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 ended September | June 30, 20172019 |
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.CO.
(Exact name of registrant as specified in its charter)
|
| | | | | |
| Delaware | | 45-0466694 |
| (State ofor other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| | | | | |
| 1700 Lincoln Street, Suite 3700 | Denver | Colorado | | 80203 |
| (Address of principal executive offices) | | (Zip Code) |
(303) (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) | | XEC | | New 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 filer☒ | ☒ | Accelerated filer☐ | ☐ | Non-accelerated filer☐ | ☐ | Smaller reporting company | ☐ |
| | (Do not check if a smaller
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 OctoberJuly 31, 20172019 was 95,260,901.101,457,009.
EXPLANATORY NOTE
The comparative period financial information for 2016 included in this Form 10-Q reflects the corrected financial information for 2016 included under the heading “Supplemental Quarterly Financial Data (Unaudited)” in an amendment to our Annual Report on Form 10-K for the year ended December 31, 2016 (the “Form 10-K/A”) filed with the Securities and Exchange Commission on May 10, 2017 in order to reflect corrections to financial information. For additional information, see the “Explanatory Note” to the Form 10-K/A.
CIMAREX ENERGY CO.
Table of Contents
GLOSSARY
Bbl/dBbls—Barrels per day
Bbls—Barrels
Bcf—Billion cubic feet
BcfeBOE—Billion cubic feetBarrels of oil equivalent
Btu—British thermal unit
Gross Acres or Gross Wells—The total acres or wells as the case may be, in which a working interest is owned.
MBbls—Thousand barrels
MBOE—Thousand barrels of oil equivalent
Mcf—Thousand cubic feet
Mcfe—Thousand cubic feet equivalent
MMBbl/MMBbls—Million barrels
MMBtu—Million British thermal units
MMcf—Million cubic feet
MMcf/d—Million cubic feet per day
MMcfe—Million cubic feet equivalent
MMcfe/d—Million cubic feet equivalent per day
Net Acres or Net Wells—The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.
Net Production—Gross production multiplied by net revenue interest
NGL or NGLs—Natural gas liquids
Tcf—Trillion cubic feet
Tcfe—Trillion cubic feet equivalent
Energy equivalent is determined using the ratio of one barrel of crude oil, condensate, or NGL to six Mcf of natural gasgas.
CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS
Throughout this Form 10-Q, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. These forward-looking statements include, among others, statements concerning our outlook with regard to timing and amount of future production of oil and gas, price realizations, amounts, nature and timing of capital expenditures for exploration and development, plans for funding operations and capital expenditures, drilling of wells, operating costs and other expenses, marketing of oil, gas, and NGLs and other statements of expectations, beliefs, future plans and strategies, anticipated events or trends, and similar expressions concerning matters that are not historical facts. The forward-looking statements in this report are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in or implied by the statements.
These risks and uncertainties include, but are not limited to, fluctuations in the price we receive for our oil and gas production, full cost ceiling test impairments to the carrying values of our oil and gas properties, the effectiveness of our internal control over financial reporting and our ability to remediate a material weakness in our internal control over financial reporting, reductions in the quantity of, and price received for, oil and gas sold due to decreased industry-wide demand and/or curtailments in production from specific properties or areas due to mechanical, transportation, marketing, weather or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated, increased financing costs due to a significant increase in interest rates, and availability of financing.financing, our ability to successfully integrate the business acquired from Resolute Energy Corporation, and the effectiveness of our internal control over financial reporting and our ability to remediate a material weakness in our internal control over financial reporting. In addition, exploration and development opportunities that we pursue may not result in economic, productive oil and gas properties. There are also numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and the timing of development expenditures. These and other risks and uncertainties affecting us are discussed in greater detail in this report and in our other filings with the Securities and Exchange Commission.
PART I
ITEM 1. - Financial Statements
CIMAREX ENERGY CO.
Condensed Consolidated Balance Sheets
(in thousands, except share and per share information)
(Unaudited)
| | | | September 30, | | December 31, | | | | | |
| | 2017 | | 2016 | | June 30, | | December 31, |
| | (in thousands, except share data) | | 2019 | | 2018 |
Assets | | |
| | |
| | |
| | |
|
Current assets: | | |
| | |
| | |
| | |
|
Cash and cash equivalents | | $ | 422,808 |
| | $ | 652,876 |
| | $ | 19,414 |
| | $ | 800,666 |
|
Accounts receivable, net of allowance: | | |
| | |
| | |
| | |
|
Trade | | 101,927 |
| | 42,287 |
| | 111,745 |
| | 122,065 |
|
Oil and gas sales | | 286,602 |
| | 217,395 |
| | 267,821 |
| | 315,063 |
|
Gas gathering, processing, and marketing | | 14,656 |
| | 14,888 |
| | 7,796 |
| | 17,072 |
|
Oil and gas well equipment and supplies | | 54,545 |
| | 33,342 |
| | 58,306 |
| | 55,553 |
|
Derivative instruments | | 6,924 |
| | — |
| | 42,957 |
| | 101,939 |
|
Prepaid expenses | | 3,913 |
| | 7,335 |
| | 8,985 |
| | 7,554 |
|
Other current assets | | 2,757 |
| | 1,181 |
| | 3,032 |
| | 4,227 |
|
Total current assets | | 894,132 |
| | 969,304 |
| | 520,056 |
| | 1,424,139 |
|
Oil and gas properties at cost, using the full cost method of accounting: | | |
| | |
| | |
| | |
|
Proved properties | | 17,071,532 |
| | 16,225,495 |
| | 19,846,426 |
| | 18,566,757 |
|
Unproved properties and properties under development, not being amortized | | 572,651 |
| | 478,277 |
| | 1,564,074 |
| | 436,325 |
|
| | 17,644,183 |
| | 16,703,772 |
| | 21,410,500 |
| | 19,003,082 |
|
Less—accumulated depreciation, depletion, amortization, and impairment | | (14,629,884 | ) | | (14,349,505 | ) | | (15,659,363 | ) | | (15,287,752 | ) |
Net oil and gas properties | | 3,014,299 |
| | 2,354,267 |
| | 5,751,137 |
| | 3,715,330 |
|
Fixed assets, net of accumulated depreciation of $278,991 and $246,901, respectively | | 208,320 |
| | 205,465 |
| |
Fixed assets, net of accumulated depreciation of $356,631 and $324,631, respectively | | | 526,429 |
| | 257,686 |
|
Goodwill | | 620,232 |
| | 620,232 |
| | 727,573 |
| | 620,232 |
|
Derivative instruments | | 129 |
| | — |
| | 613 |
| | 9,246 |
|
Deferred income taxes | | — |
| | 55,835 |
| |
Other assets | | 31,942 |
| | 32,621 |
| | 70,126 |
| | 35,451 |
|
| | $ | 4,769,054 |
| | $ | 4,237,724 |
| | $ | 7,595,934 |
| | $ | 6,062,084 |
|
Liabilities and Stockholders’ Equity | | |
| | |
| |
Liabilities, Redeemable Preferred Stock, and Stockholders’ Equity | | | |
| | |
|
Current liabilities: | | |
| | |
| | |
| | |
|
Accounts payable: | | | | |
| | | | |
|
Trade | | $ | 61,634 |
| | $ | 49,163 |
| | $ | 104,142 |
| | $ | 76,927 |
|
Gas gathering, processing, and marketing | | 27,254 |
| | 25,323 |
| | 14,934 |
| | 29,887 |
|
Accrued liabilities: | | |
| | |
| | |
| | |
|
Exploration and development | | 105,663 |
| | 82,320 |
| | 108,299 |
| | 124,674 |
|
Taxes other than income | | 22,651 |
| | 18,766 |
| | 38,201 |
| | 33,622 |
|
Other | | 215,067 |
| | 177,695 |
| | 250,710 |
| | 221,159 |
|
Derivative instruments | | 5,778 |
| | 49,370 |
| | 50,056 |
| | 27,627 |
|
Revenue payable | | 154,578 |
| | 119,715 |
| | 186,206 |
| | 194,811 |
|
Operating leases | | | 62,119 |
| | — |
|
Total current liabilities | | 592,625 |
| | 522,352 |
| | 814,667 |
| | 708,707 |
|
Long-term debt: | | |
| | |
| |
Principal | | 1,500,000 |
| | 1,500,000 |
| |
Less—unamortized debt issuance costs and discount | | (13,491 | ) | | (12,061 | ) | |
Long-term debt principal | | | 2,000,000 |
| | 1,500,000 |
|
Less—unamortized debt issuance costs and discounts | | | (15,770 | ) | | (11,446 | ) |
Long-term debt, net | | 1,486,509 |
| | 1,487,939 |
| | 1,984,230 |
| | 1,488,554 |
|
Deferred income taxes | | 99,695 |
| | — |
| | 439,429 |
| | 334,473 |
|
Asset retirement obligation | | 144,635 |
| | 140,770 |
| | 157,381 |
| | 152,758 |
|
Derivative instruments | | 212 |
| | 2,570 |
| | 840 |
| | 2,267 |
|
Operating leases | | | 191,413 |
| | — |
|
Other liabilities | | 43,315 |
| | 41,104 |
| | 64,461 |
| | 45,539 |
|
Total liabilities | | 2,366,991 |
| | 2,194,735 |
| | 3,652,421 |
| | 2,732,298 |
|
Commitments and contingencies (Note 10) | |
|
| |
|
| |
|
| |
|
|
Redeemable preferred stock - 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, $0.01 par value, 62,500 shares authorized and issued and no shares authorized and issued, respectively (Note 5) | | | 81,620 |
| | — |
|
Stockholders’ equity: | | |
| | |
| | |
| | |
|
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued | | — |
| | — |
| |
Common stock, $0.01 par value, 200,000,000 shares authorized, 95,260,701 and 95,123,525 shares issued, respectively | | 953 |
| | 951 |
| |
Common stock, $0.01 par value, 200,000,000 shares authorized, 101,473,177 and 95,755,797 shares issued, respectively | | | 1,015 |
| | 958 |
|
Additional paid-in capital | | 2,773,260 |
| | 2,763,452 |
| | 3,223,331 |
| | 2,785,188 |
|
Retained earnings (accumulated deficit) | | (373,955 | ) | | (722,359 | ) | |
Retained earnings | | | 635,339 |
| | 542,885 |
|
Accumulated other comprehensive income | | 1,805 |
| | 945 |
| | 2,208 |
| | 755 |
|
Total stockholders’ equity | | 2,402,063 |
| | 2,042,989 |
| | 3,861,893 |
| | 3,329,786 |
|
| | $ | 4,769,054 |
| | $ | 4,237,724 |
| | $ | 7,595,934 |
| | $ | 6,062,084 |
|
See accompanying Notes to Condensed Consolidated Financial Statements.
5
CIMAREX ENERGY CO.
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
(in thousands, except per share information)
(Unaudited)
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | | | | | | | |
| | 2017 | | 2016 | | 2017 | | 2016 | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | (in thousands, except per share data) | | 2019 | | 2018 | | 2019 | | 2018 |
Revenues: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Oil sales | | $ | 231,441 |
| | $ | 166,079 |
| | $ | 687,960 |
| | $ | 445,657 |
| | $ | 411,766 |
| | $ | 342,184 |
| | $ | 761,072 |
| | $ | 693,907 |
|
Gas sales | | 125,707 |
| | 109,278 |
| | 390,126 |
| | 268,501 |
| |
NGL sales | | 95,191 |
| | 50,464 |
| | 256,503 |
| | 135,755 |
| |
Gas and NGL sales | | | 126,044 |
| | 202,202 |
| | 343,959 |
| | 405,920 |
|
Gas gathering and other | | 11,056 |
| | 9,824 |
| | 32,416 |
| | 25,276 |
| | 9,769 |
| | 11,810 |
| | 20,031 |
| | 23,262 |
|
Gas marketing, net of related costs of $41,978, $32,266, $120,715, and $84,013, respectively | | 286 |
| | 72 |
| | 304 |
| | 1 |
| |
Gas marketing | | | (1,116 | ) | | 78 |
| | (1,642 | ) | | 319 |
|
| | 463,681 |
| | 335,717 |
| | 1,367,309 |
| | 875,190 |
| | 546,463 |
| | 556,274 |
| | 1,123,420 |
| | 1,123,408 |
|
Costs and expenses: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Impairment of oil and gas properties | | — |
| | 105,593 |
| | — |
| | 757,670 |
| |
Depreciation, depletion, and amortization | | 111,396 |
| | 90,277 |
| | 315,096 |
| | 302,999 |
| | 213,327 |
| | 143,388 |
| | 403,744 |
| | 276,247 |
|
Asset retirement obligation | | 1,497 |
| | 2,033 |
| | 4,077 |
| | 6,081 |
| | 2,157 |
| | 2,053 |
| | 4,206 |
| | 3,113 |
|
Production | | 65,410 |
| | 52,976 |
| | 190,409 |
| | 180,891 |
| | 87,726 |
| | 79,215 |
| | 164,959 |
| | 150,486 |
|
Transportation, processing, and other operating | | 58,387 |
| | 48,706 |
| | 172,034 |
| | 139,585 |
| | 48,331 |
| | 51,933 |
| | 101,939 |
| | 97,098 |
|
Gas gathering and other | | 8,856 |
| | 7,905 |
| | 25,930 |
| | 23,477 |
| | 13,605 |
| | 9,467 |
| | 25,925 |
| | 19,290 |
|
Taxes other than income | | 24,314 |
| | 15,974 |
| | 63,104 |
| | 43,879 |
| | 41,033 |
| | 27,930 |
| | 74,727 |
| | 58,118 |
|
General and administrative | | 21,039 |
| | 20,118 |
| | 58,835 |
| | 55,439 |
| | 24,911 |
| | 19,739 |
| | 53,995 |
| | 43,060 |
|
Stock compensation | | 7,038 |
| | 5,764 |
| | 19,619 |
| | 18,782 |
| | 6,494 |
| | 3,095 |
| | 13,207 |
| | 9,825 |
|
(Gain) loss on derivative instruments, net | | 16,109 |
| | (9,758 | ) | | (50,261 | ) | | 23,050 |
| | (40,768 | ) | | 21,699 |
| | 74,684 |
| | 17,540 |
|
Other operating expense, net | | 95 |
| | 179 |
| | 977 |
| | 293 |
| | 590 |
| | 5,252 |
| | 8,916 |
| | 5,455 |
|
| | 314,141 |
| | 339,767 |
| | 799,820 |
| | 1,552,146 |
| | 397,406 |
| | 363,771 |
| | 926,302 |
| | 680,232 |
|
Operating income (loss) | | 149,540 |
| | (4,050 | ) | | 567,489 |
| | (676,956 | ) | |
Operating income | | | 149,057 |
| | 192,503 |
| | 197,118 |
| | 443,176 |
|
Other (income) and expense: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Interest expense | | 16,838 |
| | 20,931 |
| | 57,985 |
| | 62,560 |
| | 24,674 |
| | 16,895 |
| | 45,079 |
| | 33,678 |
|
Capitalized interest | | (5,373 | ) | | (5,421 | ) | | (17,456 | ) | | (15,958 | ) | | (16,805 | ) | | (4,850 | ) | | (25,547 | ) | | (9,660 | ) |
Loss on early extinguishment of debt | | — |
| | — |
| | 28,169 |
| | — |
| | — |
| | — |
| | 4,250 |
| | — |
|
Other, net | | (4,563 | ) | | (3,828 | ) | | (9,004 | ) | | (7,489 | ) | | (2,167 | ) | | (2,605 | ) | | (4,408 | ) | | (7,172 | ) |
Income (loss) before income tax | | 142,638 |
| | (15,732 | ) | | 507,795 |
| | (716,069 | ) | |
Income tax expense (benefit) | | 51,239 |
| | (5,059 | ) | | 188,162 |
| | (259,483 | ) | |
Net income (loss) | | $ | 91,399 |
| | $ | (10,673 | ) | | $ | 319,633 |
| | $ | (456,586 | ) | |
Income before income tax | | | 143,355 |
| | 183,063 |
| | 177,744 |
| | 426,330 |
|
Income tax expense | | | 34,046 |
| | 42,066 |
| | 42,119 |
| | 99,015 |
|
Net income | | | $ | 109,309 |
| | $ | 140,997 |
| | $ | 135,625 |
| | $ | 327,315 |
|
| | | | | | | | | | | | | | | | |
Earnings (loss) per share to common stockholders: | | |
| | |
| | |
| | |
| |
Earnings per share to common stockholders: | | | |
| | |
| | |
| | |
|
Basic | | $ | 0.96 |
| | $ | (0.12 | ) | | $ | 3.36 |
| | $ | (4.90 | ) | | $ | 1.07 |
| | $ | 1.48 |
| | $ | 1.34 |
| | $ | 3.44 |
|
Diluted | | $ | 0.96 |
| | $ | (0.12 | ) | | $ | 3.36 |
| | $ | (4.90 | ) | | $ | 1.07 |
| | $ | 1.48 |
| | $ | 1.34 |
| | $ | 3.44 |
|
| | | | | | | | | | | | | | | | |
Dividends declared per share | | $ | 0.08 |
| | $ | 0.08 |
| | $ | 0.24 |
| | $ | 0.24 |
| |
| | | | | | | | | |
Comprehensive income (loss): | | |
| | |
| | |
| | |
| |
Net income (loss) | | $ | 91,399 |
| | $ | (10,673 | ) | | $ | 319,633 |
| | $ | (456,586 | ) | |
Comprehensive income: | | | |
| | |
| | |
| | |
|
Net income | | | $ | 109,309 |
| | $ | 140,997 |
| | $ | 135,625 |
| | $ | 327,315 |
|
Other comprehensive income: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
Change in fair value of investments, net of tax of $134, $165, $494, and $325, respectively | | 234 |
| | 287 |
| | 860 |
| | 567 |
| |
Total comprehensive income (loss) | | $ | 91,633 |
| | $ | (10,386 | ) | | $ | 320,493 |
| | $ | (456,019 | ) | |
Change in fair value of investments, net of tax of $89, $57, $428 and $1, respectively | | | 304 |
| | 192 |
| | 1,453 |
| | 2 |
|
Total comprehensive income | | | $ | 109,613 |
| | $ | 141,189 |
| | $ | 137,078 |
| | $ | 327,317 |
|
See accompanying Notes to Condensed Consolidated Financial Statements.
6
CIMAREX ENERGY CO.
Condensed Consolidated Statements of Cash Flows
(in thousands)
(Unaudited)
| | | | Nine Months Ended September 30, | | | | | |
| | 2017 | | 2016 | | Six Months Ended June 30, |
| | (in thousands) | | 2019 | | 2018 |
Cash flows from operating activities: | | |
| | |
| | |
| | |
|
Net income (loss) | | $ | 319,633 |
| | $ | (456,586 | ) | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | |
| | |
| |
Impairment of oil and gas properties | | — |
| | 757,670 |
| |
Net income | | | $ | 135,625 |
| | $ | 327,315 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | |
| | |
|
Depreciation, depletion, and amortization | | 315,096 |
| | 302,999 |
| | 403,744 |
| | 276,247 |
|
Asset retirement obligation | | 4,077 |
| | 6,081 |
| | 4,206 |
| | 3,113 |
|
Deferred income taxes | | 188,168 |
| | (258,368 | ) | | 42,119 |
| | 99,732 |
|
Stock compensation | | 19,619 |
| | 18,782 |
| | 13,207 |
| | 9,825 |
|
(Gain) loss on derivative instruments, net | | (50,261 | ) | | 23,050 |
| |
Loss on derivative instruments, net | | | 74,684 |
| | 17,540 |
|
Settlements on derivative instruments | | (2,742 | ) | | 9,718 |
| | (2,814 | ) | | (19,919 | ) |
Loss on early extinguishment of debt | | 28,169 |
| | — |
| | 4,250 |
| | — |
|
Amortization of debt issuance costs and discounts | | | 1,502 |
| | 1,456 |
|
Changes in non-current assets and liabilities | | 2,144 |
| | 4,121 |
| | 2,749 |
| | 713 |
|
Other, net | | 4,630 |
| | 2,931 |
| | 8,152 |
| | 723 |
|
Changes in operating assets and liabilities: | | |
| | |
| | |
| | |
|
Receivables | | (128,921 | ) | | (1,723 | ) | |
Accounts receivable | | | 117,692 |
| | 15,012 |
|
Other current assets | | (19,372 | ) | | 23,034 |
| | (761 | ) | | 1,886 |
|
Accounts payable and other current liabilities | | 75,565 |
| | 9,079 |
| | (140,272 | ) | | (29,304 | ) |
Net cash provided by operating activities | | 755,805 |
| | 440,788 |
| | 664,083 |
| | 704,339 |
|
Cash flows from investing activities: | | |
| | |
| | |
| | |
|
Acquisition of Resolute Energy, net of cash acquired (Note 13) | | | (284,441 | ) | | — |
|
Oil and gas capital expenditures | | (901,949 | ) | | (485,114 | ) | | (711,757 | ) | | (650,807 | ) |
Other capital expenditures | | | (40,141 | ) | | (56,112 | ) |
Sales of oil and gas assets | | 8,136 |
| | 19,013 |
| | 13,233 |
| | 34,842 |
|
Sales of other assets | | 510 |
| | 5,718 |
| | 434 |
| | 525 |
|
Other capital expenditures | | (31,332 | ) | | (24,013 | ) | |
Net cash used by investing activities | | (924,635 | ) | | (484,396 | ) | | (1,022,672 | ) | | (671,552 | ) |
Cash flows from financing activities: | | |
| | |
| | |
| | |
|
Borrowings of long-term debt | | 748,110 |
| | — |
| | 1,710,310 |
| | — |
|
Repayments of long-term debt | | (750,000 | ) | | — |
| | (2,081,000 | ) | | — |
|
Call premium, financing, and underwriting fees | | (29,194 | ) | | (1 | ) | |
Financing, underwriting, and debt redemption fees | | | (11,791 | ) | | — |
|
Finance lease payments | | | (1,555 | ) | | — |
|
Dividends paid | | (22,743 | ) | | (30,243 | ) | | (38,647 | ) | | (22,801 | ) |
Employee withholding taxes paid upon the net settlement of equity-classified stock awards | | (7,637 | ) | | (11,457 | ) | | (654 | ) | | (946 | ) |
Proceeds from exercise of stock options | | 226 |
| | 4,623 |
| | 674 |
| | 1,249 |
|
Net cash used by financing activities | | (61,238 | ) | | (37,078 | ) | | (422,663 | ) | | (22,498 | ) |
Net decrease in cash and cash equivalents | | (230,068 | ) | | (80,686 | ) | |
Net change in cash and cash equivalents | | | (781,252 | ) | | 10,289 |
|
Cash and cash equivalents at beginning of period | | 652,876 |
| | 779,382 |
| | 800,666 |
| | 400,534 |
|
Cash and cash equivalents at end of period | | $ | 422,808 |
| | $ | 698,696 |
| | $ | 19,414 |
| | $ | 410,823 |
|
See accompanying Notes to Condensed Consolidated Financial Statements.
7
CIMAREX ENERGY CO.
Condensed Consolidated StatementStatements of Stockholders’ Equity
(in thousands)
(Unaudited)
| | | | | | | | Additional Paid-in Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive Income | | Total Stockholders’ Equity | | | | | | Additional Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income | | Total Stockholders’ Equity |
| | Common Stock | | Common Stock |
| | Shares | | Amount | | Shares | | Amount |
| | (in thousands) | |
Balance, December 31, 2016 | | 95,124 |
| | $ | 951 |
| | $ | 2,763,452 |
| | $ | (722,359 | ) | | $ | 945 |
| | $ | 2,042,989 |
| |
Balance, December 31, 2018 | | | 95,756 |
| | $ | 958 |
| | $ | 2,785,188 |
| | $ | 542,885 |
| | $ | 755 |
| | $ | 3,329,786 |
|
Dividends paid on stock awards subsequently forfeited | | — |
| | — |
| | 10 |
| | 32 |
| | — |
| | 42 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
Dividends in excess of retained earnings | | — |
| | — |
| | (22,854 | ) | | — |
| | — |
| | (22,854 | ) | |
Dividends declared on common stock ($0.20 per share) | | | — |
| | — |
| | — |
| | (20,308 | ) | | — |
| | (20,308 | ) |
Dividends declared on redeemable preferred stock ($20.31 per share) | | | — |
| | — |
| | — |
| | (1,269 | ) | | — |
| | (1,269 | ) |
Net income | | — |
| | — |
| | — |
| | 319,633 |
| | — |
| | 319,633 |
| | — |
| | — |
| | — |
| | 26,316 |
| | — |
| | 26,316 |
|
Issuance of stock for Resolute Energy acquisition (Note 13) | | | 5,652 |
| | 56 |
| | 412,959 |
| | — |
| | — |
| | 413,015 |
|
Unrealized change in fair value of investments, net of tax | | — |
| | — |
| | — |
| | — |
| | 860 |
| | 860 |
| | — |
| | — |
| | — |
| | — |
| | 1,149 |
| | 1,149 |
|
Issuance of restricted stock awards | | 250 |
| | 3 |
| | (3 | ) | | — |
| | — |
| | — |
| | 11 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Common stock reacquired and retired | | (78 | ) | | (1 | ) | | (7,636 | ) | | — |
| | — |
| | (7,637 | ) | | (10 | ) | | — |
| | (654 | ) | | — |
| | — |
| | (654 | ) |
Restricted stock forfeited and retired | | (39 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Exercise of stock options | | 4 |
| | — |
| | 226 |
| | — |
| | — |
| | 226 |
| | 3 |
| | — |
| | 80 |
| | — |
| | — |
| | 80 |
|
Stock-based compensation | | — |
| | — |
| | 35,698 |
| | — |
| | — |
| | 35,698 |
| | — |
| | — |
| | 13,245 |
| | — |
| | — |
| | 13,245 |
|
Cumulative effect adjustment of adopting ASU 2016-09 (Note 6) | | — |
| | — |
| | 4,393 |
| | 28,739 |
| | — |
| | 33,132 |
| |
Other | | — |
| | — |
| | (26 | ) | | — |
| | — |
| | (26 | ) | |
Balance, September 30, 2017 | | 95,261 |
| | $ | 953 |
| | $ | 2,773,260 |
| | $ | (373,955 | ) | | $ | 1,805 |
| | $ | 2,402,063 |
| |
Balance, March 31, 2019 | | | 101,408 |
| | 1,014 |
| | 3,210,818 |
| | 547,626 |
| | 1,904 |
| | 3,761,362 |
|
Dividends paid on stock awards subsequently forfeited | | | — |
| | — |
| | 1 |
| | 4 |
| | — |
| | 5 |
|
Dividends declared on common stock ($0.20 per share) | | | — |
| | — |
| | — |
| | (20,330 | ) | | — |
| | (20,330 | ) |
Dividends declared on redeemable preferred stock ($20.31 per share) | | | — |
| | — |
| | — |
| | (1,270 | ) | | — |
| | (1,270 | ) |
Net income | | | — |
| | — |
| | — |
| | 109,309 |
| | — |
| | 109,309 |
|
Unrealized change in fair value of investments, net of tax | | | — |
| | — |
| | — |
| | — |
| | 304 |
| | 304 |
|
Issuance of restricted stock awards | | | 54 |
| | 1 |
| | (1 | ) | | — |
| | — |
| | — |
|
Restricted stock forfeited and retired | | | (4 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Exercise of stock options | | | 15 |
| | — |
| | 594 |
| | — |
| | — |
| | 594 |
|
Stock-based compensation | | | — |
| | — |
| | 11,919 |
| | — |
| | — |
| | 11,919 |
|
Balance, June 30, 2019 | | | 101,473 |
| | $ | 1,015 |
| | $ | 3,223,331 |
| | $ | 635,339 |
| | $ | 2,208 |
| | $ | 3,861,893 |
|
See accompanying Notes to Condensed Consolidated Financial Statements.
CIMAREX ENERGY CO.
Condensed Consolidated Statements of Stockholders’ Equity
(in thousands)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Additional Paid-in Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive Income | | Total Stockholders’ Equity |
| Common Stock |
| Shares | | Amount |
Balance, December 31, 2017 | | 95,437 |
| | $ | 954 |
| | $ | 2,764,384 |
| | $ | (199,259 | ) | | $ | 2,199 |
| | $ | 2,568,278 |
|
Dividends paid on stock awards subsequently forfeited | | — |
| | — |
| | 3 |
| | 4 |
| | — |
| | 7 |
|
Dividends declared on common stock ($0.16 per share) | | — |
| | — |
| | (15,271 | ) | | — |
| | — |
| | (15,271 | ) |
Net income | | — |
| | — |
| | — |
| | 186,318 |
| | — |
| | 186,318 |
|
Unrealized change in fair value of investments, net of tax | | — |
| | — |
| | — |
| | — |
| | (190 | ) | | (190 | ) |
Issuance of restricted stock awards | | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Common stock reacquired and retired | | (3 | ) | | — |
| | (305 | ) | | — |
| | — |
| | (305 | ) |
Restricted stock forfeited and retired | | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Exercise of stock options | | 4 |
| | — |
| | 345 |
| | — |
| | — |
| | 345 |
|
Stock-based compensation | | — |
| | — |
| | 12,411 |
| | — |
| | — |
| | 12,411 |
|
Balance, March 31, 2018 | | 95,433 |
| | 954 |
| | 2,761,567 |
| | (12,937 | ) | | 2,009 |
| | 2,751,593 |
|
Dividends paid on stock awards subsequently forfeited | | — |
| | — |
| | 26 |
| | 13 |
| | — |
| | 39 |
|
Dividends declared on common stock ($0.16 per share) | | — |
| | — |
| | 21 |
| | (15,262 | ) | | — |
| | (15,241 | ) |
Net income | | — |
| | — |
| | — |
| | 140,997 |
| | — |
| | 140,997 |
|
Unrealized change in fair value of investments, net of tax | | — |
| | — |
| | — |
| | — |
| | 192 |
| | 192 |
|
Issuance of restricted stock awards | | 27 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Common stock reacquired and retired | | (5 | ) | | — |
| | (641 | ) | | — |
| | — |
| | (641 | ) |
Restricted stock forfeited and retired | | (75 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Exercise of stock options | | 13 |
| | — |
| | 904 |
| | — |
| | — |
| | 904 |
|
Stock-based compensation | | — |
| | — |
| | 8,655 |
| | — |
| | — |
| | 8,655 |
|
Balance, June 30, 2018 | | 95,393 |
| | $ | 954 |
| | $ | 2,770,532 |
| | $ | 112,811 |
| | $ | 2,201 |
| | $ | 2,886,498 |
|
See accompanying Notes to Condensed Consolidated Financial Statements.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20172019
(Unaudited)
The accompanying unaudited financial statements have been prepared by Cimarex Energy Co. (“Cimarex,” “we,” or “us”), a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, and New Mexico. 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 “Explanatory Note”, financial statements, summary of significant accounting policies, and footnotes included in our Annual Report on Form 10-K/A10-K for the year ended December 31, 2016.2018.
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 20172019 financial statement presentation.
On March 1, 2019, we acquired Resolute Energy Corporation (“Resolute”) in a cash and stock transaction. The results of Resolute’s operations have been included in our consolidated financial statements since the March 1, 2019 acquisition date. See Note 13 for more information on this transaction.
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, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, and contingencies.
Oil and Gas Well Equipment and Supplies
Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. We have not recorded an impairment to our oil and gas well equipment and supplies during the nine months ended September 30, 2017. 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. Accounting rules require usAll 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. The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results.
At each quarter-end date
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
We did not recognize a ceiling test impairment during the ninethree and six months ended SeptemberJune 30, 2017,2019 and 2018 because the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we have not recognizedlimitation. However, at June 30, 2019, a ceiling test impairment during the nine months ended September 30, 2017. During the three and nine months ended September 30, 2016, we recognized ceiling test impairments of $105.6 million ($67.1 million, net of tax) and $757.7 million ($481.4 million, net of tax), respectively. These impairments resulted primarily from decreasesdecline in the trailing twelve-month average prices for oil, natural gas, and NGLs utilizedvalue of our ceiling limitation of approximately 4% or more would have resulted in determining the future net revenues from proved reserves. 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.an impairment. If pricing conditions decline,deteriorate, including the further widening of local market basis differentials, or if there is a negative impact on one or more of the other components of the calculation, we may incur full cost ceiling test impairments in future quarters. The calculated ceiling limitation is not intended to be indicative of the fair marketvalue 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.
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, 2019, 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.
Our gas and NGLs are sold under a limited number of contract structure types common in our industry. Under these contracts the gas and its components, including NGLs, may be sold to a single purchaser or the residue gas and NGLs may be sold to separate purchasers. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product. However, depending on the contract structure type, certain transportation, processing, and other charges may be deducted against the prices received for the product. Our oil typically is sold at specific delivery points under contract terms that also are common in our industry.
Gas Gathering
When we transport and/or process 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 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 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.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20172019
(Unaudited)
Recently IssuedLease Accounting Standards
In May 2014,February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-9, Revenue from Contracts with Customers (Topic 606), which is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in this update supersedes the revenue recognition requirements in 2016-02, Leases (“Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. Entities can choose to adopt the standard using either the full retrospective approach or a modified retrospective approach. We intend to adopt the standard utilizing a modified retrospective approach. Management does not expect the new standard will have a material impact on net income (loss) or cash flows from operations; however, we continue to evaluate the “gross versus net” presentation of certain revenues and associated expenses in the consolidated statements of operations and comprehensive income. Any such presentation changes would have no impact on operating income or net income (loss). We are currently developing accounting policies, business processes, and control activities that we expect to implement in connection with the new standard.
In February 2016, the FASB issued ASU 2016-2, Leases (Topic 842)842”). The key provision of this ASU is that a lessee mustFASB subsequently issued various ASUs which provided additional implementation guidance. Topic 842 requires lessees to recognize (i)lease liabilities to make lease payments and (ii) right-of-use assets on itsthe balance sheet. The ASU permitssheet for contracts that provide lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months. Under current generally accepted accounting principles (“GAAP”), a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases. Under this ASU, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease. Leases convey the right to control the use of an identified assetassets for a period of time. The scope of Topic 842 excludes leases to explore for or use minerals, oil, natural gas, and similar nonregenerative resources. We adopted Topic 842 effective January 1, 2019, using the modified retrospective method applied to all leases that existed on that date, which resulted in exchange for consideration. Only the lease components of a contract must be accounted for in accordance with this ASU. Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics. An entity may make a policy election to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component. This ASU retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and comprehensive income and cash flows, however, both types of leases require the recognition of lease liabilities of $276.9 million and right-of-use assets and liabilities on the balance sheet. This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years,of $265.0 million. In connection with early adoption permitted. Upon transition, lessees will be required to recognize and measure leases at the beginningwe made use of the earliest period presented using following practical expedients, which are provided in Topic 842:
a modified retrospective approach. Wepackage of practical expedients to not reassess: 1) whether expired or existing contracts are or contain a lease, 2) lease classification for expired or existing leases, and 3) initial direct costs for existing leases;
an election not to apply the recognition requirements in Topic 842 to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that the process of evaluatingCompany is reasonably certain to exercise);
a practical expedient that permits combining lease and nonlease components in a contract and accounting for the potential impact of adopting this guidance, but believe the primary effect will becombination as a lease (elected by asset class); and
a practical expedient to record assets and liabilities for contracts currently accounted for as operating leases. We do not intendreassess certain land easements in existence prior to adopt the standard early.January 1, 2019.
Long-term debt at SeptemberJune 30, 20172019 and December 31, 20162018 consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
(in thousands) | | Principal | | Unamortized Debt Issuance Costs and Discount (1) | | Long-term Debt, net | | Principal | | Unamortized Debt Issuance Costs | | Long-term Debt, net |
5.875% Senior Notes | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 750,000 |
| | $ | (5,691 | ) | | $ | 744,309 |
|
4.375% Senior Notes | | 750,000 |
| | (5,626 | ) | | 744,374 |
| | 750,000 |
| | (6,370 | ) | | 743,630 |
|
3.90% Senior Notes | | 750,000 |
| | (7,865 | ) | | 742,135 |
| | — |
| | — |
| | — |
|
Total long-term debt | | $ | 1,500,000 |
| | $ | (13,491 | ) | | $ | 1,486,509 |
| | $ | 1,500,000 |
| | $ | (12,061 | ) | | $ | 1,487,939 |
|
| | | | | | | | | | | | |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2019 | | December 31, 2018 |
(in thousands) | | Principal | | Unamortized Debt Issuance Costs and Discounts (1) | | Long-term Debt, net | | Principal | | Unamortized Debt Issuance Costs and Discount (1) | | Long-term Debt, net |
4.375% Notes due 2024 | | $ | 750,000 |
| | $ | (3,982 | ) | | $ | 746,018 |
| | $ | 750,000 |
| | $ | (4,439 | ) | | $ | 745,561 |
|
3.90% Notes due 2027 | | 750,000 |
| | (6,651 | ) | | 743,349 |
| | 750,000 |
| | (7,007 | ) | | 742,993 |
|
4.375% Notes due 2029 | | 500,000 |
| | (5,137 | ) | | 494,863 |
| | — |
| | — |
| | — |
|
| | $ | 2,000,000 |
| | $ | (15,770 | ) | | $ | 1,984,230 |
| | $ | 1,500,000 |
| | $ | (11,446 | ) | | $ | 1,488,554 |
|
| |
(1) | At SeptemberJune 30, 2017,2019, the unamortized debt issuance costs and discount related to the 3.90% notesNotes due 2027 were $6.0$5.1 million and $1.8$1.5 million, respectively. At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.4 million and $1.6 million, respectively. At June 30, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.5 million and $0.7 million, respectively. The 4.375% notesNotes due 2024 were issued at par. |
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20172019
(Unaudited)
Bank Debt
We have a
On February 5, 2019, we entered into an Amended and Restated Credit Agreement for our senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020. The Credit Facility has. Among other things, the amended and restated credit facility increased the aggregate commitments of $1.0to $1.25 billion with an option for us to increase the aggregate commitments to $1.25$1.5 billion, at any time. There is no borrowing base subjectand extended the maturity date to the discretion of the lenders based on the value of our proved reserves under the Credit Facility.February 5, 2024. As of SeptemberJune 30, 2017,2019, 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 $997.5 million.$1.248 billion. During the three months ended June 30, 2019, we borrowed and repaid an aggregate of $528.0 million on the Credit Facility to meet cash requirements as needed.
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-capital ratio of no greater than 65%. As of SeptemberJune 30, 2017,2019, we were in compliance with all of the financial covenants.
At SeptemberJune 30, 20172019 and December 31, 2016,2018, we had $3.6$4.6 million and $4.5$2.2 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. We incurred $3.0 million in additional debt issuance costs in amending our Credit Facility.
Senior Notes
On April 10, 2017,March 8, 2019, we completed a cash tender offer to purchase any of our 5.875% notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5issued $500 million aggregate principal amount of the notes validly tendered. We settled these tendered notes for $268.1 million, including accrued interest. On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for $512.0 million, including accrued interest. During the three months ended June 30, 2017, we recognized a loss on early extinguishment of debt related to these transactions of $28.2 million, composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs. The original maturity date of the 5.875% notes was May 1, 2022.
On April 10, 2017, we issued $750 million aggregate principal amount of 3.90%4.375% senior unsecured notes due MayMarch 15, 20272029 at 99.748%99.862% of par to yield 3.93%4.392% per annum. We received $741.8$494.7 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs. The notes bear an annual interest rate of 4.375% and interest is payable semiannually on March 15 and September 15, with the first payment due September 15, 2019. We used the net proceeds to repay borrowings that were outstanding under our Credit Facility that were used to help fund the Resolute acquisition on March 1, 2019. 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 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, with15. The effective interest rate on these notes, including the first payment to be made November 15, 2017. Along with cash on hand, we used the proceeds to fund the settlementamortization of the tendereddebt issuance costs and redeemed 5.875% notes. discount, is 4.01%.
In June 2014, we issued $750 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%.
Each of our
Our senior unsecured notes isare governed by an indentureindentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of SeptemberJune 30, 2017. The effective interest rate on the 4.375% notes and the 3.90% notes, including the amortization of debt issuance costs and discount, as applicable, is 4.50% and 4.01%, respectively.2019.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(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 revenuescash flow from favorable price changes. We may enter into derivative instruments with durations of five to six quarters covering up to 50% of our oil and natural gas production on a forward eight quarter basis. 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.positions from current levels.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
September 30, 2017
(Unaudited)
As of SeptemberJune 30, 2017,2019, we have entered into oil and gas collars, oil basis swaps, oil and basis swaps.gas fixed price swaps, and sold oil calls. 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 MidlandNYMEX (Cushing Oklahoma) price and the WTI NYMEX (Cushing Oklahoma)Midland price. For our Permian and Mid-Continent gas production, the contract prices in the PEPL and Perm EPour collars are consistent with the index prices used to sell our production. Under our fixed price swaps, we receive the difference between the fixed price and the published index price if the published index price is below the fixed price and we pay the difference between the fixed price and the published index price if the published index price is above the fixed price. Under our sold oil calls, we pay the difference between the fixed price and the published index price if the published index price is above the fixed price. The following tables summarize our outstanding derivative contracts as of SeptemberJune 30, 2017:2019:
| | | | First | | Second | | Third | | Fourth | | | |
| | Quarter | | Quarter | | Quarter | | Quarter | | Total | |
Oil Collars: | | | | | | | | | | |
| |
2017: | | | | | | | | | | |
| |
Oil Collars | | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total |
2019: | | | | | | | | | | | |
|
WTI (1) | | | | | | | | | | |
| | | | | | | | | | |
|
Volume (Bbls) | | — |
| | — |
| | — |
| | 1,932,000 |
| | 1,932,000 |
| | — |
| | — |
| | 3,312,000 |
| | 2,576,000 |
| | 5,888,000 |
|
Weighted Avg Price - Floor | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 46.29 |
| | $ | 46.29 |
| | $ | — |
| | $ | — |
| | $ | 54.28 |
| | $ | 55.50 |
| | $ | 54.81 |
|
Weighted Avg Price - Ceiling | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 56.64 |
| | $ | 56.64 |
| | $ | — |
| | $ | — |
| | $ | 67.88 |
| | $ | 68.36 |
| | $ | 68.09 |
|
2018: | | | | | | | | | | |
| |
2020: | | | | | | | | | | | |
|
WTI (1) | | | | | | | | | | |
| | | | | | | | | | |
|
Volume (Bbls) | | 1,980,000 |
| | 1,456,000 |
| | 1,104,000 |
| | 552,000 |
| | 5,092,000 |
| | 1,820,000 |
| | 1,092,000 |
| | 368,000 |
| | 368,000 |
| | 3,648,000 |
|
Weighted Avg Price - Floor | | $ | 47.05 |
| | $ | 46.94 |
| | $ | 45.92 |
| | $ | 48.00 |
| | $ | 46.87 |
| | $ | 54.90 |
| | $ | 51.50 |
| | $ | 50.00 |
| | $ | 50.00 |
| | $ | 52.89 |
|
Weighted Avg Price - Ceiling | | $ | 56.41 |
| | $ | 55.40 |
| | $ | 54.21 |
| | $ | 53.95 |
| | $ | 55.38 |
| | $ | 68.49 |
| | $ | 63.59 |
| | $ | 62.15 |
| | $ | 62.15 |
| | $ | 65.74 |
|
| | | | | | | | | | | |
| |
(1) | The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”). |
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20172019
(Unaudited)
| | | | First | | Second | | Third | | Fourth | | | |
| | Quarter | | Quarter | | Quarter | | Quarter | | Total | |
Gas Collars: | | | | | | | | | | | |
2017: | | | | | | | | | | | |
Gas Collars | | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total |
2019: | | | | | | | | | | | |
PEPL (1) | | | | | | | | | | | | | | | | | | | | |
Volume (MMBtu) | | — |
| | — |
| | — |
| | 11,040,000 |
| | 11,040,000 |
| | — |
| | — |
| | 12,880,000 |
| | 10,120,000 |
| | 23,000,000 |
|
Weighted Avg Price - Floor | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2.65 |
| | $ | 2.65 |
| | $ | — |
| | $ | — |
| | $ | 1.93 |
| | $ | 1.92 |
| | $ | 1.92 |
|
Weighted Avg Price - Ceiling | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3.07 |
| | $ | 3.07 |
| | $ | — |
| | $ | — |
| | $ | 2.32 |
| | $ | 2.36 |
| | $ | 2.33 |
|
Perm EP (2) | | | | | | | | | | | | | | | | | | | | |
Volume (MMBtu) | | — |
| | — |
| | — |
| | 7,360,000 |
| | 7,360,000 |
| | — |
| | — |
| | 8,280,000 |
| | 5,520,000 |
| | 13,800,000 |
|
Weighted Avg Price - Floor | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2.64 |
| | $ | 2.64 |
| | $ | — |
| | $ | — |
| | $ | 1.46 |
| | $ | 1.38 |
| | $ | 1.43 |
|
Weighted Avg Price - Ceiling | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3.04 |
| | $ | 3.04 |
| | $ | — |
| | $ | — |
| | $ | 1.76 |
| | $ | 1.71 |
| | $ | 1.74 |
|
2018: | | | | | | | | | | | |
Waha (3) | | | | | | | | | | | |
Volume (MMBtu) | | | — |
| | — |
| | 5,520,000 |
| | 5,520,000 |
| | 11,040,000 |
|
Weighted Avg Price - Floor | | | $ | — |
| | $ | — |
| | $ | 1.48 |
| | $ | 1.48 |
| | $ | 1.48 |
|
Weighted Avg Price - Ceiling | | | $ | — |
| | $ | — |
| | $ | 1.82 |
| | $ | 1.82 |
| | $ | 1.82 |
|
2020: | | | | | | | | | | | |
PEPL (1) | | | | | | | | | | | | | | | | | | | | |
Volume (MMBtu) | | 9,000,000 |
| | 6,370,000 |
| | 3,680,000 |
| | 920,000 |
| | 19,970,000 |
| | 7,280,000 |
| | 4,550,000 |
| | 1,840,000 |
| | 1,840,000 |
| | 15,510,000 |
|
Weighted Avg Price - Floor | | $ | 2.62 |
| | $ | 2.50 |
| | $ | 2.45 |
| | $ | 2.50 |
| | $ | 2.54 |
| | $ | 1.93 |
| | $ | 1.91 |
| | $ | 1.85 |
| | $ | 1.85 |
| | $ | 1.91 |
|
Weighted Avg Price - Ceiling | | $ | 3.00 |
| | $ | 2.87 |
| | $ | 2.67 |
| | $ | 2.65 |
| | $ | 2.88 |
| | $ | 2.36 |
| | $ | 2.28 |
| | $ | 2.31 |
| | $ | 2.31 |
| | $ | 2.32 |
|
Perm EP (2) | | | | | | | | | | | | | | | | | | | | |
Volume (MMBtu) | | 6,300,000 |
| | 4,550,000 |
| | 2,760,000 |
| | 920,000 |
| | 14,530,000 |
| | 3,640,000 |
| | 2,730,000 |
| | 1,840,000 |
| | 1,840,000 |
| | 10,050,000 |
|
Weighted Avg Price - Floor | | $ | 2.59 |
| | $ | 2.42 |
| | $ | 2.37 |
| | $ | 2.40 |
| | $ | 2.48 |
| | $ | 1.40 |
| | $ | 1.40 |
| | $ | 1.35 |
| | $ | 1.35 |
| | $ | 1.38 |
|
Weighted Avg Price - Ceiling | | $ | 2.94 |
| | $ | 2.75 |
| | $ | 2.56 |
| | $ | 2.58 |
| | $ | 2.78 |
| | $ | 1.79 |
| | $ | 1.82 |
| | $ | 1.66 |
| | $ | 1.66 |
| | $ | 1.75 |
|
| | | | | | | | | | | |
Waha (3) | | | | | | | | | | | |
Volume (MMBtu) | | | 4,550,000 |
| | 2,730,000 |
| | — |
| | — |
| | 7,280,000 |
|
Weighted Avg Price - Floor | | | $ | 1.50 |
| | $ | 1.57 |
| | $ | — |
| | $ | — |
| | $ | 1.53 |
|
Weighted Avg Price - Ceiling | | | $ | 1.87 |
| | $ | 1.97 |
| | $ | — |
| | $ | — |
| | $ | 1.91 |
|
| |
(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. |
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
| | | | First | | Second | | Third | | Fourth | | | |
| | Quarter | | Quarter | | Quarter | | Quarter | | Total | |
Oil Basis Swaps: | | | | | | | | | | |
| |
2017: | | | | | | | | | | |
| |
Oil Basis Swaps | | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total |
2019: | | | | | | | | | | | |
|
WTI Midland (1) | | | | | | | | | | |
| | | | | | | | | | |
|
Volume (Bbls) | | — |
| | — |
| | — |
| | 460,000 |
| | 460,000 |
| | — |
| | — |
| | 3,266,000 |
| | 3,266,000 |
| | 6,532,000 |
|
Weighted Avg Differential (2) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 0.94 |
| | $ | 0.94 |
| | $ | — |
| | $ | — |
| | $ | (7.36 | ) | | $ | (6.32 | ) | | $ | (6.84 | ) |
2018: | | | | | | | | | | |
| |
2020: | | | | | | | | | | | |
|
WTI Midland (1) | | | | | | | | | | |
| | | | | | | | | | |
|
Volume (Bbls) | | 720,000 |
| | 728,000 |
| | 736,000 |
| | 276,000 |
| | 2,460,000 |
| | 2,093,000 |
| | 1,365,000 |
| | 736,000 |
| | 736,000 |
| | 4,930,000 |
|
Weighted Avg Differential (2) | | $ | 0.87 |
| | $ | 0.87 |
| | $ | 0.87 |
| | $ | 0.76 |
| | $ | 0.86 |
| | $ | 0.16 |
| | $ | 0.19 |
| | $ | 0.71 |
| | $ | 0.71 |
| | $ | 0.33 |
|
| | | | | | | | | | | |
| |
(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 lessplus or minus, as applicable, the weighted average differential shown in the table. |
|
| | | | | | | | | | | | | | | | | | | | |
Oil Swaps | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total |
2019: | | | | | | | | | | |
|
WTI (1) | | | | | | | | | | |
|
Volume (Bbls) | | — |
| | — |
| | 460,000 |
| | 460,000 |
| | 920,000 |
|
Weighted Avg Price | | $ | — |
| | $ | — |
| | $ | 64.54 |
| | $ | 64.54 |
| | $ | 64.54 |
|
| |
(1) | The fixed price on these swaps is NYMEX WTI. |
|
| | | | | | | | | | | | | | | | | | | | |
Gas Swaps | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total |
2019: | | | | | | | | | | |
|
Henry Hub (1) | | | | | | | | | | |
|
Volume (MMBtu) | | — |
| | — |
| | 3,220,000 |
| | 3,220,000 |
| | 6,440,000 |
|
Weighted Avg Price | | $ | — |
| | $ | — |
| | $ | 3.00 |
| | $ | 3.00 |
| | $ | 3.00 |
|
| |
(1) | The fixed price on these swaps is NYMEX Henry Hub. |
|
| | | | | | | | | | | | | | | | | | | | |
Sold Oil Calls | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total |
2019: | | | | | | | | | | |
|
WTI (1) | | | | | | | | | | |
|
Volume (Bbls) | | — |
| | — |
| | 337,640 |
| | 337,640 |
| | 675,280 |
|
Weighted Avg Call Price | | $ | — |
| | $ | — |
| | $ | 64.36 |
| | $ | 64.36 |
| | $ | 64.36 |
|
| |
(1) | The index on these sold calls is NYMEX WTI. |
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20172019
(Unaudited)
The following tables summarizetable summarizes our derivative contracts entered into subsequent to SeptemberJune 30, 2017:2019 through August 1, 2019:
|
| | | | | | | | | | | | | | | | | | | | |
| | First | | Second | | Third | | Fourth | | |
| | Quarter | | Quarter | | Quarter | | Quarter | | Total |
Oil Collars: | | | | | | | | | | |
|
2018: | | | | | | | | | | |
|
WTI (1) | | | | | | | | | | |
|
Volume (Bbls) | | 540,000 |
| | 546,000 |
| | 552,000 |
| | 552,000 |
| | 2,190,000 |
|
Weighted Avg Price - Floor | | $ | 48.00 |
| | $ | 48.00 |
| | $ | 48.00 |
| | $ | 48.00 |
| | $ | 48.00 |
|
Weighted Avg Price - Ceiling | | $ | 55.21 |
| | $ | 55.21 |
| | $ | 55.21 |
| | $ | 55.21 |
| | $ | 55.21 |
|
2019: | | | | | | | | | | |
WTI (1) | | | | | | | | | | |
Volume (Bbls) | | 540,000 |
| | 546,000 |
| | — |
| | — |
| | 1,086,000 |
|
Weighted Avg Price - Floor | | $ | 48.00 |
| | $ | 48.00 |
| | $ | — |
| | $ | — |
| | $ | 48.00 |
|
Weighted Avg Price - Ceiling | | $ | 55.21 |
| | $ | 55.21 |
| | $ | — |
| | $ | — |
| | $ | 55.21 |
|
| | | | | | | | | | |
| |
(1) | The index price for these collars is WTI NYMEX. |
|
| | | | | | | | | | | | | | | | | | | | |
Oil Collars | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter | | Total |
2019: | | | | | | | | | | |
|
WTI | | | | | | | | | | |
|
Volume (Bbls) | | — |
| | — |
| | 368,000 |
| | 368,000 |
| | 736,000 |
|
Wtd Avg Price - Floor | | $ | — |
| | $ | — |
| | $ | 50.00 |
| | $ | 50.00 |
| | $ | 50.00 |
|
Wtd Avg Price - Ceiling | | $ | — |
| | $ | — |
| | $ | 63.45 |
| | $ | 63.45 |
| | $ | 63.45 |
|
2020: | | | | | | | | | | |
|
WTI | | | | | | | | | | |
|
Volume (Bbls) | | 364,000 |
| | 364,000 |
| | 368,000 |
| | 368,000 |
| | 1,464,000 |
|
Wtd Avg Price - Floor | | $ | 50.00 |
| | $ | 50.00 |
| | $ | 50.00 |
| | $ | 50.00 |
| | $ | 50.00 |
|
Wtd Avg Price - Ceiling | | $ | 63.45 |
| | $ | 63.45 |
| | $ | 63.45 |
| | $ | 63.45 |
| | $ | 63.45 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | First | | Second | | Third | | Fourth | | |
| | Quarter | | Quarter | | Quarter | | Quarter | | Total |
Gas Collars: | | | | | | | | | | |
2018: | | | | | | | | | | |
PEPL (1) | | | | | | | | | | |
Volume (MMBtu) | | 1,800,000 |
| | 1,820,000 |
| | 1,840,000 |
| | 1,840,000 |
| | 7,300,000 |
|
Weighted Avg Price - Floor | | $ | 2.40 |
| | $ | 2.40 |
| | $ | 2.40 |
| | $ | 2.40 |
| | $ | 2.40 |
|
Weighted Avg Price - Ceiling | | $ | 2.64 |
| | $ | 2.64 |
| | $ | 2.64 |
| | $ | 2.64 |
| | $ | 2.64 |
|
Perm EP (2) | | | | | | | | | | |
Volume (MMBtu) | | 900,000 |
| | 910,000 |
| | 920,000 |
| | 920,000 |
| | 3,650,000 |
|
Weighted Avg Price - Floor | | $ | 2.30 |
| | $ | 2.30 |
| | $ | 2.30 |
| | $ | 2.30 |
| | $ | 2.30 |
|
Weighted Avg Price - Ceiling | | $ | 2.42 |
| | $ | 2.42 |
| | $ | 2.42 |
| | $ | 2.42 |
| | $ | 2.42 |
|
2019: | | | | | | | | | | |
PEPL (1) | | | | | | | | | | |
Volume (MMBtu) | | 1,800,000 |
| | 1,820,000 |
| | — |
| | — |
| | 3,620,000 |
|
Weighted Avg Price - Floor | | $ | 2.40 |
| | $ | 2.40 |
| | $ | — |
| | $ | — |
| | $ | 2.40 |
|
Weighted Avg Price - Ceiling | | $ | 2.64 |
| | $ | 2.64 |
| | $ | — |
| | $ | — |
| | $ | 2.64 |
|
Perm EP (2) | | | | | | | | | | |
Volume (MMBtu) | | 900,000 |
| | 910,000 |
| | — |
| | — |
| | 1,810,000 |
|
Weighted Avg Price - Floor | | $ | 2.30 |
| | $ | 2.30 |
| | $ | — |
| | $ | — |
| | $ | 2.30 |
|
Weighted Avg Price - Ceiling | | $ | 2.42 |
| | $ | 2.42 |
| | $ | — |
| | $ | — |
| | $ | 2.42 |
|
| | | | | | | | | | |
| |
(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. |
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
September 30, 2017
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | |
| | First | | Second | | Third | | Fourth | | |
| | Quarter | | Quarter | | Quarter | | Quarter | | Total |
Oil Basis Swaps: | | | | | | | | | | |
|
2018: | | | | | | | | | | |
|
WTI Midland (1) | | | | | | | | | | |
|
Volume (Bbls) | | 450,000 |
| | 455,000 |
| | 460,000 |
| | 460,000 |
| | 1,825,000 |
|
Weighted Avg Differential (2) | | $ | 0.47 |
| | $ | 0.47 |
| | $ | 0.47 |
| | $ | 0.47 |
| | $ | 0.47 |
|
2019: | | | | | | | | | | |
|
WTI Midland (1) | | | | | | | | | | |
|
Volume (Bbls) | | 450,000 |
| | 455,000 |
| | — |
| | — |
| | 905,000 |
|
Weighted Avg Differential (2) | | $ | 0.47 |
| | $ | 0.47 |
| | $ | — |
| | $ | — |
| | $ | 0.47 |
|
| | | | | | | | | | |
| |
(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 NYMEX less the weighted average differential shown in the table. |
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 (Gain) loss on derivative instruments, net for the periods indicated.
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
(in thousands) | | 2019 | | 2018 | | 2019 | | 2018 |
(Increase) decrease in fair value of derivative instruments, net: | | |
| | |
| | | | |
Gas contracts | | $ | (6,370 | ) | | $ | 14,566 |
| | $ | (16,216 | ) | | $ | 2,777 |
|
Oil contracts | | (28,161 | ) | | (397 | ) | | 88,086 |
| | (5,156 | ) |
| | (34,531 | ) | | 14,169 |
| | 71,870 |
| | (2,379 | ) |
Cash (receipts) payments on derivative instruments, net: | | |
| | |
| | | | |
Gas contracts | | (21,176 | ) | | (9,918 | ) | | (17,412 | ) | | (15,037 | ) |
Oil contracts | | 14,939 |
| | 17,448 |
| | 20,226 |
| | 34,956 |
|
| | (6,237 | ) | | 7,530 |
| | 2,814 |
| | 19,919 |
|
(Gain) loss on derivative instruments, net | | $ | (40,768 | ) | | $ | 21,699 |
| | $ | 74,684 |
| | $ | 17,540 |
|
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
(Gain) Loss on Derivative Instruments, Net (in thousands): | | 2017 | | 2016 | | 2017 | | 2016 |
Change in fair value of derivative instruments, net | | $ | 19,085 |
| | $ | (8,967 | ) | | $ | (53,003 | ) | | $ | 32,768 |
|
Cash (receipts) payments on derivative instruments, net | | (2,976 | ) | | (791 | ) | | 2,742 |
| | (9,718 | ) |
(Gain) loss on derivative instruments, net | | $ | 16,109 |
| | $ | (9,758 | ) | | $ | (50,261 | ) | | $ | 23,050 |
|
Derivative Fair Value
Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to enforceable master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty. Our 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 SeptemberJune 30, 20172019 and December 31, 2016,2018, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.
|
| | | | | | | | | | |
| | | | June 30, 2019 |
(in thousands) | | Balance Sheet Location | | Asset | | Liability |
Oil contracts | | Current assets — Derivative instruments | | $ | 23,060 |
| | $ | — |
|
Gas contracts | | Current assets — Derivative instruments | | 19,897 |
| | — |
|
Oil contracts | | Non-current assets — Derivative instruments | | 613 |
| | — |
|
Oil contracts | | Current liabilities — Derivative instruments | | — |
| | 50,056 |
|
Oil contracts | | Non-current liabilities — Derivative instruments | | — |
| | 171 |
|
Gas contracts | | Non-current liabilities — Derivative instruments | | — |
| | 669 |
|
Total gross amounts presented in the balance sheet | | 43,570 |
| | 50,896 |
|
Less: gross amounts not offset in the balance sheet | | (23,966 | ) | | (23,966 | ) |
Net amount | | $ | 19,604 |
| | $ | 26,930 |
|
| | | | | | |
| | | | | | |
| | | | December 31, 2018 |
(in thousands) | | Balance Sheet Location | | Asset | | Liability |
Oil contracts | | Current assets — Derivative instruments | | $ | 94,240 |
| | $ | — |
|
Gas contracts | | Current assets — Derivative instruments | | 7,699 |
| | — |
|
Oil contracts | | Non-current assets — Derivative instruments | | 9,246 |
| | — |
|
Oil contracts | | Current liabilities — Derivative instruments | | — |
| | 23,378 |
|
Gas contracts | | Current liabilities — Derivative instruments | | — |
| | 4,249 |
|
Oil contracts | | Non-current liabilities — Derivative instruments | | — |
| | 311 |
|
Gas contracts | | Non-current liabilities — Derivative instruments | | — |
| | 1,956 |
|
Total gross amounts presented in the balance sheet | | 111,185 |
| | 29,894 |
|
Less: gross amounts not offset in the balance sheet | | (29,894 | ) | | (29,894 | ) |
Net amount | | $ | 81,291 |
| | $ | — |
|
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
September 30, 2017
(Unaudited)
|
| | | | | | | | | | |
September 30, 2017: | | | | | | |
(in thousands) | | Balance Sheet Location | | Asset | | Liability |
Oil contracts | | Current assets — Derivative instruments | | $ | 2,288 |
| | $ | — |
|
Gas contracts | | Current assets — Derivative instruments | | 4,636 |
| | — |
|
Oil contracts | | Non-current assets — Derivative instruments | | 110 |
| | — |
|
Gas contracts | | Non-current assets — Derivative instruments | | 19 |
| | — |
|
Oil contracts | | Current liabilities — Derivative instruments | | — |
| | 4,919 |
|
Gas contracts | | Current liabilities — Derivative instruments | | — |
| | 859 |
|
Oil contracts | | Non-current liabilities — Derivative instruments | | — |
| | 210 |
|
Gas contracts | | Non-current liabilities — Derivative instruments | | — |
| | 2 |
|
Total gross amounts presented in the balance sheet | | 7,053 |
| | 5,990 |
|
Less: gross amounts not offset in the balance sheet | | (4,540 | ) | | (4,540 | ) |
Net amount | | | | $ | 2,513 |
| | $ | 1,450 |
|
| | | | | | |
December 31, 2016: | | | | | | |
(in thousands) | | Balance Sheet Location | | Asset | | Liability |
Oil contracts | | Current liabilities — Derivative instruments | | $ | — |
| | $ | 27,892 |
|
Gas contracts | | Current liabilities — Derivative instruments | | — |
| | 21,478 |
|
Oil contracts | | Non-current liabilities — Derivative instruments | | — |
| | 1,059 |
|
Gas contracts | | Non-current liabilities — Derivative instruments | | — |
| | 1,511 |
|
Total gross amounts presented in the balance sheet | | — |
| | 51,940 |
|
Less: gross amounts not offset in the balance sheet | | — |
| | — |
|
Net amount | | | | $ | — |
| | $ | 51,940 |
|
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 havehas 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. Because some of the member banks have discontinued derivative activities, inpositions, 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.
| |
4. | FAIR VALUE MEASUREMENTS |
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
September 30, 2017
(Unaudited)
The following table provides fair value measurement information for certain assets and liabilities as of SeptemberJune 30, 20172019 and December 31, 2016:2018:
|
| | | | | | | | | | | | | | | | |
| | June 30, 2019 | | December 31, 2018 |
(in thousands) | | Book Value | | Fair Value | | Book Value | | Fair Value |
Financial Assets (Liabilities): | | |
| | | | | | |
|
4.375% Notes due 2024 | | $ | (750,000 | ) | | $ | (793,913 | ) | | $ | (750,000 | ) | | $ | (744,578 | ) |
3.90% Notes due 2027 | | $ | (750,000 | ) | | $ | (769,643 | ) | | $ | (750,000 | ) | | $ | (701,273 | ) |
4.375% Notes due 2029 | | $ | (500,000 | ) | | $ | (530,535 | ) | | $ | — |
| | $ | — |
|
Derivative instruments — assets | | $ | 43,570 |
| | $ | 43,570 |
| | $ | 111,185 |
| | $ | 111,185 |
|
Derivative instruments — liabilities | | $ | (50,896 | ) | | $ | (50,896 | ) | | $ | (29,894 | ) | | $ | (29,894 | ) |
|
| | | | | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | Book | | Fair | | Book | | Fair |
(in thousands) | | Value | | Value | | Value | | Value |
Financial Assets (Liabilities): | | |
| | | | | | |
|
5.875% Notes due 2022 | | $ | — |
| | $ | — |
| | $ | (750,000 | ) | | $ | (782,835 | ) |
4.375% Notes due 2024 | | $ | (750,000 | ) | | $ | (794,663 | ) | | $ | (750,000 | ) | | $ | (779,453 | ) |
3.90% Notes due 2027 | | $ | (750,000 | ) | | $ | (764,408 | ) | | $ | — |
| | $ | — |
|
Derivative instruments — assets | | $ | 7,053 |
| | $ | 7,053 |
| | $ | — |
| | $ | — |
|
Derivative instruments — liabilities | | $ | (5,990 | ) | | $ | (5,990 | ) | | $ | (51,940 | ) | | $ | (51,940 | ) |
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 their last traded value before period end.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 price andprices, volatility curves, interest rates, and the strike prices for the instruments.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”Other” at SeptemberJune 30, 2017 are:2019 were accrued operating expenses (e.g. production, transportation, and gathering expenses) of approximately $82.8 million. Included in “Accrued liabilities — Other” at December 31, 2018 were: (i) accrued operating expenses of approximately $59.1$69.1 million, and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $36.2 million. Included in “Accrued liabilities — other” at December 31, 2016 are: (i) accrued operating expenses$47.4 million, and (iii) an accrual of approximately $53.9$35.8 million and (ii) accrued general and administrative, primarily payroll-related, costs of approximately $43.5 million.representing the amount by which checks issued, but not yet presented to our banks, exceeded balances in applicable bank accounts.
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.
We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At SeptemberJune 30, 20172019 and December 31, 2016,2018, the allowance for doubtful accounts was $1.9$3.2 million and $1.6$2.7 million, respectively.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At SeptemberJune 30, 2017,2019, there were 95.3101.5 million shares of common stock and nooutstanding.
From the 15 million shares of preferred stock outstanding. authorized, our Board of Directors created a series of preferred stock designated as 8.125% Series A Cumulative Perpetual Convertible Preferred Stock and authorized 62.5 thousand shares. In March 2019, in conjunction with the Resolute acquisition (see Note 13), we issued 62.5 thousand shares of 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share (the “Convertible Preferred Stock”). Holders of the Convertible Preferred Stock are entitled to receive, when, as, and if declared by the Board out of funds of Cimarex legally available for payment, cumulative cash dividends at the annual rate of 8.125% of each share’s liquidation preference of $1,000. Dividends on the preferred stock are payable quarterly in arrears and accumulate from the most recent date as to which dividends have been paid. In the event of any liquidation, winding up, or dissolution of Cimarex, whether voluntary or involuntary, each holder will be entitled to receive in respect of its shares and to be paid out of the assets of Cimarex legally available for distribution to its stockholders, after satisfaction of liabilities to Cimarex’s creditors and any senior stock (of which there is currently none) and before any payment or distribution is made to holders of junior stock (including common stock), the liquidation preference of $1,000 per share, with the total liquidation preference being $62.5 million in the aggregate. Each holder has the right at any time, at its option, to convert any or all of such holder’s shares of Convertible Preferred Stock at an initial conversion rate of 8.0421 shares of fully paid and nonassessable shares of our common stock and $471.40 in cash per share of Convertible Preferred Stock. Additionally, at any time on or after October 15, 2021, we shall have the right, at our option, if the closing sale price of our common stock meets certain criteria, to elect to cause all, and not part, of the outstanding shares of Convertible Preferred Stock to be automatically converted into that number of shares of Cimarex common stock for each share of Convertible Preferred Stock equal to the conversion rate in effect on the mandatory conversion date as such terms are defined in the Certificate of Designations for the Convertible Preferred Stock and $471.40 in cash per share of Convertible Preferred Stock. As a result of the cash redemption features included in the Convertible Preferred Stock conversion option, with such conversion not solely within our control, the instruments are classified as Redeemable preferred stock in temporary equity on the Condensed Consolidated Balance Sheet.
Dividends
Common Stock
In August 2017,May 2019, our Board of Directors declared a cash dividend of $0.08$0.20 per share.share of common stock. The dividend is payable on or before December 1, 2017,August 30, 2019 to stockholders of record on NovemberAugust 15, 2017.2019. 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 $22.9$20.3 million in dividendsdividend declared year-to-date September 30, 2017 wereduring the second quarter 2019 was recorded as a reduction of additional paid-in capital.retained earnings and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet. Nonforfeitable dividends paid on stock awards that subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to stock compensation
expense in the period in which the forfeitures occur. Future dividend payments will depend on our level of earnings, financingfinancial requirements, and other factors considered relevant by our Board of Directors.
Preferred Stock
In May 2019, our Board of Directors declared a cash dividend of $20.31 per share of Convertible Preferred Stock. The dividend was paid in July to stockholders of record on July 1, 2019. The $1.3 million dividend declared during the second quarter 2019 was recorded as a reduction of retained earnings and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(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) | | 2019 | | 2018 | | 2019 | | 2018 |
Restricted stock awards: | | | | | | | | |
Performance stock awards | | $ | 5,535 |
| | $ | 3,809 |
| | $ | 10,929 |
| | $ | 10,538 |
|
Service-based stock awards | | 5,993 |
| | 4,247 |
| | 13,224 |
| | 9,319 |
|
| | 11,528 |
| | 8,056 |
| | 24,153 |
| | 19,857 |
|
Stock option awards | | 396 |
| | 637 |
| | 1,018 |
| | 1,254 |
|
Total stock compensation cost | | 11,924 |
| | 8,693 |
| | 25,171 |
| | 21,111 |
|
Less amounts capitalized to oil and gas properties | | (5,430 | ) | | (5,598 | ) | | (11,964 | ) | | (11,286 | ) |
Stock compensation expense | | $ | 6,494 |
| | $ | 3,095 |
| | $ | 13,207 |
| | $ | 9,825 |
|
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
(in thousands) | | 2017 | | 2016 | | 2017 | | 2016 |
Restricted stock awards: | | | | | | | | |
Performance stock awards | | $ | 6,508 |
| | $ | 5,465 |
| | $ | 19,348 |
| | $ | 18,374 |
|
Service-based stock awards | | 5,317 |
| | 4,624 |
| | 14,449 |
| | 13,540 |
|
| | 11,825 |
| | 10,089 |
| | 33,797 |
| | 31,914 |
|
Stock option awards | | 698 |
| | 571 |
| | 1,943 |
| | 1,974 |
|
Total stock compensation cost | | 12,523 |
| | 10,660 |
| | 35,740 |
| | 33,888 |
|
Less amounts capitalized to oil and gas properties | | (5,485 | ) | | (4,896 | ) | | (16,121 | ) | | (15,106 | ) |
Compensation expense | | $ | 7,038 |
| | $ | 5,764 |
| | $ | 19,619 |
| | $ | 18,782 |
|
Periodic stock 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. The increase in total stock compensation cost in the 20172019 periods as compared to the 20162018 periods is primarily due to awards granted either during or subsequent to the2016 periods. These increases 2018 periods and performance stock award forfeitures that occurred during the second quarter of 2018, both of which were partially offset by the following decreases: (i) awards vesting prior to or during the 2017 periods, (ii) reversals of previously recognized expense on 2017 forfeitures, and (iii) expense associated with the voluntary Early Retirement Incentive Program during the 2016 periods.
We adopted Accounting Standards Update 2016-9, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-9”) on January 1, 2017. ASU 2016-9 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, accounting for forfeitures, and classification on the statement of cash flows. Pursuant to ASU 2016-9, we made an2019 periods. Our accounting policy electionis to account for forfeitures in compensation cost when they occur, rather than including an estimateoccur.
CIMAREX ENERGY CO.
Notes to vest in our compensation cost. The amendments within ASU 2016-9 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by $33.1 million, reduced beginning accumulated deficit by $28.7 million, and increased beginning additional paid-in capital by $4.4 million. The amendments within ASU 2016-9 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to the payment of tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method. In accordance with this method, we adjusted the statement of cash flows for the nine months ended SeptemberCondensed Consolidated Financial Statements
June 30, 2016 by increasing net cash provided by operating activities by $11.5 million and increasing net cash used by financing activities by $11.5 million for the payment of tax withholdings on the net settlement of equity-classified awards. There were no cash flows related to excess tax benefits during the nine months ended September 30, 2017 and 2016.2019
| |
7. | ASSET RETIREMENT OBLIGATIONS |
We recognize the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the plugging and abandonment of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is accreted each period. If there is a change in the estimated cost or timing of retirement, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are included as a component of the depreciation and depletion calculations.
The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the ninesix months ended SeptemberJune 30, 2017:2019:
|
| | | | |
(in thousands) | | Six Months Ended June 30, 2019 |
Asset retirement obligation at January 1, 2019 | | $ | 166,904 |
|
Liabilities incurred | | 12,611 |
|
Liability settlements and disposals | | (11,771 | ) |
Accretion expense | | 3,714 |
|
Revisions of estimated liabilities | | 2,415 |
|
Asset retirement obligation at June 30, 2019 | | 173,873 |
|
Less current obligation | | (16,492 | ) |
Long-term asset retirement obligation | | $ | 157,381 |
|
|
| | | |
(in thousands) | |
Asset retirement obligation at January 1, 2017 | $ | 154,523 |
|
Liabilities incurred | 5,730 |
|
Liability settlements and disposals | (10,287 | ) |
Accretion expense | 5,637 |
|
Revisions of estimated liabilities | 1,644 |
|
Asset retirement obligation at September 30, 2017 | 157,247 |
|
Less current obligation | (12,612 | ) |
Long-term asset retirement obligation | $ | 144,635 |
|
For the six months ended June 30, 2019, liabilities incurred included $9.4 million for the Resolute acquisition.
| |
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:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
(in thousands, except per share data) | | 2017 | | 2016 | | 2017 | | 2016 |
Basic: | | |
| | |
| | |
| | |
|
Net income (loss) | | $ | 91,399 |
| | $ | (10,673 | ) | | $ | 319,633 |
| | $ | (456,586 | ) |
Participating securities’ share in earnings (1) | | (1,572 | ) | | — |
| | (5,478 | ) | | — |
|
Net income (loss) available to common stockholders | | $ | 89,827 |
| | $ | (10,673 | ) | | $ | 314,155 |
| | $ | (456,586 | ) |
Diluted: | | |
| | |
| | |
| | |
|
Net income (loss) | | $ | 91,399 |
| | $ | (10,673 | ) | | $ | 319,633 |
| | $ | (456,586 | ) |
Participating securities’ share in earnings (1) | | (1,572 | ) | | — |
| | (5,476 | ) | | — |
|
Net income (loss) available to common stockholders | | $ | 89,827 |
| | $ | (10,673 | ) | | $ | 314,157 |
| | $ | (456,586 | ) |
Shares: | | |
| | |
| | |
| | |
|
Basic shares outstanding | | 93,501 |
| | 93,221 |
| | 93,431 |
| | 93,221 |
|
Dilutive effect of potential common shares (2) | | 30 |
| | — |
| | 34 |
| | — |
|
Fully diluted common stock | | 93,531 |
| | 93,221 |
| | 93,465 |
| | 93,221 |
|
Earnings (loss) per share to common stockholders (3): | | |
| | |
| | |
| | |
|
Basic | | $ | 0.96 |
| | $ | (0.12 | ) | | $ | 3.36 |
| | $ | (4.90 | ) |
Diluted | | $ | 0.96 |
| | $ | (0.12 | ) | | $ | 3.36 |
| | $ | (4.90 | ) |
| |
(1) | Participating securities are not included in undistributed earnings when a loss exists. |
| |
(2) | Inclusion of certain shares would have an anti-dilutive effect; therefore, 298.7 thousand and 302.9 thousand shares were excluded from the calculations for the three and nine months ended September 30, 2017 and 2.1 million and 2.1 million shares were excluded from the calculations for the three and nine months ended September 30, 2016. |
| |
(3) | Earnings (loss) per share are based on actual figures rather than the rounded figures presented. |
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
SeptemberJune 30, 20172019
(Unaudited)
The calculations of basic and diluted net earnings per common share under the two-class method are presented below for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, |
| | 2019 | | 2018 |
(in thousands, except per share information) | | Income (Numerator) | | Shares (Denominator) | | Per-Share Amount | | Income (Numerator) | | Shares (Denominator) | | Per-Share Amount |
Net income | | $ | 109,309 |
| | |
| | | | $ | 140,997 |
| | | | |
Less: net income attributable to participating securities | | (1,596 | ) | | | | | | (1,892 | ) | | | | |
Less: preferred stock dividends | | (1,270 | ) | | | | | | — |
| | | | |
Basic earnings per share | | | | | | | | | | | | |
Income available to common stockholders | | 106,443 |
| | 99,658 |
| | $ | 1.07 |
| | 139,105 |
| | 93,728 |
| | $ | 1.48 |
|
Effects of dilutive securities (1) | | | | | | | | | | | | |
Options | | — |
| | 7 |
| | | | — |
| | 31 |
| | |
Diluted earnings per share | | | | | | | | | | | | |
Income available to common stockholders and assumed conversions | | $ | 106,443 |
| | 99,665 |
| | $ | 1.07 |
| | $ | 139,105 |
| | 93,759 |
| | $ | 1.48 |
|
| |
(1) | Inclusion of certain potential common shares would have an anti-dilutive effect, therefore, these shares were excluded from the calculations of diluted earnings per share. Excluded from the three months ended June 30, 2019 calculation were 387.5 thousand potential common shares from the assumed exercise of employee stock options and 502.6 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock. Excluded from the three months ended June 30, 2018 calculation were 292.1 thousand potential common shares from the assumed exercise of employee stock options. |
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, |
| | 2019 | | 2018 |
(in thousands, except per share information) | | Income (Numerator) | | Shares (Denominator) | | Per-Share Amount | | Income (Numerator) | | Shares (Denominator) | | Per-Share Amount |
Net income | | $ | 135,625 |
| | |
| | | | $ | 327,315 |
| | | | |
Less: net income attributable to participating securities | | (2,067 | ) | | | | | | (4,546 | ) | | | | |
Less: preferred stock dividends | | (2,539 | ) | | | | | | — |
| | | | |
Basic earnings per share | | | | | | | | | | | | |
Income available to common stockholders | | 131,019 |
| | 97,800 |
| | $ | 1.34 |
| | 322,769 |
| | 93,713 |
| | $ | 3.44 |
|
Effects of dilutive securities (1) | | | | | | | | | | | | |
Options | | — |
| | 9 |
| | | | 1 |
| | 35 |
| | |
Diluted earnings per share | | | | | | | | | | | | |
Income available to common stockholders and assumed conversions | | $ | 131,019 |
| | 97,809 |
| | $ | 1.34 |
| | $ | 322,770 |
| | 93,748 |
| | $ | 3.44 |
|
| |
(1) | Inclusion of certain potential common shares would have an anti-dilutive effect, therefore, these shares were excluded from the calculations of diluted earnings per share. Excluded from the six months ended June 30, 2019 calculation were 391.1 thousand potential common shares from the assumed exercise of employee stock options and 502.6 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock. Excluded from the six months ended June 30, 2018 calculation were 295.6 thousand potential common shares from the assumed exercise of employee stock options. |
The components of our provision for income taxes areand our combined federal and state effective income tax rates were as follows:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
(in thousands) | | 2019 | | 2018 | | 2019 | | 2018 |
Current tax (benefit) | | $ | — |
| | $ | (717 | ) | | $ | — |
| | $ | (717 | ) |
Deferred tax expense | | 34,046 |
| | 42,783 |
| | 42,119 |
| | 99,732 |
|
| | $ | 34,046 |
| | $ | 42,066 |
| | $ | 42,119 |
| | $ | 99,015 |
|
| | | | | | | | |
Combined federal and state effective income tax rate | | 23.7 | % | | 23.0 | % | | 23.7 | % | | 23.2 | % |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
Income Tax Expense (Benefit) (in thousands): | | 2017 | | 2016 | | 2017 | | 2016 |
Current tax benefit | | $ | — |
| | $ | (1,115 | ) | | $ | (6 | ) | | $ | (1,115 | ) |
Deferred tax expense (benefit) | | 51,239 |
| | (3,944 | ) | | 188,168 |
| | (258,368 | ) |
| | $ | 51,239 |
| | $ | (5,059 | ) | | $ | 188,162 |
| | $ | (259,483 | ) |
Combined federal and state effective income tax rate | | 35.9 | % | | 32.2 | % | | 37.1 | % | | 36.2 | % |
At December 31, 2016,2018, we had a U.S. net tax operating loss carryforward of approximately $1,182.4 million,$1.16 billion, which will expire in tax years 20312032 through 2036.2037. We believe that the carryforward will be utilized before it expires. We also had an alternative minimumenhanced oil recovery and marginal well credits of $3.5 million at December 31, 2018.
On March 1, 2019, the Company completed its acquisition of Resolute. For federal income tax purposes, the acquisition was a tax-free merger whereby the Company acquired carryover tax basis in Resolute’s assets and liabilities. As of March 1, 2019, the Company recorded a net deferred tax liability of $62.4 million associated with the acquired assets. The net deferred tax liability includes certain deferred tax assets net of valuation allowances. The acquired tax attributes include federal net operating loss, capital loss, and enhanced oil recovery tax credit carryforwardcarryforwards. The carryforwards are subject to an annual limitation under Internal Revenue Code Section 382.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
At SeptemberJune 30, 2017,2019, we had no unrecognized tax benefits that would impact our effective tax rate and have made no provisions for interest or penalties related to uncertain tax positions. The tax years 20142016 through 20162018 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 20132015 through 2016.2018.
Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 35%21% primarily due to state income taxes and non-deductible expenses.
| |
10. | COMMITMENTS AND CONTINGENCIES |
Lease Commitments
Effective January 1, 2019, we began accounting for leases in accordance with Topic 842, which requires lessees to recognize lease liabilities and right-of-use assets on the balance sheet for contracts that provide lessees with the right to control the use of identified assets for periods of greater than 12 months. Prior to January 1, 2019, we accounted for leases in accordance with ASC Topic 840, Leases, under which operating leases were not recorded on the balance sheet.
Real Estate Leases
We have operating leases for office space in various locations that provide us the right to control the use of the specified office space over the term of the contract. These leases require us to make monthly “base rent” payments, as well as “additional payments” for our share of operating expenses and taxes incurred by the landlord. At our option, the terms of these leases can be renewed for varying periods, and in some cases may be terminated early at our option. As of June 30, 2019, these leases had remaining lease terms ranging from 4.9 to 7.2 years. These leases do not contain residual value guarantees, options to purchase the underlying office space, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of office space.
Lease liabilities associated with our real estate leases were recorded at the present value of the future lease payments, after considering the following:
“Base rent” payments are considered fixed lease payments, while “additional payments” are considered variable lease payments.
At Septembercommencement of each real estate lease we were not reasonably certain to exercise the option to renew or terminate such lease.
The discount rate used to calculate each lease liability was based on our incremental borrowing rate, which was estimated utilizing trading metrics for our senior unsecured notes as adjusted using relevant market factors to develop a synthetic secured yield curve.
As an accounting policy we have elected not to separate nonlease components from lease components for our real estate class of assets.
Where applicable, we determined that the effect of accounting for the right to use land separately from other lease components would be insignificant.
Production-Related Leases
We have operating leases for equipment used in connection with our oil and gas production operations, including well-head compressors, pipeline compressors, and artificial lift mechanisms. These leases provide us the right to control the use of explicitly or implicitly identified equipment during the term of the contract. These leases often include an “evergreen” provision that allows the contract term to continue on a month-to-month basis following expiration of the initial term stated in the contract. As of June 30, 2017,2019, these leases had remaining lease terms ranging from one month to 11.3 years. These leases require us to make monthly payments of fixed amounts, which cover the
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
cost of renting the equipment and, in some cases, the cost of maintaining the leased equipment. These leases do not typically require us to make variable lease payments. These leases do not contain residual value guarantees, options to purchase the underlying equipment, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of production-related equipment.
Lease liabilities associated with our production-related operating leases were recorded at the present value of the future lease payments, after considering the following:
For leases with an evergreen provision, the term of the lease was determined to be the noncancellable period in the contract plus the period beyond the noncancellable period that we believe it is reasonably certain we will need the equipment for operational purposes, limited to the point in time at which both we and the lessor each have the right to terminate the lease without permission from the other party with no more than an insignificant penalty.
The discount rate used to calculate each lease liability was based on our incremental borrowing rate, which was estimated utilizing trading metrics for our senior unsecured notes as adjusted using relevant market factors to develop a synthetic secured yield curve.
As an accounting policy we have elected not to separate nonlease components from lease components for our production-related class of assets.
We have one finance lease, which results from a gathering agreement (the “Gathering Agreement”) on a gathering system. Under terms of the Gathering Agreement, we have the option to acquire a portion of the underlying gathering system upon termination of the Gathering Agreement. We make monthly payments under the Gathering Agreement based on the volume of oil gathered and a gathering rate per barrel, which is adjusted periodically. As of June 30, 2019, this lease had a remaining term of 6.2 years.
Exploration and Development-Related Leases
We have operating leases for equipment used in connection with our exploration and development activities, including drilling rigs, pressure pumping equipment, directional drilling tools, well-control devices, and various pieces of support equipment. These leases provide us the right to control the use of explicitly or implicitly identified equipment during the term of the contract. As of June 30, 2019, these leases had remaining lease terms of 12 months or less. These leases typically require us to make payments in amounts based on the usage of the underlying equipment. These leases do not contain residual value guarantees, options to purchase the underlying equipment, or terms or covenants that impose restrictions on our ability to pay dividends, incur debt, or enter into additional leases. We have no subleases of exploration and development-related equipment.
As an accounting policy we have elected not to apply the recognition requirements of Topic 842 to our exploration and development-related class of assets with lease terms at commencement of 12 months or less. As such, we have not recorded any lease liabilities associated with our exploration and development-related leases. In addition, as an accounting policy we have elected not to separate nonlease components from lease components for our exploration and development-related class of assets.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
Balance Sheet Presentation
The following tables present the amounts and classifications of our right-of-use assets and estimated lease liabilities as of June 30, 2019:
|
| | | | | | |
(in thousands) | | Balance Sheet Location | | June 30, 2019 |
Operating lease right-of-use assets | | Non-current assets — Fixed assets, net | | $ | 243,089 |
|
Finance lease right-of-use asset | | Non-current assets — Other assets | | 27,042 |
|
Total right-of-use assets | | $ | 270,131 |
|
|
| | | | | | |
(in thousands) | | Balance Sheet Location | | June 30, 2019 |
Operating lease liabilities — current | | Current liabilities — Operating leases | | $ | 62,119 |
|
Operating lease liabilities — non-current | | Non-current liabilities — Operating leases | | 191,413 |
|
Finance lease liability — current | | Current liabilities — Accrued liabilities-Other | | 6,576 |
|
Finance lease liability — non-current | | Non-current liabilities — Other liabilities | | 21,895 |
|
Total lease liabilities | | $ | 282,003 |
|
Lease Cost and Cash Flows
The following table summarizes estimated total lease cost, which includes amounts recognized in income and amounts capitalized for the indicated period:
|
| | | | | | | | |
(in thousands) | | Three Months Ended June 30, 2019 | | Six Months Ended June 30, 2019 |
Finance lease cost: | | | | |
Amortization of right-of-use asset | | $ | 1,097 |
| | $ | 2,193 |
|
Interest on lease liability | | 457 |
| | 943 |
|
Operating lease cost: (1) | | | | |
Production expense | | 3,943 |
| | 7,777 |
|
Gas gathering and other expense | | 6,522 |
| | 12,686 |
|
General and administrative expense | | 2,335 |
| | 4,634 |
|
Short-term lease cost (2) | | 162,334 |
| | 317,044 |
|
Total lease cost | | $ | 176,688 |
| | $ | 345,277 |
|
| |
(1) | Operating lease cost in the table above is composed of costs incurred under real estate and production-related leases. These costs are included in the indicated captions on the Condensed Consolidated Statements of Operations. |
| |
(2) | Short-term lease cost in the table above is composed of costs incurred under leases with terms of 12 months or less for right-of-use assets used in exploration and development activities. Payments under such leases are typically based on usage of the underlying right-of-use asset and, therefore, are also variable lease payments. These costs are capitalized as part of proved properties on the Condensed Consolidated Balance Sheet. |
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
The following table summarizes estimated cash paid for our leases for the indicated period:
|
| | | | |
(in thousands) | | Six Months Ended June 30, 2019 |
Cash paid for amounts included in the measurement of lease liabilities: | | |
Financing cash outflows from finance lease | | $ | 1,555 |
|
Operating cash outflows from operating leases | | $ | 25,466 |
|
| | |
Cash paid for short-term leases and variable lease payments: | | |
Investing cash outflows from operating leases | | $ | 309,150 |
|
During the six months ended June 30, 2019, we recognized $49.1 million in right-of-use assets in connection with new operating leases entered into during the period.
Lease Liability Maturity Analysis
The following table presents the weighted-average remaining lease terms and discount rates of our leases as of the indicated date:
|
| | | |
| | June 30, 2019 |
Weighted-average remaining lease term (in years): | | |
Finance lease | | 6.2 |
|
Operating leases | | 4.5 |
|
| | |
Weighted-average discount rate: | | |
Finance lease | | 6.5 | % |
Operating leases | | 4.0 | % |
The following table reflects the undiscounted future cash flows utilized in the calculation of the lease liabilities recorded at June 30, 2019:
|
| | | | | | | | |
| | June 30, 2019 |
(in thousands) | | Operating Leases | | Finance Lease |
July 1, 2019 — June 30, 2020 | | $ | 72,320 |
| | $ | 6,802 |
|
July 1, 2020 — June 30, 2021 | | 64,198 |
| | 5,846 |
|
July 1, 2021 — June 30, 2022 | | 58,280 |
| | 5,562 |
|
July 1, 2022 — June 30, 2023 | | 45,166 |
| | 5,279 |
|
July 1, 2023 — June 30, 2024 | | 21,977 |
| | 4,995 |
|
Remaining periods | | 18,814 |
| | 5,469 |
|
Total undiscounted future cash flows | | 280,755 |
| | 33,953 |
|
Less effects of discounting | | (27,223 | ) | | (5,482 | ) |
Lease liabilities recognized | | $ | 253,532 |
| | $ | 28,471 |
|
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
As of December 31, 2018 the following future minimum cash payments were required under leases for office space:
|
| | | | |
(in thousands) | | December 31, 2018 |
2019 | | $ | 9,849 |
|
2020 | | 10,790 |
|
2021 | | 11,000 |
|
2022 | | 11,130 |
|
2023 | | 11,433 |
|
Remaining periods | | 20,831 |
|
Total future minimum lease payments | | $ | 75,033 |
|
In addition, as of December 31, 2018, we had various contractual commitments for compressor equipment under operating lease arrangements totaling $34.8 million with lease terms expiring over 1 - 35 months.
Other Commitments
At June 30, 2019, we had estimated commitments of approximately: (i) $181.2$304.6 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $24.6$19.2 million to finish gathering system construction in progress.
At SeptemberJune 30, 2017,2019, we had firm sales contracts to deliver approximately 207.2290.7 Bcf of natural gas over the next 7.35.6 years. If we do not deliver this gas, our estimated financial commitment, calculated using the October 2017July 2019 index price, would be approximately $491.0$303.3 million. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.
In connection with gas gathering and processing agreements, we have volume commitments over the next 8.69.5 years. If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of SeptemberJune 30, 2017,2019, would be approximately $312.3$655.2 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these 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, the estimated maximum amount that would be payable under these commitments, calculated as of SeptemberJune 30, 2017,2019, would be approximately $13.7$153.3 million. Of this total, we have accrued a liability of $1.9$4.6 million, representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.
At SeptemberJune 30, 2017,2019, we have various firm transportation agreements for gas and oil pipeline capacity with end dates ranging from 20172020 - 20252028 under which we will have to pay an estimated $37.6$70.5 million over the remaining terms of the agreements. These agreements were entered into to support our residue gas and oil marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation.
We have various future commitments for office space under operating lease arrangements totaling approximately $89.6 million at September 30, 2017.
All of the noted commitments were routine and made in the ordinary course of our business.
Litigation
We have various litigation matters related to the ordinary course of our business. We assess the probability of estimable amounts related to these matters in accordance with guidance established by the FASB and adjust our
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
accruals accordingly. Though some of the related claims may be significant, we believe the resolution of them, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals.
| |
11. | SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
(in thousands) | | 2019 | | 2018 | | 2019 | | 2018 |
Cash paid during the period for: | | |
| | |
| | |
| | |
|
Interest (net of capitalized amounts of $19,381, $9,233, $20,121 and $9,389, respectively) (1) | | $ | 14,396 |
| | $ | 22,954 |
| | $ | 32,984 |
| | $ | 23,343 |
|
Income taxes | | $ | 1,200 |
| | $ | — |
| | $ | 1,206 |
| | $ | — |
|
Cash received for income tax refunds | | $ | 335 |
| | $ | 717 |
| | $ | 336 |
| | $ | 718 |
|
| |
(1) | The six months ended June 30, 2019 includes $17.6 million in interest paid upon the redemption of Resolute’s senior notes and credit facility on March 1, 2019. |
| |
12. | RELATED PARTY TRANSACTIONS |
Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to Cimarex. Cimarex incurred drilling costs of approximately $22.1 million and $46.6 million related to these services during the three and six months ended June 30, 2019 and $16.4 million and $40.0 million during the three and six months ended June 30, 2018. The amount incurred in 2019 is included in the short-term lease costs disclosed in Note 10. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.
On March 1, 2019, we completed the acquisition of Resolute Energy Corporation, an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the Permian Basin of west Texas. The principal factors considered by management in making this acquisition included: (i) our expectation that the acquired assets’ attractive returns are competitive with those in our existing portfolio, (ii) the opportunity to apply our experience and learnings from already operating in this area to generating productivity gains from the acquired properties, (iii) the ability to increase our acreage position in the Delaware Basin, and (iv) the expectation that the acquisition will be financially accretive.
We acquired 100% of the outstanding common shares and voting interests of Resolute in a cash and stock transaction. The acquisition date fair value of the consideration transferred totaled $820.3 million, which consisted of cash, common stock, and a newly created series of preferred stock (see Note 5 for more information on the preferred stock) as follows:
|
| | | | |
(in thousands) | | Fair Value of Consideration Transferred |
Cash | | $ | 325,677 |
|
Common stock (5,652 shares issued) | | 413,015 |
|
Preferred stock (63 shares issued) | | 81,620 |
|
| | $ | 820,312 |
|
The fair value of the common stock issued as part of the consideration was determined on the basis of the closing market price of Cimarex common stock on the acquisition date. The fair value of the preferred stock issued as part of the consideration was determined using a multiple probability simulation model.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
(in thousands) | | 2017 | | 2016 | | 2017 | | 2016 |
Cash paid for: | | |
| | |
| | |
| | |
|
Interest expense (net of capitalized amounts of $477, $286, $12,439, and $10,343, respectively) | | $ | 109 |
| | $ | 527 |
| | $ | 28,881 |
| | $ | 30,204 |
|
Income taxes | | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | 13 |
|
Cash income tax refunds received | | $ | — |
| | $ | 1,115 |
| | $ | 21 |
| | $ | 1,140 |
|
Preliminary Purchase Price Allocation
The Resolute acquisition has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the Resolute purchase price to the identifiable assets acquired and liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded to goodwill. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, finalization of the fair value of certain assets and liabilities, including pre-acquisition working capital balances and completion of the final Resolute tax returns that will provide the underlying tax basis of Resolute’s assets and liabilities and net operating losses. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.
The following table sets forth the preliminary purchase price allocation:
21 |
| | | | |
(in thousands) | | March 1, 2019 |
Cash | | $ | 41,236 |
|
Accounts receivable | | 50,739 |
|
Other current assets | | 13,280 |
|
Proved oil and gas properties | | 692,600 |
|
Unproved oil and gas properties | | 1,054,200 |
|
Fixed assets | | 5,355 |
|
Goodwill | | 107,341 |
|
Other assets | | 142 |
|
Current liabilities | | (202,735 | ) |
Long-term debt | | (870,000 | ) |
Deferred income taxes | | (62,409 | ) |
Asset retirement obligation | | (9,437 | ) |
Total identifiable net assets | | $ | 820,312 |
|
In connection with the acquisition, we assumed, and immediately repaid, $870.0 million principal amount of long-term debt consisting of $600.0 million of senior notes and $270.0 million of credit facility borrowings. On March 1, 2019, we repaid Resolute’s credit facility borrowings, delivered a notice of optional redemption of Resolute’s senior notes for an April 1, 2019 redemption date, and irrevocably deposited with a trustee the full amount of funds to repay the aggregate outstanding senior notes principal balance plus accrued and unpaid interest, incurring a $4.3 million loss on early extinguishment of debt. The cash consideration transferred and the repayment of Resolute’s long-term debt was funded using cash on hand and borrowings on our Credit Facility. We subsequently repaid the borrowings on our Credit Facility using the net proceeds from the March 8, 2019 issuance of $500 million aggregate principal amount of 4.375% senior unsecured notes (see Note 2 for more information on our debt issuance).
Goodwill of $107.3 million has been recognized principally as a result of recording net deferred tax liabilities arising from the difference between the tax basis and the purchase price allocated to Resolute’s assets and liabilities, and anticipated opportunities for cost savings through administrative and operational synergies. Goodwill is not expected to be deductible for tax purposes.
Acquisition-related costs incurred in 2019 were $8.4 million. These costs, which are comprised primarily of advisory, legal, and other professional and consulting fees, are included in the Other operating expense, net line item on our Condensed Consolidated Statements of Operations and Comprehensive Income.
CIMAREX ENERGY CO.
Notes to Condensed Consolidated Financial Statements
June 30, 2019
(Unaudited)
The results of Resolute’s operations have been included in our consolidated financial statements since the March 1, 2019 acquisition date. The amount of revenue and direct operating expenses resulting from the acquisition included in our Condensed Consolidated Statements of Operations and Comprehensive Income from March 1, 2019 through June 30, 2019 is $100.0 million and $21.9 million, respectively.
Pro Forma Financial Information
The following supplemental pro forma information for the three and six month periods ended June 30, 2019 and 2018 has been prepared to give effect to the Resolute acquisition as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of the combined company’s proved oil and gas properties, (ii) the capitalization of interest expense, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by Cimarex of $8.4 million and transaction-related costs incurred by Resolute of $60.0 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by Cimarex to integrate the Resolute assets. The pro forma financial data has not been adjusted to reflect any other acquisitions or dispositions made during the periods presented as their results were not deemed material.
The pro forma information is not necessarily indicative of the results that might have occurred had the transaction actually taken place on January 1, 2018 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities, and other factors.
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
(in thousands) | | 2019 | | 2018 | | 2019 | | 2018 |
Revenue | | $ | 546,463 |
| | $ | 625,332 |
| | $ | 1,176,556 |
| | $ | 1,263,410 |
|
Net income | | $ | 109,365 |
| | $ | 148,486 |
| | $ | 121,909 |
| | $ | 335,544 |
|
Net income per share: | | | | | | | | |
Basic | | $ | 1.07 |
| | $ | 1.48 |
| | $ | 1.18 |
| | $ | 3.33 |
|
Diluted | | $ | 1.07 |
| | $ | 1.47 |
| | $ | 1.18 |
| | $ | 3.33 |
|
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Cimarex is an independent oil and gas exploration and production company. Our operations are entirely located in the United States, mainly in Oklahoma, Texas, and New Mexico. Currently our operations are focused in two main areas: the Permian Basin and the Mid-Continent region.Mid-Continent. Our Permian Basin region encompasses west Texas and southeast New Mexico. Our Mid-Continent region consists of Oklahoma and the Texas Panhandle.
Our principal business objective is to profitably growincrease shareholder value through the profitable long-term growth of our proved reserves and production while seeking to minimize our impact on the communities in which we operate for the long-term benefit of our stockholders through a balanced and abundant drilling inventory.long-term. Our strategy centers on maximizing cash flow from producing properties and profitably reinvestingso that cash flowwe can reinvest in exploration and development activities.opportunities and provide cash returns to shareholders through dividends. We consider property acquisitions, dispositions,merger and occasional mergers toacquisition opportunities that enhance our competitive position.position and we occasionally divest non-core assets.
On March 1, 2019, we completed the acquisition of Resolute Energy Corporation (“Resolute”), an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the Permian Basin of west Texas. The principal factors considered by management in making this acquisition included: (i) our expectation that the acquired assets’ attractive returns are competitive with those in our existing portfolio, (ii) the opportunity to apply our experience and learnings from already operating in this area to generating productivity gains from the acquired properties, (iii) the ability to increase our acreage position in the Delaware Basin, and (iv) the expectation that the acquisition will be financially accretive. The acquisition date fair value of the consideration transferred totaled $820.3 million, which consisted of cash, common stock, and preferred stock (see Note 13 to the Condensed Consolidated Financial Statements for more information on the acquisition).
We believe that detailed technical analysis, operational focus, and a disciplined capital investment process mitigate risk and position 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-strategicnon-core assets, and, occasionalfrom time to time, public financing based on our monitoring of capital markets and our balance sheet. Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand fluctuations in commodity prices.
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.
Oil prices have improved from early 2016; however, they continue to be volatile and we expect this volatility to persist. For the first nine months of 2017, average NYMEX oil and gas prices were $49.46 per barrel and $3.17 per Mcf, respectively, representing an increase of 20% and 39%, respectively, from the NYMEX prices for the same period in 2016. Further, localLocal market prices for oil and gas can be impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials. The
As demonstrated in the table below, our company-wide average realized prices for the three and six months ended June 30, 2019 as compared to the same periods in 2018 have declined for all products. In the case of oil sales, these decreases result from a combination of declining NYMEX prices in the 2019 periods and differentials in our Mid-Continent region, which deteriorated in the 2019 periods, and differentials in our Permian Basin andregion, which improved in the second quarter of 2019 but worsened in the six months ended June 30, 2019. In the case of gas sales, these decreases are driven largely by differentials in our Permian Basin region, which deteriorated significantly in the 2019 periods, partially offset by differentials in our Mid-Continent region, natural gas production growth has resultedwhich improved in higherthe 2019 periods.
|
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Six Months Ended June 30, | | Variance Between 2019 / 2018 |
| | 2019 | | 2018 | | | 2019 | | 2018 | |
Average NYMEX price | | | | | | | | | | | | |
Oil — per barrel | | $ | 59.82 |
| | $ | 67.88 |
| | (12)% | | $ | 57.36 |
| | $ | 65.37 |
| | (12)% |
Gas — per Mcf | | $ | 2.64 |
| | $ | 2.80 |
| | (6)% | | $ | 2.90 |
| | $ | 2.90 |
| | —% |
| | | | | | | | | | | | |
Average realized price | | |
| | |
| | | | |
| | |
| | |
Oil — per barrel | | $ | 54.24 |
| | $ | 60.99 |
| | (11)% | | $ | 51.64 |
| | $ | 60.45 |
| | (15)% |
Gas — per Mcf | | $ | 0.50 |
| | $ | 1.65 |
| | (70)% | | $ | 1.19 |
| | $ | 1.96 |
| | (39)% |
| | | | | | | | | | | | |
Average price differential | | |
| | |
| | | | |
| | |
| | |
Oil — per barrel | | $ | (5.58 | ) | | $ | (6.89 | ) | | (19)% | | $ | (5.72 | ) | | $ | (4.92 | ) | | 16% |
Gas — per Mcf | | $ | (2.14 | ) | | $ | (1.15 | ) | | 86% | | $ | (1.71 | ) | | $ | (0.94 | ) | | 82% |
The average price differentials andthat we realized in our two primary areas of operation are shown in the table below for the periods indicated.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Average Price Differentials |
| | 2019 | | 2018 |
| | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
| | | | | | | | | | | | |
Oil | | | | | | | | | | | | |
Permian Basin | | $ | (5.80 | ) | | $ | (6.90 | ) | | $ | (11.64 | ) | | $ | (14.34 | ) | | $ | (8.05 | ) | | $ | (3.12 | ) |
Mid-Continent | | $ | (4.39 | ) | | $ | (2.17 | ) | | $ | (2.33 | ) | | $ | (1.08 | ) | | $ | (2.18 | ) | | $ | (2.34 | ) |
| | | | | | | | | | | | |
Gas | | | | | | | | | | | | |
Permian Basin | | $ | (3.10 | ) | | $ | (1.91 | ) | | $ | (2.21 | ) | | $ | (1.25 | ) | | $ | (1.31 | ) | | $ | (0.78 | ) |
Mid-Continent | | $ | (0.86 | ) | | $ | (0.46 | ) | | $ | (0.83 | ) | | $ | (0.94 | ) | | $ | (1.03 | ) | | $ | (0.70 | ) |
Pipeline expansion projects in the Permian Basin are expected to ease capacity constraints as they come online over the next few years, which is reflected in the current futures markets that show narrowing differentials. However, if pipeline constraints remain because expansion projects are delayed or canceled, production increases faster than capacity increases, pipeline disruptions or other reasons, higher differentials will persist or potentially worsen. Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and natural gas production.production and can be adversely affected by realized price decreases. See RESULTS OF OPERATIONS Revenues below for further information regarding our realized commodity prices.
If the trend of decreasing market prices and significant basis differentials continues, coupled with continued exploration and development capital spending, we will incur a ceiling test impairment by year-end. At June 30, 2019, a decline in the value of our ceiling limitation of approximately 4% or more would have resulted in an impairment.
See “Risk Factors” in Item 1A of this Form 10-Q and in our Annual Report on Form 10-K/A10-K for the year ended December 31, 2016,2018, 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 NineSix Months Ended SeptemberJune 30, 20172019 Compared to the NineSix Months Ended SeptemberJune 30, 2016:2018:
Production
Completed the acquisition of Resolute Energy Corporation. Resolute’s results are included in our financial statements since the March 1, 2019 closing date.
Total production volumes increased 16%28% to 1,121.1 MMcfe266.9 MBOE per day.
Oil volumes increased 23%28% to 55.6 MBbls per day, gas volumes increased 10% to 506.7 MMcf per day, and NGL volumes increased 20% to 46.881.4 MBbls per day.
Production revenuesGas volumes increased 57%21% to $1,334.6 million.652.5 MMcf per day.
NGL volumes increased 37% to 76.7 MBbls per day.
Total production revenue remained flat at $1.11 billion.
Cash flow provided by operating activities increased 71%decreased 6% to $755.8$664.1 million.
Exploration and development expenditures increased 1% to $693.0 million.
Net income was $319.6$135.6 million, or $3.36$1.34 per diluted share, for the first ninesix months of 2017,2019, as compared to a net lossincome of $456.6$327.3 million, or $(4.90)$3.44 per diluted share, for the first ninesix months of 2016.2018.
In response to improved commodity prices, we increased our exploration and development expenditures to $813.7 million for the first nine months of 2017, as compared to $443.3 million for the first nine months of 2016.
Total debt at both September 30, 2017 and 2016 consisted of $1.5 billion of senior notes. During the second quarter 2017, we repaid our 5.875% $750 million notes due 2022 and issued 3.90% $750 million notes due 2027. Our 4.375% $750 million notes are due 2024.
RESULTS OF OPERATIONS
Three and NineSix Months Ended SeptemberJune 30, 20172019 vs. Three and NineSix Months Ended SeptemberJune 30, 20162018
Revenues
Almost all our
Our revenues are derived from sales of our oil, natural gas, and NGL production. Increases or decreases in our revenue,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 and economic factors. See QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for more information regarding the sensitivity of our revenues to price fluctuations.
Production volumes and realized prices increasedwere higher for all products during the ninethree and six months ended SeptemberJune 30, 20172019 as compared to the ninethree and six months ended SeptemberJune 30, 20162018, while realized prices were lower. Our acquisition of Resolute and productionongoing completion of new wells have increased our volumes. However, lower market prices and large basis differentials, both of which are out of our control, have lowered our realized prices and, therefore, our revenue. In addition, transportation and processing charges for sales contracts that transfer control of the product at the wellhead versus the tailgate of processing plants are reflected as reductions to revenue under Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”) and, therefore, negatively impact our realized prices. The largest sales contract we acquired with Resolute is this type of contract and sales volumes under legacy Cimarex contracts structured this way have increased. See below “Transportation, Processing, and realized oil and NGL prices increasedOther Operating” for additional information. Our revenue decreased 1%, or $6.6 million, during the three months ended SeptemberJune 30, 20172019 as compared to the three months ended SeptemberJune 30, 2016, while realized gas prices remained relatively constant between the two quarterly periods. These production2018, and realized price increases caused our revenue to increase by $126.5increased less than 1%, or $5.2 million, or 39%, during the threesix months ended SeptemberJune 30, 20172019 as compared to the threesix months ended SeptemberJune 30, 2016 and by $484.7 million, or 57%, during the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016. For the three months ended September 30, 2017, our total production revenue was comprised of 51% oil sales, 28% gas sales, and 21% NGL sales. For the nine months ended September 30, 2017, our total production revenue was comprised of 52% oil sales, 29% gas sales, and 19% NGL sales.2018. The following tables show our production revenue for the periods indicated as well as the change in revenuesrevenue due to changes in volumes and prices.
| | | | Three Months Ended | | Change | | | | | | | | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Price/Volume Variance |
Production Revenue | | September 30, | | Between | | Price/Volume Change | |
(in thousands) | | 2017 | | 2016 | | 2017 / 2016 | | Price | | Volume | | Total | |
Production Revenue (in thousands) | | | 2019 | | 2018 | | Variance Between 2019 / 2018 | | Price | | Volume | | Total |
Oil sales | | $ | 231,441 |
| | $ | 166,079 |
| | 39% | | $ | 20,026 |
| | $ | 45,336 |
| | $ | 65,362 |
| | $ | 411,766 |
| | $ | 342,184 |
| | $ | (51,247 | ) | | $ | 120,829 |
| | $ | 69,582 |
|
Gas sales | | 125,707 |
| | 109,278 |
| | 15% | | (475 | ) | | 16,904 |
| | 16,429 |
| | 30,362 |
| | 80,787 |
| | (50,425 | ) | | (62)% | | (69,681 | ) | | 19,256 |
| | (50,425 | ) |
NGL sales | | 95,191 |
| | 50,464 |
| | 89% | | 32,963 |
| | 11,764 |
| | 44,727 |
| | 95,682 |
| | 121,415 |
| | (25,733 | ) | | (21)% | | (67,352 | ) | | 41,619 |
| | (25,733 | ) |
| | $ | 452,339 |
| | $ | 325,821 |
| | 39% | | $ | 52,514 |
| | $ | 74,004 |
| | $ | 126,518 |
| | $ | 537,810 |
| | $ | 544,386 |
| | $ | (6,576 | ) | | (1)% | | $ | (188,280 | ) | | $ | 181,704 |
| | $ | (6,576 | ) |
| | | | | | | | | | | |
| | Nine Months Ended | | Change | | |
| | |
| | |
| |
Production Revenue | | September 30, | | Between | | Price/Volume Change | |
(in thousands) | | 2017 | | 2016 | | 2017 / 2016 | | Price | | Volume | | Total | |
Oil sales | | $ | 687,960 |
| | $ | 445,657 |
| | 54% | | $ | 139,638 |
| | $ | 102,665 |
| | $ | 242,303 |
| |
Gas sales | | 390,126 |
| | 268,501 |
| | 45% | | 95,453 |
| | 26,172 |
| | 121,625 |
| |
NGL sales | | 256,503 |
| | 135,755 |
| | 89% | | 94,174 |
| | 26,574 |
| | 120,748 |
| |
| | $ | 1,334,589 |
| | $ | 849,913 |
| | 57% | | $ | 329,265 |
| | $ | 155,411 |
| | $ | 484,676 |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, | | Variance Between 2019 / 2018 | | Price/Volume Variance |
Production Revenue (in thousands) | | 2019 | | 2018 | | | Price | | Volume | | Total |
Oil sales | | $ | 761,072 |
| | $ | 693,907 |
| | $ | 67,165 |
| | 10% | | $ | (129,855 | ) | | $ | 197,020 |
| | $ | 67,165 |
|
Gas sales | | 140,338 |
| | 190,508 |
| | (50,170 | ) | | (26)% | | (90,943 | ) | | 40,773 |
| | (50,170 | ) |
NGL sales | | 203,621 |
| | 215,412 |
| | (11,791 | ) | | (5)% | | (92,295 | ) | | 80,504 |
| | (11,791 | ) |
| | $ | 1,105,031 |
| | $ | 1,099,827 |
| | $ | 5,204 |
| | —% | | $ | (313,093 | ) | | $ | 318,297 |
| | $ | 5,204 |
|
The table below presents our regional production volumes.volumes by region.
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | September 30, | | September 30, | |
| | 2017 | | 2016 | | 2017 | | 2016 | |
Production Volumes | | | 2019 | | 2018 | | 2019 | | 2018 |
Oil (Bbls per day) | | | | | | | | | | | | | | | | |
Permian Basin | | 43,735 |
| | 35,930 |
| | 43,544 |
| | 35,939 |
| | 70,669 |
| | 48,797 |
| | 67,835 |
| | 49,318 |
|
Mid-Continent | | 12,846 |
| | 8,486 |
| | 11,937 |
| | 8,889 |
| | 12,623 |
| | 12,473 |
| | 13,419 |
| | 13,841 |
|
Other | | 106 |
| | 116 |
| | 115 |
| | 192 |
| | 138 |
| | 381 |
| | 179 |
| | 263 |
|
| | 56,687 |
| | 44,532 |
| | 55,596 |
| | 45,020 |
| | 83,430 |
| | 61,651 |
| | 81,433 |
| | 63,422 |
|
Gas (MMcf per day) | | | | | | | | | | | | | | | | |
Permian Basin | | 217.9 |
| | 178.4 |
| | 212.9 |
| | 177.7 |
| | 379.3 |
| | 240.5 |
| | 360.1 |
| | 239.2 |
|
Mid-Continent | | 296.8 |
| | 266.7 |
| | 292.4 |
| | 281.3 |
| | 285.5 |
| | 297.0 |
| | 291.3 |
| | 296.2 |
|
Other | | 1.2 |
| | 1.6 |
| | 1.4 |
| | 1.5 |
| | 1.0 |
| | 2.0 |
| | 1.1 |
| | 1.7 |
|
| | 515.9 |
| | 446.7 |
| | 506.7 |
| | 460.5 |
| | 665.8 |
| | 539.5 |
| | 652.5 |
| | 537.1 |
|
NGL (Bbls per day) | | | | | | | | | | | | | | | | |
Permian Basin | | 24,659 |
| | 20,549 |
| | 23,771 |
| | 17,952 |
| | 54,813 |
| | 32,865 |
| | 50,567 |
| | 28,817 |
|
Mid-Continent | | 23,142 |
| | 18,194 |
| | 22,999 |
| | 21,009 |
| | 25,496 |
| | 26,894 |
| | 26,060 |
| | 26,927 |
|
Other | | 39 |
| | 43 |
| | 36 |
| | 41 |
| | 53 |
| | 98 |
| | 53 |
| | 66 |
|
| | 47,840 |
| | 38,786 |
| | 46,806 |
| | 39,002 |
| | 80,362 |
| | 59,857 |
| | 76,680 |
| | 55,810 |
|
Total (MMcfe per day) | | | | | | | | | |
Total (BOE per day) | | | | | | | | | |
Permian Basin | | 628.2 |
| | 517.2 |
| | 616.8 |
| | 501.1 |
| | 188,703 |
| | 121,744 |
| | 178,413 |
| | 118,002 |
|
Mid-Continent | | 512.7 |
| | 426.8 |
| | 502.1 |
| | 460.7 |
| | 85,696 |
| | 88,864 |
| | 88,028 |
| | 90,142 |
|
Other | | 2.2 |
| | 2.6 |
| | 2.2 |
| | 2.8 |
| | 368 |
| | 816 |
| | 427 |
| | 608 |
|
| | 1,143.1 |
| | 946.6 |
| | 1,121.1 |
| | 964.6 |
| | 274,767 |
| | 211,424 |
| | 266,868 |
| | 208,752 |
|
Our total production increased by 196.5 MMcfe per day and 156.5 MMcfe per day during the three and nine months ended September 30, 2017, respectively, as compared to the three and nine months ended September 30, 2016. These increases are the result of increased drilling and completion activity during 2017 as compared to 2016. Accordingly, our capital expenditures have also increased significantly during the 2017 periods as compared to the 2016 periods. See LIQUIDITY AND CAPITAL RESOURCES Capital Expendituresbelow for more information on our capital expenditures.
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, 2019, approximately 83% of our oil production was in the Permian Basin, up from approximately 78% during the six months ended June 30, 2018. Our realized prices do not include settlements of commodity derivative contracts.
| | | | Three Months Ended | | Change | | Nine Months Ended | | Change | | | | | | | | | | | | |
| | September 30, | | Between | | September 30, | | Between | | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Six Months Ended June 30, | | Variance Between 2019 / 2018 |
| | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | | 2017 / 2016 | | 2019 | | 2018 | | 2019 | | 2018 | |
Oil | | | | | | | | | | | | | | | | | | | | | | | | |
Total volume — MBbls | | 5,215 |
| | 4,097 |
| | 27% | | 15,178 |
| | 12,336 |
| | 23% | | 7,592 |
| | 5,610 |
| | 35% | | 14,739 |
| | 11,479 |
| | 28% |
Total volume — MBbls per day | | 56.7 |
| | 44.5 |
| | 27% | | 55.6 |
| | 45.0 |
| | 23% | | 83.4 |
| | 61.7 |
| | 35% | | 81.4 |
| | 63.4 |
| | 28% |
Percentage of total production | | 30 | % | | 28 | % | | | | 30 | % | | 28 | % | | | | 30 | % | | 29 | % | | | | 30 | % | | 30 | % | | |
Average realized price — per barrel | | $ | 44.38 |
| | $ | 40.54 |
| | 9% | | $ | 45.33 |
| | $ | 36.13 |
| | 25% | | $ | 54.24 |
| | $ | 60.99 |
| | (11)% | | $ | 51.64 |
| | $ | 60.45 |
| | (15)% |
Average WTI Midland price — per barrel | | $ | 47.44 |
| | $ | 44.64 |
| | 6% | | $ | 49.14 |
| | $ | 41.43 |
| | 19% | | $ | 57.72 |
| | $ | 62.76 |
| | (8)% | | $ | 54.35 |
| | $ | 63.01 |
| | (14)% |
Average WTI Cushing price — per barrel | | $ | 48.20 |
| | $ | 44.94 |
| | 7% | | $ | 49.46 |
| | $ | 41.33 |
| | 20% | | $ | 59.82 |
| | $ | 67.88 |
| | (12)% | | $ | 57.36 |
| | $ | 65.37 |
| | (12)% |
| | | | | | | | | | | | | | | | | | |
Gas | | |
| | |
| | | | |
| | |
| | | | |
| | |
| | | | |
| | |
| | |
Total volume — MMcf | | 47,467 |
| | 41,096 |
| | 16% | | 138,338 |
| | 126,164 |
| | 10% | | 60,592 |
| | 49,094 |
| | 23% | | 118,108 |
| | 97,219 |
| | 21% |
Total volume — MMcf per day | | 515.9 |
| | 446.7 |
| | 16% | | 506.7 |
| | 460.5 |
| | 10% | | 665.8 |
| | 539.5 |
| | 23% | | 652.5 |
| | 537.1 |
| | 21% |
Percentage of total production | | 45 | % | | 47 | % | | | | 45 | % | | 48 | % | | | | 41 | % | | 43 | % | | | | 41 | % | | 43 | % | | |
Average realized price — per Mcf | | $ | 2.65 |
| | $ | 2.66 |
| | —% | | $ | 2.82 |
| | $ | 2.13 |
| | 32% | |
Average realized price — per Mcf (1) | | | $ | 0.50 |
|
| $ | 1.65 |
| | (70)% | | $ | 1.19 |
|
| $ | 1.96 |
| | (39)% |
Average Henry Hub price — per Mcf | | $ | 2.99 |
| | $ | 2.81 |
| | 6% | | $ | 3.17 |
| | $ | 2.28 |
| | 39% | | $ | 2.64 |
| | $ | 2.80 |
| | (6)% | | $ | 2.90 |
| | $ | 2.90 |
| | —% |
| | | | | | | | | | | | | | | | | | |
NGL | | |
| | |
| | | | |
| | |
| | | | |
| | |
| | | | |
| | |
| | |
Total volume — MBbls | | 4,401 |
| | 3,568 |
| | 23% | | 12,778 |
| | 10,687 |
| | 20% | | 7,313 |
| | 5,447 |
| | 34% | | 13,879 |
| | 10,102 |
| | 37% |
Total volume — MBbls per day | | 47.8 |
| | 38.8 |
| | 23% | | 46.8 |
| | 39.0 |
| | 20% | | 80.4 |
| | 59.9 |
| | 34% | | 76.7 |
| | 55.8 |
| | 37% |
Percentage of total production | | 25 | % | | 25 | % | | | | 25 | % | | 24 | % | | | | 29 | % | | 28 | % | | | | 29 | % | | 27 | % | | |
Average realized price — per barrel | | $ | 21.63 |
| | $ | 14.14 |
| | 53% | | $ | 20.07 |
| | $ | 12.70 |
| | 58% | |
Average realized price — per barrel (2) | | | $ | 13.08 |
| | $ | 22.29 |
| | (41)% | | $ | 14.67 |
| | $ | 21.32 |
| | (31)% |
| | | | | | | | | | | | | | | | | | |
Total | | |
| | |
| | | | |
| | |
| | | | |
| | |
| | | | |
| | |
| | |
Total production — MMcfe | | 105,166 |
| | 87,088 |
| | 21% | | 306,073 |
| | 264,297 |
| | 16% | |
Total production — MMcfe per day | | 1,143.1 |
| | 946.6 |
| | 21% | | 1,121.1 |
| | 964.6 |
| | 16% | |
Average realized price — per Mcfe | | $ | 4.30 |
| | $ | 3.74 |
| | 15% | | $ | 4.36 |
| | $ | 3.22 |
| | 35% | |
Total production — MBOE | | | 25,004 |
| | 19,240 |
| | 30% | | 48,303 |
| | 37,784 |
| | 28% |
Total production — MBOE per day | | | 274.8 |
| | 211.4 |
| | 30% | | 266.9 |
| | 208.8 |
| | 28% |
Average realized price — per BOE (3) | | | $ | 21.51 |
| | $ | 28.30 |
| | (24)% | | $ | 22.88 |
| | $ | 29.11 |
| | (21)% |
The average realized gas, NGL, and total prices shown in the table above reflect the deduction of certain transportation, processing, and other costs as reductions of revenue under ASC 606, which reduced the average realized prices as follows:
| |
(1) | The average realized gas prices were reduced by $0.25 per Mcf, $0.08 per Mcf, $0.21 per Mcf, and $0.07 per Mcf for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively. |
| |
(2) | The average realized NGL prices were reduced by $1.29 per barrel, $0.68 per barrel, $1.29 per barrel, and $1.52 per barrel for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively. |
| |
(3) | The average realized total prices were reduced by $0.99 per BOE, $0.39 per BOE, $0.88 per BOE, and $0.59 per BOE for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively. |
Other revenues
We transport, process, and market some third-party gas that is associated with our equity gas. We market and sell natural gas for other working interest owners under short-term agreements and may earn a fee for such services. The table below reflects income from third-party gas gathering and processing and our net marketing margin for marketing third-party gas.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Variance | | Nine Months Ended | | Variance |
| | September 30, | | Between | | September 30, | | Between |
Gas Gathering and Marketing Revenues (in thousands): | | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | | 2017 / 2016 |
Gas gathering and other | | $ | 11,056 |
| | $ | 9,824 |
| | $ | 1,232 |
| | $ | 32,416 |
| | $ | 25,276 |
| | $ | 7,140 |
|
Gas marketing, net of related costs | | $ | 286 |
| | $ | 72 |
| | $ | 214 |
| | $ | 304 |
| | $ | 1 |
| | $ | 303 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Six Months Ended June 30, | | Variance Between 2019 / 2018 |
Gas Gathering and Marketing Revenues (in thousands) | | 2019 | | 2018 | | | 2019 | | 2018 | |
Gas gathering and other | | $ | 9,769 |
| | $ | 11,810 |
| | $ | (2,041 | ) | | $ | 20,031 |
| | $ | 23,262 |
| | $ | (3,231 | ) |
Gas marketing | | $ | (1,116 | ) | | $ | 78 |
| | $ | (1,194 | ) | | $ | (1,642 | ) | | $ | 319 |
| | $ | (1,961 | ) |
Fluctuations in revenues from gas gathering and gas marketing activities are a function of increases and decreases in volumes, commodity prices, and gathering rate charges.
Operating Costs and Expenses
Costs associated with producing oil and natural gas are substantial. Among other factors, some of these costs vary with commodity prices, some trend with the volume of production, otherssome are a function of the number of wells we own, and some depend on the prices charged by service companies. companies, and some fluctuate based on a combination of the foregoing.
Total operating costs and expenses for the three months ended SeptemberJune 30, 20172019 were lowerhigher by 8%9%, or $33.6 million, compared to the three months ended SeptemberJune 30, 2016.2018. The primary reasons for the decrease are:increase were: (i) the $105.6$69.9 million ($67.1 million, net of tax) ceiling test impairment recordedincrease in the 2016 period partially offset by (ii) increased depreciation, depletion, and amortization, production expense, transportation, processing, and other operating costs,(ii) the $13.1 million increase in taxes other than income, and (iii) the $8.5 million increase in production expense, partially offset by the $62.5 million increase in net lossesgains on derivative instruments in 2017. instruments.
| | | | Three Months Ended | | Variance | | | | | | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Per BOE |
| | September 30, | | Between | | Per Mcfe | |
| | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | |
Operating Costs and Expenses (in thousands, except per Mcfe): | | | | | | | | | | | |
Impairment of oil and gas properties | | $ | — |
| | $ | 105,593 |
| | $ | (105,593 | ) | | N/A |
| | N/A |
| |
Operating Costs and Expenses (in thousands, except per BOE) | | | 2019 | | 2018 | | Variance Between 2019 / 2018 | | 2019 | | 2018 |
Depreciation, depletion, and amortization | | 111,396 |
| | 90,277 |
| | 21,119 |
| | $ | 1.06 |
| | $ | 1.04 |
| | $ | 213,327 |
| | $ | 143,388 |
| | $ | 8.53 |
| | $ | 7.45 |
|
Asset retirement obligation | | 1,497 |
| | 2,033 |
| | (536 | ) | | $ | 0.01 |
| | $ | 0.02 |
| | 2,157 |
| | 2,053 |
| | 104 |
| | $ | 0.09 |
| | $ | 0.11 |
|
Production | | 65,410 |
| | 52,976 |
| | 12,434 |
| | $ | 0.62 |
| | $ | 0.61 |
| | 87,726 |
| | 79,215 |
| | 8,511 |
| | $ | 3.51 |
| | $ | 4.12 |
|
Transportation, processing, and other operating | | 58,387 |
| | 48,706 |
| | 9,681 |
| | $ | 0.56 |
| | $ | 0.56 |
| | 48,331 |
| | 51,933 |
| | (3,602 | ) | | $ | 1.93 |
| | $ | 2.70 |
|
Gas gathering and other | | 8,856 |
| | 7,905 |
| | 951 |
| | $ | 0.08 |
| | $ | 0.09 |
| | 13,605 |
| | 9,467 |
| | 4,138 |
| | $ | 0.54 |
| | $ | 0.49 |
|
Taxes other than income | | 24,314 |
| | 15,974 |
| | 8,340 |
| | $ | 0.23 |
| | $ | 0.18 |
| | 41,033 |
| | 27,930 |
| | 13,103 |
| | $ | 1.64 |
| | $ | 1.45 |
|
General and administrative | | 21,039 |
| | 20,118 |
| | 921 |
| | $ | 0.20 |
| | $ | 0.23 |
| | 24,911 |
| | 19,739 |
| | 5,172 |
| | $ | 1.00 |
| | $ | 1.03 |
|
Stock compensation | | 7,038 |
| | 5,764 |
| | 1,274 |
| | $ | 0.07 |
| | $ | 0.07 |
| | 6,494 |
| | 3,095 |
| | 3,399 |
| | $ | 0.26 |
| | $ | 0.16 |
|
(Gain) loss on derivative instruments, net | | 16,109 |
| | (9,758 | ) | | 25,867 |
| | N/A |
| | N/A |
| | (40,768 | ) | | 21,699 |
| | (62,467 | ) | | N/A |
| | N/A |
|
Other operating expense, net | | 95 |
| | 179 |
| | (84 | ) | | N/A |
| | N/A |
| | 590 |
| | 5,252 |
| | (4,662 | ) | | N/A |
| | N/A |
|
| | $ | 314,141 |
| | $ | 339,767 |
| | $ | (25,626 | ) | | |
| | |
| | $ | 397,406 |
| | $ | 363,771 |
| | $ | 33,635 |
| | |
| | |
|
Total operating costs and expenses for the ninesix months ended SeptemberJune 30, 20172019 were lowerhigher by 48%36%, or $246.1 million, compared to the ninesix months ended SeptemberJune 30, 2016.2018. The primary reasons for the decrease are:increase were due to the following increases: (i) the $757.7$127.5 million ($481.4in depreciation, depletion, and amortization, (ii) $57.1 million in net of tax) ceiling test impairment recorded in the 2016 period and (ii) increased net gainslosses on derivative instruments, in 2017, partially offset by (iii) increased transportation, processing, and other operating costs,$16.6 million in taxes other than income, (iv) $14.5 million in production expense, and depreciation, depletion,(v) $10.9 million in general and amortization in 2017.administrative.
| | | | Nine Months Ended | | Variance | | | | | | Six Months Ended June 30, | | Variance Between 2019 / 2018 | | Per BOE |
| | September 30, | | Between | | Per Mcfe | |
| | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | |
Operating Costs and Expenses (in thousands, except per Mcfe): | | | | | | | | | | | |
Impairment of oil and gas properties | | $ | — |
| | $ | 757,670 |
| | $ | (757,670 | ) | | N/A |
| | N/A |
| |
Operating Costs and Expenses (in thousands, except per BOE) | | | 2019 | | 2018 | | Variance Between 2019 / 2018 | | 2019 | | 2018 |
Depreciation, depletion, and amortization | | 315,096 |
| | 302,999 |
| | 12,097 |
| | $ | 1.03 |
| | $ | 1.15 |
| | $ | 403,744 |
| | $ | 276,247 |
| | $ | 8.36 |
| | $ | 7.31 |
|
Asset retirement obligation | | 4,077 |
| | 6,081 |
| | (2,004 | ) | | $ | 0.01 |
| | $ | 0.02 |
| | 4,206 |
| | 3,113 |
| | 1,093 |
| | $ | 0.09 |
| | $ | 0.08 |
|
Production | | 190,409 |
| | 180,891 |
| | 9,518 |
| | $ | 0.62 |
| | $ | 0.68 |
| | 164,959 |
| | 150,486 |
| | 14,473 |
| | $ | 3.42 |
| | $ | 3.98 |
|
Transportation, processing and other operating | | 172,034 |
| | 139,585 |
| | 32,449 |
| | $ | 0.56 |
| | $ | 0.53 |
| |
Transportation, processing, and other operating | | | 101,939 |
| | 97,098 |
| | 4,841 |
| | $ | 2.11 |
| | $ | 2.57 |
|
Gas gathering and other | | 25,930 |
| | 23,477 |
| | 2,453 |
| | $ | 0.08 |
| | $ | 0.09 |
| | 25,925 |
| | 19,290 |
| | 6,635 |
| | $ | 0.54 |
| | $ | 0.51 |
|
Taxes other than income | | 63,104 |
| | 43,879 |
| | 19,225 |
| | $ | 0.21 |
| | $ | 0.17 |
| | 74,727 |
| | 58,118 |
| | 16,609 |
| | $ | 1.55 |
| | $ | 1.54 |
|
General and administrative | | 58,835 |
| | 55,439 |
| | 3,396 |
| | $ | 0.19 |
| | $ | 0.21 |
| | 53,995 |
| | 43,060 |
| | 10,935 |
| | $ | 1.12 |
| | $ | 1.14 |
|
Stock compensation | | 19,619 |
| | 18,782 |
| | 837 |
| | $ | 0.06 |
| | $ | 0.07 |
| | 13,207 |
| | 9,825 |
| | 3,382 |
| | $ | 0.27 |
| | $ | 0.26 |
|
(Gain) loss on derivative instruments, net | | (50,261 | ) | | 23,050 |
| | (73,311 | ) | | N/A |
| | N/A |
| |
Loss on derivative instruments, net | | | 74,684 |
| | 17,540 |
| | 57,144 |
| | N/A |
| | N/A |
|
Other operating expense, net | | 977 |
| | 293 |
| | 684 |
| | N/A |
| | N/A |
| | 8,916 |
| | 5,455 |
| | 3,461 |
| | N/A |
| | N/A |
|
| | $ | 799,820 |
| | $ | 1,552,146 |
| | $ | (752,326 | ) | | |
| | |
| | $ | 926,302 |
| | $ | 680,232 |
| | $ | 246,070 |
| | |
| | |
|
Ceiling Test Impairment
We use the full cost method of accounting for our oil and gas operations. Accounting rules require us to perform a quarterly ceiling test calculation to test our capitalized oil and gas property costs 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. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.
At each quarter-end date during the nine months ended September 30, 2017, the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we have not recognized a ceiling test impairment during the nine months ended September 30, 2017. During the three and nine months ended September 30, 2016, we recognized ceiling test impairments of $105.6 million ($67.1 million, net of tax) and $757.7 million ($481.4 million, net of tax), respectively. These impairments were primarily the result of decreases in the trailing twelve-month average prices for oil, natural gas, and NGLs utilized in determining the estimated future net cash flows from proved reserves. The commodity prices used in the September 30, 2017 ceiling calculation, based on the required trailing twelve-month average prices, were $3.00 per Mcf of gas and $49.81 per barrel of oil. A decline of approximately 18% or more in the value of the ceiling limitation would have resulted in an impairment at September 30, 2017. Because the ceiling calculation uses trailing twelve-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation. In addition, other factors that impact the ceiling limitation calculation include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, depletion expense, and all related tax effects. Depending on fluctuations in these factors, including a decline in prices, we may incur full cost ceiling test impairments in future quarters.
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.
Depreciation, Depletion, and Amortization
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. Depletion is calculated quarterly beforeOur net proved properties, production, and reserves have increased during 2019 as compared to 2018 due to our ongoing exploration and development activities as well as due to our acquisition of Resolute. The increase in net properties and production resulted in an overall increase in depletion expense, while the ceiling test impairment calculation. increase in reserves partially offset the increased expense.
Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from 3 to 30 years. Additionally, with the adoption of Topic 842, we depreciate our right-of-use assets, with the depreciation of our finance lease gathering system right-of-use asset being included in our depreciation expense. The increase in depreciation expense during the 2019 periods as compared to 2018 periods is primarily due to: (i) increased depreciation on our gathering and plant facilities due to ongoing expenditures on this infrastructure and (ii) the depreciation on our gathering system right-of-use asset. Depreciation, depletion, and amortization (“DD&A”) consistsconsisted of the following:following for the periods indicated:
| | | | Three Months Ended | | Variance | | | | | | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Per BOE |
| | September 30, | | Between | | Per Mcfe | |
DD&A Expense (in thousands, except per Mcfe) | | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | |
DD&A Expense (in thousands, except per BOE) | | | 2019 | | 2018 | | Variance Between 2019 / 2018 | | 2019 | | 2018 |
Depletion | | $ | 99,633 |
| | $ | 78,396 |
| | $ | 21,237 |
| | $ | 0.95 |
| | $ | 0.90 |
| | $ | 196,899 |
| | $ | 131,220 |
| | $ | 7.87 |
| | $ | 6.82 |
|
Depreciation | | 11,763 |
| | 11,881 |
| | (118 | ) | | 0.11 |
| | 0.14 |
| | 16,428 |
| | 12,168 |
| | 4,260 |
| | 0.66 |
| | 0.63 |
|
| | $ | 111,396 |
| | $ | 90,277 |
| | $ | 21,119 |
| | $ | 1.06 |
| | $ | 1.04 |
| | $ | 213,327 |
| | $ | 143,388 |
| | $ | 69,939 |
| | $ | 8.53 |
| | $ | 7.45 |
|
| | | | | | | | | | | |
| | Nine Months Ended | | Variance | | | | | |
| | September 30, | | Between | | Per Mcfe | |
DD&A Expense (in thousands, except per Mcfe) | | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | |
Depletion | | $ | 280,379 |
| | $ | 267,880 |
| | $ | 12,499 |
| | $ | 0.92 |
| | $ | 1.02 |
| |
Depreciation | | 34,717 |
| | 35,119 |
| | (402 | ) | | 0.11 |
| | 0.13 |
| |
| | $ | 315,096 |
| | $ | 302,999 |
| | $ | 12,097 |
| | $ | 1.03 |
| | $ | 1.15 |
| |
|
| | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, | | Variance Between 2019 / 2018 | | Per BOE |
DD&A Expense (in thousands, except per BOE) | | 2019 | | 2018 | | | 2019 | | 2018 |
Depletion | | $ | 371,611 |
| | $ | 251,610 |
| | $ | 120,001 |
| | $ | 7.69 |
| | $ | 6.66 |
|
Depreciation | | 32,133 |
| | 24,637 |
| | 7,496 |
| | 0.67 |
| | 0.65 |
|
| | $ | 403,744 |
| | $ | 276,247 |
| | $ | 127,497 |
| | $ | 8.36 |
| | $ | 7.31 |
|
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 consistsconsisted of lease operating expense and workover expense as follows:
| | | | Three Months Ended | | Variance | | | | | | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Per BOE |
| | September 30, | | Between | | Per Mcfe | |
Production Expense (in thousands, except per Mcfe) | | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | |
Production Expense (in thousands, except per BOE) | | | 2019 | | 2018 | | Variance Between 2019 / 2018 | | 2019 | | 2018 |
Lease operating expense | | $ | 55,296 |
| | $ | 44,249 |
| | $ | 11,047 |
| | $ | 0.52 |
| | $ | 0.51 |
| | $ | 71,778 |
| | $ | 62,355 |
| | $ | 2.87 |
| | $ | 3.24 |
|
Workover expense | | 10,114 |
| | 8,727 |
| | 1,387 |
| | 0.10 |
| | 0.10 |
| | 15,948 |
| | 16,860 |
| | (912 | ) | | 0.64 |
| | 0.88 |
|
| | $ | 65,410 |
| | $ | 52,976 |
| | $ | 12,434 |
| | $ | 0.62 |
| | $ | 0.61 |
| | $ | 87,726 |
| | $ | 79,215 |
| | $ | 8,511 |
| | $ | 3.51 |
| | $ | 4.12 |
|
| | | | | | | | | | | |
| | Nine Months Ended | | Variance | | | | | |
| | September 30, | | Between | | Per Mcfe | |
Production Expense (in thousands, except per Mcfe) | | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | |
Lease operating expense | | $ | 156,644 |
| | $ | 146,895 |
| | $ | 9,749 |
| | $ | 0.51 |
| | $ | 0.55 |
| |
Workover expense | | 33,765 |
| | 33,996 |
| | (231 | ) | | 0.11 |
| | 0.13 |
| |
| | $ | 190,409 |
| | $ | 180,891 |
| | $ | 9,518 |
| | $ | 0.62 |
| | $ | 0.68 |
| |
Through efficiency gains and increasing production by 16% during the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, we reduced our per unit lease operating expense by 7% between these two periods. On an absolute basis, lease
|
| | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, | | Variance Between 2019 / 2018 | | Per BOE |
Production Expense (in thousands, except per BOE) | | 2019 | | 2018 | | | 2019 | | 2018 |
Lease operating expense | | $ | 134,186 |
| | $ | 122,831 |
| | $ | 11,355 |
| | $ | 2.78 |
| | $ | 3.25 |
|
Workover expense | | 30,773 |
| | 27,655 |
| | 3,118 |
| | 0.64 |
| | 0.73 |
|
| | $ | 164,959 |
| | $ | 150,486 |
| | $ | 14,473 |
| | $ | 3.42 |
| | $ | 3.98 |
|
Lease operating expense in the thirdsecond quarter 20172019 increased 25%15%, or $11.0$9.4 million, compared to the thirdsecond quarter of 2016. The increase was primarily caused by: (i) increased equipment maintenance costs, (ii) increased saltwater disposal and equipment rental costs, both due to increased drilling activity, and (iii) increased labor costs due to more employees and salary increases.2018. Lease operating expense for the ninesix months ended SeptemberJune 30, 20172019 increased 7%9%, or $9.7$11.4 million, as compared to the six months ended June 30, 2018. The increases have primarily stemmed from the Resolute acquisition and the addition of new wells as a result of our ongoing exploration and development activities. These increases were partially offset by expense reductions related to the sale of non-core properties principally located in Ward County, Texas in August 2018. The following types of expenses have increased in the 2019 periods as compared to the 2018 periods: (i) compressor rentals, (ii) labor, and (iii) electricity.
Workover expense in the second quarter 2019 decreased 5%, or $0.9 million, compared to the ninesecond quarter of 2018. Workover expense for the six months ended SeptemberJune 30, 2016. The increase was primarily caused by: (i)2019 increased labor costs due to more employees and salary and bonus increases, (ii) increased saltwater disposal costs due to increased drilling activity and various issues (e.g., capacity and down time) at third-party disposal wells, (iii) increased gas lift and fuel compression costs, and (iv) increased chemicals and treating costs.
Workover expense during the three and nine months ended September 30, 2017 increased 16%11%, or $1.4$3.1 million, and decreased 1%, or $0.2 million, respectively,as compared to the three and ninesix months ended SeptemberJune 30, 2016.2018. During the three and ninesix months ended SeptemberJune 30, 2017, we had an increased number2018, our workover expense was reduced due to receiving approximately $4.0 million in insurance proceeds related to the remediation and repairs incurred as a result of workover projects as well as costlier major well workover projects than during the three and nine months ended September 30, 2016, which increased expense. For the nine monthsa 2015 flooding event.
ended September 30, 2017, this increase was somewhat offset by the receipt of partial insurance proceeds in the second quarter 2017 related to a flooding event in 2015 and the subsequent remediation and repairs. During the first four months of 2016, water was still being pumped out of the flooded area, which further increased the workover expense for the nine months ended September 30, 2016. Generally, workover costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.
Transportation, Processing, and Other Operating
Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, together with gasincluding gathering, fuel, compression, and processing costs and costs to transport production to a specified sales point.costs. Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs, and 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.
The largest sales contract that we acquired with Resolute is structured this way and sales volumes under legacy Cimarex contracts structured this way have increased, therefore, our transportation and processing costs have not increased commensurate with production volume increases. Transportation, processing, and other operating costs in the threesecond quarter 2019 were 7%, or $3.6 million, lower than the same costs in the first quarter 2018. For the six months ended SeptemberJune 30, 2017 were 20%, or $9.7 million, higher than2019, transportation, processing, and other operating costs in the three months ended September 30, 2016. This increase was primarily due to increased production volumes in the 2017 quarter as compared to the 2016 quarter. Transportation, processing, and other operating costs in the nine months ended September 30, 2017 were 23%5%, or $32.4$4.8 million, higher than transportation, processing, and other operating costs infor the ninesix months ended SeptemberJune 30, 2016. This increase was primarily due to increased production volumes and transportation2018. Transportation and processing ratescosts included as a reduction in 2017 as compared to 2016.revenue since our adoption of ASC 606 on January 1, 2018 were $24.7 million and $42.6 million for the three and six months ended June 30, 2019 and $7.7 million and $22.2 million for the three and six months ended June 30, 2018.
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. Gas gathering and other in the three months ended SeptemberJune 30, 20172019 was 12%44%, or $1.0$4.1 million, higher than gas gathering and other in the three months ended SeptemberJune 30, 2016.2018. Gas gathering and other in the ninesix months ended SeptemberJune 30, 20172019 was 10%34%, or $2.5$6.6 million, higher than gas gathering and other in the ninesix months ended SeptemberJune 30, 2016.2018. The increases from 2016 are primarily due to overall increases in operating costs partially offset by lower product costs associated with processing third-party production. These increased productproduction due primarily to lower volumes and prices. The increase in operating costs are offset by increaseswas due primarily to an increase in associated revenue.compression costs.
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. Production taxes make up the majority of this expense for us, with revenue-based production taxes being the largest component of these taxes.us. Taxes other than income increased $8.3$13.1 million, or 52%47%, in the thirdsecond quarter of 20172019 as compared to the thirdsecond quarter of 2016.2018. Taxes other than income increased $19.2$16.6 million, or 44%29%, in the ninesix months ended SeptemberJune 30, 20172019 as compared to the ninesix months ended SeptemberJune 30, 2016.2018. Production taxes have increased primarily due to increased production volumes. However, the majority of the increase seen in the 2019 periods as compared to the 2018 periods was due to increases in ad valorem taxes. Ad valorem taxes increased by $7.5 million, or 210%, in the second quarter of 2019 as compared to the second quarter of 2018 and by $10.4 million, or 145%, in the six months ended June 30, 2019 as compared to the six months ended June 30, 2018. These increases are due to new properties, including those acquired in the increase in revenue seen between the comparable periods.Resolute acquisition, and expected increased assessed values. Taxes other than income was 5.4%7.6% and 4.9%5.1% of production revenues for the three months ended SeptemberJune 30, 20172019 and 2016,2018, respectively, and was 4.7%6.8% and 5.2%5.3% of production revenues for the ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, respectively. The percentage for the nine months ended September 30, 2017 has decreased from the comparative period due to the approval of reduced tax rates on several of our high-cost gas wells in the State of Texas and, as part of this process, approved severance tax refunds of $8.2 million.
General and Administrative
General and administrative (“G&A”) expenses consistexpense consists primarily of salaries and related benefits, office rent, legal and consultantconsulting fees, systems costs, and other administrative costs incurred that are not directly associated with exploration, development, or production activities.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 amountpercentage of gross G&A capitalized ranged from 45%44% to 48%50% during the periods presented in the table below, which shows our G&A costs.
| | | | Three Months Ended | | Variance Between 2017 / 2016 | | Nine Months Ended | | Variance Between 2017 / 2016 | | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Six Months Ended June 30, | | Variance Between 2019 / 2018 |
| | September 30, | | September 30, | | |
General and Administrative Expense (in thousands): | | 2017 | | 2016 | | 2017 | | 2016 | | |
General and Administrative Expense (in thousands) | | | 2019 | | 2018 | | Variance Between 2019 / 2018 | | 2019 | | 2018 | | Variance Between 2019 / 2018 |
Gross G&A | | $ | 39,885 |
| | $ | 36,752 |
| | $ | 3,133 |
| | $ | 112,516 |
| | $ | 106,208 |
| | $ | 6,308 |
| | $ | 46,930 |
| | $ | 39,276 |
| | $ | 96,166 |
| | $ | 80,124 |
| |
Less amounts capitalized to oil and gas properties | | (18,846 | ) | | (16,634 | ) | | (2,212 | ) | | (53,681 | ) | | (50,769 | ) | | (2,912 | ) | | (22,019 | ) | | (19,537 | ) | | (2,482 | ) | | (42,171 | ) | | (37,064 | ) | | (5,107 | ) |
G&A expense | | $ | 21,039 |
| | $ | 20,118 |
| | $ | 921 |
| | $ | 58,835 |
| | $ | 55,439 |
| | $ | 3,396 |
| | $ | 24,911 |
| | $ | 19,739 |
| | $ | 5,172 |
| | $ | 53,995 |
| | $ | 43,060 |
| | $ | 10,935 |
|
G&A expense for the thirdsecond quarter of 20172019 was 5%26%, or $0.9$5.2 million, higher than G&A expense for the thirdsecond quarter of 2016. This increase is2018. G&A expense for the six months ended June 30, 2019 was 25%, or $10.9 million, higher than G&A expense for the six months ended June 30, 2018. These increases were primarily due to increased employee-related costs such as salaries and wages, consulting,other compensation, and charitable donations, partially offset by decreased employee bonus expense. G&A expense forbenefits. Included in the ninesix months ended SeptemberJune 30, 20172019 was 6%, or $3.4$2.9 million higher than for the nine months ended September 30, 2016. This increase was primarily caused by increased employee bonusof severance expense charitable donations,related to former Resolute employees who performed transition work at Cimarex and consulting, partially offset by decreased severance expense. A voluntary Early Retirement Incentive Program, which included severance pay, was offered to certain employees during 2016. then were subsequently terminated.
Stock Compensation
Stock compensation expense consists of non-cash 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 expensecost as follows:
| | | | Three Months Ended | | Variance | | Nine Months Ended | | Variance | | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Six Months Ended June 30, | | Variance Between 2019 / 2018 |
| | September 30, | | Between | | September 30, | | Between | |
Stock Compensation Expense (in thousands): | | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | | 2017 / 2016 | |
Stock Compensation Expense (in thousands) | | | 2019 | | 2018 | | Variance Between 2019 / 2018 | | 2019 | | 2018 | | Variance Between 2019 / 2018 |
Restricted stock awards: | | | | | | | | | | | | | | | | | | | | | |
Performance stock awards | | $ | 6,508 |
| | $ | 5,465 |
| | $ | 1,043 |
| | $ | 19,348 |
| | $ | 18,374 |
| | $ | 974 |
| | $ | 5,535 |
| | $ | 3,809 |
| | $ | 1,726 |
| | $ | 10,929 |
| | $ | 10,538 |
| | $ | 391 |
|
Service-based stock awards | | 5,317 |
| | 4,624 |
| | 693 |
| | 14,449 |
| | 13,540 |
| | 909 |
| | 5,993 |
| | 4,247 |
| | 1,746 |
| | 13,224 |
| | 9,319 |
| | 3,905 |
|
| | 11,825 |
| | 10,089 |
| | 1,736 |
| | 33,797 |
| | 31,914 |
| | 1,883 |
| | 11,528 |
| | 8,056 |
| | 3,472 |
| | 24,153 |
| | 19,857 |
| | 4,296 |
|
Stock option awards | | 698 |
| | 571 |
| | 127 |
| | 1,943 |
| | 1,974 |
| | (31 | ) | | 396 |
| | 637 |
| | (241 | ) | | 1,018 |
| | 1,254 |
| | (236 | ) |
Total stock compensation cost | | 12,523 |
| | 10,660 |
| | 1,863 |
| | 35,740 |
| | 33,888 |
| | 1,852 |
| | 11,924 |
| | 8,693 |
| | 3,231 |
| | 25,171 |
| | 21,111 |
| | 4,060 |
|
Less amounts capitalized to oil and gas properties | | (5,485 | ) | | (4,896 | ) | | (589 | ) | | (16,121 | ) | | (15,106 | ) | | (1,015 | ) | | (5,430 | ) | | (5,598 | ) | | 168 |
| | (11,964 | ) | | (11,286 | ) | | (678 | ) |
Stock compensation expense | | $ | 7,038 |
| | $ | 5,764 |
| | $ | 1,274 |
| | $ | 19,619 |
| | $ | 18,782 |
| | $ | 837 |
| | $ | 6,494 |
| | $ | 3,095 |
| | $ | 3,399 |
| | $ | 13,207 |
| | $ | 9,825 |
| | $ | 3,382 |
|
Periodic stock 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. The increase in total stock compensation cost in the 20172019 periods as compared to the 20162018 periods is primarily due to awards granted either during or subsequent to the2016 periods. These increases 2018 periods and performance stock award forfeitures that occurred during the second quarter of 2018, both of which were partially offset by the following decreases: (i) awards vesting prior to or during the 2017 periods, (ii) reversals of previously recognized expense on 2017 forfeitures, and (iii) expense associated with the voluntary Early Retirement Incentive Program during the 2016 periods.
We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017. ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, accounting for forfeitures, and classification on the statement of cash flows. Pursuant to ASU 2016-09, we made an2019 periods. Our accounting policy electionis to account for forfeitures in compensation cost when they occur, rather than including an estimate of the number of awards that are expected to vest in ouroccur.
compensation cost. The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a modified retrospective method. In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by $33.1 million, reduced beginning accumulated deficit by $28.7 million, and increased beginning additional paid-in capital by $4.4 million. The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to the payment of tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method. In accordance with this method, we adjusted the statement of cash flows for the nine months ended September 30, 2016 by increasing net cash provided by operating activities by $11.5 million and increasing net cash used by financing activities by $11.5 million for the payment of tax withholdings on the net settlement of equity-classified awards. There were no cash flows related to excess tax benefits during the nine months ended September 30, 2017 and 2016.
(Gain) Loss on Derivative Instruments, Net
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.
The following table presents the components of (Gain) loss 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 | | Variance Between 2017 / 2016 | | Nine Months Ended | | Variance Between 2017 / 2016 |
| | September 30, | | | September 30, | |
(Gain) Loss on Derivative Instruments, Net (in thousands): | | 2017 | | 2016 | | | 2017 | | 2016 | |
Change in fair value of derivative instruments, net | | $ | 19,085 |
| | $ | (8,967 | ) | | $ | 28,052 |
| | $ | (53,003 | ) | | $ | 32,768 |
| | $ | (85,771 | ) |
Cash (receipts) payments on derivative instruments, net | | (2,976 | ) | | (791 | ) | | (2,185 | ) | | 2,742 |
| | (9,718 | ) | | 12,460 |
|
(Gain) loss on derivative instruments, net | | $ | 16,109 |
| | $ | (9,758 | ) | | $ | 25,867 |
| | $ | (50,261 | ) | | $ | 23,050 |
| | $ | (73,311 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Six Months Ended June 30, | | Variance Between 2019 / 2018 |
(Gain) Loss on Derivative Instruments, Net (in thousands) | | 2019 | | 2018 | | | 2019 | | 2018 | |
(Increase) decrease in fair value of derivative instruments, net: | | |
| | |
| | |
| | | | | | |
Gas contracts | | $ | (6,370 | ) | | $ | 14,566 |
| | $ | (20,936 | ) | | $ | (16,216 | ) | | $ | 2,777 |
| | $ | (18,993 | ) |
Oil contracts | | (28,161 | ) | | (397 | ) | | (27,764 | ) | | 88,086 |
| | (5,156 | ) | | 93,242 |
|
| | (34,531 | ) | | 14,169 |
| | (48,700 | ) | | 71,870 |
| | (2,379 | ) | | 74,249 |
|
Cash (receipts) payments on derivative instruments, net: | | |
| | |
| | | | | | | | |
Gas contracts | | (21,176 | ) | | (9,918 | ) | | (11,258 | ) | | (17,412 | ) | | (15,037 | ) | | (2,375 | ) |
Oil contracts | | 14,939 |
| | 17,448 |
| | (2,509 | ) | | 20,226 |
| | 34,956 |
| | (14,730 | ) |
| | (6,237 | ) | | 7,530 |
| | (13,767 | ) | | 2,814 |
| | 19,919 |
| | (17,105 | ) |
(Gain) loss on derivative instruments, net | | $ | (40,768 | ) | | $ | 21,699 |
| | $ | (62,467 | ) | | $ | 74,684 |
| | $ | 17,540 |
| | $ | 57,144 |
|
Other (Income)Operating Expense, Net
Other operating expense, net during the six months ended June 30, 2019 was comprised primarily of $8.4 million in acquisition-related costs incurred to effect the Resolute acquisition. These costs consisted primarily of advisory, legal, and other professional and consulting fees. Other operating expense, net during the three months ended June 30, 2018 was comprised primarily of $4.9 million in litigation settlements.
Other Income and Expense
| | | | Three Months Ended | | Variance | | Nine Months Ended | | Variance | | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Six Months Ended June 30, | | Variance Between 2019 / 2018 |
| | September 30, | | Between | | September 30, | | Between | |
Other Income and Expense (in thousands): | | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | | 2017 / 2016 | |
Other Income and Expense (in thousands) | | | 2019 | | 2018 | | Variance Between 2019 / 2018 | | 2019 | | 2018 | | Variance Between 2019 / 2018 |
Interest expense | | $ | 16,838 |
| | $ | 20,931 |
| | $ | (4,093 | ) | | $ | 57,985 |
| | $ | 62,560 |
| | $ | (4,575 | ) | | $ | 24,674 |
| | $ | 16,895 |
| | $ | 45,079 |
| | $ | 33,678 |
| |
Capitalized interest | | (5,373 | ) | | (5,421 | ) | | 48 |
| | (17,456 | ) | | (15,958 | ) | | (1,498 | ) | | (16,805 | ) | | (4,850 | ) | | (11,955 | ) | | (25,547 | ) | | (9,660 | ) | | (15,887 | ) |
Loss on early extinguishment of debt | | — |
| | — |
| | — |
| | 28,169 |
| | — |
| | 28,169 |
| | — |
| | — |
| | — |
| | 4,250 |
| | — |
| | 4,250 |
|
Other, net | | (4,563 | ) | | (3,828 | ) | | (735 | ) | | (9,004 | ) | | (7,489 | ) | | (1,515 | ) | | (2,167 | ) | | (2,605 | ) | | 438 |
| | (4,408 | ) | | (7,172 | ) | | 2,764 |
|
| | $ | 6,902 |
| | $ | 11,682 |
| | $ | (4,780 | ) | | $ | 59,694 |
| | $ | 39,113 |
| | $ | 20,581 |
| | $ | 5,702 |
| | $ | 9,440 |
| | $ | (3,738 | ) | | $ | 19,374 |
| | $ | 16,846 |
| | $ | 2,528 |
|
The majority of our interest expense relates to interest on our senior unsecured notes andnotes. Also included in interest expense is interest expense on our Credit Facility borrowings, the amortization of the related debt issuance costs and discount.discounts, and miscellaneous interest expense. See LIQUIDITY AND CAPITAL RESOURCES Long-term Debt below for further information regarding our debt. The decreaseincrease in interest expense in the 20172019 periods as compared to the 20162018 periods is primarily due to (i) the completion of a tender offer and redemption of $750 million 5.875% senior notes and theMarch 8, 2019 issuance of $750$500 million 3.90%aggregate principal amount of 4.375% senior unsecured notes which occurred duringdue March 15, 2029 at 99.862% of par to yield 4.392% per annum, (ii) borrowings on our Credit Facility in 2019 to help fund the second quarter of 2017.Resolute acquisition and thereafter to meet cash requirements as needed (we did not borrow on our Credit Facility in 2018), and (iii) interest expense on our finance lease. The $28.2$4.3 million loss on early extinguishment of debt incurred during 2017the six months ended June 30, 2019 was also associated with the debt tender offer$600 million of
8.5% senior notes we acquired with Resolute and redemption.elected to immediately repay. The loss was composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs. The original maturity date of the 5.875%Resolute notes was May 1, 2022.2020.
We capitalize interest on non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing qualifiedmidstream assets. Capitalized interest will fluctuate based on the rates applicable to borrowings outstanding during the period and the amount of costs on whichsubject to interest is capitalized. There have beencapitalization. The amount of costs subject to interest capitalization was higher capitalized costs upon which to capitalize interest in the 2017 periods than in the 2016 periods due to our increased capitalized expenditures. See LIQUIDITY AND CAPITAL RESOURCES Capital Expenditures below for further information regarding our capital expenditures. The replacement of our 5.875% notes with 3.90% notes in the second quarter of 2017 has served to lower the amount of capitalized
interest in the 2017 periodsthree and six months ended June 30, 2019 as compared to what the capitalized interest would have been had we not replacedthree and six months ended June 30, 2018, primarily due to the higher interest notes with lower interest notes.Resolute acquisition. Included in the preliminary purchase price allocation of the Resolute acquisition was non-producing leasehold costs of $1.05 billion.
Components of Other, net consist of miscellaneous income and expense items that will 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 asset sales, interest income, and income and expense associated with other non-operating activities.
Income Tax Expense (Benefit)
The components of our provision for income taxes areand our combined federal and state effective income tax rates were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | Variance | | Nine Months Ended | | Variance |
| | September 30, | | Between | | September 30, | | Between |
Income Tax Expense (Benefit) (in thousands): | | 2017 | | 2016 | | 2017 / 2016 | | 2017 | | 2016 | | 2017 / 2016 |
Current tax benefit | | $ | — |
| | $ | (1,115 | ) | | $ | 1,115 |
| | $ | (6 | ) | | $ | (1,115 | ) | | $ | 1,109 |
|
Deferred tax expense (benefit) | | 51,239 |
| | (3,944 | ) | | 55,183 |
| | 188,168 |
| | (258,368 | ) | | 446,536 |
|
| | $ | 51,239 |
| | $ | (5,059 | ) | | $ | 56,298 |
| | $ | 188,162 |
| | $ | (259,483 | ) | | $ | 447,645 |
|
Combined federal and state effective income tax rate | | 35.9 | % | | 32.2 | % | | | | 37.1 | % | | 36.2 | % | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Variance Between 2019 / 2018 | | Six Months Ended June 30, | | Variance Between 2019 / 2018 |
Income Tax Expense (in thousands) | | 2019 | | 2018 | | | 2019 | | 2018 | |
Current tax (benefit) | | $ | — |
| | $ | (717 | ) | | $ | 717 |
| | $ | — |
| | $ | (717 | ) | | $ | 717 |
|
Deferred tax expense | | 34,046 |
| | 42,783 |
| | (8,737 | ) | | 42,119 |
| | 99,732 |
| | (57,613 | ) |
| | $ | 34,046 |
| | $ | 42,066 |
| | $ | (8,020 | ) | | $ | 42,119 |
| | $ | 99,015 |
| | $ | (56,896 | ) |
| | | | | | | | | | | | |
Combined federal and state effective income tax rate | | 23.7 | % | | 23.0 | % | | | | 23.7 | % | | 23.2 | % | | |
Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 35%21% primarily due to state income taxes and non-deductible expenses. See Note 9 to the Condensed Consolidated Financial Statements for additional information regarding our income taxes.
LIQUIDITY AND CAPITAL RESOURCES
Overview
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, proceeds from sales of non-core assets, and, occasionalfrom time to time, public financings based on our monitoring of capital markets and our balance sheet.
Our liquidity is highly dependent on prices we receive for the oil, natural gas, and NGLs we produce. 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 and analysis ofregarding the impact realized prices have had on our 2017 earnings.
We deal with 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 enables us to respond quickly to industry volatility. Based on current economic conditions, our 20172019 exploration and development (“E&D”) expenditures are projected to approximate $1.2range from $1.35 billion to $1.45 billion. Investments in gathering, and processing, infrastructure and other fixed assetsinfrastructure are expectedprojected to approximate an additional $60be approximately $70 million for the year.2019. See Capital Expenditures below for information regarding our exploration and development (“E&D”)&D activities for the three and ninesix months ended SeptemberJune 30, 20172019 and 2016.2018.
We periodically use derivative instruments to mitigate volatility in commodity prices. At SeptemberJune 30, 2017,2019, we had derivative contracts covering a portion of our 2017 and 20182019 - 2020 production. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may enter intoincrease or decrease our derivative instruments with durations of five to six quarters covering up to 50% of our oil and natural gas production on a forward eight quarter basis.positions from current levels. See Note 3 to the Condensed Consolidated Financial Statements for information regarding our derivative instruments.
We believe our conservative use of leverage, strong balance sheet, and hedging activities will mitigate our exposure to lower prices.
Cash and cash equivalents at SeptemberJune 30, 20172019 were $422.8$19.4 million. At SeptemberJune 30, 2017,2019, our long-term debt consisted of $1.5$2.0 billion of senior unsecured notes, with $750 million 4.375% notes due in 2024, and $750 million 3.90% notes due in 2027. During the second quarter of 2017, we completed a tender offer2027, and redemption of $750$500 million 5.875%4.375% notes due 2022 and issued the aforementioned 3.90% notes.in 2029. At SeptemberJune 30, 2017,2019, we had no borrowings and $2.5 million in letters of credit outstanding under our credit facility, leaving an unused borrowing availability of $997.5 million.$1.248 billion. See Long-term Debt below for more information regarding our debt.
Our debt to total capitalization ratio at SeptemberJune 30, 20172019 was 38%35%, downup from 42%31% at December 31, 2016.2018. This ratio is calculated by dividing the sum of (i) the principal amount of long-term debt and (ii) redeemable preferred stock by the sum of (i) the principal amount of long-term debt, (ii) redeemable preferred stock, and (ii)(iii) total stockholders’ equity, with all numbers coming directly from the Condensed Consolidated Balance Sheet. At September 30, 2017, the ratio calculation is $1.5 billion ÷ ($1.5 billion + $2.4 billion). Management uses this ratio as one indicator of our financial condition and believes professional research analysts and rating agencies use this ratio for this purpose and to compare our financial condition to other companies’ financial conditions. Additionally,
We may, from time to time, seek to repurchase our credit facility includes a financial covenantoutstanding preferred stock through cash repurchases and/or exchanges for the maintenance of a defined total debt-to-capital ratio of no greater than 65%.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.
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 in 2017 and beyond.for the next twelve months.
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.
| | | | Nine Months Ended September 30, | | Six Months Ended June 30, |
(in thousands) | | 2017 | | 2016 | | 2019 | | 2018 |
Net cash provided by operating activities | | $ | 755,805 |
| | $ | 440,788 |
| | $ | 664,083 |
| | $ | 704,339 |
|
Net cash used by investing activities | | $ | (924,635 | ) | | $ | (484,396 | ) | | $ | (1,022,672 | ) | | $ | (671,552 | ) |
Net cash used by financing activities | | $ | (61,238 | ) | | $ | (37,078 | ) | | $ | (422,663 | ) | | $ | (22,498 | ) |
Net cash provided by operating activities for the first ninesix months of 2017ended June 30, 2019 was $755.8$664.1 million, up $315.0down $40.3 million, or 71%6%, from $440.8$704.3 million for the first ninesix months of 2016.ended June 30, 2018. The $315.0$40.3 million increasedecrease resulted primarily from a period-over-period increase in production revenue, which increased due to increased realized commodity prices and production volumes. This increase was partially offset by net increasesoperating expenses. Partially offsetting this decrease in operating costs and expenses, increasedcash flows was a decrease in cash outflows for settlements of derivative instruments,instruments. Despite increased production volumes, revenue remained flat between the two periods due to decreased pricing and, an increase in our investment in working capital.therefore, did not offset the increased cash outflows for operating expenses. See RESULTS OF OPERATIONS above for more information regarding the changes in revenue and operating expenses.
Net cash used by investing activities for the first ninesix months of 2017ended June 30, 2019 and 2018 was $924.6$1.02 billion and $671.6 million, up $440.2 million or 91% from $484.4 million for the first nine months of 2016.respectively. The majority of our cash flows used by investing activities are for E&D expenditures, which totaled $711.8 million and $650.8 million for the six months ended June 30, 2019 and 2018, respectively. Cash used by investing activities in the six months ended June 30, 2019 includes the $325.7 million in cash paid for the Resolute acquisition, net of the $41.2 million in cash acquired with Resolute. The remaining investing cash outflows are primarily for midstream asset expenditures. In response to improved commodity prices, we have increased our 2017 capital spending over 2016 levels.Included in net cash used by investing activities are the proceeds of miscellaneous asset sales, including non-core oil and gas properties.
Net cash used by financing activities was $422.7 million and $22.5 million during the six months ended June 30, 2019 and 2018, respectively. During the six months ended June 30, 2019, we issued $500 million aggregate principal amount of 4.375% senior unsecured notes due March 15, 2029 at 99.862% of par for proceeds of $499.3 million, paying $4.6 million in underwriting fees and financing costs. Additionally, we borrowed and repaid an aggregate of $1.21 billion on our credit facility during the first ninesix months ended June 30, 2019 to assist in funding the Resolute acquisition and thereafter to meet cash requirements as needed. In connection with the acquisition of 2017 was $61.2Resolute, we assumed $870.0 million up $24.2in principal amount of long-term debt that we immediately repaid, incurring a redemption fee of $4.3 million. During the six months ended June 30, 2019, we amended our credit facility, paying $3.0 million or 65% from $37.1 million forin financing costs. We had no long-term debt-related investing cash flows during the first ninesix months of 2016.ended June 30, 2018. Net cash used by financing activities for the first nine months of 2017 includes $772.9 million used for the early extinguishment of the $750 million 5.875% senior notes due 2022, which included $22.6 million in tender and redemption premiums. Additionally, the 2017 period includes $741.8 million proceeds, net of underwriters’ fees, discount, and issuance costs, that we received for the issuance of $750 million 3.90% senior notes due 2027. The other primary components of net cash used by financing activities areduring both periods included: (i) the payment of dividends, and(ii) the payment of income tax withholdings made on behalf of our employees upon the net settlement of employee stock awards.awards, and (iii) the receipt of proceeds from exercises of stock options. During each of the first three quarters of 2017,six months ended June 30, 2019, we paid an $0.08one $0.18 per common share dividend, one $0.20 per common share dividend, and one $20.31 per preferred share dividend, totaling $22.7 million in dividends paid during$38.6 million. During the ninesix months ended SeptemberJune 30, 2017. We2018, we paid aone $0.08 per common share dividend and one $0.16 per common share dividend, in the first quartertotaling $22.8 million. Future dividend payments will depend on our level of 2016earnings, financial requirements, and an $0.08 per share dividend in eachother factors considered relevant by our Board of the second and third quarters of 2016, totaling $30.2 million in dividends paid during the nine months ended September 30, 2016. Directors.
Capital Expenditures
The following table presents capitalized expenditures for oil and gas property acquisitions andacquisition, exploration, and development (“E&D”) activities as well asand property sales, proceeds for property sales.net of applicable purchase price adjustments.
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
(in thousands) | | 2017 | | 2016 | | 2017 | | 2016 | | 2019 | | 2018 | | 2019 | | 2018 |
Acquisitions: | | | | | | | | | | | | | | | | |
Proved | | $ | — |
| | $ | — |
| | $ | 260 |
| | $ | 2,618 |
| | $ | 1,200 |
| | $ | — |
| | $ | 693,800 |
| | $ | 62 |
|
Unproved | | 438 |
| | 3,200 |
| | 4,263 |
| | 11,546 |
| | 1,000 |
| | 77 |
| | 1,051,782 |
| | 2,236 |
|
| | 438 |
| | 3,200 |
| | 4,523 |
| | 14,164 |
| | 2,200 |
| | 77 |
| | 1,745,582 |
| | 2,298 |
|
Exploration and development: | | |
| | | | |
| | | | |
| | | | | | |
Land and seismic | | 12,872 |
| | 16,974 |
| | 123,359 |
| | 45,610 |
| | 14,552 |
| | 10,327 |
| | 24,079 |
| | 20,424 |
|
Exploration and development | | 322,651 |
| | 157,571 |
| | 813,693 |
| | 443,279 |
| | 310,428 |
| | 365,097 |
| | 668,919 |
| | 668,469 |
|
| | 335,523 |
| | 174,545 |
| | 937,052 |
| | 488,889 |
| | 324,980 |
| | 375,424 |
| | 692,998 |
| | 688,893 |
|
Sales proceeds: | | | | | | | | | |
Property sales: | | | | | | | | | |
Proved | | 1,807 |
| | (376 | ) | | (85 | ) | | (12,605 | ) | | (22,058 | ) | | (4,577 | ) | | (18,028 | ) | | (29,541 | ) |
Unproved | | (780 | ) | | (9,207 | ) | | (8,051 | ) | | (9,608 | ) | | (6,253 | ) | | (441 | ) | | (9,754 | ) | | (5,301 | ) |
| | 1,027 |
| | (9,583 | ) | | (8,136 | ) | | (22,213 | ) | | (28,311 | ) | | (5,018 | ) | | (27,782 | ) | | (34,842 | ) |
| | $ | 336,988 |
| | $ | 168,162 |
| | $ | 933,439 |
| | $ | 480,840 |
| | $ | 298,869 |
| | $ | 370,483 |
| | $ | 2,410,798 |
| | $ | 656,349 |
|
Amounts in the table above are presented on an accrual basis. The Condensed Consolidated Statements of Cash Flows in this report reflect activities on a cash basis, when payments are made orand proceeds received.
On March 1, 2019, we completed the acquisition of Resolute Energy Corporation, an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the Permian Basin of west Texas. The fair value of the proved and unproved properties recorded in the preliminary purchase price allocation for this acquisition was $692.6 million and $1.05 billion, respectively.
Our 20172019 E&D capital investment is projected to range from $1.35 billion to $1.45 billion, with the majority expected to approximate $1.2 billion. Approximately 61% of our 2017 capital investment is projected to be invested in the Permian Basin with most of the remainder in the Mid-Continent region.
Basin. As has been our historical practice, we regularly review our capital expenditures throughout the year and will adjust our investments based on increases or decreases in commodity prices, service costs, and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions.
We intend to continue to fund our 2019 capital investment program with cash on hand and cash flow from our operating activities.activities, cash on hand, and borrowings under our credit facility. Sales of non-core assets and borrowings under our credit facilitypossible capital markets transactions may also be used to supplement funding of capital expenditures.expenditures and acquisitions. 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.time to time. See Long-term Debt—Bank Debt below for further information regarding our credit facility.
The following table reflects wells completed by region during the periods indicated.
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | | 2019 | | 2018 | | 2019 | | 2018 |
Gross wells | | | | | | | | | | | | | | | | |
Permian Basin | | 29 |
| | 17 |
| | 65 |
| | 37 |
| | 44 |
| | 32 |
| | 56 |
| | 49 |
|
Mid-Continent | | 48 |
| | 25 |
| | 133 |
| | 61 |
| | 66 |
| | 57 |
| | 92 |
| | 94 |
|
| | 77 |
| | 42 |
| | 198 |
| | 98 |
| | 110 |
| | 89 |
| | 148 |
| | 143 |
|
Net wells | | | | | | | | | | | | | | | | |
Permian Basin | | 16 |
| | 10 |
| | 42 |
| | 22 |
| | 32 |
| | 13 |
| | 37 |
| | 22 |
|
Mid-Continent | | 14 |
| | 7 |
| | 32 |
| | 14 |
| | 8 |
| | 10 |
| | 11 |
| | 16 |
|
| | 30 |
| | 17 |
| | 74 |
| | 36 |
| | 40 |
| | 23 |
| | 48 |
| | 38 |
|
As of SeptemberJune 30, 2017,2019, we had 2227 gross (10(13 net) wells in the process of being drilled: 714 gross (4(12 net) in the Permian Basin and 1513 gross (6(1 net) in the Mid-Continent region andregion. As of June 30, 2019, there were 10999 gross (23(24 net) wells waiting on completion: 3544 gross
(13 (20 net) in the Permian Basin and 7455 gross (10(4 net) in the Mid-Continent region. We alsoAs of June 30, 2019, we had 147 operated rigs running: eightrunning, all in the Permian Basin and six in the Mid-Continent region.Basin.
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 current 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 regulatory changes that would have a material impact, based on current laws and regulations. However, compliance with new legislation or regulations could increase our costs or adversely affect demand for oil or gas and result in a material adverse effect on our financial position or operations. See our Form 10-K/A10-K for the year ended December 31, 2016,2018, Item 1.A.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 SeptemberJune 30, 20172019 and December 31, 2016,2018 consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
(in thousands) | | Principal | | Unamortized Debt Issuance Costs and Discount (1) | | Long-term Debt, net | | Principal | | Unamortized Debt Issuance Costs | | Long-term Debt, net |
5.875% Senior Notes | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 750,000 |
| | $ | (5,691 | ) | | $ | 744,309 |
|
4.375% Senior Notes | | 750,000 |
| | (5,626 | ) | | 744,374 |
| | 750,000 |
| | (6,370 | ) | | 743,630 |
|
3.90% Senior Notes | | 750,000 |
| | (7,865 | ) | | 742,135 |
| | — |
| | — |
| | — |
|
Total long-term debt | | $ | 1,500,000 |
| | $ | (13,491 | ) | | $ | 1,486,509 |
| | $ | 1,500,000 |
| | $ | (12,061 | ) | | $ | 1,487,939 |
|
| | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2019 | | December 31, 2018 |
(in thousands) | | Principal | | Unamortized Debt Issuance Costs and Discounts (1) | | Long-term Debt, net | | Principal | | Unamortized Debt Issuance Costs and Discount (1) | | Long-term Debt, net |
4.375% Notes due 2024 | | $ | 750,000 |
| | $ | (3,982 | ) | | $ | 746,018 |
| | $ | 750,000 |
| | $ | (4,439 | ) | | $ | 745,561 |
|
3.90% Notes due 2027 | | 750,000 |
| | (6,651 | ) | | 743,349 |
| | 750,000 |
| | (7,007 | ) | | 742,993 |
|
4.375% Notes due 2029 | | 500,000 |
| | (5,137 | ) | | 494,863 |
| | — |
| | — |
| | — |
|
| | $ | 2,000,000 |
| | $ | (15,770 | ) | | $ | 1,984,230 |
| | $ | 1,500,000 |
| | $ | (11,446 | ) | | $ | 1,488,554 |
|
| |
(1) | At SeptemberJune 30, 2017,2019, the unamortized debt issuance costs and discount related to the 3.90% notesNotes due 2027 were $6.0$5.1 million and $1.8$1.5 million, respectively. At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $5.4 million and $1.6 million, respectively. At June 30, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.5 million and $0.7 million, respectively. The 4.375% notesNotes due 2024 were issued at par. |
Bank Debt
We have a
On February 5, 2019, we entered into an Amended and Restated Credit Agreement for our senior unsecured revolving credit facility (“Credit Facility”) that matures October 16, 2020. The Credit Facility has. Among other things, the amended and restated credit facility increased the aggregate commitments of $1.0to $1.25 billion with an option for us to increase the aggregate commitments to $1.25$1.5 billion, at any time. There is no borrowing base subjectand extended the maturity date to the discretion of the lenders based on the value of our proved reserves under the Credit Facility.February 5, 2024. As of SeptemberJune 30, 2017,2019, 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 $997.5 million.$1.248 billion. During the three months ended June 30, 2019, we borrowed and repaid an aggregate of $528.0 million on the Credit Facility to meet cash requirements as needed.
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-capital ratio of no greater than 65%. As of SeptemberJune 30, 2017,2019, we were in compliance with all of the financial covenants.
At SeptemberJune 30, 20172019 and December 31, 2016,2018, we had $3.6$4.6 million and $4.5$2.2 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. We incurred $3.0 million in additional debt issuance costs in amending our Credit Facility.
Senior Notes
On April 10, 2017,March 8, 2019, we completed a cash tender offer to purchase any of our 5.875% notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5issued $500 million aggregate principal amount of the notes validly tendered. We settled these tendered notes for $268.1 million, including accrued interest. On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for $512.0 million, including accrued interest. During the three months ended June 30, 2017, we recognized a loss on
early extinguishment of debt related to these transactions of $28.2 million, composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs. The original maturity date of the 5.875% notes was May 1, 2022.
On April 10, 2017, we issued $750 million aggregate principal amount of 3.90%4.375% senior unsecured notes due MayMarch 15, 20272029 at 99.748%99.862% of par to yield 3.93%4.392% per annum. We received $741.8$494.7 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs. The notes bear an annual interest rate of 4.375% and interest is payable semiannually on March 15 and September 15, with the first payment due September 15, 2019. We used the net proceeds to repay borrowings under our Credit Facility. 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 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, with15. The effective interest rate on these notes, including the first payment to be made November 15, 2017. Along with cash on hand, we used the proceeds to fund the settlementamortization of the tendereddebt issuance costs and redeemed 5.875% notes. discount, is 4.01%.
In June 2014, we issued $750 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%.
Each of our
Our senior unsecured notes isare governed by an indentureindentures containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of SeptemberJune 30, 2017. As of September 30, 2017, the effective interest rate on the 4.375% notes and the 3.90% notes, including the amortization of debt issuance costs and discount, as applicable, is 4.50% and 4.01%, respectively.2019.
Working Capital Analysis
Our working capital fluctuates primarily as a result of changes in our cash and cash equivalents,realized commodity prices, increases or decreases in our realized commodity pricesproduction volumes, changes in receivables and production volumes,payables related to our operating and E&D activities, changes in our oil and gas well equipment and supplies, and changes in receivables and payables related tothe fair value of our operating and E&D activities.derivative instruments.
At SeptemberJune 30, 2017,2019, we had a working capital deficit of $301.5$294.6 million, a decrease of $145.4 million$1.01 billion or 33% compared to141% from a working capital surplus of $447.0$715.4 million at December 31, 2016.2018.
Working
Our working capital decreasesdecreased primarily due to the decrease in Cash and cash equivalents of $781.3 million, which was a result of our acquisition of Resolute and subsequent repayment of Resolute’s long-term debt. See Note 13 to the Condensed Consolidated Financial Statements for more information regarding the acquisition. In addition to the decrease in cash, other significant changes to working capital consisted primarily of the following:following decreases:
Cash and cash equivalents
Our net current derivative instrument position decreased by $230.1$81.4 million from an asset at December 31, 2018 to a liability at June 30, 2019.
The adoption of Topic 842 increased our current liabilities by $68.7 million, representing estimated lease liabilities, primarily for office space, well-head compressors, pipeline compressors, and artificial lift mechanisms. See Note 10 to the Condensed Consolidated Financial Statements for more information regarding our lease liabilities and the adoption of Topic 842.
Accounts receivable decreased by $66.8 million.
Operations-related accounts payable and accrued liabilities increased by $90.5 million.
Accrued liabilities related to our E&D expenditures increased by $23.3 million.
Decreases in working capital were partially offset by the following primary increases:
Operations-related accounts receivable increased by $128.6 million.
Current derivative instruments increased by $50.5 million to a net asset.
Oil and gas well equipment and supplies increased by $21.2 million.
Cash on hand was used during the nine months ended September 30, 2017, along with cash flow from operations, primarily to fund our capital expenditures. 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. Historically, losses associated with uncollectible receivables have not been significant. The fair value of derivative instruments fluctuates based on changes in the underlying price indices as compared to the contracted prices.
Dividends
A quarterly cash dividend has been paid to stockholderson our common stock every quarter since the first quarter of 2006. In August 2017, an $0.08May 2019, our Board of Directors declared a cash dividend of $0.20 per common share, dividend was declared,totaling $20.3 million, which is payable on or before December 1, 2017August 30, 2019 to stockholders of record on NovemberAugust 15, 2017.2019. In March 2019, in conjunction with the Resolute acquisition, we issued 62.5 thousand shares of 8.125% Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share. In May 2019, our Board of Directors declared a cash dividend
of $20.31 per preferred share, totaling $1.3 million. The dividend was paid in July to preferred stockholders of record on July 1, 2019. Future dividend payments will depend on our level of earnings, financingfinancial requirements, and other factors considered relevant by our Board of Directors. Dividends declared are recorded as a reduction of retained earningsSee Note 5 to the extent retained earnings are available at the close of the period priorCondensed Consolidated Financial Statements for further information regarding our stock and Note 13 to the date ofCondensed Consolidated Financial Statements for further information regarding the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. Resolute acquisition.
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 SeptemberJune 30, 2017,2019, our material off-balance sheet arrangements consisted of operating lease agreements which are included inwith lease terms at commencement of 12 months or less. As an accounting policy we have elected not to apply the table below.
Topic 842 to these leases. As such, we have not recorded any lease liabilities associated with these leases.
Contractual Obligations and Material Commitments
At SeptemberJune 30, 2017,2019, we had the following contractual obligations and material commitments as follows:commitments:
|
| | | | | | | | | | | | | | | | | | | | |
| Payments Due by Period | |
Contractual obligations: | | | | 1 Year or | | 2 - 3 | | 4 - 5 | | | More than | |
(in thousands) | Total | | Less | | Years | | Years | | | 5 Years | |
Long-term debt-principal (1) | $ | 1,500,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,500,000 |
| |
Long-term debt-interest (1) | | 525,032 |
| | | 63,769 |
| | | 124,125 |
| | | 124,125 |
| | | 213,013 |
| |
Operating leases | | 89,564 |
| | | 9,770 |
| | | 21,619 |
| | | 22,328 |
| | | 35,847 |
| |
Unconditional purchase obligations (2) | | 39,773 |
| | | 9,117 |
| | | 9,653 |
| | | 8,730 |
| | | 12,273 |
| |
Derivative liabilities | | 5,990 |
| | | 5,778 |
| | | 212 |
| | | — |
| | | — |
| |
Asset retirement obligation (3) | | 157,247 |
| | | 12,612 |
| | | — |
| (3) | | — |
| (3) | | — |
| (3) |
Other long-term liabilities (4) | | 34,986 |
| | | 1,736 |
| | | 3,304 |
| | | 2,771 |
| | | 27,175 |
| |
| $ | 2,352,592 |
| | $ | 102,782 |
| | $ | 158,913 |
| | $ | 157,954 |
| | $ | 1,788,308 |
| |
| | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period | |
Contractual obligations (in thousands) | | Total | | 7/1/19 - 6/30/20 | | 7/1/20 - 6/30/22 | | 7/1/22 - 6/30/24 | | 7/1/24 and Thereafter | |
Long-term debt—principal (1) | | $ | 2,000,000 |
| | $ | — |
| | $ | — |
| | $ | 750,000 |
| | $ | 1,250,000 |
| |
Long-term debt—interest (1) | | 617,313 |
| | 82,307 |
| | 167,875 |
| | 167,875 |
| | 199,256 |
| |
Operating leases (2) | | 101,885 |
| | 24,961 |
| | 38,238 |
| | 23,551 |
| | 15,135 |
| |
Unconditional purchase obligations (3) | | 99,006 |
| | 24,556 |
| | 27,235 |
| | 19,153 |
| | 28,062 |
| |
Derivative liabilities | | 50,896 |
| | 50,056 |
| | 840 |
| | — |
| | — |
| |
Asset retirement obligation (4) | | 173,873 |
| | 16,492 |
| | — |
| (4) | — |
| (4) | — |
| (4) |
Other long-term liabilities (5) | | 43,066 |
| | 2,670 |
| | 3,401 |
| | 5,217 |
| | 31,778 |
| |
| | $ | 3,086,039 |
| | $ | 201,042 |
| | $ | 237,589 |
| | $ | 965,796 |
| | $ | 1,524,231 |
| |
| |
(1) | The interest payments presented above include the accrued interest payable on our long-term debt as of SeptemberJune 30, 20172019 as well as future payments calculated using the long-term debt’s fixed rates, stated maturity dates, and principal amounts outstanding as of SeptemberJune 30, 2017.2019. 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, 2019. These lease agreements are primarily comprised of leases for commercial real estate, which consists primarily of office space, and compressor equipment. |
| |
(3) | Of the total Unconditionalunconditional purchase obligations, $37.6$28.2 million represents obligations for the purchase of sand for well completions and $70.5 million represents obligations for firm transportation agreements for gas and oil pipeline capacity. |
| |
(3)(4) | We have excluded the presentation of the timing of the cash flows associated with our 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. |
| |
(4)(5) | Other long-term liabilities which are included in the Other liabilities line item on the Condensed Consolidated Balance Sheet, 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 whichmade that may include potential future cash payments if we fail to meet various performance obligations. These are not reflected in the table above. above, unless otherwise noted.
At SeptemberJune 30, 2017,2019, we had estimated commitments of approximately: (i) $181.2$304.6 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $24.6$19.2 million to finish gathering system construction in progress.
At SeptemberJune 30, 2017,2019, we had firm sales contracts to deliver approximately 207.2290.7 Bcf of natural gas over the next 7.35.6 years. If we do not deliver this gas, our estimated financial commitment, calculated using the October 2017July 2019 index price, would be approximately $491.0$303.3 million. The value of this commitment will fluctuate due to price volatility and actual volumes delivered. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.
In connection with gas gathering and processing agreements, we have volume commitments over the next 8.69.5 years. If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of SeptemberJune 30, 2017,2019, would be approximately $312.3$655.2 million. However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these 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, the estimated maximum amount that would be payable under these commitments, calculated as of SeptemberJune 30, 2017,2019, would be approximately $13.7$153.3 million. Of this total, we have accrued a liability of $1.9$4.6 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.
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, goodwill, contingencies, asset retirement obligations, 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/A10-K for the year ended December 31, 2016.2018.
Recent Accounting Developments
See Note 1 to the Condensed Consolidated Financial Statements in this report for a discussion of recently issued accounting pronouncements and their anticipated effect on our financial statements.
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 SeptemberJune 30, 2017,2019, our total production revenue was comprised of 51%approximately 76% oil sales, 28%6% gas sales, and 21%18% NGL sales. For the ninesix months ended SeptemberJune 30, 2017,2019, our total production revenue was comprised of 52%approximately 69% oil sales, 29%13% gas sales, and 19%18% NGL sales. The following table shows how hypothetical changes in the realized prices we receive onfor our commodity sales wouldmay have impacted revenue for the periods indicated.
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| Change in Realized Price | | Three Months Ended September June 30, 20172019 | | NineSix Months Ended September June 30, 20172019 |
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Oil | ± $1.00 | per barrel | | ± $5,215$7,592 | | ± $15,178$14,739 |
Gas | ± $0.10 | per Mcf | | ± $4,747$6,059 | | ± $13,834$11,811 |
NGL | ± $1.00 | per barrel | | ± $4,401$7,313 | | ± $12,778$13,879 |
| | | | ± $14,363$20,964 | | ± $41,790$40,429 |
We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. At SeptemberJune 30, 2017,2019, we had oil and gas derivatives covering a portion of our 20172019 and 20182020 production, which were recorded as current and non-current assets and current and non-current liabilities. At SeptemberJune 30, 2017,2019, our oil and gas derivatives had a gross asset fair value of $7.1$43.6 million and a gross liability fair value of $6.0$50.9 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 revenuescash flow from favorable price movements. The following table shows how hypothetical changes in the forward prices used to calculate the fair value of our derivatives wouldmay have impacted the fair value as of SeptemberJune 30, 2017.2019.
| | | | Impact on Fair Value | | Impact on Fair Value |
| Change in Forward Price | | September 30, 2017 | Change in Forward Price | | June 30, 2019 |
| | (in thousands) | | (in thousands) |
Oil | -$1.00 | | $ | 4,063 |
| -$1.00 | | $ | 5,969 |
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Oil | +$1.00 | | $ | (4,237 | ) | +$1.00 | | $ | (6,035 | ) |
Gas | -$0.10 | | $ | 4,200 |
| -$0.10 | | $ | 7,056 |
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Gas | +$0.10 | | $ | (4,038 | ) | +$0.10 | | $ | (6,963 | ) |
Interest Rate Risk
At SeptemberJune 30, 2017,2019, our long-term debt consisted of $750 million of 4.375% senior unsecured notes that will mature on June 1, 2024, and $750 million of 3.90% senior unsecured notes that will mature on May 15, 2027.2027, 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.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Cimarex
Cimarex’s management, under the supervision and with the participation of the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), have evaluated the effectiveness of Cimarex’s disclosure controls and procedures (as defined in RulesRule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)“Exchange Act”)) as of SeptemberJune 30, 2017.2019. 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 withor submitted under the SECExchange Act is recorded, processed, summarized, and reported within the time periods specified inrequired by the SEC’sU.S. Securities and Exchange Commission’s rules and forms. The disclosure controlsforms and procedures are designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow such persons to make 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 SeptemberJune 30, 20172019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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
In addition to the other information set forth in this report, you should carefully consider the risks discussed in our Annual Report on Form 10-K/A10-K for the year ended December 31, 2016. There have been no material changes in our risk factors from those described in the Annual Report on Form 10-K/A for the year ended December 31, 2016.2018. The risks described in the Annual Report on Form 10-K/A10-K for the year ended December 31, 20162018 are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or future results. Material changes from the risk factors previously disclosed in our Form 10-K for the year ended December 31, 2018 are set forth below.
Oil, gas, and NGL prices fluctuate due to a number of factors beyond our control, creating a component of uncertainty in our development plans and overall operations. Declines in prices adversely affect our financial results and rate of growth in proved reserves and production.
Oil and gas markets are volatile. We cannot predict future prices. The prices we receive for our production heavily influence our revenue, profitability, access to capital, and future rate of growth. The prices we receive depend on numerous factors beyond our control. These factors include, but are not limited to, changes in domestic and global supply and demand for oil and gas, the level of domestic and global oil and gas exploration and production activity, pipeline capacity constraints limiting takeaway and increasing basis differentials, geopolitical instability, the actions of the Organization of Petroleum Exporting Countries, weather conditions, technological advances affecting energy consumption, governmental regulations and taxes, and the price and technological advancement of alternative fuels.
Our proved oil and gas reserves and production volumes will decrease unless those reserves are replaced with new discoveries or acquisitions. Accordingly, for the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations, our revolving credit facility, and proceeds from the sale of senior notes or equity. Low prices reduce our cash flow and the amount of oil and gas that we can economically produce and may cause us to curtail, delay, or defer certain exploration and development projects. Moreover, low prices may impact our abilities to borrow under our revolving credit facility and to raise additional debt or equity capital to fund acquisitions.
If commodity pricing conditions stay at current levels or decline further, we will be required to take write-downs of the carrying value of our oil and gas properties.
Under the full cost method of accounting, we are required to perform quarterly ceiling test calculations to test our oil and gas properties for possible impairment. At June 30, 2019, a decline of approximately 4% or more in the value of our ceiling limitation would have resulted in an impairment. If commodity pricing conditions stay at current levels or decline further we will incur full cost ceiling impairments in future quarters. Because the ceiling calculation uses trailing twelve-month average commodity prices, the effect of declining prices is a lower ceiling value each quarter. This will result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.
ITEM 6. EXHIBITS
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith.
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101.INS | | XBRL 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.SCH | | Inline XBRL Taxonomy Extension Schema Document |
101.CAL | | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
101.LAB | | Inline XBRL Taxonomy Extension Label Linkbase Document |
101.PRE | | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
101.DEF | | Inline XBRL Taxonomy Extension Definition Linkbase Document |
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.
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November 8, 2017August 5, 2019 | |
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| CIMAREX ENERGY CO. |
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| /s/ G. Mark Burford |
| G. Mark Burford |
| Senior Vice President and Chief Financial Officer |
| (Principal Financial Officer) |
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| /s/ Timothy A. Ficker |
| Timothy A. Ficker |
| Vice President, Controller, and Chief Accounting Officer |
| (Principal Accounting Officer) |