering, processing, and marketing12,422 11,694 
Oil and gas well equipment and supplies28,635 37,150 
Derivative instruments1,246 6,848 
Prepaid expenses6,823 7,113 
Other current assets999 597 
Total current assets1,311,188 657,338 
Oil and gas properties at cost, using the full cost method of accounting: 
Proved properties21,430,301 21,281,840 
Unproved properties and properties under development, not being amortized1,182,073 1,142,183 
 22,612,374 22,424,023 
Less—accumulated depreciation, depletion, amortization, and impairment(19,176,876)(18,987,354)
Net oil and gas properties3,435,498 3,436,669 
Fixed assets, net of accumulated depreciation of $434,753 and $455,815, respectively384,216 436,101 
Derivative instruments2,458 2,342 
Deferred income taxes20,472 
Other assets73,827 69,067 
 $5,207,187 $4,621,989 
Liabilities, Redeemable Preferred Stock, and Stockholders’ Equity 
Current liabilities: 
Accounts payable: 
Trade$54,911 $21,902 
Gas gathering, processing, and marketing24,439 22,388 
Accrued liabilities: 
Exploration and development89,946 50,014 
Taxes other than income40,896 29,051 
Other216,646 201,784 
Derivative instruments366,591 145,398 
Revenue payable216,889 130,637 
Operating leases57,665 59,051 
Total current liabilities1,067,983 660,225 
Long-term debt principal2,000,000 2,000,000 
Less—unamortized debt issuance costs and discounts(11,669)(12,701)
Long-term debt, net1,988,331 1,987,299 
Deferred income taxes54,248 
Asset retirement obligation119,553 165,595 
Derivative instruments16,167 17,749 
Operating leases111,325 134,705 
Other liabilities56,746 66,181 
Total liabilities3,414,353 3,031,754 
Commitments and contingencies (Note 10)00
Redeemable preferred stock - 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, $0.01 par value, 28,165 shares authorized and issued (Note 5)36,781 36,781 
Stockholders’ equity:  
Common stock, $0.01 par value, 200,000,000 shares authorized, 102,820,006 and 102,866,806 shares issued, respectively1,028 1,029 
Additional paid-in capital3,172,652 3,211,562 
Accumulated deficit(1,417,627)(1,659,137)
Total stockholders’ equity1,756,053 1,553,454 
 $5,207,187 $4,621,989 

See accompanying Notes to Condensed Consolidated Financial Statements.

7


CIMAREX ENERGY CO.
Condensed Consolidated Statements of Operations
(in thousands, except per share information)
(Unaudited)
 Three Months Ended
June 30,
Six Months Ended
June 30,
 2021202020212020
Revenues:    
Oil sales$424,175 $138,817 $768,879 $499,797 
Gas and NGL sales274,554 100,261 599,952 198,742 
Gas gathering and other13,530 11,589 25,745 25,172 
Gas marketing121 (1,284)(2,730)(1,498)
 712,380 249,383 1,391,846 722,213 
Costs and expenses:    
Impairment of oil and gas properties941,198 1,274,849 
Depreciation, depletion, and amortization110,733 194,954 223,667 410,040 
Asset retirement obligation2,514 1,661 4,732 6,385 
Impairment of goodwill714,447 
Production77,408 64,337 152,214 151,573 
Transportation, processing, and other operating59,285 53,282 122,892 108,204 
Gas gathering and other9,549 3,526 20,027 11,824 
Taxes other than income40,247 16,486 81,233 47,447 
General and administrative24,978 26,226 50,238 51,735 
Stock-based compensation7,878 6,747 16,427 13,141 
Loss (gain) on derivative instruments, net211,833 123,885 373,768 (103,055)
Other operating expense, net8,050 130 7,117 381 
 552,475 1,432,432 1,052,315 2,686,971 
Operating income (loss)159,905 (1,183,049)339,531 (1,964,758)
Other (income) and expense:    
Interest expense23,370 23,047 46,448 46,228 
Capitalized interest(11,386)(12,939)(22,951)(26,121)
Other, net(459)3,496 (598)2,625 
Income (loss) before income tax148,380 (1,196,653)316,632 (1,987,490)
Income tax expense (benefit)34,992 (271,506)75,162 (288,061)
Net income (loss)$113,388 $(925,147)$241,470 $(1,699,429)
Earnings (loss) per share to common stockholders:    
Basic$1.10 $(9.28)$2.35 $(17.05)
Diluted$1.10 $(9.28)$2.35 $(17.05)
 











See accompanying Notes to Condensed Consolidated Financial Statements.
8


CIMAREX ENERGY CO.
Condensed Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
 Six Months Ended
June 30,
 20212020
Cash flows from operating activities:  
Net income (loss)$241,470 $(1,699,429)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:  
Impairment of oil and gas properties1,274,849 
Depreciation, depletion, and amortization223,667 410,040 
Asset retirement obligation4,732 6,385 
Impairment of goodwill714,447 
Deferred income taxes74,720 (287,900)
Stock-based compensation16,427 13,141 
Loss (gain) on derivative instruments, net373,768 (103,055)
Settlements on derivative instruments(148,670)107,055 
Amortization of debt issuance costs and discounts1,776 1,602 
Changes in non-current assets and liabilities(5,654)7,019 
Other, net6,966 6,795 
Changes in operating assets and liabilities:  
Accounts receivable(142,832)204,615 
Other current assets(651)1,495 
Accounts payable and other current liabilities120,865 (203,562)
Net cash provided by operating activities766,584 453,497 
Cash flows from investing activities:  
Oil and gas capital expenditures(298,306)(411,330)
Acquisition of oil and gas properties(308)(7,250)
Other capital expenditures(5,806)(38,052)
Sales of oil and gas assets118,669 830 
Sales of other assets606 1,188 
Net cash used by investing activities(185,145)(454,614)
Cash flows from financing activities:  
Borrowings of long-term debt161,000 
Repayments of long-term debt(161,000)
Financing fees(100)(1,557)
Finance lease payments(2,437)(2,808)
Dividends paid(51,210)(45,209)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards(2,191)(189)
Proceeds from exercise of stock options669 
Net cash used by financing activities(55,269)(49,763)
Net change in cash and cash equivalents526,170 (50,880)
Cash and cash equivalents at beginning of period273,145 94,722 
Cash and cash equivalents at end of period$799,315 $43,842 
 



See accompanying Notes to Condensed Consolidated Financial Statements.
9


CIMAREX ENERGY CO.
Condensed Consolidated Statements of Stockholders’ Equity
(in thousands)
(Unaudited)
Additional
Paid-in Capital
Accumulated
Deficit
Total
Stockholders’
Equity
 Common Stock
 SharesAmount
Balance, December 31, 2020102,867 $1,029 $3,211,562 $(1,659,137)$1,553,454 
Dividends paid on stock awards subsequently forfeited— — 14 32 46 
Dividends declared on common stock ($0.27 per share)— — (27,845)— (27,845)
Dividends declared on redeemable preferred stock ($20.3125 per share)— — (572)— (572)
Net income— — — 128,082 128,082 
Issuance of restricted stock awards25 — — — — 
Restricted stock forfeited and retired(73)(1)— 
Exercise of stock options— 385 — 385 
Stock-based compensation— — 10,215 — 10,215 
Balance, March 31, 2021102,828 $1,028 $3,193,760 $(1,531,023)$1,663,765 
Dividends paid on stock awards subsequently forfeited— — 15 
Dividends declared on common stock ($0.27 per share)— — (27,855)— (27,855)
Dividends declared on redeemable preferred stock ($20.3125 per share)— — (572)— (572)
Net income— — — 113,388 113,388 
Issuance of restricted stock awards27 — — — — 
Common stock reacquired and retired(32)— (2,191)— (2,191)
Restricted stock forfeited and retired(10)— — — — 
Exercise of stock options— 284 — 284 
Stock-based compensation— — 9,219 — 9,219 
Balance, June 30, 2021102,820 $1,028 $3,172,652 $(1,417,627)$1,756,053 























See accompanying Notes to Condensed Consolidated Financial Statements.
10


CIMAREX ENERGY CO.
Condensed Consolidated Statements of Stockholders’ Equity
(in thousands)
(Unaudited)
Additional
Paid-in Capital
Retained
Earnings
(Accumulated
Deficit)
Total
Stockholders’
Equity
 Common Stock
 SharesAmount
Balance, December 31, 2019102,145 $1,021 $3,243,325 $331,795 $3,576,141 
Dividends paid on stock awards subsequently forfeited— — 23 29 
Dividends declared on common stock ($0.22 per share)— — — (22,548)(22,548)
Dividends declared on redeemable preferred stock ($20.3125 per share)— — — (1,269)(1,269)
Net loss— — — (774,282)(774,282)
Common stock reacquired and retired(12)— (165)— (165)
Restricted stock forfeited and retired(31)— — — — 
Stock-based compensation— — 11,594 — 11,594 
Balance, March 31, 2020102,102 $1,021 $3,254,760 $(466,281)$2,789,500 
Dividends paid on stock awards subsequently forfeited— — 
Dividends declared on common stock ($0.22 per share)— — (22,561)(22,559)
Dividends declared on redeemable preferred stock ($20.3125 per share)— — (1,269)— (1,269)
Net loss— — — (925,147)(925,147)
Issuance of restricted stock awards66 (1)— 
Common stock reacquired and retired(2)— (24)— (24)
Restricted stock forfeited and retired(15)— — — — 
Stock-based compensation— — 10,338 — 10,338 
Balance, June 30, 2020102,151 $1,022 $3,241,244 $(1,391,419)$1,850,847 

























See accompanying Notes to Condensed Consolidated Financial Statements.
11


CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)

1.BASIS OF PRESENTATION

Cimarex Energy Co. (“Cimarex,” “company,” “we,” or “us”), a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are located entirely within the United States, mainly in Texas, New Mexico, and Oklahoma. The accompanying unaudited financial statements have been prepared 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, 2020.

In the opinion of management, the accompanying financial statements reflect all adjustments necessary to fairly present our financial position, results of operations, and cash flows for the periods and as of the dates shown. The accounts of Cimarex and its subsidiaries are presented in the accompanying financial statements, with intercompany balances and transactions eliminated in consolidation. Certain amounts in the prior year financial statements have been reclassified to conform to the 2021 financial statement presentation.

Use of Estimates

Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, and the estimation of future abandonment obligations used in recording asset retirement obligations. Estimates and judgments also are required in determining allowances for credit losses, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, lease liabilities, and contingencies. We analyze our estimates and base them on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

Oil and Gas Well Equipment and Supplies

Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is based on estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Declines in the price of oil and gas well equipment and supplies 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. All costs associated with property acquisition, exploration, and development activities are capitalized. Under the full cost method of accounting, we are required 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, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.

12

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, overall exploration and development costs, and deferred taxes.  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 test impairment. The calculated ceiling limitation 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 and various components of our balance sheet.  Any impairment of oil and gas properties is not reversible at a later date. 

We did not incur a ceiling test impairment for the six months ended June 30, 2021. At June 30, 2021, a decline in the value of the ceiling limitation of approximately 34% or more would have resulted in an impairment. For the six months ended June 30, 2020, we incurred ceiling test impairments totaling $1.275 billion resulting primarily from the impact of decreases in the 12-month average trailing prices for oil, gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. During the three months ended March 31, 2020, the company’s market capitalization declined significantly, caused by macroeconomic and geopolitical conditions including the collapse of oil prices driven by surplus supply and decreased demand caused by the COVID-19 pandemic. In addition, the uncertainty related to oil demand significantly impacted our investment and operating decisions at the time. As a result of these events and circumstances, we performed an interim quantitative impairment test for goodwill as of March 31, 2020, which utilized quoted market prices for our common stock as a basis for determining the fair value of our reporting unit. Based upon this test, we concluded that goodwill was fully impaired at March 31, 2020. The following table reflects components of the change in the carrying amount of goodwill for the six months ended June 30, 2020 (subsequent to June 30, 2020 through June 30, 2021 we have not recognized any additional goodwill balance):
(in thousands)Six Months Ended
June 30, 2020
Goodwill balance at January 1, 2020$716,865 
Business combination purchase price adjustments(2,418)
Impairment(714,447)
Goodwill balance at June 30, 2020$

Revenue Recognition

Oil, Gas, and NGL Sales

Revenue is recognized from the sales of oil, gas, and NGLs when the customer obtains control of the product, when we have no further obligations to perform related to the sale, and when collectability is probable. All of our sales of oil, gas, and NGLs are made under contracts with customers, which typically include variable consideration based on monthly pricing tied to local indices and monthly volumes delivered. The nature of our contracts with customers does not require us to constrain that variable consideration or to estimate the amount of transaction price attributable to future performance obligations for accounting purposes. As of June 30, 2021, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas, and/or NGLs. Our contracts with customers typically require payment within one month of delivery.

13

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
Our gas is sold under various contracts. Under these contracts the gas and its components, including residue gas and NGLs, may be sold to a single purchaser or separate purchasers. Regardless of the contract, we are compensated for the value of the residue gas and NGLs at current market prices for each product. Depending on the specific contract terms, certain gathering, treating, transportation, processing, and other charges may be deducted against the prices we receive for the products. Our oil typically is sold at specific delivery points under contract terms that are common in our industry.

Gas Gathering

When we transport, process, and/or market third-party gas associated with our equity gas, we recognize revenue for the fees charged to third-parties for such services.

Gas Marketing

When we market and sell gas for other working interest owners, we act as agent under short-term sales and supply agreements and may earn a fee for such services. Revenues from such services are recognized as gas is delivered.

Gas Imbalances

Revenue from the sale of gas is recorded on the basis of gas actually sold by or for us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

2.LONG-TERM DEBT

Long-term debt at June 30, 2021 and December 31, 2020 consisted of the following:
 June 30, 2021December 31, 2020
(in thousands)Principal
Unamortized Debt
Issuance Costs
and Discounts (1)
Long-term
Debt, net
Principal
Unamortized Debt
Issuance Costs
and Discounts (1)
Long-term
Debt, net
4.375% Notes due 2024$750,000 $(2,254)$747,746 $750,000 $(2,672)$747,328 
3.90% Notes due 2027750,000 (5,156)744,844 750,000 (5,541)744,459 
4.375% Notes due 2029500,000 (4,259)495,741 500,000 (4,488)495,512 
$2,000,000 $(11,669)$1,988,331 $2,000,000 $(12,701)$1,987,299 
________________________________________
(1)The 4.375% Notes due 2024 were issued at par, therefore, the amounts shown in the table are for unamortized debt issuance costs only. At June 30, 2021, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.0 million and $1.2 million, respectively. At June 30, 2021, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $3.7 million and $0.6 million, respectively. At December 31, 2020, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.3 million and $1.3 million, respectively. At December 31, 2020, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $3.9 million and $0.6 million, respectively.

14

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
Bank Debt

On June 3, 2020, we entered into the First Amendment to Amended and Restated Credit Agreement (the “First Amendment”) dated as of February 5, 2019 for our senior unsecured revolving credit facility (“Credit Facility”). The Credit Facility has aggregate commitments of $1.25 billion with an option for us to increase the aggregate commitments to $1.5 billion, and matures on February 5, 2024. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. The First Amendment, among other things: (i) allows up to $3.5 billion of non-cash impairment charge add-backs to Shareholders’ Equity for covenant calculation purposes, (ii) institutes traditional anti-cash hoarding provisions (if borrowings are outstanding under the Credit Facility) at a consolidated cash threshold of $175.0 million, (iii) reduces the priority lien debt basket from 15% of Consolidated Net Tangible Assets (as defined in the credit agreement) to a $50.0 million cap, and (iv) adds an acknowledgement and consent to European Union bail-in legislation. As of June 30, 2021, we had 0 bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $1.248 billion.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR (or an alternate rate determined by the administrative agent for the Credit Facility in accordance with the Credit Facility when LIBOR is no longer available) 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 defined total debt-to-capitalization ratio of no greater than 65%. As of June 30, 2021, we were in compliance with all of the financial covenants.

At June 30, 2021 and December 31, 2020, we had $3.6 million and $4.3 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in “Other assets” on our Condensed Consolidated Balance Sheets. These costs are being amortized to interest expense ratably over the life of the Credit Facility.

Senior Notes

In March 2019, we issued $500.0 million aggregate principal amount of 4.375% senior unsecured notes at 99.862% of par to yield 4.392% per annum. These notes are due March 15, 2029 and interest is payable semiannually on March 15 and September 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.50%.

In April 2017, we issued $750.0 million aggregate principal amount of 3.90% senior unsecured notes at 99.748% of par to yield 3.93% per annum. These notes are due May 15, 2027 and interest is payable semiannually on May 15 and November 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.01%.

In June 2014, we issued $750.0 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and interest is payable semiannually on June 1 and December 1. The effective interest rate on these notes, including the amortization of debt issuance costs, is 4.50%.

Our senior unsecured notes are governed by indentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of June 30, 2021.

15

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
3.    DERIVATIVE INSTRUMENTS

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 cash flow 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 derivative positions from current levels. 

As of June 30, 2021, we have entered into oil and gas collars, oil basis swaps, and oil “roll differential” swaps. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the ceiling price and the index price if the index price is above the ceiling price.  No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price plus or minus a fixed differential, as applicable, and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI NYMEX (Cushing, Oklahoma) price and the WTI Midland price. For our Permian and Mid-Continent gas production, the contract prices in our collars are consistent with the index prices used to sell our production. Our roll differential swaps are settled based on the difference between the monthly roll differential and a fixed price per Bbl. The monthly roll differential is calculated as the sum of 2/3 of the difference in the WTI NYMEX closing settlement price for the first nearby month futures contract minus the second nearby month futures contract and 1/3 of the difference in the WTI NYMEX closing settlement price for the first nearby month futures contract minus the third nearby month futures contract. By using a roll differential swap, we have fixed the differential in pricing between the WTI NYMEX calendar month average price and the physical crude oil delivery month price. The following tables summarize our outstanding derivative contracts as of June 30, 2021:

Oil CollarsFirst
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
2021:
WTI (1)
Volume (Bbls)— — 3,680,000 3,680,000 7,360,000 
Weighted Avg Price - Floor$— $— $34.65 $34.65 $34.65 
Weighted Avg Price - Ceiling$— $— $44.37 $44.37 $44.37 
2022:
WTI (1)
Volume (Bbls)3,060,000 2,457,000 1,656,000 736,000 7,909,000 
Weighted Avg Price - Floor$41.94 $43.74 $47.56 $57.00 $45.08 
Weighted Avg Price - Ceiling$54.06 $56.34 $59.52 $72.43 $57.62 
________________________________________
(1)The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”).
16

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
Gas CollarsFirst
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
2021:
PEPL (1)
Volume (MMBtu)— — 8,280,000 8,280,000 16,560,000 
Weighted Avg Price - Floor$— $— $2.00 $2.00 $2.00 
Weighted Avg Price - Ceiling$— $— $2.42 $2.42 $2.42 
Perm EP (2)
Volume (MMBtu)— — 6,440,000 6,440,000 12,880,000 
Weighted Avg Price - Floor$— $— $1.86 $1.86 $1.86 
Weighted Avg Price - Ceiling$— $— $2.22 $2.22 $2.22 
Waha (3)
Volume (MMBtu)— — 9,200,000 9,200,000 18,400,000 
Weighted Avg Price - Floor$— $— $1.88 $1.88 $1.88 
Weighted Avg Price - Ceiling$— $— $2.23 $2.23 $2.23 
2022:
PEPL (1)
Volume (MMBtu)7,200,000 3,640,000 1,840,000 1,840,000 14,520,000 
Weighted Avg Price - Floor$2.25 $2.50 $2.60 $2.60 $2.40 
Weighted Avg Price - Ceiling$2.73 $3.07 $3.27 $3.27 $2.95 
Perm EP (2)
Volume (MMBtu)5,400,000 3,640,000 1,840,000 1,840,000 12,720,000 
Weighted Avg Price - Floor$2.25 $2.45 $2.50 $2.50 $2.38 
Weighted Avg Price - Ceiling$2.74 $3.01 $3.15 $3.15 $2.93 
Waha (3)
Volume (MMBtu)8,100,000 4,550,000 2,760,000 1,840,000 17,250,000 
Weighted Avg Price - Floor$2.14 $2.44 $2.47 $2.50 $2.31 
Weighted Avg Price - Ceiling$2.59 $2.94 $3.00 $3.12 $2.80 
________________________________________
(1)The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.
(2)The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.
(3)The index price for these collars is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.
17

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
Oil Basis SwapsFirst
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
2021:
WTI Midland (1)
Volume (Bbls)— — 3,220,000 3,220,000 6,440,000 
Weighted Avg Differential (2)$— $— $(0.08)$(0.08)$(0.08)
2022:
WTI Midland (1)
Volume (Bbls)2,700,000 2,093,000 1,380,000 736,000 6,909,000 
Weighted Avg Differential (2)$0.20 $0.22 $0.20 $0.05 $0.19 
________________________________________
(1)The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.
(2)The index price we receive under these basis swaps is WTI as quoted on the NYMEX plus or minus, as applicable, the weighted average differential shown in the table.

Oil Roll Differential SwapsFirst
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
2021:
WTI (1)
Volume (Bbls)— — 1,656,000 1,656,000 3,312,000 
Weighted Avg Price$— $— $(0.10)$(0.10)$(0.10)
2022:
WTI (1)
Volume (Bbls)1,620,000 1,001,000 644,000 3,265,000 
Weighted Avg Price$(0.10)$(0.01)$0.10 $$(0.03)
________________________________________
(1)The index price used to determine the settlement “roll” is WTI as quoted on the NYMEX.
18

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
Derivative Gains and Losses

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the components of “Loss (gain) on derivative instruments, net” for the periods indicated.

 Three Months Ended
June 30,
Six Months Ended
June 30,
(in thousands)2021202020212020
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts$40,026 $19,826 $39,579 $32,319 
Oil contracts85,671 168,000 185,519 (28,319)
125,697 187,826 225,098 4,000 
Cash payments (receipts) on derivative instruments, net:
Gas contracts14,403 (5,870)29,668 (17,589)
Oil contracts71,733 (58,071)119,002 (89,466)
86,136 (63,941)148,670 (107,055)
Loss (gain) on derivative instruments, net$211,833 $123,885 $373,768 $(103,055)

19

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
Derivative Fair Value

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

The following tables present the amounts and classifications of our derivative assets and liabilities as of June 30, 2021 and December 31, 2020, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.
 June 30, 2021
(in thousands)Balance Sheet LocationAssetLiability
Oil contractsCurrent assets — Derivative instruments$1,246 $— 
Oil contractsNon-current assets — Derivative instruments1,284 — 
Gas contractsNon-current assets — Derivative instruments1,174 — 
Oil contractsCurrent liabilities — Derivative instruments— 285,524 
Gas contractsCurrent liabilities — Derivative instruments— 81,067 
Oil contractsNon-current liabilities — Derivative instruments— 16,132 
Gas contractsNon-current liabilities — Derivative instruments— 35 
Total gross amounts presented in the balance sheet3,704 382,758 
Less: gross amounts not offset in the balance sheet(3,704)(3,704)
Net amount$$379,054 
 December 31, 2020
(in thousands)Balance Sheet LocationAssetLiability
Oil contractsCurrent assets — Derivative instruments$5,425 $— 
Gas contractsCurrent assets — Derivative instruments1,423 — 
Gas contractsNon-current assets — Derivative instruments2,342 — 
Oil contractsCurrent liabilities — Derivative instruments— 106,507 
Gas contractsCurrent liabilities — Derivative instruments— 38,891 
Oil contractsNon-current liabilities — Derivative instruments— 12,526 
Gas contractsNon-current liabilities — Derivative instruments— 5,223 
Total gross amounts presented in the balance sheet9,190 163,147 
Less: gross amounts not offset in the balance sheet(8,863)(8,863)
Net amount$327 $154,284 

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 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 derivative liability positions, nor do we require our counterparties to post collateral for our benefit. In the future we may enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

20

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
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. Authoritative accounting guidance 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 other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable.

The following table provides fair value measurement information for certain assets and liabilities as of June 30, 2021 and December 31, 2020:
 June 30, 2021December 31, 2020
(in thousands)Book
Value
Fair
Value
Book
Value
Fair
Value
Financial Assets (Liabilities):
4.375% Notes due 2024$750,000 $(816,375)$(750,000)$(818,025)
3.90% Notes due 2027$750,000 $(826,800)$(750,000)$(826,575)
4.375% Notes due 2029$500,000 $(567,900)$(500,000)$(567,250)
Derivative instruments — assets$3,704 $3,704 $9,190 $9,190 
Derivative instruments — liabilities$(382,758)$(382,758)$(163,147)$(163,147)

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 fixed rate notes was based on quoted market prices. The fair value of our derivative instruments (Level 2) was estimated using discounted cash flow and option pricing models. These models use certain observable variables including forward prices, volatility curves, interest rates, and credit ratings and spreads. 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. Included in “Accrued liabilities — Other” at June 30, 2021 are accrued operating expenses (e.g., production, transportation, and midstream expenses) of approximately $73.4 million. Included in “Accrued liabilities — Other” at December 31, 2020 are: (i) accrued operating expenses (e.g., production, transportation, and midstream expenses) of approximately $67.4 million and (ii) accrued general and administrative costs of approximately $46.8 million, which consisted primarily of $34.1 million in regular payroll-related costs and $11.3 million in voluntary early retirement incentive program and involuntary reduction in workforce severance accruals (the aggregate balance for these severance accruals decreased to $2.5 million at June 30, 2021 due to payments made during the six months ended June 30, 2021).

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 conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary. For properties we operate, we have the right to realize amounts due to us from non-operators by netting the non-operators’ share of production revenues from those properties.
21

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
We routinely assess the recoverability of all material accounts receivable and accrue a reserve to the allowance for credit losses based on our estimation of expected losses over the life of the receivables. At June 30, 2021 and December 31, 2020, the allowance for credit losses totaled $3.0 million and $2.6 million, respectively.

5.CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At June 30, 2021, there were 102.8 million shares of common stock outstanding and 28.2 thousand shares of 8.125% Series A Cumulative Perpetual Convertible Preferred Stock outstanding (the “Preferred Stock”). Holders of the Preferred Stock are entitled to receive, when, as, and if declared by the Board, cumulative cash dividends at an annual rate of 8.125% of each share’s liquidation preference of $1,000. In the event of any liquidation, winding up, or dissolution of Cimarex, each holder will be entitled to receive in respect of its shares, up to each share’s liquidation preference, with the total liquidation preference being $28.2 million in the aggregate at June 30, 2021, after satisfaction of liabilities and any senior stock (of which there is currently none) and before any payment or distribution to holders of junior stock (including common stock). Each holder has the right at any time, at its option, to convert any or all of such holder’s shares of Preferred Stock into a certain number of shares of Cimarex common stock based on a conversion rate that adjusts upon the occurrence of certain events, including the payment of cash dividends to common shareholders, and $471.40 in cash per share of Preferred Stock. The June 30, 2021 conversion rate was 8.45897 shares of common stock for each share of Preferred Stock. As a result of the cash component included in the redemption feature of the Preferred Stock conversion option, which conversion is not solely within our control, the instruments are classified as “Redeemable preferred stock” in temporary equity on the Condensed Consolidated Balance Sheets.

Dividends

Common Stock

In May 2021, our Board of Directors declared a cash dividend of $0.27 per share of common stock. The dividend is payable on or before September 1, 2021 to stockholders of record on August 13, 2021. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. The $27.9 million dividend declared during the second quarter 2021 was recorded as a reduction of additional paid-in capital and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet at June 30, 2021. Nonforfeitable dividends paid on unvested stock awards that subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to stock-based compensation expense in the period in which the stock award forfeitures occur. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Preferred Stock

In May 2021, our Board of Directors declared a cash dividend of $20.3125 per share of Preferred Stock. The dividend was paid in July to stockholders of record on July 1, 2021. This $0.6 million dividend was recorded as a reduction of additional paid-in capital and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet at June 30, 2021.

22

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
6.STOCK-BASED COMPENSATION

We have recognized stock-based compensation cost as shown below for the periods indicated.
Three Months Ended
June 30,
Six Months Ended
June 30,
(in thousands)2021202020212020
Restricted stock awards:  
Performance stock awards$3,441 $4,059 $6,723 $8,119 
Service-based stock awards6,543 6,585 14,842 13,962 
9,984 10,644 21,565 22,081 
Stock option awards426 416 900 914 
Total stock-based compensation cost10,410 11,060 22,465 22,995 
Less amounts capitalized to oil and gas properties(2,532)(4,313)(6,038)(9,854)
Stock-based compensation expense$7,878 $6,747 $16,427 $13,141 

Periodic stock-based compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards. Our accounting policy is to account for forfeitures in compensation cost when they occur. To the extent compensation cost relates to employees directly involved in oil and gas property acquisition, exploration, and development activities, such amounts are capitalized to oil and gas properties. The amount of stock-based compensation cost capitalized to oil and gas properties decreased as a percentage of total stock-based compensation cost during the three and six months ended June 30, 2021 as compared to the three and six months ended June 30, 2020 as a result of decreased acquisition, exploration, and development activities in response to the lower oil prices and demand destruction seen after the first quarter of 2020. The decreased capitalization caused overall stock-based compensation expense to increase.

7.ASSET RETIREMENT OBLIGATIONS

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, 2021:
(in thousands)Six Months Ended
June 30, 2021
Asset retirement obligation at January 1, 2021$177,867 
Liabilities incurred2,967 
Liability settlements and disposals(77,531)
Accretion expense3,730 
Revisions of estimated liabilities25,149 
Asset retirement obligation at June 30, 2021132,182 
Less current obligation(12,629)
Long-term asset retirement obligation$119,553 

23

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
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 for the periods indicated. Earnings (loss) per share are based on whole numbers rather than the rounded numbers presented.
Three Months Ended June 30,
20212020
(in thousands, except per share information)Income (Numerator)Shares (Denominator)Per-Share AmountIncome (Numerator)Shares (Denominator)Per-Share Amount
Net income (loss)$113,388  $(925,147)
Less: dividends and net income attributable to participating securities (1)(2,399)(569)
Less: redeemable preferred stock dividends(572)(1,269)
Basic earnings (loss) per share
Income (loss) available to common stockholders110,417 100,194 $1.10 (926,985)99,880 $(9.28)
Effects of dilutive securities
Dilutive securities (2)91 
Diluted earnings (loss) per share
Income (loss) available to common stockholders and assumed conversions$110,418 100,285 $1.10 $(926,985)99,880 $(9.28)

Six Months Ended June 30,
20212020
(in thousands, except per share information)Income (Numerator)Shares (Denominator)Per-Share AmountIncome (Numerator)Shares (Denominator)Per-Share Amount
Net income (loss)$241,470 $(1,699,429)
Less: dividends and net income attributable to participating securities (1)(5,172)(1,119)
Less: redeemable preferred stock dividends(1,144)(2,538)
Basic earnings (loss) per share
Income (loss) available to common stockholders235,154 100,160 $2.35 (1,703,086)99,861 $(17.05)
Effects of dilutive securities
Dilutive securities (2)68 
Diluted earnings (loss) per share
Income (loss) available to common stockholders and assumed conversions$235,156 100,228 $2.35 $(1,703,086)99,861 $(17.05)
________________________________________
(1)Participating securities do not have a contractual obligation to share in the losses of the entity, therefore, net losses are not attributable to participating securities.
24

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
(2)Inclusion of certain potential common shares would have an anti-dilutive effect, therefore, these shares were excluded from the calculations of diluted earnings (loss) per share. Excluded from the calculation for the three months ended June 30, 2021 were 427.4 thousand potential common shares from the assumed exercise of employee stock options and 238.2 thousand potential common shares from the assumed conversion of the Preferred Stock. Excluded from the calculation for the three months ended June 30, 2020 were 456.6 thousand potential common shares from the assumed exercise of employee stock options, 515.8 thousand potential common shares from the assumed conversion of the Preferred Stock, and 8.8 thousand potential common shares from the assumed vesting of incremental shares of unvested restricted stock units. Excluded from the calculation for the six months ended June 30, 2021 were 450.7 thousand potential common shares from the assumed exercise of employee stock options and 238.2 thousand potential common shares from the assumed conversion of the Preferred Stock. Excluded from the calculation for the six months ended June 30, 2020 were 456.6 thousand potential common shares from the assumed exercise of employee stock options, 515.8 thousand potential common shares from the assumed conversion of the Preferred Stock, and 8.8 thousand potential common shares from the assumed vesting of incremental shares of unvested restricted stock units.

9.INCOME TAXES

The components of our provision for income taxes and our combined federal and state effective income tax rates were as follows:
Three Months Ended
June 30,
Six Months Ended
June 30,
(in thousands)2021202020212020
Current tax expense (benefit)$442 $37 $442 $(161)
Deferred tax expense (benefit)34,550 (271,543)74,720 (287,900)
$34,992 $(271,506)$75,162 $(288,061)
Combined federal and state effective income tax rate23.6%22.7%23.7%14.5%

Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 21% primarily due to state income taxes, non-deductible expenses, and changes in valuation allowances. The combined federal and state effective income tax rate for the six months ended June 30, 2020 was impacted by the non-deductible impairment of goodwill recorded during the first quarter 2020.

At December 31, 2020, we had a U.S. net tax operating loss carryforward of approximately $1.997 billion, $1.773 billion of which is subject to expiration in tax years 2032 through 2037 and $224.4 million of which is not subject to expiration. We believe that the carryforward, net of valuation allowance, will be utilized before it expires. We also had enhanced oil recovery and marginal well credits of $4.2 million at December 31, 2020.

The total valuation allowance on state net operating losses at December 31, 2020 was $120.7 million since it is not more likely than not that these additional state net operating losses will be utilized before they expire. When assessing the need for a valuation allowance against a deferred tax asset, both positive and negative evidence is considered when determining the ability to utilize our deferred tax assets. Based on our estimate of the timing of future reversals of existing taxable temporary differences, our estimate of future taxable income exclusive of reversing temporary differences and carryforwards, the length of time before the deferred tax assets associated with the net operating loss carryovers begin to expire, and tax planning strategies that could be implemented to accelerate taxable amounts to utilize expiring carryovers, we believe it is more likely than not that the benefit from the deferred tax asset recorded in the financial statements will be realized. We will continue to assess all available positive and negative evidence to estimate whether sufficient future taxable income will be generated in order to utilize the deferred tax assets. Additional valuation allowances may be required in future periods if additional losses are incurred or other circumstances change.
25

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)

At June 30, 2021, we had 0 unrecognized tax benefits that would impact our effective tax rate and have made 0 provisions for interest or penalties related to uncertain tax positions. The tax years 2017 through 2019 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 2016 through 2019.

10.COMMITMENTS AND CONTINGENCIES

At June 30, 2021, we had estimated commitments of approximately: (i) $224.8 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $4.8 million to finish midstream construction in progress.

At June 30, 2021, we had firm sales contracts to deliver approximately 456.5 Bcf of gas over the next 10.0 years. If we do not deliver this gas, our estimated financial commitment, calculated using the July 2021 index prices, would be approximately $1.433 billion. The value of this commitment will fluctuate due to price volatility and actual volumes delivered.

In connection with gas gathering and processing agreements, we have volume commitments over the next 15.0 years. If we do not deliver the committed gas or NGLs, as applicable, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2021, would be approximately $728.6 million.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas or oil, as applicable, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2021, would be approximately $104.0 million. Of this total, we have accrued a liability of $4.1 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.

At June 30, 2021, we have various firm transportation agreements for gas pipeline capacity with end dates ranging from 2021 - 2025 under which we will have to pay an estimated $16.1 million over the remaining terms of the agreements.

We have minimum volume water delivery commitments associated with a water services agreement that ends in 2030. If the water volumes are not delivered by us or third parties, the estimated maximum amount that would be payable by us under this commitment, calculated as of June 30, 2021, would be approximately $60.8 million. Of this total, we have accrued a liability of $0.7 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.

In May 2021, we entered into a lease for the use of an electric hydraulic fracturing fleet and the personnel and other equipment required to use the fleet for a period of four years. The lessor is constructing the fleet and the lease will commence on the earlier of the commencement of field activity or June 30, 2022. Upon commencement of the lease, we expect to record a lease liability and right-of-use asset of between $150.0 million and $160.0 million.

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

26

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
Litigation

In the ordinary course of business, we are involved with various litigation matters. When a loss contingency exists, we assess the likelihood that a future event or events will confirm the loss or impairment of an asset or the incurrence of a liability. If the likelihood is probable, we accrue a loss if reasonably estimable. 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.

In June and July 2021, four putative stockholders of Cimarex filed separate lawsuits against Cimarex and its board of directors related to the proposed merger (the “Merger”) of Cabot Oil & Gas Corporation and Cimarex. See Note 13 to the Condensed Consolidated Financial Statements for additional information regarding the merger. Three of the lawsuits were filed in the United States District Court for the Southern District of New York and are captioned Wang v. Cimarex, et al., Case No. 1:21-cv-05672, Graff v. Cimarex, et al., Case No. 1:21-cv-05804, and Elliot v. Cimarex, et al., Case No. 1:21-cv-06315. The fourth lawsuit was filed in the United States District Court for the District of Colorado and is captioned Woodyard v. Cimarex, et al., Case No. 1:21-cv-01850. Each of the actions is asserted only on behalf of the named plaintiff.

All four actions allege violations of Section 14(a) and 20(a) of the Securities Exchange Act of 1934 (the Exchange Act) and Rule 14a-9 promulgated thereunder based on various alleged omissions of material information from the registration statement on Form S-4 filed in connection with the Merger. One of the actions (Elliot) also asserts claims that the members of the Cimarex board of directors breached fiduciary duties in connection with the Merger, and that Cimarex aided and abetted those alleged breaches. Each action names as defendants Cimarex and each of its directors, and seeks, among other things, to enjoin the Merger (or, in the alternative, rescission or an award for rescissory damages in the event the Merger is completed), an award of costs and attorneys’ and experts’ fees, and such other and further relief as the court may deem just and proper. We believe that the actions are without merit.

11.    SUPPLEMENTAL CASH FLOW INFORMATION
 Three Months Ended
June 30,
Six Months Ended
June 30,
(in thousands)2021202020212020
Cash paid during the period for:    
Interest (net of capitalized amounts of $16,001, $18,145, $22,014 and $25,473, respectively)$16,553 $14,050 $22,538 $19,609 
Income taxes$541 $$571 $
Cash received for income tax refunds$103 $280 $369 $484 

12.RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to Cimarex. Cimarex incurred drilling costs of approximately $2.3 million and $5.2 million related to these services during the three and six months ended June 30, 2021 and $7.8 million and $23.4 million during the three and six months ended June 30, 2020. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.


27

CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2021
(Unaudited)
13.MERGER AND DIVESTITURES

Merger

On May 23, 2021, Cimarex entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Cabot Oil & Gas Corporation (“Cabot”) and Double C Merger Sub, Inc., a wholly-owned subsidiary of Cabot (“Merger Sub”). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement: (i) Merger Sub will be merged with and into Cimarex (the “Merger”), with Cimarex surviving and continuing as a wholly-owned subsidiary of Cabot in the Merger, and (ii) at the effective time of the Merger, each outstanding share of common stock of Cimarex (other than certain Excluded Shares, Converted Shares, or shares of Cimarex common stock subject to a Cimarex Restricted Share Award (each as defined in the Merger Agreement)) will be converted into the right to receive 4.0146 shares of common stock of Cabot. Following the closing of the Merger, Cimarex’s existing stockholders and Cabot’s existing stockholders will own approximately 50.5% and 49.5%, respectively, of the issued and outstanding shares of the combined company. The transaction is expected to close in the fourth quarter of 2021, subject to the approval of Cimarex and Cabot stockholders and the satisfaction of other customary closing conditions. Other operating expense, net during the six months ended June 30, 2021 included $8.1 million in expenses related to the Cabot merger. These expenses were primarily for advisory and legal services.

Divestitures

During the three months ended June 30, 2021, we closed on divestitures of non-core oil and gas properties and related assets in West Texas and Southern Oklahoma for which we received $111.0 million in net cash proceeds. Final settlements, which will reflect customary post-closing adjustments, are expected to occur in the third or fourth quarter of 2021. These divestitures did not significantly alter the relationship between capitalized costs and proved reserves, therefore, in accordance with the full cost method of accounting, no gain or loss was recognized.
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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 located entirely within the United States, mainly in Texas, New Mexico, and Oklahoma. Currently our operations are focused in two main areas: the Permian Basin and the Mid-Continent. Our Permian Basin region encompasses west Texas and southeast New Mexico. Our Mid-Continent region encompasses Oklahoma and the Texas Panhandle.

Our principal business objective is to increase shareholder value through the profitable growth of our proved reserves and production while seeking to minimize our impact on the communities in which we operate for the long-term. Our strategy centers on maximizing cash flow from producing properties for reinvestment in exploration and development activities and for providing cash returns to shareholders through dividends and debt reduction. We consider merger and acquisition opportunities that enhance our competitive position and we occasionally divest non-core assets, such as our divestitures during the three months ended June 30, 2021 of non-core oil and gas properties and related assets in West Texas and Southern Oklahoma for which we received $111.0 million in net cash proceeds.

We believe that detailed technical analysis, operational focus, and a disciplined capital investment process mitigates risk and positions us to continue to achieve profitable 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 cash on hand, bank borrowings, sales of non-core assets, and, from time to time, public financing based on our monitoring of capital markets and our balance sheet.

Merger

On May 23, 2021, Cimarex entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Cabot Oil & Gas Corporation (“Cabot”) and Double C Merger Sub, Inc., a wholly-owned subsidiary of Cabot (“Merger Sub”). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement: (i) Merger Sub will be merged with and into Cimarex (the “Merger”), with Cimarex surviving and continuing as a wholly-owned subsidiary of Cabot in the Merger, and (ii) at the effective time of the Merger, each outstanding share of common stock of Cimarex (other than certain Excluded Shares, Converted Shares, or shares of Cimarex common stock subject to a Cimarex Restricted Share Award (each as defined in the Merger Agreement)) will be converted into the right to receive 4.0146 shares of common stock of Cabot. Following the closing of the Merger, Cimarex’s existing stockholders and Cabot’s existing stockholders will own approximately 50.5% and 49.5%, respectively, of the issued and outstanding shares of the combined company. The transaction is expected to close in the fourth quarter of 2021, subject to the approval of Cimarex and Cabot stockholders and the satisfaction of other customary closing conditions.

Market Conditions

The oil and gas industry is cyclical and commodity prices can fluctuate significantly. We expect this volatility to persist. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, inventory storage levels, weather conditions, and other factors. Local market prices for oil and gas can be impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials.

In the first quarter of 2020, the highly transmissible and pathogenic coronavirus known as severe acute respiratory syndrome coronavirus 2 (SARS-CoV-2) that causes the disease known as COVID-19 began to spread globally. The reduction in economic activity from the COVID-19 pandemic resulted in unprecedented demand destruction and inventory increases for oil and natural gas liquids. In addition, in early March 2020, members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia failed to reach an agreement on oil production limits and Saudi Arabia unilaterally reduced the sales price of its oil and announced that it would
29

increase its oil production. As a result of these actions and the COVID-19 pandemic, WTI oil prices dropped and even became negative for a brief time in April 2020. Oil prices have improved since then, coinciding with some recovery of global economic activity, lower supply from major oil producing countries, and moderating inventory levels. However, while COVID-19 vaccines have become more widely available, variants of the virus that causes COVID-19 continue to cause concerns that the demand recovery for oil and natural gas liquids could stall. Additionally, OPEC has recently agreed to increase production beginning in August 2021, which could lead to lower oil prices as supply increases.

Our average realized price for oil during the six months ended June 30, 2021 improved to $60.12 per barrel, increasing 84% over our average realized price for oil during the six months ended June 30, 2020. In February 2021, Texas and Oklahoma experienced an extreme winter weather event that included freezing rain, sleet, snow, and freezing temperatures over an extended period. This event caused gas demand to exceed gas supply as demand increased while supplies were simultaneously curtailed by power outages, frozen equipment, impassable roads, and other impacts of the severe weather, significantly increasing gas prices. Our average realized price for gas during the six months ended June 30, 2021 was $3.30 per Mcf, increasing 358% over our average realized price for gas during the six months ended June 30, 2020.

The table below presents average NYMEX prices and our company-wide average realized prices and price differentials for the periods indicated.

Three Months Ended
June 30,
Variance Between
2021 / 2020
Six Months Ended
June 30,
Variance Between 2021 / 2020
2021202020212020
Average NYMEX price   
Oil — per barrel$66.07 $27.85 137%$61.96 $37.01 67%
Gas — per Mcf$2.80 $1.71 64%$2.76 $1.83 51%
Average realized price   
Oil — per barrel$64.11 $19.57 228%$60.12 $32.74 84%
Gas — per Mcf$2.51 $0.91 176%$3.30 $0.72 358%
NGL — per barrel$23.16 $7.52 208%$22.83 $8.71 162%
Average price differential   
Oil — per barrel$(1.96)$(8.28)76%$(1.84)$(4.27)57%
Gas — per Mcf$(0.29)$(0.80)64%$0.54 $(1.11)149%

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The average price differentials that we realized in our two primary areas of operation are shown in the table below for the periods indicated.
Average Price Differentials
20212020
Year-to-dateSecond
Quarter
First
Quarter
YearFourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
Oil
Permian Basin$(1.81)$(1.91)$(2.00)$(3.74)$(2.79)$(2.71)$(8.12)$(2.00)
Mid-Continent$(1.96)$(2.11)$(1.96)$(4.43)$(0.99)$(5.06)$(9.53)$(2.02)
Total Company$(1.84)$(1.96)$(1.99)$(3.81)$(2.57)$(2.99)$(8.28)$(1.99)
Gas
Permian Basin$0.39 $(0.44)$1.29 $(1.39)$(1.34)$(1.15)$(1.09)$(1.85)
Mid-Continent$0.82 $(0.02)$1.69 $(0.41)$(0.36)$(0.31)$(0.31)$(0.57)
Total Company$0.54 $(0.29)$1.43 $(1.03)$(0.98)$(0.84)$(0.80)$(1.40)

Pipeline expansion projects in the Permian Basin and reduced drilling activity and production have eased take away constraints and improved price differentials over prior year. However, if pipeline projects are delayed, production increases faster than capacity increases, or the basin experiences pipeline disruptions or other constraints, differentials could potentially worsen. Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and gas production and can be adversely affected by realized price decreases.

See RISK FACTORS in Item 1A of this Form 10-Q and in our Annual Report on Form 10-K for the year ended December 31, 2020, 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.

Summary of Operating and Financial Results for the Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020:

Total production volumes decreased 14% to 228.4 MBOE per day.

Oil volumes decreased 16% to 70.7 MBbls per day.

Gas volumes decreased 15% to 572.2 MMcf per day.

NGL volumes decreased 10% to 62.4 MBbls per day.

Total production revenue increased 96% to $1.369 billion.

Cash flow provided by operating activities increased 69% to $766.6 million.

Exploration and development investments increased 8% to $357.8 million.

Net income was $241.5 million, or $2.35 per diluted share, for the first six months of 2021, as compared to a net loss of $1.699 billion, or $17.05 per diluted share, for the first six months of 2020.

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RESULTS OF OPERATIONS

Three and Six Months Ended June 30, 2021 Compared to Three and Six Months Ended June 30, 2020

Revenues

Our revenues are derived from sales of our oil, gas, and NGL production.  Increases or decreases in our revenues, 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, availability of transportation, seasonality, and geopolitical, economic, and other factors.

Production volumes were lower and realized prices were higher for all products during the three and six months ended June 30, 2021 as compared to the three and six months ended June 30, 2020. The decrease in production volumes is primarily due to deliberate and immediate action that we took to reduce our drilling and completion activity subsequent to the first quarter 2020 in response to the unprecedented demand destruction and severe oil price decreases caused by the COVID-19 pandemic and OPEC and other countries’ actions. We have since increased our drilling and completion activity, but have adjusted our capital reinvestment rates to stay below operating cash flow. Although prices remain volatile, they have improved over the levels seen in the first six months of 2020 as demand increases with a recovering global economy. Additionally, gas prices during the first quarter 2021 were boosted due to the February 2021 extreme winter weather event in Texas and Oklahoma. Our production revenue increased 192%, or $459.7 million, during the three months ended June 30, 2021 as compared to the three months ended June 30, 2020 and increased 96%, or $670.3 million, during the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. The following tables show our production revenue for the periods indicated as well as the changes in revenue due to changes in volumes and prices.
Three Months Ended
June 30,
Variance Between
2021 / 2020
Price/Volume Variance
Production Revenue
(in thousands)
20212020PriceVolumeTotal
Oil sales$424,175 $138,817 $285,358 206%$294,693 $(9,335)$285,358 
Gas sales133,260 54,154 79,106 146%85,060 (5,954)79,106 
NGL sales141,294 46,107 95,187 206%95,400 (213)95,187 
$698,729 $239,078 $459,651 192%$475,153 $(15,502)$459,651 

Six Months Ended
June 30,
Variance Between
2021 / 2020
Price/Volume Variance
Production Revenue
(in thousands)
20212020PriceVolumeTotal
Oil sales$768,879 $499,797 $269,082 54%$350,154 $(81,072)$269,082 
Gas sales342,058 88,984 253,074 284%267,216 (14,142)253,074 
NGL sales257,894 109,758 148,136 135%159,519 (11,383)148,136 
$1,368,831 $698,539 $670,292 96%$776,889 $(106,597)$670,292 
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The table below presents our production volumes by region.
Three Months Ended
June 30,
Six Months Ended
June 30,
Production Volumes2021202020212020
Oil (Bbls per day)  
Permian Basin65,785 68,791 63,894 74,198 
Mid-Continent6,704 9,063 6,604 9,502 
Other218 102 158 173 
72,707 77,956 70,656 83,873 
Gas (MMcf per day)  
Permian Basin379.6 417.8 369.5 433.4 
Mid-Continent203.2 237.3 201.5 240.7 
Other1.4 0.9 1.2 1.1 
584.2 656.0 572.2 675.2 
NGL (Bbls per day)  
Permian Basin46,408 47,291 42,788 48,111 
Mid-Continent20,531 20,068 19,556 21,089 
Other91 43 73 51 
67,030 67,402 62,417 69,251 
Total (BOE per day)  
Permian Basin175,453 185,717 168,260 194,548 
Mid-Continent61,101 68,675 59,748 70,705 
Other551 295 435 396 
237,105 254,687 228,443 265,649 

33

The table below presents our production volumes by commodity, our average realized commodity prices, and certain major U.S. index prices.  The sale of our Permian Basin oil production is typically tied to the WTI Midland benchmark price and the sale of our Mid-Continent oil production is typically tied to the WTI Cushing benchmark price.  During the six months ended June 30, 2021, approximately 90% of our oil production was in the Permian Basin, up from approximately 88% during the six months ended June 30, 2020. Our realized prices do not include settlements of commodity derivative contracts.
Three Months Ended
June 30,
Variance Between
2021 / 2020
Six Months Ended
June 30,
Variance Between 2021 / 2020
2021202020212020
Oil   
Total volume — MBbls6,616 7,094 (7)%12,789 15,265 (16)%
Total volume — MBbls per day72.7 78.0 (7)%70.7 83.9 (16)%
Percentage of total production31 %31 % 31 %32 % 
Average realized price — per barrel$64.11 $19.57 228%$60.12 $32.74 84%
Average WTI Midland price — per barrel$66.50 $28.06 137%$62.52 $37.55 66%
Average WTI Cushing price — per barrel$66.07 $27.85 137%$61.96 $37.01 67%
Gas   
Total volume — MMcf53,162 59,694 (11)%103,572 122,877 (16)%
Total volume — MMcf per day584.2 656.0 (11)%572.2 675.2 (15)%
Percentage of total production41 %43 % 42 %42 % 
Average realized price — per Mcf$2.51 $0.91 176%$3.30 $0.72 358%
Average Henry Hub price — per Mcf$2.80 $1.71 64%$2.76 $1.83 51%
NGL   
Total volume — MBbls6,100 6,134 (1)%11,297 12,604 (10)%
Total volume — MBbls per day67.0 67.4 (1)%62.4 69.3 (10)%
Percentage of total production28 %26 % 27 %26 % 
Average realized price — per barrel$23.16 $7.52 208%$22.83 $8.71 162%
Total   
Total production — MBOE21,577 23,177 (7)%41,348 48,348 (14)%
Total production — MBOE per day237.1 254.7 (7)%228.4 265.6 (14)%
Average realized price — per BOE$32.38 $10.32 214%$33.11 $14.45 129%

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Other revenues

Gas gathering and other revenue is earned when we transport, process, and market some third-party gas that is associated with our equity gas. Gas marketing is comprised of the fees we earn when we act as agent under short-term sales and supply agreements and market and sell gas for other working interest owners, net of the related expenses. Gas marketing also includes net pipeline settlements incurred as a result of these activities. The table below presents revenues from third-party gas gathering and other and our net marketing margin for marketing other working interest owners’ gas for the periods indicated. 
Three Months Ended
June 30,
Variance Between
2021 / 2020
Six Months Ended
June 30,
Variance Between 2021 / 2020
Gas Gathering and Marketing Revenues (in thousands)
2021202020212020
Gas gathering and other$13,530 $11,589 $1,941 $25,745 $25,172 $573 
Gas marketing$121 $(1,284)$1,405 $(2,730)$(1,498)$(1,232)

Fluctuations in revenues from gas gathering and gas marketing activities are primarily a function of increases and decreases in volumes, commodity prices, and gathering rate charges.

Operating Costs and Expenses

Costs associated with producing oil and gas are substantial.  Among other factors, some of these costs vary with commodity prices, some trend with the volume of production, some are a function of the number of wells we own, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. 

Total operating costs and expenses for the three months ended June 30, 2021 were lower by 61%, or $880.0 million, compared to the three months ended June 30, 2020.  The primary reasons for the decrease were the $941.2 million ceiling test impairment incurred during the three months ended June 30, 2020 (no ceiling test impairment was incurred during the three months ended June 30, 2021) and the $84.2 million decrease in depreciation, depletion, and amortization. These decreases were partially offset by a $87.9 million increase in net losses on derivative instruments and a $23.8 million increase in taxes other than income.
Three Months Ended
June 30,
Variance Between
2021 / 2020
Per BOE
Operating Costs and Expenses
(in thousands, except per BOE)
2021202020212020
Impairment of oil and gas properties$— $941,198 $(941,198)N/AN/A
Depreciation, depletion, and amortization110,733 194,954 (84,221)$5.13 $8.41 
Asset retirement obligation2,514 1,661 853 $0.12 $0.07 
Production77,408 64,337 13,071 $3.59 $2.78 
Transportation, processing, and other operating59,285 53,282 6,003 $2.75 $2.30 
Gas gathering and other9,549 3,526 6,023 $0.44 $0.15 
Taxes other than income40,247 16,486 23,761 $1.87 $0.71 
General and administrative24,978 26,226 (1,248)$1.16 $1.13 
Stock-based compensation7,878 6,747 1,131 $0.37 $0.29 
Loss on derivative instruments, net211,833 123,885 87,948 N/AN/A
Other operating expense, net8,050 130 7,920 N/AN/A
$552,475 $1,432,432 $(879,957)

35

Total operating costs and expenses for the six months ended June 30, 2021 were lower by 61%, or $1.635 billion, compared to the six months ended June 30, 2020.  The primary reasons for the decrease were the $1.275 billion in ceiling test impairments incurred during the six months ended June 30, 2020 (no ceiling test impairments were incurred during the six months ended June 30, 2021), the $714.4 million goodwill impairment incurred during the six months ended June 30, 2020, and the $186.4 million decrease in depreciation, depletion, and amortization, partially offset by a $476.8 million increase in net losses on derivative instruments.
Six Months Ended
June 30,
Variance Between
2021 / 2020
Per BOE
Operating Costs and Expenses
(in thousands, except per BOE)
2021202020212020
Impairment of oil and gas properties$— $1,274,849 $(1,274,849)N/AN/A
Depreciation, depletion, and amortization223,667 410,040 (186,373)$5.41 $8.48 
Asset retirement obligation4,732 6,385 (1,653)$0.11 $0.13 
Impairment of goodwill— 714,447 (714,447)N/AN/A
Production152,214 151,573 641 $3.68 $3.14 
Transportation, processing, and other operating122,892 108,204 14,688 $2.97 $2.24 
Gas gathering and other20,027 11,824 8,203 $0.48 $0.24 
Taxes other than income81,233 47,447 33,786 $1.96 $0.98 
General and administrative50,238 51,735 (1,497)$1.22 $1.07 
Stock-based compensation16,427 13,141 3,286 $0.40 $0.27 
Loss (gain) on derivative instruments, net373,768 (103,055)476,823 N/AN/A
Other operating expense, net7,117 381 6,736 N/AN/A
$1,052,315 $2,686,971 $(1,634,656)

Impairment of Oil and Gas Properties

We use the full cost method of accounting for our oil and gas operations. Under this method, we are required to perform quarterly ceiling test calculations to test our oil and gas properties for possible impairment.  If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense.  The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes.  We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.

The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes.  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 test impairment. The calculated ceiling limitation 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 and various components of our balance sheet.  Any impairment of oil and gas properties is not reversible at a later date. 

No ceiling test impairments were incurred during the six months ended June 30, 2021. At June 30, 2021, a decline in the value of the ceiling limitation of approximately 34% or more would have resulted in an impairment. During the six months ended June 30, 2020, we incurred ceiling test impairments totaling $1.275 billion primarily as a result of decreases in the 12-month average trailing prices for oil, gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves. We may recognize additional ceiling test impairments in the future.
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Depreciation, Depletion, and Amortization

Depreciation, depletion, and amortization (“DD&A”) consisted of the following for the periods indicated:
Three Months Ended
June 30,
Variance Between
2021 / 2020
Per BOE
DD&A Expense (in thousands, except per BOE)
2021202020212020
Depletion$93,822 $177,136 $(83,314)$4.35 $7.64 
Depreciation16,911 17,818 (907)0.78 0.77 
$110,733 $194,954 $(84,221)$5.13 $8.41 

Six Months Ended
June 30,
Variance Between
2021 / 2020
Per BOE
DD&A Expense (in thousands, except per BOE)
2021202020212020
Depletion$189,522 $375,262 $(185,740)$4.58 $7.76 
Depreciation34,145 34,778 (633)0.83 0.72 
$223,667 $410,040 $(186,373)$5.41 $8.48 

Depletion 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 depletion expense. 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. Our depletion expense decreased during the three and six months ended June 30, 2021 as compared to the three and six months ended June 30, 2020 primarily due to a decrease in our depletable basis, mostly resulting from the ceiling test impairments that we recognized in each quarter of 2020, and secondarily due to decreased production during the 2021 periods as compared to the 2020 periods.

We record our depreciable fixed assets at cost and depreciate them to depreciation expense using the straight-line method based on the expected useful lives of the individual assets, which range from 3 to 30 years. Depreciable fixed assets whose depreciation is recorded to depreciation expense consist primarily of gas gathering and plant facilities, water infrastructure, vehicles, airplanes, office furniture, leasehold improvements, computer equipment, and the right-of-use asset associated with our finance lease gas gathering system.

Impairment of Goodwill

We concluded that goodwill was impaired at March 31, 2020 and expensed the entire balance of $714.4 million at that time. See Note 1 to the Condensed Consolidated Financial Statements for additional information regarding the impairment of goodwill.

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Production

Production expense generally consists of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating, and miscellaneous other costs (lease operating expense). Production expense also includes well workover activity necessary to maintain production from existing wells. Production expense consisted of lease operating expense and workover expense as follows:
Three Months Ended
June 30,
Variance Between
2021 / 2020
Per BOE
Production Expense (in thousands, except per BOE)
2021202020212020
Lease operating expense$61,567 $58,427 $3,140 $2.85 $2.52 
Workover expense15,841 5,910 9,931 0.74 0.26 
$77,408 $64,337 $13,071 $3.59 $2.78 

Six Months Ended
June 30,
Variance Between
2021 / 2020
Per BOE
Production Expense (in thousands, except per BOE)
2021202020212020
Lease operating expense$122,800 $132,896 $(10,096)$2.97 $2.75 
Workover expense29,414 18,677 10,737 0.71 0.39 
$152,214 $151,573 $641 $3.68 $3.14 

Lease operating expense for the second quarter of 2021 increased 5%, or $3.1 million, compared to the second quarter of 2020. Lease operating expense for the six months ended June 30, 2021 decreased 8%, or $10.1 million, compared to the six months ended June 30, 2020. The per BOE expense increased in the 2021 periods as compared to the 2020 periods as a result of decreased production. The decrease in the absolute expense during the six months ended June 30, 2021 is primarily due to our reduction in headcount through our 2020 voluntary early retirement incentive program and involuntary reduction in workforce as well as the use of less contract labor.

Workover expense for the second quarter of 2021 increased 168%, or $9.9 million, compared to the second quarter of 2020. Workover expense for the six months ended June 30, 2021 increased 57%, or $10.7 million, compared to the six months ended June 30, 2020. During the 2020 periods we had fewer workover projects as a result of a concerted effort to reduce activity and delay non-essential work. With the improvement of demand and prices, we are now performing more and costlier workover projects.

Transportation, Processing, and Other Operating

Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, including gathering, fuel, compression, and processing costs. Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, changes in fuel and compression costs, and the structure of sales contracts. If the sales contract transfers control of the product at the wellhead, transportation and processing costs are included as a reduction in the revenue we record and are not included in transportation, processing, and other operating costs. Transportation, processing, and other operating costs for the second quarter of 2021 were 11%, or $6.0 million, higher than the same costs in the second quarter of 2020. Transportation, processing, and other operating costs for the six months ended June 30, 2021 were 14%, or $14.7 million, higher than the same costs in the six months ended June 30, 2020. This expense increased due primarily to higher gas prices, which cause higher fuel expense. Additionally, the first quarter of 2021 included increased fuel gas and electricity costs as a result of the February 2021 extreme winter weather event in Texas and Oklahoma. Decreased volumes partially offset the increase in this expense, but also contributed to the increase in the per BOE cost.

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Gas Gathering and Other

Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs and operating and maintenance expenses. A portion of these costs are reclassified to “Transportation, processing, and other operating” expense and “Production” expense in order to reflect an allocation of the costs incurred to operate our gas gathering facilities as a cost of transporting our equity share of gas produced and operating our wells. Gas gathering and other in the second quarter of 2021 was 171%, or $6.0 million, higher than gas gathering and other in the second quarter of 2020. Gas gathering and other in the six months ended June 30, 2021 was 69%, or $8.2 million, higher than gas gathering and other in the six months ended June 30, 2020. The increases in expense in the 2021 periods are primarily due to higher gas prices and increased maintenance expense.

Taxes Other than Income

Taxes other than income consist of production (or severance) taxes, ad valorem taxes, and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production and ad valorem taxes being based on the value of properties. The following table presents taxes other than income for the periods indicated.
Three Months Ended
June 30,
Variance Between
2021 / 2020
Six Months Ended
June 30,
Variance Between 2021 / 2020
Taxes Other than Income
(in thousands)
2021202020212020
Production$35,022 $6,868 $28,154 $71,091 $28,455 $42,636 
Ad valorem4,375 9,232 (4,857)9,106 18,451 (9,345)
Other850 386 464 1,036 541 495 
$40,247 $16,486 $23,761 $81,233 $47,447 $33,786 
Taxes other than income as a percentage of production revenue5.8%6.9%5.9%6.8%

Taxes other than income increased $23.8 million, or 144%, in the second quarter of 2021 as compared to the second quarter of 2020 and increased $33.8 million, or 71%, in the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. Production taxes typically make up the majority of our taxes other than income and they increased significantly, primarily due to increased revenues as a result of increased prices. Commodity prices were higher in the 2021 periods as compared to the 2020 periods due primarily to the increase in demand. The February 2021 extreme winter weather event in Texas and Oklahoma also contributed to increased prices in the six months ended June 30, 2021. Ad valorem tax accruals are based on the most recent actual taxes paid with adjustments made based on expected valuations, divestitures, and as better information, including actual valuations, is received. Ad valorem tax expense for the six months ended June 30, 2020 reflected accruals based on valuations received in late 2019. Decreased valuations received in late 2020 resulted in lower actual ad valorem taxes paid in the fourth quarter of 2020 and, therefore, lower ad valorem accruals in the six months ended June 30, 2021. Other taxes are comprised of franchise and consumer use and sales taxes.

General and Administrative

General and administrative (“G&A”) expense consists primarily of salaries and related benefits, office rent, legal and consulting fees, systems costs, and other administrative costs incurred. 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. The amount of expense capitalized varies and depends on whether the cost incurred can be directly identified with acquisition, exploration, and development activities. The percentage of gross G&A capitalized was 30% and 31% during the three and six months ended June 30, 2021, respectively, and was 35% and 38% during the three and six months ended June 30, 2020, respectively. The decreased capitalization rates in the 2021 periods are a result of decreased acquisition, exploration, and development
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activities in response to the lower oil prices and demand destruction seen after the first quarter of 2020. The table below shows our G&A costs for the periods presented.
Three Months Ended
June 30,
Variance Between
2021 / 2020
Six Months Ended
June 30,
Variance Between 2021 /2020
General and Administrative Expense
(in thousands)
2021202020212020
Gross G&A$35,608 $40,466 $(4,858)$73,055 $83,267 $(10,212)
Less amounts capitalized to oil and gas properties(10,630)(14,240)3,610 (22,817)(31,532)8,715 
G&A expense$24,978 $26,226 $(1,248)$50,238 $51,735 $(1,497)

Gross G&A expense decreased $4.9 million, or 12%, in the second quarter of 2021 as compared to the second quarter of 2020 and decreased $10.2 million, or 12%, in the six months ended June 30, 2021 as compared to the six months ended June 30, 2020. Gross G&A expense decreased in the 2021 periods as compared to the 2020 periods primarily due to decreases in severance costs incurred related to the voluntary early retirement incentive program that we offered during the first quarter of 2020 to employees who met certain eligibility criteria. The three and six months ended June 30, 2020 included severance expense of $3.6 million and $14.5 million, respectively, related to this program. Salaries and wages also decreased in the 2021 periods as compared to the 2020 periods as a result of the headcount reductions in 2020. In addition to the voluntary early retirement incentive program, we also had an involuntary reduction in workforce in the third quarter of 2020. The decreases in gross G&A in the 2021 periods as compared to the 2020 periods due to reduced severance and salaries and wages expense were partially offset by increased annual bonus expense and decreased amounts reimbursed to us by working interest owners.

Stock-based Compensation

Stock-based compensation expense consists primarily of charges resulting from the amortization of the cost of restricted stock and stock option awards, net of amounts capitalized to oil and gas properties. We have recognized stock-based compensation cost as follows:
Three Months Ended
June 30,
Variance Between
2021 / 2020
Six Months Ended
June 30,
Variance Between
2021 / 2020
Stock-based Compensation Expense
(in thousands)
2021202020212020
Restricted stock awards:   
Performance stock awards$3,441 $4,059 $(618)$6,723 $8,119 $(1,396)
Service-based stock awards6,543 6,585 (42)14,842 13,962 880 
9,984 10,644 (660)21,565 22,081 (516)
Stock option awards426 416 10 900 914 (14)
Total stock-based compensation cost10,410 11,060 (650)22,465 22,995 (530)
Less amounts capitalized to oil and gas properties(2,532)(4,313)1,781 (6,038)(9,854)3,816 
Stock-based compensation expense$7,878 $6,747 $1,131 $16,427 $13,141 $3,286 

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Periodic stock-based compensation expense will fluctuate based on the grant-date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards. Our accounting policy is to account for forfeitures in compensation cost when they occur. To the extent compensation cost relates to employees directly involved in oil and gas property acquisition, exploration, and development activities, such amounts are capitalized to oil and gas properties. The amount of stock-based compensation cost capitalized to oil and gas properties decreased as a percentage of total stock-based compensation cost during the three and six months ended June 30, 2021 as compared to the three and six months ended June 30, 2020 as a result of decreased acquisition, exploration, and development activities in response to the lower oil prices and demand destruction seen after the first quarter of 2020. The decreased capitalization caused overall stock-based compensation expense to increase.

Loss (Gain) on Derivative Instruments, Net

The following table presents the components of “Loss (gain) on derivative instruments, net” for the periods indicated. See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.
Three Months Ended
June 30,
Variance Between
2021 / 2020
Six Months Ended
June 30,
Variance Between
2021 / 2020
Loss (Gain) on Derivative Instruments, Net (in thousands)
2021202020212020
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts$40,026 $19,826 $20,200 $39,579 $32,319 $7,260 
Oil contracts85,671 168,000 (82,329)185,519 (28,319)213,838 
125,697 187,826 (62,129)225,098 4,000 221,098 
Cash payments (receipts) on derivative instruments, net:
Gas contracts14,403 (5,870)20,273 29,668 (17,589)47,257 
Oil contracts71,733 (58,071)129,804 119,002 (89,466)208,468 
86,136 (63,941)150,077 148,670 (107,055)255,725 
Loss (gain) on derivative instruments, net$211,833 $123,885 $87,948 $373,768 $(103,055)$476,823 

Other Operating Expense, Net

Other operating expense, net during the six months ended June 30, 2021 included $8.1 million in expenses related to the Cabot merger. These expenses were primarily for advisory and legal services. Also included in Other operating expense, net for the three and six months ended June 30, 2021 and 2020 were litigation settlements and allowance for credit losses adjustments.

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Other Income and Expense
Three Months Ended
June 30,
Variance Between
2021 / 2020
Six Months Ended
June 30,
Variance Between
2021 / 2020
Other Income and Expense
(in thousands)
2021202020212020
Interest expense$23,370 $23,047 $323 $46,448 $46,228 $220 
Capitalized interest(11,386)(12,939)1,553 (22,951)(26,121)3,170 
Other, net(459)3,496 (3,955)(598)2,625 (3,223)
$11,525 $13,604 $(2,079)$22,899 $22,732 $167 

The majority of our interest expense relates to interest on the borrowings under our senior unsecured notes, with such interest totaling $21.0 million for the three months ended June 30, 2021 and 2020 and $42.0 million for the six months ended June 30, 2021 and 2020. Also included in interest expense is interest expense on our Credit Facility borrowings, the amortization of debt issuance costs and discounts, interest expense on our finance lease, and miscellaneous interest expense.  See LIQUIDITY AND CAPITAL RESOURCES Long-term Debt below for further information regarding our debt.

We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing midstream assets. Capitalized interest will fluctuate based primarily on the amount of costs subject to interest capitalization and based on the rates applicable to borrowings outstanding during the period. The amount of costs subject to interest capitalization has decreased in the 2021 periods as compared to the 2020 periods, primarily due to the decrease in the balance of non-producing leasehold costs as a result of transfers to proved properties outweighing additions to non-producing leasehold costs.

Components of “Other, net” consist of miscellaneous income and expense items that vary from period to period, including interest income, gain or loss related to the sale or value of oil and gas well equipment and supplies, gain or loss on miscellaneous fixed asset sales, and income and expense associated with other non-operating activities.

Income Tax Expense (Benefit)

The components of our provision for income taxes and our combined federal and state effective income tax rates were as follows:
Three Months Ended
June 30,
Variance Between
2021 / 2020
Six Months Ended
June 30,
Variance Between
2021 / 2020
Income Tax Expense (Benefit)
(in thousands)
2021202020212020
Current tax expense (benefit)$442 $37 $405 $442 $(161)$603 
Deferred tax expense (benefit)34,550 (271,543)306,093 74,720 (287,900)362,620 
$34,992 $(271,506)$306,498 $75,162 $(288,061)$363,223 
Combined federal and state effective income tax rate23.6%22.7%23.7%14.5%

Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 21% primarily due to state income taxes, non-deductible expenses, and changes in valuation allowances. The combined federal and state effective income tax rate for the six months ended June 30, 2020 was impacted by the non-deductible impairment of goodwill recorded during the first quarter 2020. See Note 9 to the Condensed Consolidated Financial Statements for additional information regarding our income taxes.


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LIQUIDITY AND CAPITAL RESOURCES

Overview

With the volatility in commodity prices and recognizing the U.S. oil volume growth impact on the overall world oil supply and demand balance, we have adjusted our approach to our capital reinvestment rates to stay below operating cash flow. With this investment approach, we will have cash flow available to increase cash on our balance sheet, which we plan to initially target to reduce debt and continue to fund and increase our regular common stock cash dividend.

We strive to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include our cash flow from operations, cash on hand, available borrowing capacity under our revolving credit facility, and proceeds from sales of non-core assets.

Our liquidity is highly dependent on the prices we receive for the oil, gas, and NGLs we produce. The prices we receive are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital, and future rate of growth. See RESULTS OF OPERATIONS Revenues above for further information regarding the impact realized prices have had on our earnings.

We address volatility in commodity prices primarily by maintaining flexibility in our capital investment program. We have a balanced and abundant drilling inventory and limited long-term commitments, which enable us to respond quickly to industry volatility. In response to the decline in oil prices in the second quarter of 2020, we took immediate steps to reduce our capital investment, including releasing drilling rigs and deferring well completion activity, which resulted in an immediate reduction in capital investments that continued through 2020, increasing moderately as oil prices improved in the fourth quarter of 2020 and into 2021. We are currently running five drilling rigs and two completion crews. See Capital Expenditures below for information regarding our capital expenditures for the six months ended June 30, 2021 and our plans for annual 2021 capital expenditures.

We periodically use derivative instruments to mitigate volatility in commodity prices. At June 30, 2021, we had derivative contracts covering a portion of our 2021 and 2022 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 derivative positions from current levels. See Note 3 to the Condensed Consolidated Financial Statements for information regarding our derivative instruments.

At June 30, 2021, we had $799.3 million in cash and cash equivalents. At June 30, 2021, our long-term debt consisted of $2.0 billion of senior unsecured notes, with $750 million 4.375% notes due in 2024, $750 million 3.90% notes due in 2027, and $500 million 4.375% notes due in 2029. At June 30, 2021, we had no borrowings and $2.5 million in letters of credit outstanding under our credit facility, leaving an unused borrowing availability of $1.248 billion. We expect the investment approach discussed above will allow us to accumulate cash for the future repayment of debt. See Long-term Debt below for more information regarding our debt.

We may, from time to time, seek to repurchase shares of our outstanding preferred stock through cash repurchases and/or exchanges for equity securities, privately negotiated transactions, or otherwise. Such activities, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. See Note 5 to the Condensed Consolidated Financial Statements for information regarding our preferred stock.

We expect our operating cash flow and other capital resources to be adequate to meet our needs for planned capital expenditures, working capital, debt service, and dividends declared for the next twelve months.

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Analysis of Cash Flow Changes

The following table presents the totals of the major cash flow classification categories from our Condensed Consolidated Statements of Cash Flows for the periods indicated.
 Six Months Ended
June 30,
(in thousands)20212020
Net cash provided by operating activities$766,584 $453,497 
Net cash used by investing activities$(185,145)$(454,614)
Net cash used by financing activities$(55,269)$(49,763)

Net cash provided by operating activities for the six months ended June 30, 2021 was $766.6 million, up $313.1 million, or 69%, from $453.5 million for the six months ended June 30, 2020. The increase in net cash provided by operating activities resulted primarily from increased revenues in the six months ended June 30, 2021 as compared to the six months ended June 30, 2020 due to realized prices increasing for all products. This increase was partially offset by increased net cash payments for settlements of derivative instruments during the six months ended June 30, 2021 as compared to net cash receipts for settlements of derivative instruments during the six months ended June 30, 2020. See RESULTS OF OPERATIONS above for more information regarding changes in revenues and expenses.

Net cash used by investing activities for the six months ended June 30, 2021 and 2020 was $185.1 million and $454.6 million, respectively. The majority of our cash flows used by investing activities are for oil and gas capital expenditures, which totaled $298.3 million and $411.3 million for the six months ended June 30, 2021 and 2020, respectively. In response to the decline in oil prices in the second quarter of 2020, we took immediate steps to reduce our capital investment, including releasing drilling rigs and deferring well completion activity, which resulted in an immediate reduction in capital investments that continued through 2020, increasing moderately as oil prices improved in the fourth quarter of 2020 and into 2021. Net cash used by investing activities also includes other capital expenditures of $5.8 million and $38.1 million for the six months ended June 30, 2021 and 2020, respectively, which are primarily expenditures for midstream assets. The 2021 midstream expenditures decreased from the 2020 midstream expenditures due to the reduction in capital investments post-first quarter of 2020. Also included in net cash used by investing activities are expenditures for acquisitions of oil and gas properties and the proceeds of miscellaneous asset sales, including non-core oil and gas properties and fixed assets. The six months ended June 30, 2021 included $118.7 million in proceeds from the sale of non-core oil and gas properties and related assets in the Permian Basin and Mid-Continent.

Net cash used by financing activities was $55.3 million and $49.8 million during the six months ended June 30, 2021 and 2020, respectively. During the six months ended June 30, 2020, we borrowed and repaid an aggregate of $161.0 million on our credit facility to meet cash requirements as needed. We have not had any credit facility borrowings or repayments during the six months ended June 30, 2021. We declare cash dividends on both our common and preferred stock quarterly and pay those dividends in the quarter following declaration. During the six months ended June 30, 2021, we paid one $0.22 per share dividend and one $0.27 per share dividend on our common stock and two $20.3125 per share dividends on our preferred stock, totaling $51.2 million. During the six months ended June 30, 2020, we paid one $0.20 per share dividend and one $0.22 per share dividend on our common stock and two $20.3125 per share dividends on our preferred stock, totaling $45.2 million. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors. Also included in net cash used by financing activities are finance lease payments, payments of employee income tax withholdings on the net settlement of equity-classified stock awards, financing fee payments, and proceeds from exercise of stock options.

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Capital Expenditures

The following table presents capitalized expenditures for oil and gas property acquisition, exploration, and development activities.
 Three Months Ended
June 30,
Six Months Ended
June 30,
(in thousands)2021202020212020
Acquisitions:  
Proved$— $— $— $7,250 
Unproved— — 310 — 
 — — 310 7,250 
Exploration and development:    
Land and seismic10,074 12,116 22,047 26,040 
Exploration and development186,868 71,666 335,764 306,394 
 196,942 83,782 357,811 332,434 
    
Total acquisition, exploration, and development capital expenditures$196,942 $83,782 $358,121 $339,684 

Amounts in the table above are presented on an accrual basis. Oil and gas capital expenditures and acquisitions of oil and gas properties in the Condensed Consolidated Statements of Cash Flows reflect activities on a cash basis, when payments are made and proceeds received.

Based on current economic conditions, our 2021 total capital expenditures are projected to range from $650 million to $750 million. This includes drilling and completion capital investments of approximately $500 million to $600 million, with the remaining investments being for midstream infrastructure and other, including capitalized G&A and non-producing leasehold. The majority of our planned 2021 drilling and completion capital is expected to be invested in the Permian Basin, with the remainder in the Mid-Continent. We regularly review our capital expenditures throughout the year and will adjust our investments based on increases or decreases in our cash flow. We have the flexibility to adjust our capital expenditures based upon market conditions.

We intend to continue to fund our 2021 capital investment program with cash flow from our operating activities and potential sales of non-core assets. The timing of capital expenditures and the receipt of cash flows do not necessarily match, which may cause us to borrow and repay funds under our credit facility from time to time. See Long-term DebtBank Debt below for further information regarding our credit facility.

The following table reflects wells completed by region during the periods indicated.
 Three Months Ended
June 30,
Six Months Ended
June 30,
 2021202020212020
Gross wells  
Permian Basin44 17 52 52 
Mid-Continent20 14 39 
 53 37 66 91 
Net wells    
Permian Basin21.7 11.1 28.7 30.9 
Mid-Continent0.5 1.4 0.5 1.7 
 22.2 12.5 29.2 32.6 

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As of June 30, 2021, we had 39 gross (12.3 net) wells in the process of being drilled: 30 gross (12.3 net) in the Permian Basin and 9 gross (nil net) in the Mid-Continent region. As of June 30, 2021, we had 88 gross (45.7 net) wells waiting on completion: 75 gross (40.8 net) in the Permian Basin and 13 gross (4.9 net) in the Mid-Continent region. By mid-May 2020, we had released all but one rig and placed completion activities on hold due to economic conditions. Since that time with the stabilization of commodity prices, we have added additional drilling rigs and also began completing wells starting in September 2020. We are currently running five drilling rigs and two completion crews. We maintain flexibility to adjust our activity as conditions change.

We have made, and will continue to make, expenditures to comply with environmental and safety regulations and requirements. These costs are considered a normal recurring cost of our ongoing operations. While we expect pending legislation or regulations to increase the cost of business, we do not anticipate that we will be required to expend amounts that will have a material adverse effect on our financial position or operations, nor are we aware of any pending legislative or regulatory changes that would have a material impact. However, compliance with new legislation and regulations could increase our costs and negatively affect demand for oil or gas and result in a material adverse effect on our financial position or operations. See our Form 10-K for the year ended December 31, 2020, Item 1A Risk Factors, for a description of risks related to current and potential future environmental and safety regulations and requirements that could adversely affect our operations and financial condition.

Long-term Debt

Long-term debt at June 30, 2021 and December 31, 2020 consisted of the following:
 June 30, 2021December 31, 2020
(in thousands)Principal
Unamortized Debt
Issuance Costs
and Discounts (1)
Long-term
Debt, net
Principal
Unamortized Debt
Issuance Costs
and Discounts (1)
Long-term
Debt, net
4.375% Notes due 2024$750,000 $(2,254)$747,746 $750,000 $(2,672)$747,328 
3.90% Notes due 2027750,000 (5,156)744,844 750,000 (5,541)744,459 
4.375% Notes due 2029500,000 (4,259)495,741 500,000 (4,488)495,512 
$2,000,000 $(11,669)$1,988,331 $2,000,000 $(12,701)$1,987,299 
________________________________________
(1)The 4.375% Notes due 2024 were issued at par, therefore, the amounts shown in the table are for unamortized debt issuance costs only. At June 30, 2021, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.0 million and $1.2 million, respectively. At June 30, 2021, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $3.7 million and $0.6 million, respectively. At December 31, 2020, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.3 million and $1.3 million, respectively. At December 31, 2020, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $3.9 million and $0.6 million, respectively.

Bank Debt

On June 3, 2020, we entered into the First Amendment to Amended and Restated Credit Agreement (the “First Amendment”) dated as of February 5, 2019 for our senior unsecured revolving credit facility (“Credit Facility”). The Credit Facility has aggregate commitments of $1.25 billion with an option for us to increase the aggregate commitments to $1.5 billion, and matures on February 5, 2024. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. The First Amendment, among other things: (i) allows up to $3.5 billion of non-cash impairment charge add-backs to Shareholders’ Equity for covenant calculation purposes, (ii) institutes traditional anti-cash hoarding provisions (if borrowings are outstanding under the Credit Facility) at a consolidated cash threshold of $175.0 million, (iii) reduces the priority lien debt basket from 15% of Consolidated Net Tangible Assets (as defined in the credit agreement) to a
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$50.0 million cap, and (iv) adds an acknowledgement and consent to European Union bail-in legislation. As of June 30, 2021, we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $1.248 billion.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR (or an alternate rate determined by the administrative agent for the Credit Facility in accordance with the Credit Facility when LIBOR is no longer available) 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 defined total debt-to-capitalization ratio of no greater than 65%. As of June 30, 2021, we were in compliance with all of the financial and non-financial covenants.

At June 30, 2021 and December 31, 2020, we had $3.6 million and $4.3 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in “Other assets” on our Condensed Consolidated Balance Sheets. These costs are being amortized to interest expense ratably over the life of the Credit Facility.

Senior Notes

In March 2019, we issued $500.0 million aggregate principal amount of 4.375% senior unsecured notes at 99.862% of par to yield 4.392% per annum. These notes are due March 15, 2029 and interest is payable semiannually on March 15 and September 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.50%.

In April 2017, we issued $750.0 million aggregate principal amount of 3.90% senior unsecured notes at 99.748% of par to yield 3.93% per annum. These notes are due May 15, 2027 and interest is payable semiannually on May 15 and November 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.01%.

In June 2014, we issued $750.0 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and interest is payable semiannually on June 1 and December 1. The effective interest rate on these notes, including the amortization of debt issuance costs, is 4.50%.

Our senior unsecured notes are governed by indentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of June 30, 2021.

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Working Capital Analysis

At June 30, 2021, we had a working capital surplus of $243.2 million, an increase of $246.1 million from a working capital deficit of $2.9 million at December 31, 2020. Our working capital surplus increased primarily as a result of the following:

Working Capital Increases

Our cash balance increased by $526.2 million and our accounts receivable increased by $141.7 million, both primarily due to the increase in revenues as a result of improved prices.

Working Capital Decreases

An increase of $226.8 million in our net current derivative liability.

Operations-related accounts payable and accrued liabilities increased by $140.3 million, primarily due to increases in revenue payable and trade accounts payable.

An increase in our exploration and development and midstream capital accruals of $39.8 million due to increased activity.

Accounts receivable are a major component of our working capital and include amounts due from a diverse group of companies comprised of major energy companies, pipeline companies, local distribution companies, and other end-users. We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary. For properties we operate, we have the right to realize amounts due to us from non-operators by netting the non-operators’ share of production revenues from those properties. We routinely assess the recoverability of all material accounts receivable and accrue a reserve to the allowance for credit losses based on our estimation of expected losses over the life of the receivables. Historically, losses associated with uncollectible receivables have not been significant. However, 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, such as the impacts on the industry as a result of the COVID-19 pandemic.

Dividends

A quarterly cash dividend has been paid on our common stock every quarter since the first quarter of 2006. In May 2021, our Board of Directors declared a cash dividend of $0.27 per common share, totaling $27.9 million, which is payable on or before September 1, 2021 to stockholders of record on August 13, 2021. Also in May 2021, our Board of Directors declared a cash dividend of $20.3125 per preferred share, totaling $0.6 million. The dividend was paid in July to preferred stockholders of record on July 1, 2021. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2021, our material off-balance sheet arrangements consisted of operating lease agreements for equipment used in connection with our exploration and development activities with lease terms at commencement of 12 months or less. As an accounting policy, we have elected not to apply the recognition requirements of Topic 842 to these leases. As such, we have not recorded any lease liabilities associated with these leases.

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Contractual Obligations and Material Commitments

At June 30, 2021, we had the following contractual obligations and material commitments:
 Payments Due by Period 
Contractual obligations
(in thousands)
Total07/01/21 -
06/30/22
07/01/22 -
06/30/24
 07/01/24 -
06/30/26
 07/01/26 and Thereafter 
Long-term debt—principal (1)$2,000,000 $— $750,000  $—  $1,250,000  
Long-term debt—interest (1)448,999 81,868 167,875  102,250  97,006  
Operating leases (2)252,001 24,774 111,851  99,254  16,122  
Unconditional purchase obligations (3)16,067 6,560 6,167  3,340  —  
Derivative liabilities382,758 366,591 16,167  —  —  
Asset retirement obligation (4)132,182 12,629 — (4)— (4)— (4)
Other long-term liabilities (5)49,153 5,293 11,315  6,053  26,492  
 $3,281,160 $497,715 $1,063,375  $210,897  $1,389,620  
________________________________________
(1)The interest payments presented above include the accrued interest payable on our long-term debt as of June 30, 2021 as well as future payments calculated using the long-term debt’s fixed rates, stated maturity dates, and principal amounts outstanding as of June 30, 2021. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.
(2)Operating leases include the estimated remaining contractual payments under lease agreements as of June 30, 2021. These lease agreements are primarily comprised of leases for an electric hydraulic fracturing fleet (shown as commencing on June 30, 2022 in the table), commercial real estate, which consists primarily of office space, and compressor equipment.
(3)The unconditional purchase obligations are obligations for firm transportation agreements for gas pipeline capacity.
(4)We have excluded the presentation of the timing of the cash flows associated with our $119.6 million long-term asset retirement obligations because we cannot make a reasonably reliable estimate of the future period of cash settlement. The long-term asset retirement obligation is included in the total asset retirement obligation presented.
(5)Other long-term liabilities include contractual obligations associated with our employee supplemental savings plan, gas balancing liabilities, and other miscellaneous liabilities. All of these liabilities are accrued on our Condensed Consolidated Balance Sheet. The current portion associated with these long-term liabilities is also presented in the table above.

The following discusses various commercial commitments that we have made that may include potential future cash payments. These are not reflected in the table above, unless otherwise noted.

At June 30, 2021, we had estimated commitments of approximately: (i) $224.8 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $4.8 million to finish midstream construction in progress.

At June 30, 2021, we had firm sales contracts to deliver approximately 456.5 Bcf of gas over the next 10.0 years. If we do not deliver this gas, our estimated financial commitment, calculated using the July 2021 index prices, would be approximately $1.433 billion. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no material financial commitment will be due based on our current proved reserves and production levels and our ability to make market purchases to fulfill these volumetric obligations.

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In connection with gas gathering and processing agreements, we have volume commitments over the next 15.0 years. If we do not deliver the committed gas or NGLs, as applicable, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2021, would be approximately $728.6 million. However, we believe no material financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas or oil, as applicable, the estimated maximum amount that would be payable under these commitments, calculated as of June 30, 2021, would be approximately $104.0 million. Of this total, we have accrued a liability of $4.1 million representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points. This accrual is reflected in the table above in Other long-term liabilities. We believe no material financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume water delivery commitments associated with a water services agreement that ends in 2030. If the water volumes are not delivered by us or third parties, the estimated maximum amount that would be payable by us under this commitment, calculated as of June 30, 2021, would be approximately $60.8 million. Of this total, we have accrued a liability of $0.7 million representing the estimated amount we will have to pay due to insufficient forecasted volumes.

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

Taking into account current commodity prices and anticipated levels of production, we believe that our net cash flow generated from operations and our other capital resources will be adequate to meet future obligations.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We consider accounting policies and estimates related to oil and gas reserves, full cost accounting, and income taxes to be critical accounting policies and estimates. These are summarized in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2020.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk including the risk of loss arising from adverse changes in commodity prices and interest rates.

Price Fluctuations

Our major market risk is pricing applicable to our oil, gas, and NGL production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil, gas, and NGL production has been volatile and unpredictable. For the three months ended June 30, 2021, our total production revenue was comprised of approximately 61% oil sales, 19% gas sales, and 20% NGL sales. For the six months ended June 30, 2021, our total production revenue was comprised of approximately 56% oil sales, 25% gas sales, and 19% NGL sales. The following table shows how hypothetical changes in the realized prices we receive for our commodity sales may have impacted revenue for the period indicated.
Impact on Revenue
Change in Realized PriceThree Months Ended
June 30, 2021
Six Months Ended
June 30, 2021
(in thousands)
Oil± $1.00per barrel± $6,616± $12,789
Gas± $0.10per Mcf± $5,316± $10,357
NGL± $1.00per barrel± $6,100± $11,297
± $18,032± $34,443

We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. At June 30, 2021, we had oil and gas derivatives covering a portion of our 2021 and 2022 production, which were recorded as current and non-current assets and liabilities on our Condensed Consolidated Balance Sheet. At June 30, 2021, our oil and gas derivatives had a gross asset fair value of $3.7 million and a gross liability fair value of $382.8 million. See Note 3 to the Condensed Consolidated Financial Statements for additional information regarding our derivative instruments.

While these contracts limit the downside risk of adverse price movements, they may also limit future cash flow from favorable price movements. The following table shows how a hypothetical ± 10% change in the underlying forward prices used to calculate the fair value of our derivatives may have impacted the fair value as of June 30, 2021.
Impact on Fair Value
Change in Forward PriceJune 30, 2021
(in thousands)
Oil-10%$89,090 
Oil+10%$(96,541)
Gas-10%$27,831 
Gas+10%$(28,355)

Interest Rate Risk

At June 30, 2021, our long-term debt consisted of $750 million of 4.375% senior unsecured notes that mature on June 1, 2024, $750 million of 3.90% senior unsecured notes that mature on May 15, 2027, and $500 million of 4.375% senior unsecured notes that mature on March 15, 2029. Because all of our outstanding long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.

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ITEM 4. CONTROLS AND PROCEDURES 

Evaluation of Disclosure Controls and Procedures

Cimarex’s management, under the supervision and with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), has evaluated the effectiveness of Cimarex’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (“Exchange Act”)) as of June 30, 2021. Based on that evaluation, the CEO and CFO concluded that the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods required by the U.S. Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including the CEO and CFO, to allow timely decisions regarding required disclosures.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting that occurred during the fiscal quarter ended June 30, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II
 
ITEM 1. LEGAL PROCEEDINGS

The information set forth under the heading “Litigation” in Note 10 to the Condensed Consolidated Financial Statements is incorporated by reference in response to this item.

ITEM 1A. RISK FACTORS

The following risks and uncertainties, together with other information set forth in this Form 10-Q and our Form 10-K for the year ended December 31, 2020, should be carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties presently unknown to us or currently deemed immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, financial condition, and results of operations, which in turn could negatively impact the value of our securities.

Our business depends on oil and gas pipeline, transportation, and processing facilities, some of which are owned by others.

In addition to the existence of adequate markets, our oil and gas production depends in large part on the proximity and capacity of pipeline systems, as well as storage, processing, transportation, and fractionation facilities, most of which are owned by third parties. Oil, refined products, and gas storage reached historically high levels due to reduced demand from the COVID-19 pandemic, which places price pressure across all commodities. We do not anticipate the inability to transport our commodities; however, should that occur, our production could be curtailed, which would impact drilling plans. Curtailments of production could lead to payment being required where we fail to deliver oil, gas, and NGLs to meet minimum volume commitments. These availability and capacity issues are more likely to occur in remote areas with less established infrastructure, such as our Delaware Basin area where we have significant oil and gas production. Any of these availability or capacity issues, whether resulting from the COVID-19 pandemic, construction delays, government restrictions, such as occurred with the revocation of the permit for the Keystone XL Pipeline on the first day of the Biden administration, weather such as the severe winter storm that impacted Texas and Oklahoma in February 2021, fire, or other reasons, could negatively affect our operations, revenues, and expenses.

Risks Related to the Proposed Merger with Cabot Oil & Gas Corporation (“Cabot”)

Our ability to complete the merger with Cabot is subject to various closing conditions, including approval by our and Cabot’s stockholders.

On May 23, 2021, we entered into a definitive agreement (the “Merger Agreement”) with Cabot, an independent oil and gas company engaged in the development, exploitation, exploration, and production of oil and gas properties concentrated in the Marcellus Shale.

The Merger is subject to a number of conditions to closing as specified in the Merger Agreement. These closing conditions include, among others, (1) the receipt of certain approvals from our stockholders and Cabot stockholders, (2) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), (3) the effectiveness of a registration statement on Form S-4 filed by Cabot for the issuance of common stock to current holders of our common stock, (4) the approval of the listing of the shares of Cabot Common Stock on the NYSE, and (5) the representations and warranties of us and Cabot being true and correct, subject to the materiality standards contained in the Merger Agreement. The HSR Act waiting period expired at 11:59 p.m. Eastern Time on July 14, 2021, and the condition for HSR Act clearance has been satisfied.

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No assurance can be given that the other required conditions to closing will be satisfied. Any delay in completing the Merger could cause the combined company not to realize, or to be delayed in realizing, some or all of the benefits that we and Cabot expect to achieve if the Merger is successfully completed within its expected time frame.

The termination of the Merger Agreement could negatively impact our business or result in our having to pay a termination fee.

If the Merger is not completed for any reason, including as a result of a failure to obtain the required approvals from our or Cabot’s stockholders, our ongoing business may be adversely affected and, without realizing any of the expected benefits of having completed the Merger, we would be subject to a number of risks, including the following:

we may experience negative reactions from the financial markets, including negative impacts on our stock price;

we may experience negative reactions from our commercial partners and employees; and

we will be required to pay our costs relating to the Merger, such as financial advisory, legal, financing and accounting costs and associated fees and expenses, whether or not the Merger is completed.

Additionally, if the Merger Agreement is terminated under certain circumstances, we may be required to pay a termination fee of $250.0 million, including if the proposed Merger is terminated because our Board of Directors has changed its recommendation in respect of the stockholder proposal relating to the Merger. In addition, we may be required to reimburse Cabot for its expenses in an amount equal to $40.0 million if the Merger Agreement is terminated because of a failure of our stockholders to approve the stockholder proposal concerning the merger.

Whether or not the Merger is completed, the announcement and pendency of the Merger could cause disruptions in our business, which could have an adverse effect on our business and financial results.

Whether or not the Merger is completed, the announcement and pendency of the Merger could cause disruptions in our business. Specifically:

our and Cabot’s current and prospective employees will experience uncertainty about their future roles with the combined company, which might adversely affect the two companies’ abilities to retain key managers and other employees;

uncertainty regarding the completion of the Merger may cause our and Cabot’s commercial partners or others that do business with us or Cabot to delay or defer certain business decisions or to decide to seek to terminate, change or renegotiate their relationships with us or Cabot, which could negatively affect our respective revenues, earnings and cash flows;

the Merger Agreement restricts us and our subsidiaries from taking specified actions during the pendency of the Merger without Cabot’s consent, which may prevent us from making appropriate changes to our business or organizational structure or prevent us from pursuing attractive business opportunities or strategic transactions that may arise prior to the completion of the Merger; and

the attention of our and Cabot’s management may be directed toward the completion of the Merger, as well as integration planning, which could otherwise have been devoted to day-to-day operations or to other opportunities that may have been beneficial to our business.

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We have diverted, and will continue to divert, significant management resources in an effort to complete the Merger and are subject to restrictions contained in the Merger Agreement on the conduct of our business. If the Merger is not completed, we will have incurred significant costs, including the diversion of management resources, for which we will have received little or no benefit.

Combining our business with Cabot’s may be more difficult, costly or time-consuming than expected and the combined company may fail to realize the anticipated benefits of the Merger, which may adversely affect the combined company’s business results and negatively affect the value of the combined company’s common stock.

The success of the Merger will depend on, among other things, the ability of the two companies to combine their businesses in a manner that facilitates opportunities to maximize stockholder value and realizes expected cost savings. The combined company may encounter difficulties in integrating our and Cabot’s businesses and realizing the anticipated benefits of the Merger. If the combined company is not able to successfully achieve these objectives, the anticipated benefits of the Merger may not be realized fully, or at all, or may take longer to realize than expected.

The Merger involves the combination of two companies which currently operate, and until the completion of the Merger will continue to operate, as independent public companies. There can be no assurances that our respective businesses can be integrated successfully. It is possible that the integration process could result in the loss of key employees from both companies; the loss of commercial and vendor partners; the disruption of our, Cabot’s or both companies’ ongoing businesses; inconsistencies in standards, controls, procedures and policies; unexpected integration issues; higher than expected integration costs and an overall post-closing integration process that takes longer than originally anticipated. The combined company will be required to devote management attention and resources to integrating its business practices and operations, and prior to the Merger, management attention and resources will be required to plan for such integration.

An inability to realize the full extent of the anticipated benefits of the Merger and the other transactions contemplated by the Merger Agreement, as well as any delays encountered in the integration process, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may adversely affect the value of the common stock of the combined company. In addition, the actual integration may result in additional and unforeseen expenses, and the anticipated benefits of the integration plan may not be realized.

Lawsuits have been filed against Cimarex and its directors in connection with the Merger and additional lawsuits relating to the Merger may be filed against Cimarex and its directors or against Cabot and its directors in the future. An adverse ruling in any such lawsuit could result in an injunction preventing the completion of the Merger and/or substantial costs to Cimarex and Cabot.

Securities and fiduciary lawsuits are often brought against public companies that have entered into acquisition, merger, or other business combination agreements like the Merger Agreement. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on Cimarex’s and Cabot’s respective liquidity and financial condition.

In June and July 2021, four putative stockholders of Cimarex filed separate lawsuits relating to the Merger. Each of the actions is asserted only on behalf of the named plaintiff. All four actions allege violations of Section 14(a) and 20(a) of the Exchange Act and Rule 14a-9 promulgated thereunder based on various alleged omissions of material information from the registration statement on Form S-4 filed in connection with the Merger. One of the actions also alleges claims that the members of the Cimarex board of directors breached fiduciary duties in connection with the Merger and that Cimarex aided and abetted those alleged breaches. Each action names as defendants Cimarex and each of its directors, and seeks, among other things, to enjoin the Merger (or, in the alternative, rescission or an award for rescissory damages in the event the Merger is completed), an award of costs and attorneys’ and experts’ fees, and such other and further relief as the court may deem just and proper. We believe that the actions are without merit.

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One of the conditions to the closing of the Merger is that no injunction by any governmental entity having jurisdiction over Cimarex or Cabot has been entered and continues to be in effect and no law has been adopted, in either case, that prohibits the closing of the Merger. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Merger, that injunction may delay or prevent the Merger from being completed within the expected timeframe or at all, which may adversely affect Cimarex’s and Cabot’s respective businesses, financial condition, cash flows and results of operations. In addition, either Cimarex or Cabot may terminate the Merger Agreement if any governmental entity having jurisdiction over any party has issued any order, decree, ruling or injunction permanently prohibiting the closing of the Merger that has become final and nonappealable, or if any law has been adopted that permanently prohibits the closing of the Merger, so long as the terminating party has not breached any material covenant or agreement under the Merger Agreement that has caused, materially contributed to or resulted in such order, decree, ruling or injunction or other action.

Cimarex can provide no assurance that any of the defendants would be successful in the outcome of the lawsuits that have been filed thus far or any potential future lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Merger is completed may adversely affect Cimarex’s or Cabot’s business, financial condition, cash flows, and results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

The following table sets forth information regarding repurchases of our common stock during the three months ended June 30, 2021. The shares repurchased represent shares of our common stock that employees elected to surrender to satisfy their tax withholding obligations upon the vesting of shares of restricted stock. Cimarex does not consider this a share buyback program.

PeriodTotal number of shares purchasedAverage price paid per shareTotal number of shares purchased as part of publicly announced plans or programsMaximum number of shares that may yet be purchased under the plans or programs
April 1-30, 20211,160 $62.57 — — 
May 1-31, 2021— — — — 
June 1-30, 202130,004 70.62 — — 
     Total31,164 $70.32 — — 
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ITEM 6. EXHIBITS

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith.
Exhibit NumberDescription
101.INSXBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCHInline XBRL Taxonomy Extension Schema Document
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document
101.LABInline XBRL Taxonomy Extension Label Linkbase Document
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

August 6, 2021
  
  
 CIMAREX ENERGY CO.
  
  
 /s/ G. Mark Burford
 G. Mark Burford
 Senior Vice President and Chief Financial Officer
 (Principal Financial Officer)
  
  
 /s/ Timothy A. Ficker
 Timothy A. Ficker
 Vice President, Controller, and Chief Accounting Officer
 (Principal Accounting Officer)

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