Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 28, 2018 | Jun. 30, 2017 | |
Document And Entity Information [Line Items] | |||
Entity Registrant Name | Parsley Energy, Inc. | ||
Trading Symbol | PE | ||
Entity Central Index Key | 1,594,466 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 7,591,987,385 | ||
Class A Common Stock | |||
Document And Entity Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 264,053,796 | ||
Class B Common Stock | |||
Document And Entity Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 52,731,731 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 554,189 | $ 133,379 |
Short-term investments | 149,283 | 0 |
Restricted cash | 0 | 3,290 |
Accounts receivable: | ||
Joint interest owners and other | 42,174 | 12,698 |
Oil, natural gas and NGLs | 123,147 | 59,174 |
Related parties | 388 | 290 |
Short-term derivative instruments | 41,957 | 39,708 |
Assets held for sale | 1,790 | 0 |
Other current assets | 6,558 | 50,949 |
Total current assets | 919,486 | 299,488 |
PROPERTY, PLANT AND EQUIPMENT | ||
Oil and natural gas properties, successful efforts method | 8,551,314 | 4,063,417 |
Accumulated depreciation, depletion, amortization and impairment | (822,459) | (506,175) |
Total oil and natural gas properties, net | 7,728,855 | 3,557,242 |
Other property, plant and equipment net | 106,587 | 59,318 |
Total property, plant and equipment, net | 7,835,442 | 3,616,560 |
NONCURRENT ASSETS | ||
Assets held for sale, net | 14,985 | 0 |
Long-term derivative instruments | 15,732 | 16,416 |
Other noncurrent assets | 7,553 | 6,318 |
Total noncurrent assets | 38,270 | 22,734 |
TOTAL ASSETS | 8,793,198 | 3,938,782 |
CURRENT LIABILITIES | ||
Accounts payable and accrued expenses | 407,698 | 162,317 |
Revenue and severance taxes payable | 109,917 | 69,452 |
Current portion of long-term debt | 2,352 | 67,214 |
Short-term derivative instruments | 84,919 | 44,153 |
Current portion of asset retirement obligations | 7,203 | 1,818 |
Total current liabilities | 612,089 | 344,954 |
NONCURRENT LIABILITIES | ||
Liabilities related to assets held for sale | 405 | 0 |
Long-term debt | 2,179,525 | 1,041,324 |
Asset retirement obligations | 19,967 | 9,574 |
Deferred tax liability, net | 21,403 | 5,483 |
Payable pursuant to tax receivable agreement | 58,479 | 94,326 |
Long-term derivative instruments | 20,624 | 12,815 |
Total noncurrent liabilities | 2,300,403 | 1,163,522 |
COMMITMENTS AND CONTINGENCIES | ||
STOCKHOLDERS’ EQUITY | ||
Preferred stock, $0.01 par value, 50,000,000 shares authorized, none issued and outstanding | 0 | 0 |
Additional paid in capital | 4,666,365 | 2,151,197 |
Retained earnings (accumulated deficit) | 43,519 | (63,255) |
Treasury stock, at cost, 159,301 shares and 139,416 at December 31, 2017 and December 31, 2016 | (735) | (381) |
Total stockholders’ equity | 4,712,295 | 2,089,638 |
Noncontrolling interest | 1,168,411 | 340,668 |
Total equity | 5,880,706 | 2,430,306 |
TOTAL LIABILITIES AND EQUITY | 8,793,198 | 3,938,782 |
Class A, $0.01 par value, 600,000,000 shares authorized, 252,419,601 shares issued and 252,260,300 shares outstanding at December 31, 2017 and 179,730,033 shares issued and 179,590,617 shares outstanding at December 31, 2016 | ||
STOCKHOLDERS’ EQUITY | ||
Common stock | 2,524 | 1,797 |
Class B, $0.01 par value, 125,000,000 shares authorized, 62,128,257 and 28,008,573 issued and outstanding at December 31, 2017 and December 31, 2016 | ||
STOCKHOLDERS’ EQUITY | ||
Common stock | $ 622 | $ 280 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Treasury stock, shares | 159,301 | 139,416 |
Class A Common Stock | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 600,000,000 | 600,000,000 |
Common stock, shares issued | 252,419,601 | 179,730,033 |
Common stock, shares outstanding | 252,260,300 | 179,590,617 |
Class B Common Stock | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 125,000,000 | 125,000,000 |
Common stock, shares issued | 62,128,257 | 28,008,573 |
Common stock, shares outstanding | 62,128,257 | 28,008,573 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
REVENUES | |||
Oil sales | $ 802,230 | $ 387,303 | $ 215,795 |
Natural gas sales | 56,571 | 30,928 | 26,582 |
Natural gas liquids sales | 103,193 | 38,273 | 23,680 |
Other | 5,050 | 1,269 | 417 |
Total revenues | 967,044 | 457,773 | 266,474 |
OPERATING EXPENSES | |||
Lease operating expenses | 102,169 | 59,293 | 62,913 |
Production and ad valorem taxes | 59,641 | 27,916 | 17,800 |
Depreciation, depletion and amortization | 352,247 | 233,766 | 178,281 |
General and administrative expenses (including stock-based compensation of $19,619, $12,871 and $8,133 for the years ended December 31, 2017, 2016 and 2015) | 124,255 | 84,591 | 55,294 |
Exploration and abandonment costs | 40,415 | 13,931 | 13,865 |
Impairment | 0 | 0 | 950 |
Acquisition costs | 10,977 | 1,081 | 0 |
Accretion of asset retirement obligations | 971 | 732 | 826 |
Rig termination costs | 0 | 0 | 8,970 |
Other operating expenses | 9,568 | 5,316 | 1,696 |
Total operating expenses | 700,243 | 426,626 | 340,595 |
OPERATING INCOME (LOSS) | 266,801 | 31,147 | (74,121) |
OTHER (EXPENSE) INCOME | |||
Interest expense, net | (97,381) | (56,225) | (45,581) |
Loss on sale of property | (14,332) | (119) | (34,374) |
Loss on early extinguishment of debt | (3,891) | (36,335) | 0 |
(Loss) gain on derivatives | (66,135) | (50,835) | 60,818 |
Change in TRA liability | 35,847 | 7,351 | 0 |
Interest income | 7,936 | 992 | 28 |
Other income (expense) | 783 | (2,317) | (3,556) |
Total other expense, net | (137,173) | (137,488) | (22,665) |
INCOME (LOSS) BEFORE INCOME TAXES | 129,628 | (106,341) | (96,786) |
INCOME TAX (EXPENSE) BENEFIT | (5,708) | 17,424 | 23,755 |
NET INCOME (LOSS) | 123,920 | (88,917) | (73,031) |
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS | (17,146) | 14,735 | 22,547 |
NET INCOME (LOSS) ATTRIBUTABLE TO PARSLEY ENERGY, INC. STOCKHOLDERS | $ 106,774 | $ (74,182) | $ (50,484) |
Net income (loss) per common share: | |||
Basic (in dollars per share) | $ 0.44 | $ (0.46) | $ (0.45) |
Diluted (in dollars per share) | $ 0.42 | $ (0.46) | $ (0.45) |
Weighted average common shares outstanding: | |||
Basic (shares) | 240,733 | 161,793 | 111,271 |
Diluted (shares) | 296,512 | 161,793 | 111,271 |
CONSOLIDATED STATEMENTS OF OPE5
CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Stock based compensation | $ 19,619 | $ 12,871 | $ 8,133 |
General and Administrative Expense | |||
Stock based compensation | $ 19,619 | $ 12,871 | $ 8,133 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Thousands | Total | Class A Common Stock | Class B Common Stock | Common StockClass A Common Stock | Common StockClass B Common Stock | Additional paid in capital | (Accumulated deficit) retained earnings | Treasury stock | Total stockholders’ equity | Noncontrolling interest |
Balance (in shares) at Dec. 31, 2014 | 93,937,000 | 32,145,000 | 37,000 | |||||||
Balance at Dec. 31, 2014 | $ 992,489 | $ 932 | $ 321 | $ 644,636 | $ 61,352 | $ 707,241 | $ 285,248 | |||
Issuance of Class A Common Stock, net of underwriters discount and expenses (in shares) | 42,748,000 | |||||||||
Issuance of Class A Common Stock, net of underwriters discount and expenses | 669,418 | $ 428 | 668,990 | 669,418 | ||||||
Change in equity due to issuance of PE Units by Parsley LLC | (56,856) | (56,856) | 56,856 | |||||||
Increase in net deferred tax liability due to issuance of PE Units by Parsley LLC | (18,383) | (18,383) | (18,383) | |||||||
Tax benefit from tax receivable agreement | 5,500 | 5,500 | 5,500 | |||||||
Initial noncontrolling interest allocation attributable to Pacesetter | 2,592 | 2,592 | ||||||||
Issuance of restricted stock (in shares) | 42,000 | |||||||||
Vesting of restricted stock units (in shares) | 2,000 | |||||||||
Vesting of restricted stock units | (6) | $ (6) | (6) | |||||||
Restricted stock forfeited (in shares) | 68,000 | |||||||||
Restricted stock forfeited | (364) | (293) | $ (71) | (364) | ||||||
Stock-based compensation | 8,426 | 8,426 | 8,426 | |||||||
Net (loss) income | (73,031) | (50,484) | (50,484) | (22,547) | ||||||
Balance (in shares) at Dec. 31, 2015 | 136,729,000 | 32,145,000 | 105,000 | |||||||
Balance at Dec. 31, 2015 | 1,586,641 | $ 1,360 | $ 321 | 1,252,020 | 10,868 | $ (77) | 1,264,492 | 322,149 | ||
Adoption of ASU 2016-09 | Adoption of ASU 2016-09 | 59 | 59 | 59 | |||||||
Restated balance (in shares) | 136,729,000 | 32,145,000 | 105,000 | |||||||
Restated balance | 1,586,700 | $ 1,360 | $ 321 | 1,252,020 | 10,927 | $ (77) | 1,264,551 | 322,149 | ||
Issuance of Class A Common Stock, net of underwriters discount and expenses (in shares) | 38,812,000 | |||||||||
Issuance of Class A Common Stock, net of underwriters discount and expenses | 930,315 | $ 388 | 929,927 | 930,315 | ||||||
Change in equity due to issuance of PE Units by Parsley LLC | (80,255) | (80,255) | 80,255 | |||||||
Increase in net deferred tax liability due to issuance of PE Units by Parsley LLC | (13,215) | (13,215) | (13,215) | |||||||
Tax benefit from tax receivable agreement | 8,855 | 8,855 | 8,855 | |||||||
Exchange of PE Units and Class B Common Stock for Class A Common Stock (in shares) | 4,137,000 | (4,137,000) | ||||||||
Exchange of PE Units and Class B Common Stock for Class A Common Stock | $ 41 | $ (41) | 47,001 | 47,001 | (47,001) | |||||
Change in net deferred tax liability due to exchange of PE Units and Class B Common Stock for Class A Common Stock | (5,999) | (5,999) | (5,999) | |||||||
Issuance of restricted stock (in shares) | 37,000 | |||||||||
Vesting of restricted stock units (in shares) | 15,000 | |||||||||
Vesting of restricted stock units | (91) | $ 8 | (8) | $ (91) | (91) | |||||
Repurchase of common stock (in shares) | 12,000 | |||||||||
Repurchase of common stock | (213) | $ (213) | (213) | |||||||
Restricted stock forfeited (in shares) | 22,000 | |||||||||
Restricted stock forfeited | (105) | (105) | (105) | |||||||
Stock-based compensation | 12,976 | 12,976 | 12,976 | |||||||
Net (loss) income | (88,917) | (74,182) | (74,182) | (14,735) | ||||||
Balance (in shares) at Dec. 31, 2016 | 179,730,000 | 28,008,000 | 139,000 | |||||||
Balance at Dec. 31, 2016 | 2,430,306 | $ 1,797 | $ 280 | 2,151,197 | (63,255) | $ (381) | 2,089,638 | 340,668 | ||
Restated balance (in shares) | 179,590,617 | 28,008,573 | ||||||||
Issuance of Class A Common Stock, net of underwriters discount and expenses (in shares) | 66,700,000 | |||||||||
Issuance of Class A Common Stock, net of underwriters discount and expenses | 2,123,527 | $ 667 | 2,122,860 | 2,123,527 | ||||||
Shares of Class B Common Stock issued for acquisition (in shares) | 39,849,000 | |||||||||
Shares of Class B Common Stock issued for acquisition | 1,183,318 | $ 399 | 1,182,919 | 1,183,318 | ||||||
Change in equity due to issuance of PE Units by Parsley LLC | (915,749) | (915,749) | 915,749 | |||||||
Exchange of PE Units and Class B Common Stock for Class A Common Stock (in shares) | 5,729,000 | (5,729,000) | ||||||||
Exchange of PE Units and Class B Common Stock for Class A Common Stock | $ 57 | $ (57) | 105,522 | 105,522 | (105,522) | |||||
Issuance of restricted stock (in shares) | 228,000 | |||||||||
Issuance of restricted stock | 370 | $ 3 | (3) | 370 | ||||||
Vesting of restricted stock units (in shares) | 33,000 | |||||||||
Repurchase of common stock (in shares) | 12,000 | |||||||||
Repurchase of common stock | (354) | $ (354) | (354) | |||||||
Restricted stock forfeited (in shares) | 8,000 | |||||||||
Restricted stock forfeited | (14) | (14) | (14) | |||||||
Stock-based compensation | 19,633 | 19,633 | 19,633 | |||||||
Net (loss) income | 123,920 | 106,774 | 106,774 | 17,146 | ||||||
Balance (in shares) at Dec. 31, 2017 | 252,420,000 | 62,128,000 | 159,000 | |||||||
Balance at Dec. 31, 2017 | $ 5,880,706 | $ 2,524 | $ 622 | $ 4,666,365 | $ 43,519 | $ (735) | $ 4,712,295 | $ 1,168,411 | ||
Restated balance (in shares) | 252,260,300 | 62,128,257 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $ 123,920 | $ (88,917) | $ (73,031) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 352,247 | 233,766 | 178,281 |
Impairment expense | 0 | 0 | 950 |
Inventory write down | 1,060 | 0 | 4,147 |
Accretion of asset retirement obligations | 971 | 732 | 826 |
Loss on sale of property | 14,332 | 119 | 34,374 |
Loss on early extinguishment of debt | 3,891 | 36,335 | 0 |
Amortization and write off of deferred loan origination costs | 4,720 | 3,190 | 2,702 |
Amortization of bond premium | (516) | (874) | (764) |
Deferred income tax expense (benefit) | 5,752 | (17,582) | (24,041) |
Change in TRA liability | (35,847) | (7,351) | 0 |
Stock-based compensation expense | 19,619 | 12,871 | 8,133 |
Loss (gain) on derivatives | 66,135 | 50,835 | (60,818) |
Net cash received for derivative settlements | 16,172 | 32,364 | 43,767 |
Net cash (paid) received for option premiums | (28,426) | (10,334) | 40,656 |
Net premiums (paid) received on options that settled during the period | (37,103) | 31,757 | 11,406 |
Other | 33,719 | 6,169 | 7,310 |
Changes in operating assets and liabilities, net of acquisitions: | |||
Restricted cash | 3,290 | (2,151) | (1,139) |
Accounts receivable | (95,239) | (35,774) | 24,103 |
Accounts receivable—related parties | (98) | 100 | 3,675 |
Materials and supplies | 0 | 0 | 3,767 |
Other current assets | 82,520 | (71,052) | (22,793) |
Other noncurrent assets | (536) | 748 | (588) |
Accounts payable and accrued expenses | 122,992 | 20,897 | (7,001) |
Revenue and severance taxes payable | 40,465 | 32,343 | (1,257) |
Other noncurrent liabilities | 0 | 0 | (375) |
Net cash provided by operating activities | 694,040 | 228,191 | 172,290 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Development of oil and natural gas properties | (1,089,256) | (505,802) | (382,550) |
Acquisitions of oil and natural gas properties | (2,192,093) | (1,346,190) | (73,807) |
Acquisition of Pacesetter Drilling, LLC | 0 | 0 | (2,408) |
Additions to other property and equipment | (54,896) | (33,374) | (19,755) |
Proceeds from sale of property | 30,537 | 0 | 51,355 |
Purchases of short-term investments | (149,283) | 0 | 0 |
Other | (1,869) | 0 | 0 |
Net cash used in investing activities | (3,456,860) | (1,885,366) | (427,165) |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Borrowings under long-term debt | 1,152,780 | 1,057,500 | 105,000 |
Payments on long-term debt | (74,769) | (521,944) | (225,794) |
Debt issue costs | (17,371) | (18,097) | (1,138) |
Proceeds from issuance of common stock, net | 2,123,344 | 930,315 | 669,418 |
Purchases of common stock | (354) | (213) | (71) |
Vesting of restricted stock units | 0 | (91) | (6) |
Net cash provided by financing activities | 3,183,630 | 1,447,470 | 547,409 |
Net increase (decrease) in cash and cash equivalents | 420,810 | (209,705) | 292,534 |
Cash and cash equivalents at beginning of year | 133,379 | 343,084 | 50,550 |
Cash and cash equivalents at end of year | 554,189 | 133,379 | 343,084 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | |||
Cash paid for interest | 63,170 | 65,513 | 43,993 |
Cash paid for income taxes | 350 | 315 | 0 |
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES: | |||
Asset retirement obligations incurred, including changes in estimate | 15,428 | (6,646) | 3,441 |
Additions (reductions) to oil and natural gas properties - change in capital accruals | 118,145 | (9,831) | 18,300 |
Additions to other property and equipment funded by capital lease borrowings | 3,904 | 2,758 | 939 |
Common stock issued for oil and natural gas properties | $ 1,183,501 | $ 0 | $ 0 |
Organization and Nature of Oper
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | ORGANIZATION AND NATURE OF OPERATIONS Parsley Energy, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company”) was formed on December 11, 2013, pursuant to the laws of the State of Delaware to succeed the Company’s predecessor, which began operations in August 2008 when it acquired operator rights to wells producing from the Spraberry Trend in the Midland Basin. The Company is engaged in the acquisition and development of unconventional oil and natural gas reserves located in the Permian Basin, which is located in West Texas and Southeastern New Mexico. Double Eagle Acquisition On April 20, 2017, the Company, and its subsidiary, Parsley Energy LLC (“Parsley LLC”), completed the acquisition (the “Double Eagle Acquisition”) of all of the interests in Double Eagle Lone Star LLC, DE Operating LLC, and Veritas Energy Partners, LLC (which were subsequently renamed Parsley DE Lone Star LLC, Parsley DE Operating LLC, and Parsley Veritas Energy Partners, LLC, respectively) from Double Eagle Energy Permian Operating LLC (“DE Operating”), Double Eagle Energy Permian LLC (“DE Permian”), and Double Eagle Energy Permian Member LLC (together with DE Operating and DE Permian, “Double Eagle”), as well as certain related transactions with an affiliate of Double Eagle. The aggregate purchase price for the Double Eagle Acquisition consisted of approximately (i) $1,395.6 million in cash and (ii) 39,848,518 units of Parsley LLC (“PE Units”) and a corresponding 39,848,518 shares of the Company’s Class B common stock, par value $0.01 per share (“Class B Common Stock”). The Double Eagle Acquisition is discussed in further detail in Note 5—Acquisitions of Oil and Natural Gas Properties. As described in Note 8—Equity , under the Second Amended and Restated Limited Liability Company Agreement of Parsley LLC (the “Parsley LLC Agreement”), the holders of PE Units generally have the right to exchange their PE Units (and a corresponding number of shares of Class B Common Stock) for shares of the Company’s Class A common stock, par value $0.01 per share (“Class A Common Stock”), at an exchange ratio of one share of Class A Common Stock for each PE Unit (and corresponding share of Class B Common Stock) exchanged, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications. Public Offerings of Common Stock During 2015, the Company entered into multiple underwriting agreements to sell a total of 42,747,161 shares of Class A Common Stock (including 1,950,000 shares issued pursuant to the underwriters’ option to purchase additional shares) in multiple underwritten public offerings (the “2015 Equity Offerings”). The 2015 Equity Offerings resulted in gross proceeds of approximately $683.7 million to the Company and net proceeds to the Company, after deducting underwriting discounts and commissions and offering expenses, of approximately $669.4 million . The Company used a portion of the net proceeds to repay outstanding borrowings under the Company’s Revolving Credit Agreement (as defined in Note 7—Debt ), to fund certain acquisitions of oil and natural gas interests and for general corporate purposes. During 2016, the Company entered into multiple underwriting agreements to sell a total of 38,812,500 shares of Class A Common Stock (including 5,062,500 shares issued pursuant to the underwriters’ option to purchase additional shares) in multiple underwritten public offerings (the “2016 Equity Offerings”). The 2016 Equity Offerings resulted in gross proceeds to the Company of approximately $962.2 million and net proceeds to the Company, after deducting underwriting discounts and commissions and offering expenses, of approximately $930.3 million . The Company used a portion of the net proceeds to fund certain acquisitions of oil and natural gas interests and the remaining net proceeds to fund a portion of its capital program and for general corporate purposes, including acquisitions. On January 10, 2017 , the Company entered into an underwriting agreement to sell 25,300,000 shares of Class A Common Stock (including 3,300,000 shares issued pursuant to the underwriters’ option to purchase additional shares) at a price of $35.00 per share in an underwritten public offering (the “January Offering”). The January Offering closed on January 17, 2017 and resulted in gross proceeds to the Company of approximately $885.5 million and net proceeds to the Company, after deducting underwriting discounts and commissions and offering expenses, of approximately $863.0 million . The Company used a portion of the net proceeds from the January Offering to fund the aggregate purchase price for certain acquisitions of oil and natural gas interests in the Midland and Delaware Basins and the remaining net proceeds to fund a portion of its capital program and for general corporate purposes, including acquisitions. On February 7, 2017 , the Company entered into an underwriting agreement to sell 41,400,000 shares of Class A Common Stock (including 5,400,000 shares issued pursuant to the underwriters’ option to purchase additional shares), at a price of $31.00 per share in an underwritten public offering (the “February Offering,” and together with the January Offering, the “2017 Equity Offerings”). The February Offering closed on February 13, 2017 and resulted in gross proceeds to the Company of approximately $1,283.4 million and net proceeds to the Company, after deducting underwriting discounts and commissions and offering expenses of approximately $1,260.5 million . As discussed in Note 5— Acquisitions of Oil and Natural Gas Properties , a portion of the net proceeds was used to partially fund the cash portion of the purchase price for the Double Eagle Acquisition. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation These consolidated financial statements include the accounts of (i) the Company, (ii) Parsley LLC, (iii) the direct and indirect wholly owned subsidiaries of Parsley LLC, and (iv) an indirect, majority owned subsidiary of Parsley LLC, Pacesetter Drilling, LLC, of which Parsley LLC owns, indirectly, a 63.0% interest. Parsley LLC also owns, indirectly, a 42.5% noncontrolling interest in Spraberry Production Services, LLC (“SPS”). The Company accounts for its investment in SPS using the equity method of accounting. All significant intercompany and intra-company balances and transactions have been eliminated. Use of Estimates These consolidated financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires the Company to (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the SEC and (ii) make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The Company’s management believes the major estimates and assumptions impacting the Company’s consolidated financial statements are the following: • estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization and impairment of capitalized costs of oil and natural gas properties; • operating costs accrued and volumes and prices for revenues accrued; • estimates of asset retirement obligations; • estimates of the fair value assets acquired and liabilities assumed in business combinations; • evaluations of impairment of proved and unproved properties are subject to number uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks; • impairment of other assets; • depreciation of property and equipment; • valuation of commodity derivative instruments; and • estimates of the fair value of stock-based compensation. Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting. Cash and Cash Equivalents The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. Restricted Cash The Company’s restricted cash at December 31, 2016 of $3.3 million consisted of cash deposited into an escrow account that was contractually restricted involving a non-related party. The restricted cash included revenues associated with an operated well. During December 2017, the matter was resolved, resulting in the release of $4.8 million , including all of the escrowed funds, and the Company’s recognition of $3.6 million of sales, net of production taxes. As of December 31, 2017 , the Company had no restricted cash. Short-term Investments Periodically, the Company invests in commercial paper with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than three months at the date of purchase; otherwise, investments are reflected as short-term investments in the accompanying consolidated balance sheets based on their maturity dates. As of December 31, 2017, all of the Company’s short-term investments mature within one year. Accounts Receivable Accounts receivable consist of receivables from joint interest owners on properties the Company operates and crude oil, natural gas and NGLs production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments are received within three months after the production date. Amounts due from joint interest owners or purchasers are stated net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2017 or December 31, 2016 . Significant Customers For the years ended December 31, 2017 , 2016 and 2015 , each of the following purchasers accounted for more than 10% of the Company’s revenue: Year Ended December 31, 2017 2016 2015 Shell Trading (US) Company 62% 44% 23% BML, Inc. 2% 13% 19% Targa Pipeline Mid-Continent, LLC 13% 13% 12% TransOil Marketing, LLC 1% 8% 13% The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties and mineral interests are subject to depreciation, depletion and amortization (“DD&A”). Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated reservoir. The Company capitalizes interest on expenditures made in connection with long term projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use and only to the extent the company has incurred interest expense. On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from the property accounts and any gain or loss is recognized. For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing first day of the month 12-month average price, net of historical differentials, with no provision for price and cost escalations in future years except by contractual arrangements. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Oil and gas properties are depleted by field using the units-of-production method. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. Asset Retirement Obligations For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely the plugging and abandonment of wells and land remediation. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period. If the liability is settled for an amount other than the recorded amount, the difference is recorded in other income (expense) in the consolidated statements of operations. Inherent to the present value calculation are numerous estimates, assumptions and judgments, including, but not limited to: the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions affect the present value of the abandonment liability, the Company makes corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. These revisions result in prospective changes to DD&A expense and accretion of the discounted abandonment liability. The following table summarizes the changes in the Company’s asset retirement obligation for the periods indicated (in thousands): Year ended December 31, 2017 2016 Asset retirement obligations, beginning of year $ 11,392 $ 18,220 Additional liabilities incurred 9,081 3,290 Disposition of wells (432 ) (858 ) Accretion expense 971 732 Liabilities settled upon plugging and abandoning wells (189 ) (56 ) Revision of estimates 6,752 (9,936 ) Liabilities related to assets held for sale (405 ) — Asset retirement obligations, end of year $ 27,170 $ 11,392 Allocation of Purchase Price in Business Combinations As part of its business strategy, the Company regularly pursues the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The Company’s most significant estimates in its allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. Impairment of Oil and Natural Gas Properties The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties by field. Whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, an impairment loss is indicated if the sum of the expected future cash flows related to proved properties in the applicable field is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. See Note 13— Disclosures about Fair Value of Financial Instruments for additional information regarding the Company’s impairment of proved oil and natural gas properties. Exploration and Abandonment Costs Exploration and abandonment costs, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures and other geological and geophysical costs, exploratory dry holes, impairment and amortization of unproved leasehold costs and lease rentals. The costs of exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a 12-month period after drilling is complete. Unproved oil and natural gas properties are assessed quarterly for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. The following table summarizes exploration and abandonment costs incurred by the Company for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Leasehold abandonments $ 32,872 $ 6,063 $ 8,227 Geological and geophysical costs 5,429 3,015 5,459 Idle drilling rig fees 1,070 4,304 — Unproved leasehold amortization 1,044 549 179 Total exploration and abandonment costs $ 40,415 $ 13,931 $ 13,865 Other Property and Equipment, net Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three years to 15 years . Depreciation expense on other property and equipment was $11.5 million , $6.6 million and $4.7 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Materials and supplies are stated at the lower of cost or market and consists of oil and gas drilling or repair items such a tubing, casing and pumping units. These items are primarily acquired for use in future drilling or repair operations and are carried at lower of cost or market. “Market,” in the context of valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint account under joint operating agreements to which the Company is a party. The Company evaluated materials and supplies based on current operations and determined that these materials and supplies would not be utilized in the current year and includes them in noncurrent assets as non-depreciable other property, plant and equipment. See Note 13—Disclosures about Fair Value of Financial Instruments for additional information regarding the Company’s impairment of materials and supplies. Equity Investments Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss, after elimination of intra-company profit or loss, is recognized in the consolidated statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2017 , 2016 and 2015 . Derivative Instruments The Company uses derivative financial instruments to reduce exposure to fluctuations in commodity prices. These transactions are in the form of crude options and collars. The Company reports the fair value of derivatives on the consolidated balance sheets in derivative instrument assets and derivative instrument liabilities as either current or noncurrent. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The Company reports these on a gross basis by contract. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses resulting from the changes in fair value of derivatives are included in cash flows from operating activities. Fair Value of Financial Instruments Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants at the reporting date. The Company’s assets and liabilities that are measured at fair value at each reporting date are classified according to a hierarchy that prioritizes inputs and assumptions underlying the valuation techniques. This fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs and consists of three broad levels: Level 1 : Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 : Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date. Level 3 : Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. Deferred Loan Costs Deferred loan costs are stated at cost, net of amortization and are amortized to interest expense using the effective interest method over the life of the loan. Revenue Recognition Revenues from the sale of crude oil, natural gas and NGLs are recognized when the production is sold, net of any royalty interest. Because final settlement of the Company’s hydrocarbon sales can take up to two months, the expected sales volumes and prices for those properties are estimated and accrued using information available at the time the revenue is recorded. Natural gas revenues are recorded using the entitlement method of accounting whereby revenue is recognized based on the Company’s proportionate share of natural gas production. At December 31, 2017 , 2016 and 2015 , the Company did not have any natural gas imbalances. Transportation expenses are included as a reduction of natural gas revenue and are not material. Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for the benefit of all employees at their date of hire. The plan allows eligible employees to contribute a portion of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contribution of up to a certain percentage of an employee’s contributions. For the years ended December 31, 2017 , 2016 and 2015 , the Company made contributions to the plan of $2.8 million , $1.9 million and $1.4 million , respectively. Income Taxes The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities. SEC Staff Accounting Bulletin No. 118 provides guidance for companies that have not completed their accounting for the income tax effects of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), in the period of enactment and allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. As of February 28, 2018 , the Company has substantially completed its accounting for the tax effects of the enactment of the Tax Act. The Company has made a reasonable estimate of the effects on its deferred tax balances. The Company is still analyzing certain aspects of the Tax Act and the Company is refining its calculations, which could potentially affect the measurement of related deferred tax balances or potentially give rise to new deferred tax amounts. The Company does not expect that a material adjustment to its deferred tax position will result from the completion of its computations, which the Company expects to finalize by the fourth quarter of 2018. To account for the effects of the Tax Cut and Jobs Act, the Company remeasured its deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, and they now generally reflect a federal income tax rate of 21%. The enacted rate change resulted in a noncash increase of approximately $23.9 million to the Company’s income tax provision, a corresponding reduction of $23.9 million to the Company’s net noncurrent deferred tax asset balance and a reduction in valuation allowance of $24.3 million December 31, 2017 . Any adjustments recorded to these estimates through 2018 will be included in income from operations as an adjustment to tax expense. The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends and its outlook for future years. Earnings per Share The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and restricted stock units. Comprehensive Income The Company has no elements of comprehensive income other than net income. Segment Reporting Operating segments are defined as components of an enterprise (i) that engage in activities from which it may earn revenues and incur expenses and (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based on the organization and management of the Company, the Company has only one reportable operating segment, which is oil and natural gas exploration and production. The Company considers drilling rig services ancillary to its oil and gas exploration and production activities and manages these services to support such activities. Reclassifications Certain reclassifications have been made to prior period amounts to conform to the current presentation. Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, Revenue Recognition, and most industry-specific guidance. This revenue recognition model provides a five-step analysis for determining when and how revenue is recognized, and requires an entity (i) to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) provide expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers , which deferred the effective date of ASU 2014-09 by one year. The Company adopted this standard effective January 1, 2018 using the modified retrospective approach. During the fourth quarter of 2017, the Company completed a detailed review of various contracts that represent its material revenue streams and, based on such review, does not expect the standard to materially affect the Company’s results of operations, liquidity or financial position in 2018. Additionally, the Company will begin recognizing revenues based on the entitlement method rather than the sales method; this change will not have a material impact on the Company’s results of operations or financial position in 2018. The Company has also implemented processes and controls to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the required disclosures under the standards. As described above, beginning with the Company’s Form 10-Q for the three months ended March 31, 2018, additional disclosures will be required to describe the nature, amount, timing and certainty of revenue and cash flows from contracts with customers, including a disaggregation of revenue and remaining performance obligations. As an example of this evaluation and disclosure, under the Company’s natural gas processing contracts, the Company delivers natural gas to midstream processing companies at the wellhead or their system inlets. The midstream processing companies gather and process the delivered natural gas and, in turn, remit proceeds to the Company for sales of NGLs and residue gas. In these scenarios, the Company evaluates whether the midstream processing company is acting as the principal or the agent. For those contracts where it is concluded the midstream processing company is acting as an agent and the ultimate third party is the Company’s customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in its Statement of Operations. For those contracts where it is concluded the midstream processing company is acting as the principal and the Company is the customer, the Company recognizes natural gas and NGLs revenues based on the net amount of proceeds received. In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall , which addresses the fair value measurements, impairment assessment and disclosure requirements of equity securities, equity investments and other financial instruments and also clarifies current guidance to aid in the reduction of diversity in practice. For public business entities, the amended guidance is effective for fiscal years beginning after December 15, 2017 and for interim periods within those years. The amended guidance should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments related to equity securities without readily determinable fair values should be applied prospectively. The Company has completed its evaluation of the effect of the standard on its ongoing financial reporting and has determined the ASU will not materially impact its consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which modifies lessees’ recognition of lease assets and lease liabilities for those leases classified as operating leases under previous GAAP. In January 2018, the FASB issued ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which permits an entity to elect an optional transition practical expedient to not evaluate under land easements that exist or expired before the entity's adoption of this ASU and that were not previously accounted for as leases. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating all existing leases and agreements that are covered by this standard and will continue to evaluate the impact on the financial statements and related disclosures. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) , which provides guidance on eight specific cash flow issues, including cash payments associated with debt and debt modification, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and corporate-owned life insurance policies, distributions made from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017. The amendments should be applied using a retrospective transition method to each period presented. Early adoption is permitted for any entity in any interim or annual period. The Company has completed their evaluation of the ASU and has determined the standard will not materially affect the Company’s consolidated financial statements or notes to the consolidated financial statements, with the exception of presentation on the Company’s statement of cash flows. In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740) , which requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. This ASU also eliminates the exception for an intra-entity transfer of an asset other than inventory. The amended guidance does not include new disclosure requirements; however, existi |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Financial Instruments | DERIVATIVE FINANCIAL INSTRUMENTS Commodity Derivative Instruments and Concentration of Risk Objective and Strategy The Company utilizes put spread options, three-way collars, two-way collars, commodity swap contracts and basis swap contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company uses put spread options and collars to manage commodity price risk for NYMEX WTI. A put spread option is a combination of two options: a purchased put and a sold put. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price plus the excess of the purchased put strike price over the sold put strike price. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. Additionally, the Company uses basis swap contracts to mitigate basis risk caused by the volatility of the Company’s basis differentials. The basis swap contracts establish the differential between Cushing WTI prices and the relevant price index at which oil production is sold. Oil Production Derivative Activities The Company’s material physical sales contracts governing its oil production are tied directly to, or are typically correlated with, NYMEX WTI oil prices. The Company uses put spread options, collars and three-way collars to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX WTI prices and the actual index prices at which the oil is sold. The following table sets forth the volumes associated with the Company’s outstanding oil derivative contracts expiring during the periods indicated and the weighted average oil prices for those contracts: Year Ending December 31, Crude Options 2018 2019 Put spread Purchased: Puts (1) Notional (MBbl) 10,500 2,100 Weighted average strike price $ 50.43 $ 50.00 Sold: Puts (1) Notional (MBbl) (10,500 ) (2,100 ) Weighted average strike price $ 40.29 $ 40.00 Three-way collars Purchased: Puts Notional (MBbl) 14,100 3,000 Weighted average strike price $ 50.21 $ 50.00 Sold: Puts Notional (MBbl) (14,100 ) (3,000 ) Weighted average strike price $ 40.05 $ 40.00 Calls Notional (MBbl) (14,100 ) (3,000 ) Weighted average strike price $ 70.54 $ 80.40 Two-way Collars Purchased: Puts Notional (MBbl) 825 — Weighted average strike price $ 45.67 $ — Sold: Calls Notional (MBbl) (825 ) — Weighted average strike price $ 61.31 $ — Basis swap contracts: (2) Midland-Cushing index swap volume (MBbl) (3) 4,158 — Price differential ($/Bbl) $ (0.86 ) $ — (1) Excludes 1,818 notional MBbls with a fair value of $1.4 million related to amounts recognized under master netting agreements with derivative counterparties. (2) Represents swaps that fix the basis differentials between the index prices at which the Company sells its oil produced in the Permian Basin and the Cushing WTI price. Natural Gas Production Derivative Activities All material physical sales contracts governing the Company’s natural gas production are tied directly or indirectly to NYMEX Henry Hub natural gas prices or regional index prices where the natural gas is sold. The Company uses three-way collars and swaps to manage natural gas price volatility. The following table sets forth the volumes associated with the Company’s outstanding natural gas derivative contracts expiring during the periods indicated and the weighted average natural gas prices for those contracts: Year Ending December 31, Natural Gas 2018 Three-Way Collars Purchased: Puts Notional (MMbtu) 5,400 Weighted average strike price $ 3.11 Sold: Puts Notional (MMbtu) (5,400 ) Weighted average strike price $ 2.68 Calls Notional (MMbtu) (5,400 ) Weighted average strike price $ 4.09 Swaps Volume (MMbtu) 450 Strike price ($/MMbtu) $ 3.50 Effect of Derivative Instruments on the Consolidated Financial Statements All of the Company’s derivatives are accounted for as non-hedge derivatives and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The table below summarizes the Company’s gains (losses) on derivative instruments for the years ended December 31, 2017 , 2016 and 2015 (in thousands): Year Ending December 31, 2017 2016 2015 Changes in fair value of derivative instruments $ (44,702 ) $ (109,033 ) 2,958 Net derivative settlements 15,670 26,441 46,454 Net premiums realization on options that settled during the period (37,103 ) 31,757 11,406 (Loss) gain on derivatives $ (66,135 ) $ (50,835 ) $ 60,818 The Company classifies the fair value amounts of derivative assets and liabilities as gross current or noncurrent derivative assets or gross current or noncurrent derivative liabilities, whichever the case may be, excluding those amounts netted under master netting agreements. The fair value of the derivative instruments is discussed in Note 13—Disclosures about Fair Value of Financial Instruments. The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and liabilities at settlement or in the event of default under the agreements. Additionally, the Company maintains accounts with its brokers to facilitate financial derivative transactions in support of its risk management activities. Based on the value of the Company’s positions in these accounts and the associated margin requirements, the Company may be required to deposit cash into these broker accounts. During the years ended December 31, 2017 , 2016 and 2015 , the Company did not receive or post any margins in connection with collateralizing its derivative positions. The following table presents the Company’s net exposure from its offsetting derivative asset and liability positions, as well as option premiums payable and receivable as of the reporting dates indicated (in thousands): Gross Amount Netting Adjustments Net Exposure December 31, 2017 Derivative assets with right of offset or master netting agreements $ 59,132 $ (1,443 ) $ 57,689 Derivative liabilities with right of offset or master netting agreements (106,986 ) 1,443 (105,543 ) December 31, 2016 Derivative assets with right of offset or master netting agreements $ 66,417 $ (10,293 ) $ 56,124 Derivative liabilities with right of offset or master netting agreements (67,261 ) 10,293 (56,968 ) Concentration of Credit Risk The financial integrity of the Company’s exchange-traded contracts is assured by NYMEX through systems of financial safeguards and transaction guarantees and is therefore subject to nominal credit risk. Over-the-counter traded options expose the Company to counterparty credit risk. These over-the-counter options are entered into with a large multinational financial institution with investment grade credit rating or through brokers that require all the transaction parties to collateralize their open option positions. The gross and net credit exposure from the Company’s commodity derivative contracts as of December 31, 2017 and 2016 is summarized in the preceding table. The Company monitors the creditworthiness of its counterparties, established credit limits according to the Company’s credit policies and guidelines and assesses the impact on fair values of its counterparties’ creditworthiness. The Company typically enters into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with its derivative counterparties. The terms of the ISDA Agreements provide the Company and its counterparties and brokers with rights of net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The Company routinely exercises its contractual right to offset realized gains against realized losses when settling with derivative counterparties. The Company did not incur any losses due to counterparty bankruptcy filings during any of the years ended December 31, 2017 , 2016 or 2015 . Credit Risk Related Contingent Features in Derivatives Certain commodity derivative instruments contain provisions that require the Company to either post additional collateral or immediately settle any outstanding liability balances upon the occurrence of a specified credit risk related event. These events, which are defined by the existing commodity derivative contracts, are primarily downgrades in the credit ratings of the Company and its affiliates. None of the Company’s commodity derivative instruments, excluding net premiums payable, were in a net liability position with respect to any individual counterparty at December 31, 2017 or 2016 . |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment includes the following (in thousands): December 31, 2017 December 31, 2016 Oil and natural gas properties: Subject to depletion $ 4,492,802 $ 2,376,712 Not subject to depletion Incurred in 2017 2,837,766 — Incurred in 2016 947,210 1,215,920 Incurred in 2015 and prior 273,536 470,785 Total not subject to depletion 4,058,512 1,686,705 Oil and natural gas properties, successful efforts method 8,551,314 4,063,417 Less accumulated depreciation, depletion and impairment (822,459 ) (506,175 ) Total oil and natural gas properties, net 7,728,855 3,557,242 Other property, plant and equipment 131,115 73,382 Less accumulated depreciation (24,528 ) (14,064 ) Other property, plant and equipment, net 106,587 59,318 Total property, plant and equipment, net $ 7,835,442 $ 3,616,560 Costs subject to depletion are proved costs and costs not subject to depletion are unproved costs and current drilling projects. At December 31, 2017 and 2016 , the Company had excluded $4,058.5 million and $1,686.7 million of capitalized costs from depletion. As the Company’s exploration and development work progresses, and the reserves on the Company’s properties are proven, capitalized costs attributed to the properties and mineral interests are subject to DD&A. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated reservoir. Depletion expense on capitalized oil and gas properties was $340.8 million , $227.2 million and $173.6 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. The Company had no exploratory wells in progress at December 31, 2017 , 2016 or 2015 . Costs not subject to depletion primarily include leasehold costs, broker and legal expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Leasehold costs are transferred into costs subject to depletion on an ongoing basis as these properties are evaluated and proved reserves are established. Costs not subject to depletion also include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $94.4 million and $49.4 million at December 31, 2017 and 2016, respectively. The Company anticipates that the $94.4 million associated with the wells in progress at December 31, 2017 will be transferred to costs subject to depletion during 2017. The $49.4 million associated with the wells in progress at December 31, 2016 was transferred to costs subject to depletion during 2017. The Company capitalizes interest on expenditures made in connection with long term projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use and only to the extent the company has incurred interest expense. There was no capitalized interest recorded during the year ended December 31, 2017 , 2016 or 2015 . |
Acquisitions of Oil and Natural
Acquisitions of Oil and Natural Gas Properties | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Acquisitions of Oil and Natural Gas Properties | ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES The Company incurred costs of $194.5 million , $79.1 million and $38.8 million related to the acquisition of leasehold acreage during the years ended December 31, 2017 , 2016 and 2015 , respectively, which are included as part of costs not subject to depletion. During the year ended December 31, 2017 , the Company reflected $176.5 million , as part of costs not subject to depletion and $18.0 million , as part of costs subject to depletion within its oil and natural gas properties. During 2017, the Company acquired, from unaffiliated individuals and entities, interests in certain oil and natural gas properties through a number of separate, individually negotiated transactions, including the Double Eagle Acquisition (as defined in Note—1 Organization and Nature of Operations ), for total consideration of $3,181.1 million . These acquisitions were accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the acquired assets and liabilities to be recorded at fair values as of the respective acquisition dates. The Company reflected $464.2 million of the total consideration paid as part of its costs subject to depletion within its oil and natural gas properties and $2,716.9 million , as unproved leasehold costs within its oil and natural gas properties for year ended December 31, 2017. Excluding the Double Eagle Acquisition, the revenues and operating expenses attributable to these acquisitions during the year ended December 31, 2017 were not material. As described in Note—1 Organization and Nature of Operations, on April 20, 2017, the Company and Parsley LLC completed the Double Eagle Acquisition, as well as certain related transactions with an affiliate of Double Eagle. The aggregate consideration for the Double Eagle Acquisition, following post-closing adjustments, was $2,579.1 million , which consisted of (i) approximately $1,395.6 million in cash and (ii) 39,848,518 PE Units and a corresponding 39,848,518 shares of Class B Common Stock. Of the aggregate consideration transferred, approximately $172.3 million in cash and approximately 4,921,557 PE Units (and a corresponding approximately 4,921,557 shares of Class B Common Stock) were deposited in an indemnity holdback escrow account. The Company is in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in the Double Eagle Acquisition, and as a result, the estimates for fair value are subject to change. The Company anticipates certain changes, including, but not limited to, adjustments to working capital that are expected to be finalized prior to the measurement period’s expiration. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed as a result of the Double Eagle Acquisition (in thousands): Cash $ 2,469 Receivables 20,413 Derivatives 3,970 Proved oil and natural gas properties 353,000 Unproved oil and natural gas properties 2,257,289 Total assets acquired 2,637,141 Accounts payable (47,859 ) Deferred tax liability (10,167 ) Total liabilities assumed (58,026 ) Estimated fair value of net assets acquired $ 2,579,115 The Company has included in its consolidated statements of operations revenues of $75.9 million and earnings of $25.9 million for the period of April 20, 2017 to December 31, 2017 due to the Double Eagle Acquisition. The Double Eagle Acquisition was deemed material for purposes of the following pro forma disclosures. The Double Eagle Acquisition was not included in the Company’s consolidated results until its closing date. The following unaudited pro forma information for the years ended December 31, 2017 and 2016 represents the results of the Company’s consolidated operations as if the Double Eagle Acquisition had occurred on January 1, 2016. This information is based on historical results of operations, adjusted for certain estimated accounting adjustments and does not purport to show the Company’s actual results of operations if the transaction would have occurred on January 1, 2016, nor is it necessarily indicative of future results. The financial information was derived from the Company’s unaudited historical consolidated financial statements for the years ended December 31, 2017 and 2016 and Double Eagle’s unaudited interim financial statements from January 1, 2016 to April 20, 2017. Year Ending December 31, (in thousands, except per share data) 2017 2016 Revenues $ 986,168 $ 494,073 Operating income 276,015 19,284 Net income (loss) 138,912 (116,696 ) Net income (loss) attributable to Parsley Energy, Inc. Stockholders 105,629 (86,280 ) Net income (loss) per common share: Basic $ 0.43 $ (0.44 ) Diluted $ 0.41 $ (0.44 ) During 2016 , the Company acquired from unaffiliated individuals and entities, interests in certain oil and natural gas properties through a number of separate, individually negotiated transactions for total cash consideration of $1,267.1 million . The Company reflected $261.4 million of the total consideration paid as part of its costs subject to depletion and $1,005.7 million as unproved leasehold costs within its oil and gas properties. The revenues and operating expenses attributable to the working interest acquisitions during the years ended December 31, 2017 and 2016 were not material. During 2017 and 2016, the Company exchanged certain unproved acreage and oil and natural gas properties with a third party, with no gain or loss recognized. During 2015 , the Company acquired from unaffiliated individuals and entities, interests in certain oil and natural gas properties through a number of separate, individually negotiated transactions for total cash consideration of $35.0 million . The Company reflected $16.4 million of the total consideration paid as part of its costs subject to depletion and $18.6 million as unproved leasehold costs within its oil and gas properties. The revenues and operating expenses attributable to the working interest acquisitions during the years ended December 31, 2017 , 2016 and 2015 were not material. |
Sales of Oil and Natural Gas Pr
Sales of Oil and Natural Gas Properties | 12 Months Ended |
Dec. 31, 2017 | |
Gain (Loss) on Disposition of Oil and Gas Property [Abstract] | |
Sales of Oil And Natural Gas Properties | SALES OF OIL AND NATURAL GAS PROPERTIES In 2017, the Company sold 21,939 gross ( 7,476 net) acres for total proceeds of $30.5 million and recognized a $14.3 million loss on the divestitures. In 2016, there was no such divestiture activity. In 2015, the Company sold its interest in 91 net operated wells and 25,077 gross ( 16,319 net) acres for total proceeds of $48.7 million and recognized a $33.5 million loss on the divestitures. Assets Held For Sale As of December 31, 2017 , certain assets and related liabilities (the “Assets Held For Sale”) were classified as held for sale due to a pending divestiture. Upon the classification change occurring on December 31, 2017 , the Company ceased recording depletion on the Assets Held For Sale. Based on the Company’s anticipated sales price and historical cost, the Company will not recognize an impairment charge at December 31, 2017 . The following table presents balance sheet information related to the Assets Held for Sale: Assets: Accounts receivable, net $ 1,790 Oil and natural gas properties Proved oil and natural gas properties 18,435 Less: Accumulated depreciation, depletion and amortization (3,450 ) Oil and natural gas properties, net 14,985 Total assets held for sale, net $ 16,775 Liabilities: Asset retirement obligations 405 Total liabilities related to assets held for sale $ 405 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt | DEBT The Company’s debt consists of the following (in thousands): December 31, 2017 December 31, 2016 Revolving Credit Agreement $ — $ — 7.500% senior unsecured notes due 2022 — 61,846 6.250% senior unsecured notes due 2024 400,000 400,000 5.375% senior unsecured notes due 2025 650,000 650,000 5.250% senior unsecured notes due 2025 450,000 — 5.625% senior unsecured notes due 2027 700,000 — Capital leases 4,906 3,752 Other — 3,500 Total debt 2,204,906 1,119,098 Debt issuance costs on senior unsecured notes (26,341 ) (14,388 ) Premium on senior unsecured notes 3,312 3,828 Less: current portion (2,352 ) (67,214 ) Total long-term debt $ 2,179,525 $ 1,041,324 Revolving Credit Agreement On October 28, 2016, the Company and its subsidiary Parsley LLC entered into a new revolving credit agreement with, among others, Wells Fargo Bank, National Association, as administrative agent (the “New Revolving Credit Agreement”), providing for an initial borrowing base of $900.0 million and an initial commitment level of $600.0 million . The Revolving Credit Agreement replaced the Company’s previously existing amended and restated revolving credit agreement with, among others, Wells Fargo Bank, National Association, as administrative agent, which was terminated concurrently with entry into the New Revolving Credit Agreement. As used in these consolidated financial statements, the term “Revolving Credit Agreement” refers, prior to October 28, 2016, to the previously existing amended and restated credit agreement and, subsequent to October 28, 2016, to the New Revolving Credit Agreement. The Revolving Credit Agreement provides for a five -year senior secured revolving credit facility, maturing on October 28, 2021, with a borrowing capacity of the lesser of (i) the borrowing base, (ii) aggregate elected borrowing base commitments and (iii) $2.5 billion . The Revolving Credit Agreement is secured by substantially all of Parsley LLC’s and its restricted subsidiaries’ assets. As of December 31, 2017 , the Revolving Credit Agreement, as amended to date, provides for a borrowing base of $1.8 billion , which will continue to be redetermined by the lenders on a semi-annual basis each April 1 and October 1, with a commitment level of $1.0 billion . There were no borrowings outstanding and $2.7 million in letters of credit outstanding under the Revolving Credit Agreement as of December 31, 2017 , resulting in availability of approximately $997.3 million . The amount Parsley LLC is able to borrow under the Revolving Credit Agreement is subject to compliance with the financial covenants, satisfaction of various conditions precedent to borrowing and other provisions of the Revolving Credit Agreement. Borrowings under the Revolving Credit Agreement can be made in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBO rate plus an applicable margin ranging from 1.5% to 2.5% , depending on the percentage of the borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greater of (i) the prime rate of Wells Fargo, (ii) the federal funds effective rate plus 0.5% and (iii) the adjusted LIBO rate plus 1.0% , plus an applicable margin ranging from 0.5% to 1.5% , depending on the percentage of the borrowing base utilized. The Revolving Credit Agreement also provides for a commitment fee ranging from 0.375% to 0.500% , depending on the percentage of the borrowing base utilized. As of December 31, 2017 , letters of credit outstanding under the Revolving Credit Agreement had a weighted average interest rate of 1.50% . The Company may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. The Revolving Credit Agreement is subject to various financial covenants, which include, for example, the maintenance of the following financial ratios: • a minimum current ratio (based on the ratio of consolidated current assets to consolidated current liabilities) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and • a maximum Consolidated Leverage Ratio of not more than 4.0 to 1.0 as of the last day of any fiscal quarter for the four fiscal quarters ending on such date. The Revolving Credit Agreement places restrictions on Parsley LLC and certain of its subsidiaries with respect to, for example, additional indebtedness, liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters. The Revolving Credit Agreement also places customary “holding company” restrictions on the activities of the Company. Redemption of 2022 Notes On December 6, 2016, Parsley LLC commenced a cash tender offer (the “Tender Offer”) to purchase any and all of the Company’s 7.500% senior unsecured notes due 2022 (the “2022 Notes”). On December 13, 2016, the Tender Offer expired and, at such time, $487.7 million aggregate principal amount of the 2022 Notes was validly tendered (which did not include $1.2 million aggregate principal amount of the 2022 Notes that remained subject to guaranteed delivery procedures). Parsley LLC accepted all of the 2022 Notes validly tendered and not validly withdrawn in the Tender Offer and, on December 13, 2016, made a cash payment of $537.1 million , which included principal of $487.7 million , a prepayment premium on the extinguishment of debt of $32.5 million , accrued interest of $12.0 million and other debt issuance costs of $4.9 million . On December 15, 2016, Parsley LLC made a cash payment of $0.5 million for the tender of an additional $0.4 million aggregate principal amount of the 2022 Notes and $0.1 million of prepayment premium on the extinguishment of debt and accrued interest. On January 5, 2017, Parsley LLC redeemed $61.8 million aggregate principal of the 2022 Notes that remained outstanding and made a cash payment of $67.5 million to the remaining holders of the 2022 Notes, which included principal of $61.8 million , prepayment premium on the extinguishment of debt of $3.9 million and accrued interest of $1.8 million . During the years ended December 31, 2017 and 2016, the Company recognized a loss on extinguishment of debt of $3.9 million and $36.3 million , respectively, which are included in Prepayment premium on extinguishment of debt on the Company’s consolidated statements of operations and in operating activities on the Company’s statements of cash flows. 6.250% Senior Unsecured Notes due 2024 On May 27, 2016, Parsley LLC and Parsley Finance Corp. (the “Issuers”) issued $200.0 million aggregate principal amount of 6.250% senior unsecured notes due 2024 (the “Initial 2024 Notes”) in an offering that was exempt from registration under the Securities Act (the “Initial 2024 Notes Offering”). The Initial 2024 Notes Offering resulted in net proceeds to the Company, after deducting initial purchaser discounts and commissions and offering expenses, of approximately $195.4 million . On August 19, 2016, the Issuers issued an additional $200.0 million aggregate principal amount of 6.250% senior notes due 2024 (the “New 2024 Notes” and together with the Initial 2024 Notes, the “2024 Notes”) at 102.000% of par, plus accrued and unpaid interest from May 27, 2016, in an offering that was exempt from registration under the Securities Act (the “New 2024 Notes Offering”). The New 2024 Notes were issued as additional notes under the indenture governing the Initial 2024 Notes. The New 2024 Notes have identical terms, other than the issue date, as the Initial 2024 Notes and the New 2024 Notes and Initial 2024 Notes will be treated as a single class of securities under the indenture governing the 2024 Notes. Interest is payable on the 2024 Notes semi-annually in arrears on each June 1 and December 1 and commenced December 1, 2016. The 2024 Notes are fully and unconditionally guaranteed on a senior unsecured basis by all of the subsidiaries of Parsley LLC that guarantee the indebtedness under the Revolving Credit Agreement, other than Finance Corp. (the “Guarantor Subsidiaries”). The 2024 Notes are not guaranteed by the Company and the Company is not subject to the terms of the indenture governing the 2024 Notes. The New 2024 Notes Offering resulted in gross proceeds to the Company of $206.8 million , including a $4.0 million premium and $2.8 million of accrued and unpaid interest and net proceeds to the Company, after deducting accrued and unpaid interest, initial purchaser discounts and commissions and offering expenses, of approximately $199.6 million . The interest received is included in Accounts payable and accrued expenses on the Company’s consolidated balance sheets and as an operating activity on the consolidated statements of cash flows. At any time prior to June 1, 2019, the Issuers may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 106.250% of the principal amount of the 2024 Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption, provided that at least 65% of the aggregate principal amount issued under the indenture governing the 2024 Notes remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. Prior to June 1, 2019, the Issuers may, on any one or more occasions, redeem all or a part of the 2024 Notes for cash at a redemption price equal to 100% of the principal amount of the 2024 Notes redeemed, plus a “make-whole” premium as of and accrued and unpaid interest, if any, to, the date of redemption. On and after June 1, 2019, the Issuers may redeem the 2024 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 104.688% for the 12-month period beginning on June 1, 2019, 103.125% for the 12-month period beginning June 1, 2020, 101.563% for the 12-month period beginning on June 1, 2021 and 100% beginning on June 1, 2022, plus accrued and unpaid interest to the redemption date. The indenture governing the 2024 Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Issuers’ ability and the ability of their restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. 5.375% Senior Unsecured Notes due 2025 On December 13, 2016, the Issuers issued $650.0 million aggregate principal amount of 5.375% senior unsecured notes due 2025 (the “2025 Notes”) in an offering that was exempt from registration under the Securities Act (the “2025 Notes Offering”). Interest is payable on the 2025 Notes semi-annually in arrears on each January 15 and July 15, commencing July 15, 2017. The 2025 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantor Subsidiaries. The 2025 Notes are not guaranteed by the Company and the Company is not subject to the terms of the indenture governing the 2025 Notes. The 2025 Notes Offering resulted in gross proceeds to the Company of $650.0 million and net proceeds to the Company, after deducting initial purchaser discounts and commissions and offering expenses, of approximately $644.1 million . At any time prior to January 15, 2020, the Issuers may, from time to time, redeem up to 35% of the aggregate principal amount of the 2025 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 105.375% of the principal amount of the 2025 Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption, provided that at least 65% of the aggregate principal amount issued under the indenture governing the 2025 Notes remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. Prior to January 15, 2020, the Issuers may, on any one or more occasions, redeem all or a part of the 2025 Notes at a redemption price equal to 100% of the principal amount of the 2025 Notes redeemed, plus a “make-whole” premium as of and accrued and unpaid interest, if any, to, the date of redemption. On and after January 15, 2020, the Issuers may redeem the 2025 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 104.031% for the 12-month period beginning on January 15, 2020, 103.750% for the 12-month period beginning January 15, 2021, 101.344% for the 12-month period beginning on January 15, 2022 and 100% beginning on January 15, 2023, plus accrued and unpaid interest to the redemption date. The indenture governing the 2025 Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Issuers’ ability and the ability of their restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. 5.250% Senior Unsecured Notes due 2025 On February 13, 2017, the Issuers issued $450.0 million aggregate principal amount of 5.250% senior unsecured notes due 2025 (the “New 2025 Notes”) in an offering that was exempt from registration under the Securities Act (the “New 2025 Notes Offering”). Interest is payable on the New 2025 Notes semi-annually in arrears on each February 15 and August 15, commencing August 15, 2017. The New 2025 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantor Subsidiaries. The New 2025 Notes are not guaranteed by the Company and the Company is not subject to the terms of the indenture governing the New 2025 Notes. The New 2025 Notes Offering resulted in net proceeds to the Company, after deducting initial purchaser discounts and commissions and offering expenses, of approximately $444.1 million . At any time prior to August 15, 2020, the Issuers may, from time to time, redeem up to 35% of the aggregate principal amount of the New 2025 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 105.250% of the principal amount of the New 2025 Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption, provided that at least 65% of the aggregate principal amount issued under the indenture governing the New 2025 Notes remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. Prior to August 15, 2020, the Issuers may, on any one or more occasions, redeem all or a part of the New 2025 Notes at a redemption price equal to 100% of the principal amount of the New 2025 Notes redeemed, plus a “make-whole” premium as of and accrued and unpaid interest, if any, to, the date of redemption. On and after January 15, 2020, the Issuers may redeem the New 2025 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 103.938% for the 12-month period beginning on August 15, 2020, 102.625% for the 12-month period beginning August 15, 2021, 101.313% for the 12-month period beginning on August 15, 2022 and 100% beginning on August 15, 2023, plus accrued and unpaid interest to the redemption date. The indenture governing the New 2025 Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Issuers’ ability and the ability of their restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. 5.625% Senior Unsecured Notes due 2027 On October 11, 2017, the Issuers issued $700.0 million aggregate principal amount of 5.625% senior unsecured notes due 2027 (the “2027 Notes” and together with the 2024 Notes, the 2025 Notes and the New 2025 Notes, the “Notes”) in an offering that was exempt from registration under the Securities Act (the “2027 Notes Offering”). Interest is payable on the 2027 Notes semi-annually in arrears on each April 15 and October 15, commencing April 15, 2018. The 2027 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantor Subsidiaries. The 2027 Notes are not guaranteed by the Company and the Company is not subject to the terms of the indenture governing the 2027 Notes. The 2027 Notes Offering resulted in gross proceeds to the Company of $700.0 million and net proceeds to the Company, after deducting initial purchaser discounts and commissions and offering expenses, of approximately $692.1 million . At any time prior to October 15, 2020, the Issuers may, from time to time, redeem up to 35% of the aggregate principal amount of the 2027 Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 105.625% of the principal amount of the 2027 Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption, provided that at least 65% of the aggregate principal amount issued under the indenture governing the 2027 Notes remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. Prior to October 15, 2020, the Issuers may, on any one or more occasions, redeem all or a part of the 2027 Notes at a redemption price equal to 100% of the principal amount of the 2027 Notes redeemed, plus a “make-whole” premium as of and accrued and unpaid interest, if any, to, the date of redemption. On and after October 15, 2022, the Issuers may redeem the 2027 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 102.813% for the 12-month period beginning on October 15, 2022, 101.875% for the 12-month period beginning October 15, 2023, 100.938% for the 12-month period beginning on October 15, 2024 and 100% beginning on October 15, 2025, plus accrued and unpaid interest to the redemption date. The indenture governing the 2027 Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Issuers’ ability and the ability of their restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. At December 31, 2017 , the Company was in compliance with all required covenants under the Revolving Credit Agreement and each of the indentures governing the Notes. The Revolving Credit Agreement is subject to customary events of default, including a change in control (as defined in the Revolving Credit Agreement). If an event of default occurs and is continuing, the administrative agent or the Majority Lenders (as defined in the Revolving Credit Agreement) may accelerate any amounts outstanding and terminate lender commitments. If at any time when the Notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default or event of default (as defined in the indentures governing the Notes) has occurred and is continuing, many of such covenants will be suspended. If the ratings on the Notes were to decline subsequently to below investment grade, the suspended covenants would be reinstated. Principal Maturities of Debt Principal maturities debt outstanding at December 31, 2017 are as follows (in thousands): 2018 $ 2,352 2019 1,906 2020 617 2021 17 2022 14 Thereafter 2,200,000 Total $ 2,204,906 Interest Expense The following amounts have been incurred and charged to interest expense for the year ended December 31, 2017 , 2016 and 2015 (in thousands): Year ended December 31, 2017 2016 2015 Cash payments for interest $ 63,170 $ 65,513 $ 43,993 Change in interest accrual 30,007 (11,604 ) (350 ) Amortization of deferred loan origination costs 3,985 2,739 2,170 Write-off of deferred loan origination costs 735 451 532 Amortization of bond premium (516 ) (874 ) (764 ) Total interest expense, net $ 97,381 $ 56,225 $ 45,581 |
Equity
Equity | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Equity | EQUITY Preferred Stock Pursuant to the Company’s amended and restated bylaws, the Company’s board of directors, subject to any limitations prescribed by law, may, without further stockholder approval, establish and issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50.0 million shares of preferred stock. The Company had no shares of preferred stock outstanding at December 31, 2017 and 2016 . Class A Common Stock The Company has 252.3 million shares of its Class A Common Stock outstanding as of December 31, 2017 , which includes 0.8 million shares of restricted stock. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. Upon liquidation, dissolution, distribution of assets or other winding up, the holders of Class A Common Stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and the liquidation preference of any of the Company’s outstanding shares of preferred stock. Class B Common Stock The Company has 62.1 million shares of its Class B Common Stock outstanding as of December 31, 2017 . Holders of the Class B Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Holders of Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval, except with respect to the amendment of certain provisions of the Company’s certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B Common Stock so as to affect them adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate class, or as otherwise required by applicable law. Holders of Class B Common Stock do not have any right to receive dividends, unless the dividend consists of shares of Class B Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class B Common Stock paid proportionally with respect to each outstanding share of Class B Common Stock and a dividend consisting of shares of Class A Common Stock or of rights, options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class A Common Stock on the same terms is simultaneously paid to the holders of Class A Common Stock. Holders of Class B Common Stock do not have any right to receive a distribution upon a liquidation or winding up of the Company. Earnings per Share Basic earnings per share (“EPS”) measures the performance of an entity over the reporting period. Diluted earnings per share measures the performance of an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-converted” method to determine the potential dilutive effect of exchanges of outstanding PE Units (and corresponding shares of its outstanding Class B Common Stock), and the treasury stock method to determine the potential dilutive effect of vesting of its outstanding restricted stock and restricted stock units. For the years ended December 31, 2016 and 2015, Class B Common Stock and time-based restricted stock were not recognized in dilutive EPS calculations as they would have been antidilutive. The following table reflects the allocation of net income (loss) to common stockholders and EPS computations for the periods indicated based on a weighted average number of common stock outstanding for the period: December 31, 2017 December 31, 2016 December 31, 2015 Basic EPS (in thousands, except per share data) Numerator: Basic net income (loss) attributable to Parsley Energy, Inc. Stockholders $ 106,774 $ (74,182 ) $ (50,484 ) Denominator: Basic weighted average shares outstanding 240,733 161,793 111,271 Basic EPS attributable to Parsley Energy, Inc. Stockholders $ 0.44 $ (0.46 ) $ (0.45 ) Diluted EPS Numerator: Net income (loss) attributable to Parsley Energy, Inc. Stockholders 106,774 (74,182 ) (50,484 ) Effect of conversion of the shares of Company’s Class B Common Stock to shares of the Company’s Class A Common Stock 17,646 — — Diluted net income (loss) attributable to Parsley Energy, Inc. Stockholders $ 124,420 $ (74,182 ) $ (50,484 ) Denominator: Basic weighted average shares outstanding 240,733 161,793 111,271 Effect of dilutive securities: Class B Common Stock 54,665 — — Time-Based Restricted Stock and Time-Based Restricted Stock Units 1,114 — — Diluted weighted average shares outstanding (1) 296,512 161,793 111,271 Diluted EPS attributable to Parsley Energy, Inc. Stockholders $ 0.42 $ (0.46 ) $ (0.45 ) (1) Approximately 640,062 , 453,863 and 211,935 shares related to performance-based restricted stock units that could be converted to common shares in the future based on predetermined performance and market goals were not included in the computation of EPS for the year ended December 31, 2017 , 2016 and 2015, because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the contingency period. Noncontrolling Interest Concurrent with the closing of the Pacesetter Acquisition, Pacesetter’s President acquired a 37.0% interest in Pacesetter, with Parsley Energy Operations, LLC (“Operations”), a wholly owned subsidiary of Parsley LLC, retaining 63.0% of Pacesetter. As a result, the Company has consolidated the financial position and results of operations of Pacesetter due to Operations’ ownership interest. The 37.0% interest retained by Pacesetter’s President is reflected as a noncontrolling interest. As a result of the 2015 Equity Offerings, the Company’s ownership of Parsley LLC increased from 74.3% to 81.0% and the ownership of the other holders of PE Units (the “PE Unit Holders”) of Parsley LLC decreased from 25.7% to 19.0% of Parsley LLC. During the year ended December 31, 2015, no PE Unit Holders elected to exchange pursuant to their Exchange Right (as defined in Note 11—Related Party Transactions ). During the year ended December 31, 2016, certain PE Unit Holders exercised their Exchange Right under the Parsley LLC Agreement, collectively electing to exchange an aggregate of 4.1 million PE Units (and a corresponding number of shares of Class B Common Stock) for an aggregate of 4.1 million shares of Class A Common Stock (collectively, the “2016 Exchanges”). In turn, the Company exercised its call right under the Parsley LLC Agreement, electing to issue Class A Common Stock directly to each of the exchanging PE Unit Holders in satisfaction of their election notices. As a result of the 2016 Equity Offerings and the 2016 Exchanges, the Company’s ownership of Parsley LLC increased from 81.0% to 86.5% and the PE Unit Holders’ ownership of Parsley LLC decreased from 19.0% to 13.5% . As a result of the 2017 Equity Offerings, the Company’s ownership of Parsley LLC increased from 86.5% to 89.8% and the PE Unit Holders’ ownership of Parsley LLC decreased from 13.5% to 10.2% . Subsequently, as a result of the consummation of the Double Eagle Acquisition, the Company’s ownership of Parsley LLC decreased from 89.8% to 78.4% and the PE Unit Holders’ ownership of Parsley LLC increased from 10.2% to 21.6% . Any impact to additional paid in capital as a result of the 2017 Equity Offerings was completely offset by a valuation allowance. During the year ended December 31, 2017, certain PE Unit Holders exercised their Exchange Right under the Parsley LLC Agreement, collectively electing to exchange an aggregate of 5.7 million PE Units (and a corresponding number of shares of Class B Common Stock) for an aggregate of 5.7 million shares of Class A Common Stock (collectively, the “2017 Exchanges”). In turn, the Company exercised its call right under the Parsley LLC Agreement, electing to issue Class A Common Stock directly to each of the exchanging PE Unit Holders in satisfaction of their election notices. As a result of the 2017 Exchanges, the Company’s ownership of Parsley LLC increased from 78.4% to 80.2% and the PE Unit Holders’ ownership of Parsley LLC decreased from 21.6% to 19.8% . Because the changes in the Company’s ownership interest of Parsley LLC do not result in a change of control, the transaction is accounted for as an equity transaction under ASC Topic 810, Consolidation , which requires that any differences between the amount by which the carrying value of the Company’s basis in Parsley LLC is adjusted and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. The Company has consolidated the financial position and results of operations of Parsley LLC and reflected that portion retained by the PE Unit Holders as a noncontrolling interest. The following table summarizes the net income (loss) attributable to noncontrolling interests: Year ended December 31, 2017 2016 2015 (in thousands) Net income (loss) attributable to the noncontrolling interests of: Parsley LLC $ 17,645 $ (14,953 ) $ (21,870 ) Pacesetter Drilling, LLC (499 ) 218 (677 ) Total net income (loss) attributable to noncontrolling interests $ 17,146 $ (14,735 ) $ (22,547 ) |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | STOCK-BASED COMPENSATION In connection with the Company’s initial public offering (“IPO”), the Company adopted the Parsley Energy, Inc. 2014 Long Term Incentive Plan (“LTIP”) for employees and directors of the Company who perform services for the Company. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company including shares purchased on the open market. A total of 12.7 million shares of Class A Common Stock have been authorized for issuance under the LTIP. At December 31, 2017 , the Company had 10.0 million shares of Class A Common Stock available for future grant. The following table reflects stock-based compensation expense recorded for each type of stock-based compensation award for the years ended December 31, 2017 , 2016 and 2015 (in thousands): Year ended December 31, 2017 2016 2015 Time-based restricted stock $ 5,492 $ 3,523 $ 3,856 Time-based restricted stock units 7,778 5,677 2,710 Performance-based restricted stock units 6,349 3,671 1,567 Total stock-based compensation expense $ 19,619 $ 12,871 $ 8,133 (1) Stock-based compensation expense on time-based restricted stock units with graded vesting is recognized on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. Stock-based compensation is included in General and administrative expenses on the Company’s consolidated statement of operations. Time-Based Restricted Stock Time-based restricted stock are awards of Class A Common Stock that are legally issued and outstanding (“RSA”). RSAs are subject to restrictions on transfer and to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restrictions. The stock-based compensation expense for these awards was determined using the closing price on the date of grant applied to the total number of shares that were anticipated to fully vest. The following table summarizes the RSA activity for the year ended December 31, 2017 : Time-Based Restricted Stock Grant Date Fair Value Outstanding at January 1, 2017 600,761 $ 19.02 Awards granted 227,564 $ 31.55 Forfeited (41,014 ) $ 26.84 Vested (7,965 ) $ 18.14 Outstanding at December 31, 2017 779,346 $ 22.30 Time-Based Restricted Stock Units Time-based restricted stock units (“RSU”) represent the right to receive Class A Common Stock at the end of the vesting period equal to the number of RSUs granted. RSUs are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restriction. The stock-based compensation expense of such RSUs was determined using the closing price on the date of grant applied to the total number of shares that were anticipated to fully vest. The following table summarizes the RSU activity for the year ended December 31, 2017 : Time-Based Restricted Stock Units Grant Date Fair Value Outstanding at January 1, 2017 1,045,786 $ 16.96 Awards granted 209,186 $ 31.86 Forfeited (33,170 ) $ 22.69 Vested (22,083 ) $ 22.77 Outstanding at December 31, 2017 1,199,719 $ 19.36 Performance-Based Restricted Stock Units During 2017 , 2016 and 2015 , performance-based, stock-settled restricted stock unit awards (“PSU”) were granted with a performance period of three years . The number of shares of Class A Common Stock actually delivered pursuant to these PSUs depends on the performance of the Company’s Class A Common Stock over the performance period in relation to the performance of the common stock of a predetermined peer group. The conditions of the grants allow for an actual payout ranging between no payout and 200% of target. The payout level is calculated based on actual performance achieved during the performance period compared to a defined peer group. The fair value of such PSUs was determined using a Monte Carlo simulation and will be recognized over the next three years. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities in the model were estimated using a historical period consistent with the performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant. The Company used the following assumptions to estimate the fair value of PSUs granted during the periods indicated: Year Ended December 31, 2017 2016 2015 Risk-free interest rate 1.45 % 0.88 % 1.05 % Range of volatilities 37.7% - 79.5% 35.0% - 65.1% 42.2% - 84.8% The following table summarizes the PSU activity for the year ended December 31, 2017 : Performance-Based Restricted Units Grant Date Fair Value Outstanding at January 1, 2017 453,863 $ 25.06 Awards granted 186,199 $ 42.40 Outstanding at December 31, 2017 640,062 $ 30.11 The following table reflects the future stock-based compensation expense to be recorded for the stock-based compensation awards that were outstanding at December 31, 2017 (in thousands): Time-Based Restricted Stock Time-Based Restricted Stock Units Performance-Based Restricted Units Total 2018 $ 3,537 $ 5,292 $ 4,923 $ 13,752 2019 1,977 2,403 2,753 7,133 2020 255 259 8 522 Total $ 5,769 $ 7,954 $ 7,684 $ 21,407 Incentive Units Pursuant to the Parsley LLC Agreement, certain incentive units were issued to legacy investors, management and employees of Parsley LLC. The incentive units were intended to be compensation for services rendered to Parsley LLC. The original terms of the incentive units were as follows: Tier I incentive units vested ratably over three years , but were subject to forfeiture if payout was not achieved. In addition, all unvested Tier I incentive units vested immediately upon Tier I payout. Tier I payout was realized upon the return of the Preferred Holders’ invested capital and a specified rate of return. Tier II, III and IV incentive units vested only upon the achievement of certain payout thresholds for each such tier and each tier of the incentive units was subject to forfeiture if the applicable required payouts were not achieved. In addition, vested and unvested incentive units would be forfeited if an incentive unit holder’s employment was terminated for any reason or if the incentive unit holder voluntarily terminated their employment. The incentive units were accounted for as liability-classified awards pursuant to ASC Topic 718, Compensation—Stock Compensation, as achievement of the payout conditions required the settlement of such awards by transferring cash to the incentive unit holder. As such, the fair value of the incentive unit was remeasured each reporting period through the date of settlement, with the percentage of such fair value recorded to compensation expense each period being equal to the percentage of the requisite explicit or implied service period that has been rendered at that date. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES The Company is a corporation and is subject to U.S. federal income tax and the Texas Margins Tax. On December 22, 2017, the Tax Act was enacted by the U.S. government. The Tax Act significantly impacts the Company’s 2017 effective tax rate and made broad and complex changes to the U.S. corporate income tax code. Among other changes, the Tax Act: (i) reduces the U.S. federal corporate income tax rate from 35% to 21%; (ii) repeals the corporate alternative minimum tax and provides for a refund of previously accrued alternative minimum tax credits; (iii) modifies the provisions relating to the limitations on deductions for executive compensation of publicly traded corporations; (iv) enacts new limitations regarding the deductibility of interest expense and (v) imposes new limitations on the utilization of net operating losses arising in taxable years beginning after December 31, 2017. GAAP requires that the impact of tax legislation be recognized in the period in which the law was enacted. As a result of the Tax Act, the Company remeasured its deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, and they now generally reflect a federal income tax rate of 21%. The enacted rate change resulted in a noncash increase of approximately $23.9 million to the Company’s income tax provision, a corresponding reduction of $23.9 million to the Company’s net noncurrent deferred tax asset balance and a reduction in valuation allowance of $24.3 million December 31, 2017 . Any adjustments recorded to these estimates through 2018 will be included in income from operations as an adjustment to tax expense. The ultimate impact of the Tax Act may differ from the Company’s estimates based on the Company’s further analysis of the new law and additional regulatory guidance that may be issued. Further, the amount of the Company’s future federal income tax will be dependent upon its future taxable income. The Company’s effective combined U.S. federal and state income tax rate as of December 31, 2017 , 2016 and 2015 was 4.4% , 16.4% and 24.5% respectively. During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized an income tax expense of $5.7 million and income tax benefits of $17.4 million and $23.8 million , respectively. Total income tax differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the change in the valuation allowance, the change in the TRA liability, state taxes and the impact of income (loss) attributable to noncontrolling ownership interests. At December 31, 2017 , the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. The components of the income tax expense (benefit) were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Federal: Current $ (44 ) $ 158 $ 286 Deferred (423 ) (18,461 ) (27,535 ) Total federal (467 ) (18,303 ) (27,249 ) State, net of federal benefit: Deferred 6,175 879 3,494 Total state 6,175 879 3,494 Income tax expense (benefit) $ 5,708 $ (17,424 ) $ (23,755 ) The following table reconciles the income tax expense (benefit) with income tax expense at the federal statutory rate for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Income (loss) before income taxes $ 129,628 $ (106,341 ) $ (96,785 ) Less: net loss (income) before income taxes attributable (18,725 ) 14,579 22,438 Income (loss) attributable to Parsley Energy, Inc. Stockholders before income taxes 110,903 (91,762 ) (74,347 ) Income taxes at the federal statutory rate 38,816 (32,120 ) (26,022 ) State income taxes, net of federal benefit 6,175 879 3,494 Provision to return adjustment 178 (237 ) (1,217 ) Permanent and other 166 (61 ) (10 ) TRA Liability change (12,547 ) (2,573 ) — Valuation allowance (26,657 ) 32,215 — Valuation allowance charged to equity — (15,527 ) — Valuation allowance due to the reduction in federal statutory rate (24,356 ) — — Income tax provision due to change in federal statutory rate 23,933 — — Income tax expense (benefit) $ 5,708 $ (17,424 ) $ (23,755 ) Net income (loss) attributable to Parsley Energy, Inc. Stockholders $ 106,774 $ (74,182 ) $ (50,484 ) Net income (loss) attributable to noncontrolling interest $ 17,146 $ (14,735 ) $ (22,547 ) As of December 31, 2017 , the Company had approximately $0.4 million of alternative minimum tax credits available that are expected to be refunded between 2018 and 2021 as a result of the Tax Act. In addition, the Company had approximately $229.1 million of federal net operating loss carryovers that expire during the years 2034 through 2037 . The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not. When the future utilization of some portion of the carryforwards is determined not be more likely than not, a valuation allowance is provided to reduce the recorded tax benefits from such assets. As of December 31, 2017 , the Company had a valuation allowance of $9.3 million as a result of management’s assessment of the realizability of deferred tax assets. Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company does not believe it experienced an ownership change within the meaning of IRC Section 382 during 2017. Even if the Company did experience an ownership change in 2017, any resulting limitation on the use of the Company’s net operating loss carryforwards under IRC Section 382 would not result in a current federal tax liability at December 31, 2017, and the Company does not believe that the resulting Section 382 annual limitation would prevent its utilization of NOLs prior to their expiration . The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows (in thousands): December 31, 2017 2016 Assets: Asset retirement obligations $ 4,854 $ 3,535 Deferred stock-based compensation 7,874 6,868 Derivative fair value loss 12,493 8,252 Accrued compensation 4,241 3,398 Net operating loss carryforward 48,666 44,407 Other 78 166 Total deferred tax assets 78,206 66,626 Less: Valuation allowance (9,264 ) (32,215 ) Net deferred tax assets 68,942 34,411 Liabilities: Book basis of oil and natural gas properties (89,299 ) (38,489 ) Earnings in investment in subsidiary (828 ) (1,116 ) Other (218 ) (289 ) Total deferred tax liabilities (90,345 ) (39,894 ) Net deferred tax liability $ (21,403 ) $ (5,483 ) With respect to income taxes, the Company’s policy is to account for interest charges as interest expense, net and any penalties as Other income (expense) in the Company’s consolidated statements of operations. The Company files income tax returns in the U.S. federal jurisdiction and the Texas state jurisdiction, a number of which remain open for examination. The Company’s earliest open years in its key jurisdictions are as follows: U.S. federal 2014 State of Texas 2013 The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2017 , the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. Tax Receivable Agreement In connection with the IPO, on May 29, 2014, the Company entered into a Tax Receivable Agreement (the “TRA”) with Parsley LLC and certain PE Unit Holders prior to the IPO (each such person a “TRA Holder”), including certain executive officers. The TRA generally provides for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result of (i) any tax basis increases resulting from the contribution in connection with the IPO by such TRA Holder of all or a portion of its PE Units to the Company in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the exchange by such TRA Holder of PE Units for shares of Class A Common Stock or, if either the Company or Parsley LLC so elects, cash, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRA. The term of the TRA commenced on May 29, 2014, and continues until all such tax benefits have been utilized or expired, unless the Company exercises its right to terminate the TRA. If the Company elects to terminate the TRA early, it would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the TRA (based upon certain assumptions and deemed events set forth in the TRA). In addition, payments due under the TRA will be similarly accelerated following certain mergers or other changes of control. The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers and the portion of the Company’s payments under the TRA constituting imputed interest. As of December 31, 2017 , there have been no payments associated with the TRA. As a result of the Tax Act corporate rate reduction from 35% to 21% and the reduction in the valuation allowance recorded in 2016, during the year ended December 31,2017, the Company recorded a net decrease to the TRA liability of $35.8 million , which is comprised of a decrease of $55.9 million associated with the corporate rate reduction and an increase of $20.1 million related to the change in valuation allowance. As of December 31, 2017 and December 31, 2016 , the Company had recorded a TRA liability of $58.5 million and $94.3 million , respectively, for the estimated payments that will be made to the PE Unit Holders who have exchanged shares along with corresponding deferred tax assets, net of valuation allowance, of $68.8 million and $111.0 million , respectively, as a result of the increase in tax basis arising from such exchanges and decrease in tax basis as a result of the decrease in the future statutory tax rate. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED PARTY TRANSACTIONS Well Operations During the years ended December 31, 2017 , 2016 and 2015 , several of the Company’s directors, officers, their immediate family and entities affiliated or controlled by such parties (“Related Party Working Interest Owners”) owned non-operated working interests in certain of the oil and natural gas properties that the Company operates. The revenues disbursed to such Related Party Working Interest Owners for the years ended December 31, 2017 , 2016 and 2015 totaled $1.5 million , $2.5 million and $5.2 million , respectively. As a result of this ownership, from time to time, the Company will be in a net receivable or net payable position with these individuals and entities. The Company does not consider any net receivables from these parties to be uncollectible. Spraberry Production Services, LLC At December 31, 2017 , the Company owned a 42.5% interest in SPS and accounts for this investment using the equity method. Using the equity method of accounting results in transactions between the Company and SPS and its subsidiaries being accounted for as related party transactions. During the years ended December 31, 2017 , 2016 and 2015 , the Company incurred charges totaling $10.2 million , $4.4 million and $4.8 million , respectively, for services performed by SPS for the Company’s well operations and drilling activities. Lone Star Well Service, LLC The Company makes purchases of equipment used in its drilling operations from Lone Star Well Service, LLC (“Lone Star”). Lone Star is controlled by SPS. During the years ended December 31, 2017 , 2016 and 2015 , the Company incurred charges totaling $6.5 million , $6.3 million and $5.0 million , respectively, for services performed by Lone Star for the Company’s well operations and drilling activities. Davis, Gerald & Cremer, P.C. During the years ended 2016 and 2015 , the Company incurred charges totaling $0.5 million and $0.2 million , respectively, for legal services from Davis, Gerald & Cremer, P.C., of which the Company’s director David H. Smith is a shareholder. There were no material charges incurred during the year ended December 31, 2017 . Riverbend Acquisition During the year ended December 31, 2016, the Company acquired 8,800 gross ( 6,269 net) acres located in Glasscock, Midland and Reagan Counties, Texas, along with net production of approximately 900 Boe/d from existing wells, from Riverbend Permian L.L.C. (“Riverbend”), for total consideration of $177.1 million , after customary purchase price adjustments (the “Riverbend Acquisition”). Randolph J. Newcomer, Jr., a former member of the Company’s board of directors, is the President and Chief Executive Officer of Riverbend. As the transaction involved a related party at the time it was entered into, the Riverbend Acquisition was approved by the disinterested members of the Company’s board of directors. The Company reflected $37.9 million of the total consideration paid as part of its cost subject to depletion within its oil and natural gas properties and $139.2 million as unproved leasehold costs within its oil and natural gas properties for the year ended December 31, 2016. Exchange Right In accordance with the terms of the Parsley LLC Agreement, the PE Unit Holders generally have the right to exchange (the “Exchange Right”) their PE Units (and a corresponding number of shares of the Class B Common Stock) for shares of Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each PE Unit (and a corresponding share of Class B Common Stock) exchanged (subject to conversion rate adjustments for stock splits, stock dividends and reclassifications) or, if the Company or Parsley LLC so elects, cash. As a PE Unit Holder exchanges its PE Units, the Company’s interest in Parsley LLC will be correspondingly increased. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES Legal Matters From time to time, the Company is a party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment-related disputes. The Company does not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on its business, financial condition, results of operations, or liquidity. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed or readily determinable. At December 31, 2017 and 2016 , the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability. Asset Retirement Obligations The following table summarizes the Company’s asset retirement obligations as of December 31, 2017 (in thousands): Payments Due by Period 2018 2019 2020 2021 2022 Thereafter Total Asset retirement obligations $ 6,297 $ 774 $ 824 $ 834 $ 929 $ 17,512 $ 27,170 Drilling Commitments The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which well capital is incurred or rig services are provided. The following table summarizes the Company’s drilling commitments as of December 31, 2017 (in thousands): Payments Due by Period 2018 2019 2020 2021 2022 Thereafter Total Drilling commitments $ 30,752 $ 46,150 $ — $ — $ — $ — $ 76,902 Derivative Obligations The future deferred premium payments related to derivative agreements as of December 31, 2017 was as follows (in thousands): Payments Due by Period 2018 2019 2020 2021 2022 Thereafter Total Derivative obligations $ 49,601 $ 14,730 $ — $ — $ — $ — $ 64,331 Operating Leases The estimated future minimum lease payments under long-term operating lease agreements as of December 31, 2017 was as follows (in thousands): For the years ended December 31, 2018 2019 2020 2021 2022 Thereafter Total Office Leases $ 8,810 $ 9,626 $ 9,640 $ 9,219 $ 9,102 $ 20,219 $ 66,616 Office Equipment 155 76 4 1 — — 236 Total $ 8,965 $ 9,702 $ 9,644 $ 9,220 $ 9,102 $ 20,219 $ 66,852 Rent expense for the years ended December 31, 2017 , 2016 and 2015 was $9.5 million , $7.1 million and $4.7 million , respectively. Firm Transportation and Processing Agreements During the year ended December 31, 2016, the Company entered into a contract with a private midstream company that provides for firm pipeline transportation from its acreage in Reagan, Upton and Midland Counties, Texas to Crane, Colorado City and Midland, Texas, which enables the Company to choose from multiple destinations for a substantial portion of its crude oil production. During the year ended December 31, 2017, the Company entered into a contract that provides firm transportation off one of the pipeline systems through which the Company transports or sells crude oil. Satisfaction of the volume requirements includes volumes produced by the Company, and other third-party working, royalty, and overriding royalty interest owners whose volumes the Company markets on their behalf. The Company’s consolidated statements of operations reflects its share of firm transportation costs. This contract requires the Company to pay a deficiency fee if it fails to deliver the required volumes. As of December 31, 2017, approximately 69% of the Company’s gross oil production was being transported by these pipelines systems and sold under these agreements. The Company does not believe, however, that the termination of either of these agreements would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. |
Disclosures about Fair Value of
Disclosures about Fair Value of Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Disclosures about Fair Value of Financial Instruments | DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy: Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2: Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date. Level 3: Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. These assets and liabilities can include inventory, proved and unproved oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired. The Company periodically reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable ( e.g. , if there was a sustained decline in commodity prices or the productivity of the Company’s wells). The Company reviews its oil and natural gas properties by field. An impairment loss is recognized if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying amount of a particular asset, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of such asset. Materials and Supplies. During the year ended December 31, 2017 , the Company recognized impairment of $1.1 million primarily to reduce the carrying value of oil and gas drilling and repair items. No impairment charge was recorded during the year ended December 31, 2016 . The Company estimates fair value of the inventory using significant Level 2 assumptions based on third-party price quotes for the asset in an active market. The impairment charges are included in Other income (expense) in the Company’s consolidated statements of operations. Proved Oil and Natural Gas Properties. During the years ended December 31, 2017 and 2016, the Company did no t recognize impairment charges, as the carrying amount of the assets exceeds the undiscounted future cash flows of the assets. The Company estimates fair values using a discounted future cash flow model. Management’s assumptions associated with the calculation of discounted future cash flows include commodity prices based on NYMEX futures price strips (Level 1), as well as Level 3 assumptions including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes and (v) estimated reserves. It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) commodity futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and (iv) results of future drilling activities. Financial Assets and Liabilities Measured at Fair Value Commodity derivative contracts are marked-to-market each quarter and are thus stated at fair value in the Company’s consolidated balance sheets and in Note 3—Derivative Financial Instruments . The company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The following summarizes the fair value of the Company’s derivative assets and liabilities according to their fair value hierarchy as of the reporting dates indicated (in thousands): December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Money market funds $ 476,619 $ — $ — 476,619 Commodity derivative contracts — 57,689 — 57,689 Total assets $ 476,619 $ 57,689 $ — $ 534,308 Liabilities: Commodity derivative contracts $ — $ (105,543 ) $ — $ (105,543 ) Total liabilities $ — $ (105,543 ) $ — $ (105,543 ) Net asset (liability) $ 476,619 $ (47,854 ) $ — $ 428,765 December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Money market funds $ 94,280 $ — $ — 94,280 Commodity derivative contracts — 56,124 — 56,124 Total assets 94,280 56,124 — 150,404 Liabilities: Commodity derivative contracts — (56,968 ) — (56,968 ) Total liabilities — (56,968 ) — (56,968 ) Net asset (liability) $ 94,280 $ (844 ) $ — $ 93,436 Money market funds in the preceding tables consist of money market funds included in cash and cash equivalents on the Company’s consolidated balance sheets at December 31, 2017 and 2016. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments. During the years ended December 31, 2017 and 2016, income related to these investments was $7.6 million and $0.9 million , respectively, and is recorded on the Company’s consolidated statements of operations as Interest income. There were no transfers in to or out of Level 2 during the years ended December 31, 2017 or 2016 . Financial Instruments Not Carried at Fair Value The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets (in thousands): December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents: Commercial paper $ 24,939 $ 24,918 $ — $ — Short-term investments: Commercial paper 149,283 149,151 — — Current portion of long-term debt: 7.500% senior unsecured notes due 2022 — — 61,846 65,737 Long-term debt: 6.250% senior unsecured notes due 2024 400,000 423,824 400,000 422,548 5.375% senior unsecured notes due 2025 650,000 658,483 650,000 654,531 5.250% senior unsecured notes due 2025 450,000 454,010 — — — 5.625% senior unsecured notes due 2027 700,000 715,169 — — Revolving Credit Agreement — — — — The fair values of the 2024 Notes, the 2025 Notes, the New 2025 Notes and the 2027 Notes included in long-term debt were determined using the December 31, 2017 quoted market price, a Level 1 classification in the fair value hierarchy. The fair value of the 2022 Notes included in Current portion of long-term debt at December 31, 2016 is equal to the principal amount of the cash payment made on January 5, 2017. The book value of the Revolving Credit Agreement approximates its fair value as the interest rate is variable. As of December 31, 2017 , there were no indicators for change in the Company’s market spread. Periodically, the Company invests in commercial paper with investment grade rated entities. The investments are carried at amortized cost and classified as held-to-maturity because the Company has the intent and ability to hold them until they mature. The net carrying value of held-to-maturity investments is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the investments. Income related to these investments is recorded on the Company’s consolidated statements of operations as Interest income. The following table provides the components of the Company’s cash and cash equivalents and short-term investments as of the dates indicated (in thousands): December 31, 2017 Consolidated Balance Sheet Location Cash Commercial Paper Money Market Funds Total Cash and cash equivalents $ 52,631 $ 24,939 $ 476,619 $ 554,189 Short-term investments — 149,283 — 149,283 December 31, 2016 Consolidated Balance Sheet Location Cash Commercial Paper Money Market Funds Total Cash and cash equivalents $ 39,099 $ — $ 94,280 $ 133,379 The Company has other financial instruments consisting primarily of accounts receivable, prepaid expenses, other current assets, accounts payable and accrued liabilities and capital leases that approximate their fair value due to the short-term nature of these instruments. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS The Company has evaluated subsequent events through the date these financial statements were issued. The Company determined there were no events, other than as described below, that required disclosure or recognition in these financial statements. Divestiture of Non-Operated Properties As part of an ongoing initiative to high-grade its acreage portfolio, the Company recently closed the divestiture of a portion of its non-operated properties, which were classified as held for sale as of December 31, 2017. In aggregate, the Company divested 42,852 gross ( 3,710 net) acres in Martin, Howard, Reagan, Irion, Dawson, and Pecos Counties for approximately $39.4 million with no gain or loss recognized. |
Supplemental Disclosure of Oil
Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) | SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited) The Company has only one reportable operating segment, which is oil and gas development, exploration and production in the United States. See the Company’s consolidated statements of operations for information about results of operations for oil and gas producing activities. Capitalized Costs December 31, 2017 2016 (in thousands) Oil and natural gas properties: Proved properties $ 4,492,802 $ 2,376,712 Unproved properties 4,058,512 1,686,705 Total oil and natural gas properties 8,551,314 4,063,417 Less accumulated depreciation, depletion and amortization (822,459 ) (506,175 ) Net oil and natural gas properties capitalized $ 7,728,855 $ 3,557,242 Costs Incurred for Oil and Natural Gas Producing Activities Year Ended December 31, 2017 2016 2015 (in thousands) Acquisition costs: Proved properties $ 482,160 $ 273,940 $ 16,422 Unproved properties 2,893,434 1,072,250 57,385 Development costs 1,207,401 495,971 404,291 Total $ 4,582,995 $ 1,842,161 $ 478,098 Reserve Quantity Information The following information represents estimates of the Company’s proved reserves as of December 31, 2017 , which have been prepared and presented under SEC rules. These rules require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12 -month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2017 was based on an unweighted average 12-month average WTI posted price per Bbl for oil and NGLs and a Waha spot natural gas price per Mcf for natural gas, adjusted for transportation, quality and basis differentials, as set forth in the following table: Year Ended December 31, 2017 2016 2015 Oil (per Bbl) $ 49.17 $ 39.36 $ 46.54 Natural gas (per Mcf) $ 2.53 $ 2.23 $ 2.53 Natural gas liquids (per Bbl) $ 22.20 $ 15.04 $ 16.42 Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves with the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more. The Company’s proved oil and natural gas reserves are located in the U.S. in the Permian Basin of West Texas. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB. Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. The following table and subsequent narrative disclosure provides a roll forward of the total proved reserves for the years ended December 31, 2017 , 2016 and 2015 , as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Year Ended December 31, 2017 Crude Oil (MBbls) Natural Gas Liquids MBoe Proved Developed and Undeveloped Reserves: Beginning of the year 136,536 223,605 48,543 222,347 Extensions and discoveries 99,916 161,989 33,426 160,340 Revisions of previous estimates (709 ) 32,342 4,522 9,205 Purchases of reserves in place 33,017 64,055 12,121 55,814 Divestures of reserves in place (3,839 ) (6,962 ) (1,468 ) (6,467 ) Production (16,390 ) (23,326 ) (4,512 ) (24,792 ) End of the year 248,531 451,703 92,632 416,447 Proved Developed Reserves: Beginning of the year 61,133 123,946 24,306 106,097 End of the year 119,591 240,337 49,751 209,399 Proved Undeveloped Reserves: Beginning of the year 75,403 99,659 24,237 116,250 End of the year 128,940 211,366 42,880 207,048 Year Ended December 31, 2016 Crude Oil (MBbls) Natural Gas Liquids MBoe Proved Developed and Undeveloped Reserves: Beginning of the year 73,877 157,175 23,738 123,811 Extensions and discoveries 64,005 83,815 20,698 98,672 Revisions of previous estimates (4,476 ) (19,032 ) 3,898 (3,750 ) Purchases of reserves in place 16,041 25,024 4,023 24,235 Divestures of reserves in place (3,543 ) (9,914 ) (1,424 ) (6,619 ) Production (9,368 ) (13,463 ) (2,390 ) (14,002 ) End of the year 136,536 223,605 48,543 222,347 Proved Developed Reserves: Beginning of the year 27,628 77,612 10,890 51,453 End of the year 61,133 123,946 24,306 106,097 Proved Undeveloped Reserves: Beginning of the year 46,249 79,563 12,848 72,358 End of the year 75,403 99,659 24,237 116,250 Year Ended December 31, 2015 Crude Oil (MBbls) Natural Gas Liquids MBoe Proved Developed and Undeveloped Reserves: Beginning of the year 47,617 123,645 22,667 90,891 Extensions and discoveries 38,282 52,629 9,163 56,217 Revisions of previous estimates (7,493 ) (14,572 ) (7,278 ) (17,201 ) Purchases of reserves in place 1,897 6,946 921 3,976 Divestures of reserves in place (1,619 ) (1,134 ) (235 ) (2,042 ) Production (4,807 ) (10,339 ) (1,500 ) (8,030 ) End of the year 73,877 157,175 23,738 123,811 Proved Developed Reserves: Beginning of the year 23,547 65,484 11,491 45,952 End of the year 27,628 77,612 10,890 51,453 Proved Undeveloped Reserves: Beginning of the year 24,070 58,161 11,176 44,939 End of the year 46,249 79,563 12,848 72,358 Extensions and Discoveries. For the years ended December 31, 2017 , 2016 and 2015 , extensions and discoveries contributed to the increase of 160,340 MBoe, 98,672 MBoe and 56,217 MBoe in the Company’s proved reserves, respectively, and for each such year the increase is attributable to the Company’s successful horizontal drilling program in the Midland Basin and Delaware Basin. Revisions of Previous Estimates. The Company made total revisions in proved reserves of 9,205 MBoe, 3,750 MBoe and 17,201 MBoe for the years ended December 31, 2017 , 2016 and 2015 , respectively. Positive revisions of previous estimates for 2017 were 9,205 MBoe. The main driver of this adjustment was related to positive revisions due to better than expected performance for a total of 8,134 MBoe. Additionally, positive revisions of 2,752 MBoe and 3,044 MBoe were recorded due to the increase in oil prices and production, respectively, when compared to 2016. This was offset by the reclassification of PUD reserves to unproved reserves, which accounted for a 4,725 MBoe downward revision to previous estimates related to the removal of reserves for locations determined to be outside of the Company’s five-year capital expenditure plan. Negative revisions of previous estimates for 2016 were 3,750 MBOE. The revisions include the reclassification of proved undeveloped reserves to unproved reserves, which accounted for a 26,597 MBoe downward revision to previous estimates (of which 18,532 MBoe related to the removal of reserves for all of the Company’s vertical proved undeveloped reserve locations). Additionally, downward revisions of 2,873 MBoe were recorded due to the decline of oil prices when compared to 2015. This was offset by positive revisions due to better than expected performance and cost reduction initiatives for a total of 25,720 MBoe. Negative revisions of previous estimates for 2015 were 17,201 MBoe. This figure includes downward revisions of 13,087 MBoe due to the decline of oil prices as compared to 2014. Additionally, this includes the reclassification of proved undeveloped reserves to unproved reserves, which accounted for 11,688 MBoe of downward revisions to previous estimates due to the removal of vertical proved undeveloped reserve locations. These amounts were offset by positive revisions of 7,574 MBoe due to better than expected performance during 2015 and cost reduction initiatives. Purchases of Reserves in Place. For the years ended December 31, 2017 , 2016 and 2015 , the Company added 55,814 MBoe, 24,235 MBoe and 3,976 MBoe of reserves, respectively, primarily as a result of the acquisition of developed and undeveloped acreage in the Midland and Delaware Basins. For the year ended December 31, 2017 , the Company acquired 53,105 MBoe of proved reserves in the Midland Basin and 2,709 MBoe of proved reserves in the Delaware Basin. For the year ended December 31, 2016, the Company acquired 19,184 MBoe of proved reserves in the Midland Basin and 5,051 MBoe of proved reserves in the Delaware Basin. All of the Company’s acquisitions of proved reserves for the years ended December 31, 2015 were in the Midland Basin. Divestitures of Reserves in Place . As a result of divestitures of developed and undeveloped acreage in the Midland and Delaware Basins, the Company’s reserves decreased by 6,467 MBoe, 6,619 MBoe and 2,042 MBoe during the years ended December 31, 2017 , 2016 and 2015 , respectively. For the year ended December 31, 2017, the Company divested 5,936 MBoe of proved reserves in the Midland Basin and 531 MBoe of proved reserves in the Delaware Basin. For the year ended December 31, 2016, the Company divested 6,588 MBoe of proved reserves in the Midland Basin and 31 MBoe of proved reserves in the Delaware Basin. All of the Company’s divestitures of proved reserves for the year ended December 31, 2015 were in the Midland Basin. Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2017 , 2016 and 2015 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10% . The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGLs reserves is as follows: December 31, 2017 2016 2015 (in thousands) Future cash inflows $ 15,421,590 $ 6,603,206 $ 4,225,912 Future development costs (2,181,447 ) (1,019,823 ) (829,560 ) Future production costs (4,536,530 ) (2,176,081 ) (1,534,011 ) Future income tax expenses (1,102,385 ) (370,337 ) (240,203 ) Future net cash flows 7,601,228 3,036,965 1,622,138 10% discount to reflect timing of cash flows (4,585,723 ) (1,852,653 ) (1,024,290 ) Standardized measure of discounted future net cash flows $ 3,015,505 $ 1,184,312 $ 597,848 In the foregoing determination of future cash inflows, sales prices used for oil, natural gas and NGLs for December 31, 2017 , 2016 and 2015 , were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions. It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of its’ predecessor’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves. Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGLs reserves are as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Standardized measure of discounted future net cash flows at the beginning of the year $ 1,184,312 $ 597,848 $ 955,629 Sales of oil and natural gas, net of production costs (800,553 ) (369,295 ) (185,344 ) Purchase of minerals in place 489,910 118,795 4,872 Divestiture of minerals in place (50,257 ) (14,591 ) (53,018 ) Extensions and discoveries, net of future development costs 1,864,041 770,947 485,380 Previously estimated development costs incurred during the period 58,377 61,756 12,560 Net changes in prices and production costs 525,693 (80,492 ) (821,783 ) Changes in estimated future development costs (150,028 ) 118,930 77,621 Revisions of previous quantity estimates 142,510 84,309 (225,485 ) Accretion of discount 148,314 69,731 131,442 Net change in income taxes (603,696 ) (199,368 ) 249,065 Net changes in timing of production and other 206,882 25,742 (33,091 ) Standardized measure of discounted future net cash flows at the end of the year $ 3,015,505 $ 1,184,312 $ 597,848 |
Summary of Quarterly Financial
Summary of Quarterly Financial Results (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summary of Quarterly Financial Results (Unaudited) | SUMMARY OF QUARTERLY RESULTS OF OPERATIONS (Unaudited) The Company’s unaudited quarterly financial data for the years ended December 31, 2017 and 2016 is summarized as follows: First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts) 2017 Revenues $ 200,858 $ 213,677 $ 241,021 $ 311,488 Operating income $ 72,531 $ 45,259 $ 63,072 $ 85,939 Income tax (expense) benefit $ (18,402 ) $ (12,216 ) $ 5,080 $ 19,830 Net income (loss) $ 38,290 $ 55,794 $ (15,161 ) $ 44,997 Net income (loss) attributable to noncontrolling interests $ 8,848 $ 15,048 $ (1,828 ) $ (39,214 ) Net income (loss) attributable to Parsley Energy, Inc. stockholders $ 29,442 $ 40,746 $ (13,333 ) $ 49,919 Net income (loss) per common share: Basic $ 0.13 $ 0.17 $ (0.05 ) $ 0.20 Diluted $ 0.13 $ 0.17 $ (0.05 ) $ 0.16 2016 Revenues $ 62,488 $ 106,872 $ 132,537 $ 155,876 Operating (loss) income $ (26,042 ) $ 1,636 $ 12,340 $ 43,213 Income tax benefit (expense) $ 9,568 $ 10,918 $ 1,279 $ (4,341 ) Net loss $ (25,691 ) $ (27,488 ) $ (1,641 ) $ (34,097 ) Net income (loss) attributable to noncontrolling interests $ (6,337 ) $ (6,111 ) $ 1,065 $ (3,352 ) Net loss attributable to Parsley Energy, Inc. stockholders $ (19,354 ) $ (21,377 ) $ (2,706 ) $ (30,745 ) Net loss per common share: Basic $ (0.14 ) $ (0.13 ) $ (0.02 ) $ (0.17 ) Diluted $ (0.14 ) $ (0.13 ) $ (0.02 ) $ (0.17 ) |
Summary of Significant Accoun24
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | Principles of Consolidation These consolidated financial statements include the accounts of (i) the Company, (ii) Parsley LLC, (iii) the direct and indirect wholly owned subsidiaries of Parsley LLC, and (iv) an indirect, majority owned subsidiary of Parsley LLC, Pacesetter Drilling, LLC, of which Parsley LLC owns, indirectly, a 63.0% interest. Parsley LLC also owns, indirectly, a 42.5% noncontrolling interest in Spraberry Production Services, LLC (“SPS”). The Company accounts for its investment in SPS using the equity method of accounting. All significant intercompany and intra-company balances and transactions have been |
Use of Estimates | Use of Estimates These consolidated financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires the Company to (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the SEC and (ii) make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The Company’s management believes the major estimates and assumptions impacting the Company’s consolidated financial statements are the following: • estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization and impairment of capitalized costs of oil and natural gas properties; • operating costs accrued and volumes and prices for revenues accrued; • estimates of asset retirement obligations; • estimates of the fair value assets acquired and liabilities assumed in business combinations; • evaluations of impairment of proved and unproved properties are subject to number uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks; • impairment of other assets; • depreciation of property and equipment; • valuation of commodity derivative instruments; and • estimates of the fair value of stock-based compensation. Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. |
Restricted Cash | Restricted Cash The Company’s restricted cash at December 31, 2016 of $3.3 million consisted of cash deposited into an escrow account that was contractually restricted involving a non-related party. The restricted cash included revenues associated with an operated well. During December 2017, the matter was resolved, resulting in the release of $4.8 million , including all of the escrowed funds, and the Company’s recognition of $3.6 million of sales, net of production taxes. As of December 31, 2017 , the Company had no restricted cash. |
Short-term Investments | Short-term Investments Periodically, the Company invests in commercial paper with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than three months at the date of purchase; otherwise, investments are reflected as short-term investments in the accompanying consolidated balance sheets based on their maturity dates. As of December 31, 2017, all of the Company’s short-term investments mature within one year. |
Accounts Receivable | Accounts Receivable Accounts receivable consist of receivables from joint interest owners on properties the Company operates and crude oil, natural gas and NGLs production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments are received within three months after the production date. Amounts due from joint interest owners or purchasers are stated net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2017 or December 31, 2016 . |
Significant Customers | Significant Customers For the years ended December 31, 2017 , 2016 and 2015 , each of the following purchasers accounted for more than 10% of the Company’s revenue: Year Ended December 31, 2017 2016 2015 Shell Trading (US) Company 62% 44% 23% BML, Inc. 2% 13% 19% Targa Pipeline Mid-Continent, LLC 13% 13% 12% TransOil Marketing, LLC 1% 8% 13% The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties and mineral interests are subject to depreciation, depletion and amortization (“DD&A”). Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated reservoir. The Company capitalizes interest on expenditures made in connection with long term projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use and only to the extent the company has incurred interest expense. On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from the property accounts and any gain or loss is recognized. For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. |
Oil and Gas Reserves | Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing first day of the month 12-month average price, net of historical differentials, with no provision for price and cost escalations in future years except by contractual arrangements. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Oil and gas properties are depleted by field using the units-of-production method. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. |
Asset Retirement Obligations | Asset Retirement Obligations For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely the plugging and abandonment of wells and land remediation. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period. If the liability is settled for an amount other than the recorded amount, the difference is recorded in other income (expense) in the consolidated statements of operations. Inherent to the present value calculation are numerous estimates, assumptions and judgments, including, but not limited to: the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions affect the present value of the abandonment liability, the Company makes corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. These revisions result in prospective changes to DD&A expense and accretion of the discounted abandonment liability. The following table summarizes the changes in the Company’s asset retirement obligation for the periods indicated (in thousands): Year ended December 31, 2017 2016 Asset retirement obligations, beginning of year $ 11,392 $ 18,220 Additional liabilities incurred 9,081 3,290 Disposition of wells (432 ) (858 ) Accretion expense 971 732 Liabilities settled upon plugging and abandoning wells (189 ) (56 ) Revision of estimates 6,752 (9,936 ) Liabilities related to assets held for sale (405 ) — Asset retirement obligations, end of year $ 27,170 $ 11,392 |
Allocation of Purchase Price in Business Combinations | Allocation of Purchase Price in Business Combinations As part of its business strategy, the Company regularly pursues the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The Company’s most significant estimates in its allocation typically relate to the value assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. |
Impairment of Oil and Natural Gas Properties | Impairment of Oil and Natural Gas Properties The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties by field. Whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, an impairment loss is indicated if the sum of the expected future cash flows related to proved properties in the applicable field is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. See Note 13— Disclosures about Fair Value of Financial Instruments for additional information regarding the Company’s impairment of proved oil and natural gas properties. |
Exploration and Abandonment Costs | Exploration and Abandonment Costs Exploration and abandonment costs, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures and other geological and geophysical costs, exploratory dry holes, impairment and amortization of unproved leasehold costs and lease rentals. The costs of exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a 12-month period after drilling is complete. Unproved oil and natural gas properties are assessed quarterly for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. The following table summarizes exploration and abandonment costs incurred by the Company for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Leasehold abandonments $ 32,872 $ 6,063 $ 8,227 Geological and geophysical costs 5,429 3,015 5,459 Idle drilling rig fees 1,070 4,304 — Unproved leasehold amortization 1,044 549 179 Total exploration and abandonment costs $ 40,415 $ 13,931 $ 13,865 |
Other Property and Equipment, net | Other Property and Equipment, net Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three years to 15 years . Depreciation expense on other property and equipment was $11.5 million , $6.6 million and $4.7 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. Materials and supplies are stated at the lower of cost or market and consists of oil and gas drilling or repair items such a tubing, casing and pumping units. These items are primarily acquired for use in future drilling or repair operations and are carried at lower of cost or market. “Market,” in the context of valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint account under joint operating agreements to which the Company is a party. The Company evaluated materials and supplies based on current operations and determined that these materials and supplies would not be utilized in the current year and includes them in noncurrent assets as non-depreciable other property, plant and equipment. See Note 13—Disclosures about Fair Value of Financial Instruments for additional information regarding the Company’s impairment of materials and supplies. |
Equity Investments | Equity Investments Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss, after elimination of intra-company profit or loss, is recognized in the consolidated statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2017 , 2016 and 2015 . |
Derivatives Instruments | Derivative Instruments The Company uses derivative financial instruments to reduce exposure to fluctuations in commodity prices. These transactions are in the form of crude options and collars. The Company reports the fair value of derivatives on the consolidated balance sheets in derivative instrument assets and derivative instrument liabilities as either current or noncurrent. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual trades. The Company reports these on a gross basis by contract. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses resulting from the changes in fair value of derivatives are included in cash flows from operating activities. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants at the reporting date. The Company’s assets and liabilities that are measured at fair value at each reporting date are classified according to a hierarchy that prioritizes inputs and assumptions underlying the valuation techniques. This fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs and consists of three broad levels: Level 1 : Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 : Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date. Level 3 : Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. |
Deferred Loan Costs | Deferred Loan Costs Deferred loan costs are stated at cost, net of amortization and are amortized to interest expense using the effective interest method over the life of the loan. |
Revenue Recognition | Revenue Recognition Revenues from the sale of crude oil, natural gas and NGLs are recognized when the production is sold, net of any royalty interest. Because final settlement of the Company’s hydrocarbon sales can take up to two months, the expected sales volumes and prices for those properties are estimated and accrued using information available at the time the revenue is recorded. Natural gas revenues are recorded using the entitlement method of accounting whereby revenue is recognized based on the Company’s proportionate share of natural gas production. At December 31, 2017 , 2016 and 2015 , the Company did not have any natural gas imbalances. Transportation expenses are included as a reduction of natural gas revenue and are not material. |
Defined Contribution Plan | Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for the benefit of all employees at their date of hire. The plan allows eligible employees to contribute a portion of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contribution of up to a certain percentage of an employee’s contributions. For the years ended December 31, 2017 , 2016 and 2015 , the Company made contributions to the plan of $2.8 million , $1.9 million and $1.4 million , respectively. |
Income Taxes | Income Taxes The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities. SEC Staff Accounting Bulletin No. 118 provides guidance for companies that have not completed their accounting for the income tax effects of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), in the period of enactment and allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. As of February 28, 2018 , the Company has substantially completed its accounting for the tax effects of the enactment of the Tax Act. The Company has made a reasonable estimate of the effects on its deferred tax balances. The Company is still analyzing certain aspects of the Tax Act and the Company is refining its calculations, which could potentially affect the measurement of related deferred tax balances or potentially give rise to new deferred tax amounts. The Company does not expect that a material adjustment to its deferred tax position will result from the completion of its computations, which the Company expects to finalize by the fourth quarter of 2018. To account for the effects of the Tax Cut and Jobs Act, the Company remeasured its deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, and they now generally reflect a federal income tax rate of 21%. The enacted rate change resulted in a noncash increase of approximately $23.9 million to the Company’s income tax provision, a corresponding reduction of $23.9 million to the Company’s net noncurrent deferred tax asset balance and a reduction in valuation allowance of $24.3 million December 31, 2017 . Any adjustments recorded to these estimates through 2018 will be included in income from operations as an adjustment to tax expense. The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends and its outlook for future years. |
Earnings Per Share | Earnings per Share The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and restricted stock units. |
Comprehensive Income | Comprehensive Income The Company has no elements of comprehensive income other than net income. |
Segment Reporting | Segment Reporting Operating segments are defined as components of an enterprise (i) that engage in activities from which it may earn revenues and incur expenses and (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based on the organization and management of the Company, the Company has only one reportable operating segment, which is oil and natural gas exploration and production. The Company considers drilling rig services ancillary to its oil and gas exploration and production activities and manages these services to support such activities. |
Reclassifications | Reclassifications Certain reclassifications have been made to prior period amounts to conform to the current presentation. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, Revenue Recognition, and most industry-specific guidance. This revenue recognition model provides a five-step analysis for determining when and how revenue is recognized, and requires an entity (i) to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) provide expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers , which deferred the effective date of ASU 2014-09 by one year. The Company adopted this standard effective January 1, 2018 using the modified retrospective approach. During the fourth quarter of 2017, the Company completed a detailed review of various contracts that represent its material revenue streams and, based on such review, does not expect the standard to materially affect the Company’s results of operations, liquidity or financial position in 2018. Additionally, the Company will begin recognizing revenues based on the entitlement method rather than the sales method; this change will not have a material impact on the Company’s results of operations or financial position in 2018. The Company has also implemented processes and controls to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the required disclosures under the standards. As described above, beginning with the Company’s Form 10-Q for the three months ended March 31, 2018, additional disclosures will be required to describe the nature, amount, timing and certainty of revenue and cash flows from contracts with customers, including a disaggregation of revenue and remaining performance obligations. As an example of this evaluation and disclosure, under the Company’s natural gas processing contracts, the Company delivers natural gas to midstream processing companies at the wellhead or their system inlets. The midstream processing companies gather and process the delivered natural gas and, in turn, remit proceeds to the Company for sales of NGLs and residue gas. In these scenarios, the Company evaluates whether the midstream processing company is acting as the principal or the agent. For those contracts where it is concluded the midstream processing company is acting as an agent and the ultimate third party is the Company’s customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in its Statement of Operations. For those contracts where it is concluded the midstream processing company is acting as the principal and the Company is the customer, the Company recognizes natural gas and NGLs revenues based on the net amount of proceeds received. In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall , which addresses the fair value measurements, impairment assessment and disclosure requirements of equity securities, equity investments and other financial instruments and also clarifies current guidance to aid in the reduction of diversity in practice. For public business entities, the amended guidance is effective for fiscal years beginning after December 15, 2017 and for interim periods within those years. The amended guidance should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments related to equity securities without readily determinable fair values should be applied prospectively. The Company has completed its evaluation of the effect of the standard on its ongoing financial reporting and has determined the ASU will not materially impact its consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which modifies lessees’ recognition of lease assets and lease liabilities for those leases classified as operating leases under previous GAAP. In January 2018, the FASB issued ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which permits an entity to elect an optional transition practical expedient to not evaluate under land easements that exist or expired before the entity's adoption of this ASU and that were not previously accounted for as leases. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating all existing leases and agreements that are covered by this standard and will continue to evaluate the impact on the financial statements and related disclosures. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) , which provides guidance on eight specific cash flow issues, including cash payments associated with debt and debt modification, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and corporate-owned life insurance policies, distributions made from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017. The amendments should be applied using a retrospective transition method to each period presented. Early adoption is permitted for any entity in any interim or annual period. The Company has completed their evaluation of the ASU and has determined the standard will not materially affect the Company’s consolidated financial statements or notes to the consolidated financial statements, with the exception of presentation on the Company’s statement of cash flows. In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740) , which requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. This ASU also eliminates the exception for an intra-entity transfer of an asset other than inventory. The amended guidance does not include new disclosure requirements; however, existing disclosure requirements might be applicable when accounting for the current and deferred income taxes. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017. The amendments should be applied using a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. Early adoption is permitted for any entity as of the beginning of an annual reporting period for which financial statements have not been issued or been made available for issuance. The Company has completed their evaluation of the ASU and has determined the standard will not materially affect the Company’s consolidated financial statements or notes to the consolidated financial statements. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230) , which requires that a statement of cash flows explain the total change during the period in cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statements of cash flows. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017. The amendments should be applied using a retrospective transition method to each period presented. The amendments should be applied using a retrospective transition method to each period presented. Early adoption is permitted for any entity in any interim or annual period. The Company will implement the new guidance on January 1, 2018. The amended guidance is not expected to materially affect the Company’s consolidated financial statements or notes to the consolidated financial statement, with the exception of the presentation of restricted cash and restricted cash equivalents on the consolidated statements of cash flows. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805) , which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this ASU provide a framework which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments should be applied prospectively on or after their effective date and no disclosures are required at transition. Early adoption is permitted for transactions when the acquisition date or disposal date occurs before the issuance date or effective date of the amendment, but only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The Company plans to implement the new guidance on January 1, 2018 and because the ASU will be implemented on a prospective basis, it will only affect the consolidated financial statements and notes to the consolidated financial statements in future periods. In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting to provide clarity and reduce both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The standard has an effective date for fiscal years beginning after December 31, 2017, and interim periods within those fiscal years, with early adoption permitted. The Company elected to early adopt this standard in the fourth quarter ended December 31, 2017. The amendments in this standard are to be applied prospectively to an award modified on or after the adoption date. Adopting this standard had no impact on the Company’s consolidated financial statements. |
Summary of Significant Accoun25
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Revenue Percentage Accounted by Purchasers | For the years ended December 31, 2017 , 2016 and 2015 , each of the following purchasers accounted for more than 10% of the Company’s revenue: Year Ended December 31, 2017 2016 2015 Shell Trading (US) Company 62% 44% 23% BML, Inc. 2% 13% 19% Targa Pipeline Mid-Continent, LLC 13% 13% 12% TransOil Marketing, LLC 1% 8% 13% |
Summary of Changes in Asset Retirement Obligations | The following table summarizes the changes in the Company’s asset retirement obligation for the periods indicated (in thousands): Year ended December 31, 2017 2016 Asset retirement obligations, beginning of year $ 11,392 $ 18,220 Additional liabilities incurred 9,081 3,290 Disposition of wells (432 ) (858 ) Accretion expense 971 732 Liabilities settled upon plugging and abandoning wells (189 ) (56 ) Revision of estimates 6,752 (9,936 ) Liabilities related to assets held for sale (405 ) — Asset retirement obligations, end of year $ 27,170 $ 11,392 The following table summarizes the Company’s asset retirement obligations as of December 31, 2017 (in thousands): Payments Due by Period 2018 2019 2020 2021 2022 Thereafter Total Asset retirement obligations $ 6,297 $ 774 $ 824 $ 834 $ 929 $ 17,512 $ 27,170 |
Exploration Costs | The following table summarizes exploration and abandonment costs incurred by the Company for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Leasehold abandonments $ 32,872 $ 6,063 $ 8,227 Geological and geophysical costs 5,429 3,015 5,459 Idle drilling rig fees 1,070 4,304 — Unproved leasehold amortization 1,044 549 179 Total exploration and abandonment costs $ 40,415 $ 13,931 $ 13,865 |
Derivative Financial Instrume26
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Summary of Outstanding Oil and Gas Derivative Contracts and Weighted Average Oil and Gas Prices | The following table sets forth the volumes associated with the Company’s outstanding oil derivative contracts expiring during the periods indicated and the weighted average oil prices for those contracts: Year Ending December 31, Crude Options 2018 2019 Put spread Purchased: Puts (1) Notional (MBbl) 10,500 2,100 Weighted average strike price $ 50.43 $ 50.00 Sold: Puts (1) Notional (MBbl) (10,500 ) (2,100 ) Weighted average strike price $ 40.29 $ 40.00 Three-way collars Purchased: Puts Notional (MBbl) 14,100 3,000 Weighted average strike price $ 50.21 $ 50.00 Sold: Puts Notional (MBbl) (14,100 ) (3,000 ) Weighted average strike price $ 40.05 $ 40.00 Calls Notional (MBbl) (14,100 ) (3,000 ) Weighted average strike price $ 70.54 $ 80.40 Two-way Collars Purchased: Puts Notional (MBbl) 825 — Weighted average strike price $ 45.67 $ — Sold: Calls Notional (MBbl) (825 ) — Weighted average strike price $ 61.31 $ — Basis swap contracts: (2) Midland-Cushing index swap volume (MBbl) (3) 4,158 — Price differential ($/Bbl) $ (0.86 ) $ — (1) Excludes 1,818 notional MBbls with a fair value of $1.4 million related to amounts recognized under master netting agreements with derivative counterparties. (2) Represents swaps that fix the basis differentials between the index prices at which the Company sells its oil produced in the Permian Basin and the Cushing WTI price. The following table sets forth the volumes associated with the Company’s outstanding natural gas derivative contracts expiring during the periods indicated and the weighted average natural gas prices for those contracts: Year Ending December 31, Natural Gas 2018 Three-Way Collars Purchased: Puts Notional (MMbtu) 5,400 Weighted average strike price $ 3.11 Sold: Puts Notional (MMbtu) (5,400 ) Weighted average strike price $ 2.68 Calls Notional (MMbtu) (5,400 ) Weighted average strike price $ 4.09 Swaps Volume (MMbtu) 450 Strike price ($/MMbtu) $ 3.50 |
Derivative Instruments, Gain (Loss) [Table Text Block] | The table below summarizes the Company’s gains (losses) on derivative instruments for the years ended December 31, 2017 , 2016 and 2015 (in thousands): Year Ending December 31, 2017 2016 2015 Changes in fair value of derivative instruments $ (44,702 ) $ (109,033 ) 2,958 Net derivative settlements 15,670 26,441 46,454 Net premiums realization on options that settled during the period (37,103 ) 31,757 11,406 (Loss) gain on derivatives $ (66,135 ) $ (50,835 ) $ 60,818 |
Schedule of Netting Offsets of Derivative Asset and Liability Positions | The following table presents the Company’s net exposure from its offsetting derivative asset and liability positions, as well as option premiums payable and receivable as of the reporting dates indicated (in thousands): Gross Amount Netting Adjustments Net Exposure December 31, 2017 Derivative assets with right of offset or master netting agreements $ 59,132 $ (1,443 ) $ 57,689 Derivative liabilities with right of offset or master netting agreements (106,986 ) 1,443 (105,543 ) December 31, 2016 Derivative assets with right of offset or master netting agreements $ 66,417 $ (10,293 ) $ 56,124 Derivative liabilities with right of offset or master netting agreements (67,261 ) 10,293 (56,968 ) |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Oil and Natural Gas Properties | Property, plant and equipment includes the following (in thousands): December 31, 2017 December 31, 2016 Oil and natural gas properties: Subject to depletion $ 4,492,802 $ 2,376,712 Not subject to depletion Incurred in 2017 2,837,766 — Incurred in 2016 947,210 1,215,920 Incurred in 2015 and prior 273,536 470,785 Total not subject to depletion 4,058,512 1,686,705 Oil and natural gas properties, successful efforts method 8,551,314 4,063,417 Less accumulated depreciation, depletion and impairment (822,459 ) (506,175 ) Total oil and natural gas properties, net 7,728,855 3,557,242 Other property, plant and equipment 131,115 73,382 Less accumulated depreciation (24,528 ) (14,064 ) Other property, plant and equipment, net 106,587 59,318 Total property, plant and equipment, net $ 7,835,442 $ 3,616,560 |
Acquisitions of Oil and Natur28
Acquisitions of Oil and Natural Gas Properties (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | The Company is in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in the Double Eagle Acquisition, and as a result, the estimates for fair value are subject to change. The Company anticipates certain changes, including, but not limited to, adjustments to working capital that are expected to be finalized prior to the measurement period’s expiration. The following table summarizes the estimated fair value of the assets acquired and liabilities assumed as a result of the Double Eagle Acquisition (in thousands): Cash $ 2,469 Receivables 20,413 Derivatives 3,970 Proved oil and natural gas properties 353,000 Unproved oil and natural gas properties 2,257,289 Total assets acquired 2,637,141 Accounts payable (47,859 ) Deferred tax liability (10,167 ) Total liabilities assumed (58,026 ) Estimated fair value of net assets acquired $ 2,579,115 |
Business Acquisition, Pro Forma Information [Table Text Block] | The following unaudited pro forma information for the years ended December 31, 2017 and 2016 represents the results of the Company’s consolidated operations as if the Double Eagle Acquisition had occurred on January 1, 2016. This information is based on historical results of operations, adjusted for certain estimated accounting adjustments and does not purport to show the Company’s actual results of operations if the transaction would have occurred on January 1, 2016, nor is it necessarily indicative of future results. The financial information was derived from the Company’s unaudited historical consolidated financial statements for the years ended December 31, 2017 and 2016 and Double Eagle’s unaudited interim financial statements from January 1, 2016 to April 20, 2017. Year Ending December 31, (in thousands, except per share data) 2017 2016 Revenues $ 986,168 $ 494,073 Operating income 276,015 19,284 Net income (loss) 138,912 (116,696 ) Net income (loss) attributable to Parsley Energy, Inc. Stockholders 105,629 (86,280 ) Net income (loss) per common share: Basic $ 0.43 $ (0.44 ) Diluted $ 0.41 $ (0.44 ) |
Sales of Oil and Natural Gas 29
Sales of Oil and Natural Gas Properties (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Gain (Loss) on Disposition of Oil and Gas Property [Abstract] | |
Schedule of assets held for sale | The following table presents balance sheet information related to the Assets Held for Sale: Assets: Accounts receivable, net $ 1,790 Oil and natural gas properties Proved oil and natural gas properties 18,435 Less: Accumulated depreciation, depletion and amortization (3,450 ) Oil and natural gas properties, net 14,985 Total assets held for sale, net $ 16,775 Liabilities: Asset retirement obligations 405 Total liabilities related to assets held for sale $ 405 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Debt | The Company’s debt consists of the following (in thousands): December 31, 2017 December 31, 2016 Revolving Credit Agreement $ — $ — 7.500% senior unsecured notes due 2022 — 61,846 6.250% senior unsecured notes due 2024 400,000 400,000 5.375% senior unsecured notes due 2025 650,000 650,000 5.250% senior unsecured notes due 2025 450,000 — 5.625% senior unsecured notes due 2027 700,000 — Capital leases 4,906 3,752 Other — 3,500 Total debt 2,204,906 1,119,098 Debt issuance costs on senior unsecured notes (26,341 ) (14,388 ) Premium on senior unsecured notes 3,312 3,828 Less: current portion (2,352 ) (67,214 ) Total long-term debt $ 2,179,525 $ 1,041,324 |
Schedule of Principal Maturities of Long-term Debt | Principal maturities debt outstanding at December 31, 2017 are as follows (in thousands): 2018 $ 2,352 2019 1,906 2020 617 2021 17 2022 14 Thereafter 2,200,000 Total $ 2,204,906 |
Schedule of Interest Expense | Interest Expense The following amounts have been incurred and charged to interest expense for the year ended December 31, 2017 , 2016 and 2015 (i |
Equity (Tables)
Equity (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Allocation of Net Income to Common Stockholders and EPS Computations | The following table reflects the allocation of net income (loss) to common stockholders and EPS computations for the periods indicated based on a weighted average number of common stock outstanding for the period: December 31, 2017 December 31, 2016 December 31, 2015 Basic EPS (in thousands, except per share data) Numerator: Basic net income (loss) attributable to Parsley Energy, Inc. Stockholders $ 106,774 $ (74,182 ) $ (50,484 ) Denominator: Basic weighted average shares outstanding 240,733 161,793 111,271 Basic EPS attributable to Parsley Energy, Inc. Stockholders $ 0.44 $ (0.46 ) $ (0.45 ) Diluted EPS Numerator: Net income (loss) attributable to Parsley Energy, Inc. Stockholders 106,774 (74,182 ) (50,484 ) Effect of conversion of the shares of Company’s Class B Common Stock to shares of the Company’s Class A Common Stock 17,646 — — Diluted net income (loss) attributable to Parsley Energy, Inc. Stockholders $ 124,420 $ (74,182 ) $ (50,484 ) Denominator: Basic weighted average shares outstanding 240,733 161,793 111,271 Effect of dilutive securities: Class B Common Stock 54,665 — — Time-Based Restricted Stock and Time-Based Restricted Stock Units 1,114 — — Diluted weighted average shares outstanding (1) 296,512 161,793 111,271 Diluted EPS attributable to Parsley Energy, Inc. Stockholders $ 0.42 $ (0.46 ) $ (0.45 ) (1) Approximately 640,062 , 453,863 and 211,935 shares related to performance-based restricted stock units that could be converted to common shares in the future based on predetermined performance and market goals were not included in the computation of EPS for the year ended December 31, 2017 , 2016 and 2015, because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the contingency period. |
Summary of Noncontrolling Interest Income | The following table summarizes the net income (loss) attributable to noncontrolling interests: Year ended December 31, 2017 2016 2015 (in thousands) Net income (loss) attributable to the noncontrolling interests of: Parsley LLC $ 17,645 $ (14,953 ) $ (21,870 ) Pacesetter Drilling, LLC (499 ) 218 (677 ) Total net income (loss) attributable to noncontrolling interests $ 17,146 $ (14,735 ) $ (22,547 ) |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Share-based Compensation, by Award | The following table reflects stock-based compensation expense recorded for each type of stock-based compensation award for the years ended December 31, 2017 , 2016 and 2015 (in thousands): Year ended December 31, 2017 2016 2015 Time-based restricted stock $ 5,492 $ 3,523 $ 3,856 Time-based restricted stock units 7,778 5,677 2,710 Performance-based restricted stock units 6,349 3,671 1,567 Total stock-based compensation expense $ 19,619 $ 12,871 $ 8,133 (1) Stock-based compensation expense on time-based restricted stock units with graded vesting is recognized on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. |
Summary of RSA, Activity | The following table summarizes the RSA activity for the year ended December 31, 2017 : Time-Based Restricted Stock Grant Date Fair Value Outstanding at January 1, 2017 600,761 $ 19.02 Awards granted 227,564 $ 31.55 Forfeited (41,014 ) $ 26.84 Vested (7,965 ) $ 18.14 Outstanding at December 31, 2017 779,346 $ 22.30 |
Schedule of Nonvested Restricted Stock Units Activity | The following table summarizes the RSU activity for the year ended December 31, 2017 : Time-Based Restricted Stock Units Grant Date Fair Value Outstanding at January 1, 2017 1,045,786 $ 16.96 Awards granted 209,186 $ 31.86 Forfeited (33,170 ) $ 22.69 Vested (22,083 ) $ 22.77 Outstanding at December 31, 2017 1,199,719 $ 19.36 |
Schedule of Valuation Assumptions | The Company used the following assumptions to estimate the fair value of PSUs granted during the periods indicated: Year Ended December 31, 2017 2016 2015 Risk-free interest rate 1.45 % 0.88 % 1.05 % Range of volatilities 37.7% - 79.5% 35.0% - 65.1% 42.2% - 84.8% |
Schedule of PSU, Activity | The following table summarizes the PSU activity for the year ended December 31, 2017 : Performance-Based Restricted Units Grant Date Fair Value Outstanding at January 1, 2017 453,863 $ 25.06 Awards granted 186,199 $ 42.40 Outstanding at December 31, 2017 640,062 $ 30.11 |
Schedule of Expected Share Based Compensation Expense | The following table reflects the future stock-based compensation expense to be recorded for the stock-based compensation awards that were outstanding at December 31, 2017 (in thousands): Time-Based Restricted Stock Time-Based Restricted Stock Units Performance-Based Restricted Units Total 2018 $ 3,537 $ 5,292 $ 4,923 $ 13,752 2019 1,977 2,403 2,753 7,133 2020 255 259 8 522 Total $ 5,769 $ 7,954 $ 7,684 $ 21,407 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Components of Income Tax Provision | The components of the income tax expense (benefit) were as follows for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Federal: Current $ (44 ) $ 158 $ 286 Deferred (423 ) (18,461 ) (27,535 ) Total federal (467 ) (18,303 ) (27,249 ) State, net of federal benefit: Deferred 6,175 879 3,494 Total state 6,175 879 3,494 Income tax expense (benefit) $ 5,708 $ (17,424 ) $ (23,755 ) |
Schedule of Reconciliation of Income Tax (Benefit) Provision with Income Tax Expense at Federal Statutory Rate | The following table reconciles the income tax expense (benefit) with income tax expense at the federal statutory rate for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Income (loss) before income taxes $ 129,628 $ (106,341 ) $ (96,785 ) Less: net loss (income) before income taxes attributable (18,725 ) 14,579 22,438 Income (loss) attributable to Parsley Energy, Inc. Stockholders before income taxes 110,903 (91,762 ) (74,347 ) Income taxes at the federal statutory rate 38,816 (32,120 ) (26,022 ) State income taxes, net of federal benefit 6,175 879 3,494 Provision to return adjustment 178 (237 ) (1,217 ) Permanent and other 166 (61 ) (10 ) TRA Liability change (12,547 ) (2,573 ) — Valuation allowance (26,657 ) 32,215 — Valuation allowance charged to equity — (15,527 ) — Valuation allowance due to the reduction in federal statutory rate (24,356 ) — — Income tax provision due to change in federal statutory rate 23,933 — — Income tax expense (benefit) $ 5,708 $ (17,424 ) $ (23,755 ) Net income (loss) attributable to Parsley Energy, Inc. Stockholders $ 106,774 $ (74,182 ) $ (50,484 ) Net income (loss) attributable to noncontrolling interest $ 17,146 $ (14,735 ) $ (22,547 ) |
Schedule of Tax Effects of Significant Portions of the Deferred Tax Assets and Deferred Tax Liabilities | The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows (in thousands): December 31, 2017 2016 Assets: Asset retirement obligations $ 4,854 $ 3,535 Deferred stock-based compensation 7,874 6,868 Derivative fair value loss 12,493 8,252 Accrued compensation 4,241 3,398 Net operating loss carryforward 48,666 44,407 Other 78 166 Total deferred tax assets 78,206 66,626 Less: Valuation allowance (9,264 ) (32,215 ) Net deferred tax assets 68,942 34,411 Liabilities: Book basis of oil and natural gas properties (89,299 ) (38,489 ) Earnings in investment in subsidiary (828 ) (1,116 ) Other (218 ) (289 ) Total deferred tax liabilities (90,345 ) (39,894 ) Net deferred tax liability $ (21,403 ) $ (5,483 ) |
Schedule Of Open Tax Years | The Company’s earliest open years in its key jurisdictions are as follows: U.S. federal 2014 State of Texas 2013 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Summary of Changes in Asset Retirement Obligations | The following table summarizes the changes in the Company’s asset retirement obligation for the periods indicated (in thousands): Year ended December 31, 2017 2016 Asset retirement obligations, beginning of year $ 11,392 $ 18,220 Additional liabilities incurred 9,081 3,290 Disposition of wells (432 ) (858 ) Accretion expense 971 732 Liabilities settled upon plugging and abandoning wells (189 ) (56 ) Revision of estimates 6,752 (9,936 ) Liabilities related to assets held for sale (405 ) — Asset retirement obligations, end of year $ 27,170 $ 11,392 The following table summarizes the Company’s asset retirement obligations as of December 31, 2017 (in thousands): Payments Due by Period 2018 2019 2020 2021 2022 Thereafter Total Asset retirement obligations $ 6,297 $ 774 $ 824 $ 834 $ 929 $ 17,512 $ 27,170 |
Schedule of Company Drilling and Derivative Commitments | The following table summarizes the Company’s drilling commitments as of December 31, 2017 (in thousands): Payments Due by Period 2018 2019 2020 2021 2022 Thereafter Total Drilling commitments $ 30,752 $ 46,150 $ — $ — $ — $ — $ 76,902 Derivative Obligations The future deferred premium payments related to derivative agreements as of December 31, 2017 was as follows (in thousands): Payments Due by Period 2018 2019 2020 2021 2022 Thereafter Total Derivative obligations $ 49,601 $ 14,730 $ — $ — $ — $ — $ 64,331 |
Schedule of Future Minimum Lease Payments under Long Term Operating Lease Agreements | The estimated future minimum lease payments under long-term operating lease agreements as of December 31, 2017 was as follows (in thousands): For the years ended December 31, 2018 2019 2020 2021 2022 Thereafter Total Office Leases $ 8,810 $ 9,626 $ 9,640 $ 9,219 $ 9,102 $ 20,219 $ 66,616 Office Equipment 155 76 4 1 — — 236 Total $ 8,965 $ 9,702 $ 9,644 $ 9,220 $ 9,102 $ 20,219 $ 66,852 |
Disclosures about Fair Value 35
Disclosures about Fair Value of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Financial Assets and Liabilities Measured at Fair Value | The following summarizes the fair value of the Company’s derivative assets and liabilities according to their fair value hierarchy as of the reporting dates indicated (in thousands): December 31, 2017 Level 1 Level 2 Level 3 Total Assets: Money market funds $ 476,619 $ — $ — 476,619 Commodity derivative contracts — 57,689 — 57,689 Total assets $ 476,619 $ 57,689 $ — $ 534,308 Liabilities: Commodity derivative contracts $ — $ (105,543 ) $ — $ (105,543 ) Total liabilities $ — $ (105,543 ) $ — $ (105,543 ) Net asset (liability) $ 476,619 $ (47,854 ) $ — $ 428,765 December 31, 2016 Level 1 Level 2 Level 3 Total Assets: Money market funds $ 94,280 $ — $ — 94,280 Commodity derivative contracts — 56,124 — 56,124 Total assets 94,280 56,124 — 150,404 Liabilities: Commodity derivative contracts — (56,968 ) — (56,968 ) Total liabilities — (56,968 ) — (56,968 ) Net asset (liability) $ 94,280 $ (844 ) $ — $ 93,436 |
Schedule Of Fair Value Of Financial Instruments Not Recorded At Fair Value Table | The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets (in thousands): December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents: Commercial paper $ 24,939 $ 24,918 $ — $ — Short-term investments: Commercial paper 149,283 149,151 — — Current portion of long-term debt: 7.500% senior unsecured notes due 2022 — — 61,846 65,737 Long-term debt: 6.250% senior unsecured notes due 2024 400,000 423,824 400,000 422,548 5.375% senior unsecured notes due 2025 650,000 658,483 650,000 654,531 5.250% senior unsecured notes due 2025 450,000 454,010 — — — 5.625% senior unsecured notes due 2027 700,000 715,169 — — Revolving Credit Agreement — — — — |
Schedule of Cash and Cash Equivalents [Table Text Block] | The following table provides the components of the Company’s cash and cash equivalents and short-term investments as of the dates indicated (in thousands): December 31, 2017 Consolidated Balance Sheet Location Cash Commercial Paper Money Market Funds Total Cash and cash equivalents $ 52,631 $ 24,939 $ 476,619 $ 554,189 Short-term investments — 149,283 — 149,283 December 31, 2016 Consolidated Balance Sheet Location Cash Commercial Paper Money Market Funds Total Cash and cash equivalents $ 39,099 $ — $ 94,280 $ 133,379 |
Supplemental Disclosure of Oi36
Supplemental Disclosure of Oil and Natural Gas Operations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Schedule of Capitalized Costs | Capitalized Costs December 31, 2017 2016 (in thousands) Oil and natural gas properties: Proved properties $ 4,492,802 $ 2,376,712 Unproved properties 4,058,512 1,686,705 Total oil and natural gas properties 8,551,314 4,063,417 Less accumulated depreciation, depletion and amortization (822,459 ) (506,175 ) Net oil and natural gas properties capitalized $ 7,728,855 $ 3,557,242 |
Schedule of Costs Incurred for Oil and Gas Producing Activities | Costs Incurred for Oil and Natural Gas Producing Activities Year Ended December 31, 2017 2016 2015 (in thousands) Acquisition costs: Proved properties $ 482,160 $ 273,940 $ 16,422 Unproved properties 2,893,434 1,072,250 57,385 Development costs 1,207,401 495,971 404,291 Total $ 4,582,995 $ 1,842,161 $ 478,098 |
Schedule of Reserve Quantity Information Average Sales Price | The pricing that was used for estimates of the Company’s reserves as of December 31, 2017 was based on an unweighted average 12-month average WTI posted price per Bbl for oil and NGLs and a Waha spot natural gas price per Mcf for natural gas, adjusted for transportation, quality and basis differentials, as set forth in the following table: Year Ended December 31, 2017 2016 2015 Oil (per Bbl) $ 49.17 $ 39.36 $ 46.54 Natural gas (per Mcf) $ 2.53 $ 2.23 $ 2.53 Natural gas liquids (per Bbl) $ 22.20 $ 15.04 $ 16.42 |
Schedule of Proved Developed and Proved Undeveloped Reserves | The following table and subsequent narrative disclosure provides a roll forward of the total proved reserves for the years ended December 31, 2017 , 2016 and 2015 , as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Year Ended December 31, 2017 Crude Oil (MBbls) Natural Gas Liquids MBoe Proved Developed and Undeveloped Reserves: Beginning of the year 136,536 223,605 48,543 222,347 Extensions and discoveries 99,916 161,989 33,426 160,340 Revisions of previous estimates (709 ) 32,342 4,522 9,205 Purchases of reserves in place 33,017 64,055 12,121 55,814 Divestures of reserves in place (3,839 ) (6,962 ) (1,468 ) (6,467 ) Production (16,390 ) (23,326 ) (4,512 ) (24,792 ) End of the year 248,531 451,703 92,632 416,447 Proved Developed Reserves: Beginning of the year 61,133 123,946 24,306 106,097 End of the year 119,591 240,337 49,751 209,399 Proved Undeveloped Reserves: Beginning of the year 75,403 99,659 24,237 116,250 End of the year 128,940 211,366 42,880 207,048 Year Ended December 31, 2016 Crude Oil (MBbls) Natural Gas Liquids MBoe Proved Developed and Undeveloped Reserves: Beginning of the year 73,877 157,175 23,738 123,811 Extensions and discoveries 64,005 83,815 20,698 98,672 Revisions of previous estimates (4,476 ) (19,032 ) 3,898 (3,750 ) Purchases of reserves in place 16,041 25,024 4,023 24,235 Divestures of reserves in place (3,543 ) (9,914 ) (1,424 ) (6,619 ) Production (9,368 ) (13,463 ) (2,390 ) (14,002 ) End of the year 136,536 223,605 48,543 222,347 Proved Developed Reserves: Beginning of the year 27,628 77,612 10,890 51,453 End of the year 61,133 123,946 24,306 106,097 Proved Undeveloped Reserves: Beginning of the year 46,249 79,563 12,848 72,358 End of the year 75,403 99,659 24,237 116,250 Year Ended December 31, 2015 Crude Oil (MBbls) Natural Gas Liquids MBoe Proved Developed and Undeveloped Reserves: Beginning of the year 47,617 123,645 22,667 90,891 Extensions and discoveries 38,282 52,629 9,163 56,217 Revisions of previous estimates (7,493 ) (14,572 ) (7,278 ) (17,201 ) Purchases of reserves in place 1,897 6,946 921 3,976 Divestures of reserves in place (1,619 ) (1,134 ) (235 ) (2,042 ) Production (4,807 ) (10,339 ) (1,500 ) (8,030 ) End of the year 73,877 157,175 23,738 123,811 Proved Developed Reserves: Beginning of the year 23,547 65,484 11,491 45,952 End of the year 27,628 77,612 10,890 51,453 Proved Undeveloped Reserves: Beginning of the year 24,070 58,161 11,176 44,939 End of the year 46,249 79,563 12,848 72,358 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGLs reserves is as follows: December 31, 2017 2016 2015 (in thousands) Future cash inflows $ 15,421,590 $ 6,603,206 $ 4,225,912 Future development costs (2,181,447 ) (1,019,823 ) (829,560 ) Future production costs (4,536,530 ) (2,176,081 ) (1,534,011 ) Future income tax expenses (1,102,385 ) (370,337 ) (240,203 ) Future net cash flows 7,601,228 3,036,965 1,622,138 10% discount to reflect timing of cash flows (4,585,723 ) (1,852,653 ) (1,024,290 ) Standardized measure of discounted future net cash flows $ 3,015,505 $ 1,184,312 $ 597,848 |
Schedule of Changes in Standardized Measure Discounted Future Net Cash Flows | Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGLs reserves are as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Standardized measure of discounted future net cash flows at the beginning of the year $ 1,184,312 $ 597,848 $ 955,629 Sales of oil and natural gas, net of production costs (800,553 ) (369,295 ) (185,344 ) Purchase of minerals in place 489,910 118,795 4,872 Divestiture of minerals in place (50,257 ) (14,591 ) (53,018 ) Extensions and discoveries, net of future development costs 1,864,041 770,947 485,380 Previously estimated development costs incurred during the period 58,377 61,756 12,560 Net changes in prices and production costs 525,693 (80,492 ) (821,783 ) Changes in estimated future development costs (150,028 ) 118,930 77,621 Revisions of previous quantity estimates 142,510 84,309 (225,485 ) Accretion of discount 148,314 69,731 131,442 Net change in income taxes (603,696 ) (199,368 ) 249,065 Net changes in timing of production and other 206,882 25,742 (33,091 ) Standardized measure of discounted future net cash flows at the end of the year $ 3,015,505 $ 1,184,312 $ 597,848 |
Summary of Quarterly Financia37
Summary of Quarterly Financial Results (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summary of Quarterly Financial Results (Unaudited) | The Company’s unaudited quarterly financial data for the years ended December 31, 2017 and 2016 is summarized as follows: First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts) 2017 Revenues $ 200,858 $ 213,677 $ 241,021 $ 311,488 Operating income $ 72,531 $ 45,259 $ 63,072 $ 85,939 Income tax (expense) benefit $ (18,402 ) $ (12,216 ) $ 5,080 $ 19,830 Net income (loss) $ 38,290 $ 55,794 $ (15,161 ) $ 44,997 Net income (loss) attributable to noncontrolling interests $ 8,848 $ 15,048 $ (1,828 ) $ (39,214 ) Net income (loss) attributable to Parsley Energy, Inc. stockholders $ 29,442 $ 40,746 $ (13,333 ) $ 49,919 Net income (loss) per common share: Basic $ 0.13 $ 0.17 $ (0.05 ) $ 0.20 Diluted $ 0.13 $ 0.17 $ (0.05 ) $ 0.16 2016 Revenues $ 62,488 $ 106,872 $ 132,537 $ 155,876 Operating (loss) income $ (26,042 ) $ 1,636 $ 12,340 $ 43,213 Income tax benefit (expense) $ 9,568 $ 10,918 $ 1,279 $ (4,341 ) Net loss $ (25,691 ) $ (27,488 ) $ (1,641 ) $ (34,097 ) Net income (loss) attributable to noncontrolling interests $ (6,337 ) $ (6,111 ) $ 1,065 $ (3,352 ) Net loss attributable to Parsley Energy, Inc. stockholders $ (19,354 ) $ (21,377 ) $ (2,706 ) $ (30,745 ) Net loss per common share: Basic $ (0.14 ) $ (0.13 ) $ (0.02 ) $ (0.17 ) Diluted $ (0.14 ) $ (0.13 ) $ (0.02 ) $ (0.17 ) |
Organization and Nature of Op38
Organization and Nature of Operations - Double Eagle Acquisition (Details) - USD ($) $ / shares in Units, $ in Millions | Apr. 20, 2017 | Dec. 31, 2017 | Dec. 31, 2016 |
Double Eagle Acquisition | |||
Business Acquisition [Line Items] | |||
Total consideration for acquisition | $ 1,395.6 | ||
PE Units | Double Eagle Acquisition | |||
Business Acquisition [Line Items] | |||
Consideration transferred (shares) | 39,848,518 | ||
Class B Common Stock | |||
Business Acquisition [Line Items] | |||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 | |
Class B Common Stock | Common Stock | Double Eagle Acquisition | |||
Business Acquisition [Line Items] | |||
Consideration transferred (shares) | 39,848,518 | ||
Common stock, par value (in dollars per share) | 0.01 | ||
Class A Common Stock | |||
Business Acquisition [Line Items] | |||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Organization and Nature of Op39
Organization and Nature of Operations - Public Offering Of Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands | Feb. 13, 2017 | Feb. 07, 2017 | Jan. 17, 2017 | Jan. 10, 2017 | Apr. 08, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Subsidiary, Sale of Stock [Line Items] | ||||||||
Proceeds from issuance of common stock, net | $ 2,123,344 | $ 930,315 | $ 669,418 | |||||
Class A Common Stock | Common Stock | ||||||||
Subsidiary, Sale of Stock [Line Items] | ||||||||
Common stock sold in initial public offering net of offering costs (in shares) | 66,700,000 | 38,812,000 | 42,748,000 | |||||
Class A Common Stock | Public Offering | Common Stock | ||||||||
Subsidiary, Sale of Stock [Line Items] | ||||||||
Common stock sold in initial public offering net of offering costs (in shares) | 41,400,000 | 25,300,000 | 38,812,500 | 42,747,161 | ||||
Option to purchase additional shares (in shares) | 5,400,000 | 3,300,000 | 5,062,500 | 1,950,000 | ||||
Price per share (in dollars per share) | $ 31 | $ 35 | ||||||
Gross proceeds received from public offering | $ 1,283,400 | $ 885,500 | $ 962,200 | $ 683,700 | ||||
Proceeds from issuance of common stock, net | $ 1,260,500 | $ 863,000 | $ 930,300 | $ 669,400 |
Summary of Significant Accoun40
Summary of Significant Accounting Policies - Additional Information (Details) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2017USD ($)segment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||
Restricted cash | $ 0 | $ 0 | $ 3,290,000 | $ 0 | $ 3,290,000 | |||||||
Release of escrow funds | 4,800,000 | |||||||||||
Revenue, net | 3,600,000 | 311,488,000 | $ 241,021,000 | $ 213,677,000 | $ 200,858,000 | 155,876,000 | $ 132,537,000 | $ 106,872,000 | $ 62,488,000 | 967,044,000 | 457,773,000 | $ 266,474,000 |
Allowance for doubtful accounts receivable | $ 0 | $ 0 | $ 0 | 0 | 0 | |||||||
Depreciation expense | 11,500,000 | 6,600,000 | 4,700,000 | |||||||||
Impairment of equity investments | 0 | 0 | 0 | |||||||||
Contribution by company | 2,800,000 | $ 1,900,000 | $ 1,400,000 | |||||||||
Tax Cuts And Jobs Act Of 2017, Incomplete Accounting, Provisional Income Tax Expense | 23,900,000 | |||||||||||
Tax Cuts And Jobs Act Of 2017, Incomplete Accounting, Change In Tax Rate, Deferred Tax Asset, Provisional Income Tax Expense | 23,900,000 | |||||||||||
Tax Cuts And Jobs Act Of 2017, Incomplete Accounting, Change In Tax Rate, Deferred Tax Asset Valuation Allowance, Provisional Income Tax Expense | $ 24,300,000 | |||||||||||
Number of segments | segment | 1 | |||||||||||
Minimum | ||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||
Property and equipment, estimated useful lives | 3 years | |||||||||||
Maximum | ||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||
Property and equipment, estimated useful lives | 15 years | |||||||||||
SPS | ||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||
Equity method investment, ownership percentage | 42.50% | 42.50% | 42.50% | |||||||||
Parsley LLC | Parent | Pacesetter Drilling, LLC | ||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||
Percentage of ownership interest, parent | 63.00% | 63.00% | 63.00% |
Summary of Significant Accoun41
Summary of Significant Accounting Policies - Summary of Revenue Percentage Accounted by Purchasers (Details) - Customer Concentration Risk - Sales Revenue, Net | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Shell Trading (US) Company | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 62.00% | 44.00% | 23.00% |
BML, Inc. | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 2.00% | 13.00% | 19.00% |
Targa Pipeline Mid-Continent, LLC | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 13.00% | 13.00% | 12.00% |
TransOil Marketing, LLC | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 1.00% | 8.00% | 13.00% |
Summary of Significant Accoun42
Summary of Significant Accounting Policies - Summary of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Asset retirement obligations, beginning of year | $ 11,392 | $ 18,220 | |
Additional liabilities incurred | 9,081 | 3,290 | |
Disposition of wells | (432) | (858) | |
Accretion expense | 971 | 732 | $ 826 |
Liabilities settled upon plugging and abandoning wells | (189) | (56) | |
Revision of estimates | 6,752 | (9,936) | |
Liabilities related to assets held for sale | (405) | 0 | |
Asset retirement obligations, end of year | $ 27,170 | $ 11,392 | $ 18,220 |
Summary of Significant Accoun43
Summary of Significant Accounting Policies - Summary of Exploration Costs Incurred (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | |||
Exploration and abandonment costs | $ 40,415 | $ 13,931 | $ 13,865 |
Leasehold abandonments | |||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | |||
Exploration and abandonment costs | 32,872 | 6,063 | 8,227 |
Geological and geophysical costs | |||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | |||
Exploration and abandonment costs | 5,429 | 3,015 | 5,459 |
Idle drilling rig fees | |||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | |||
Exploration and abandonment costs | 1,070 | 4,304 | 0 |
Unproved leasehold amortization | |||
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items] | |||
Exploration and abandonment costs | $ 1,044 | $ 549 | $ 179 |
Derivative Financial Instrume44
Derivative Financial Instruments - Summary of Outstanding Oil and Gas Derivative Contracts and Weighted Average Oil and Gas Prices (Details) - Forecast $ in Millions | 12 Months Ended | |
Dec. 31, 2019$ / MBblsMBbls | Dec. 31, 2018USD ($)MMBTU$ / MBbls$ / MMBTUMBbls | |
Crude Oil (MBbls) | Purchased | Puts | ||
Derivative [Line Items] | ||
Notional (MBbl) | (2,100) | (10,500) |
Weighted average strike price (in dollars per unit) | $ / MBbls | 50 | 50.43 |
Crude Oil (MBbls) | Sold | Puts | ||
Derivative [Line Items] | ||
Notional (MBbl) | (2,100) | (10,500) |
Weighted average strike price (in dollars per unit) | $ / MBbls | 40 | 40.29 |
Natural Gas | Purchased | Puts | ||
Derivative [Line Items] | ||
Notional (MMbtu) | MMBTU | (5,400) | |
Weighted average strike price (in dollars per unit) | $ / MMBTU | 3.11 | |
Natural Gas | Sold | Puts | ||
Derivative [Line Items] | ||
Notional (MMbtu) | MMBTU | (5,400) | |
Weighted average strike price (in dollars per unit) | $ / MMBTU | 2.68 | |
Natural Gas | Sold | Calls | ||
Derivative [Line Items] | ||
Notional (MMbtu) | MMBTU | (5,400) | |
Weighted average strike price (in dollars per unit) | $ / MMBTU | 4.09 | |
Swap [Member] | Natural Gas | ||
Derivative [Line Items] | ||
Price differential ($/Bbl) | $ / MMBTU | 3.50 | |
Notional (MMbtu) | MMBTU | (450) | |
Basis Swap | Crude Oil (MBbls) | ||
Derivative [Line Items] | ||
Price differential ($/Bbl) | $ / MBbls | 0 | 0.86 |
Basis Swap | Crude Oil (MBbls) | Midland-Cushing Index | ||
Derivative [Line Items] | ||
Notional (MBbl) | 0 | (4,158) |
Subject to Master Netting Agreement with Counter Party | Crude Oil (MBbls) | Sold | Puts | ||
Derivative [Line Items] | ||
Notional (MBbl) | (1,818) | |
Fair value of notional MBbls excluded | $ | $ 1.4 | |
Three Way Collars [Member] | Crude Oil (MBbls) | Purchased | Puts | ||
Derivative [Line Items] | ||
Notional (MBbl) | (3,000) | (14,100) |
Weighted average strike price (in dollars per unit) | $ / MBbls | 50 | 50.21 |
Three Way Collars [Member] | Crude Oil (MBbls) | Sold | Puts | ||
Derivative [Line Items] | ||
Notional (MBbl) | (3,000) | (14,100) |
Weighted average strike price (in dollars per unit) | $ / MBbls | 40 | 40.05 |
Three Way Collars [Member] | Crude Oil (MBbls) | Sold | Calls | ||
Derivative [Line Items] | ||
Notional (MBbl) | (3,000) | (14,100) |
Weighted average strike price (in dollars per unit) | $ / MBbls | 80.40 | 70.54 |
Collars [Member] | Crude Oil (MBbls) | Purchased | Puts | ||
Derivative [Line Items] | ||
Notional (MBbl) | 0 | (825) |
Weighted average strike price (in dollars per unit) | $ / MBbls | 0 | 45.67 |
Collars [Member] | Crude Oil (MBbls) | Sold | Calls | ||
Derivative [Line Items] | ||
Notional (MBbl) | 0 | (825) |
Weighted average strike price (in dollars per unit) | $ / MBbls | 0 | 61.31 |
Derivative Financial Instrume45
Derivative Financial Instruments - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Changes in fair value of derivative instruments | $ (66,135) | $ (50,835) | $ 60,818 |
Net premiums realization on options that settled during the period | 37,103 | (31,757) | (11,406) |
Not Designated as Hedging Instrument [Member] | |||
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |||
Changes in fair value of derivative instruments | (44,702) | (109,033) | 2,958 |
Net derivative settlements | 15,670 | 26,441 | 46,454 |
Net premiums realization on options that settled during the period | (37,103) | 31,757 | 11,406 |
(Loss) gain on derivatives | $ (66,135) | $ (50,835) | $ 60,818 |
Derivative Financial Instrume46
Derivative Financial Instruments - Schedule of Netting Offsets of Derivative Asset and Liability Positions (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative asset, Gross Amount Presented on Balance Sheet | $ 59,132 | $ 66,417 |
Derivative asset, Netting Adjustments | (1,443) | (10,293) |
Derivative asset, Net Exposure | 57,689 | 56,124 |
Derivative liability, Gross Amount Presented on Balance Sheet | (106,986) | (67,261) |
Derivative liability, Netting Adjustments | 1,443 | 10,293 |
Derivative liability, Net Exposure | $ (105,543) | $ (56,968) |
Oil and Natural Gas Properties
Oil and Natural Gas Properties - Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Oil and natural gas properties: | ||
Subject to depletion | $ 4,492,802 | $ 2,376,712 |
Not subject to depletion | 4,058,512 | 1,686,705 |
Oil and natural gas properties, successful efforts method | 8,551,314 | 4,063,417 |
Less accumulated depreciation, depletion and impairment | (822,459) | (506,175) |
Total oil and natural gas properties, net | 7,728,855 | 3,557,242 |
Other property, plant and equipment | 131,115 | 73,382 |
Less accumulated depreciation | (24,528) | (14,064) |
Other property, plant and equipment, net | 106,587 | 59,318 |
Total property, plant and equipment, net | 7,835,442 | 3,616,560 |
Incurred in 2017 | ||
Oil and natural gas properties: | ||
Not subject to depletion | 2,837,766 | 0 |
Incurred in 2016 | ||
Oil and natural gas properties: | ||
Not subject to depletion | 947,210 | 1,215,920 |
Incurred in 2015 and prior | ||
Oil and natural gas properties: | ||
Not subject to depletion | $ 273,536 | $ 470,785 |
Oil and Natural Gas Propertie48
Oil and Natural Gas Properties - Additional Information (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($)Well | Dec. 31, 2016USD ($)Well | Dec. 31, 2015USD ($)Well | |
Property, Plant and Equipment [Abstract] | |||
Capitalized costs excluded from depletion | $ 4,058,512,000 | $ 1,686,705,000 | |
Depletion expense on capitalized oil and gas property | $ 340,800,000 | $ 227,200,000 | $ 173,600,000 |
Number of exploratory wells in progress | Well | 0 | 0 | 0 |
Additions pending determination of proved reserves | $ 94,400,000 | $ 49,400,000 | |
Interest costs capitalized | $ 0 | $ 0 | $ 0 |
Acquisitions of Oil and Natur49
Acquisitions of Oil and Natural Gas Properties (Details) - USD ($) | Apr. 20, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Business Acquisition [Line Items] | ||||
Acquisition costs | $ 10,977,000 | $ 1,081,000 | $ 0 | |
Costs incurred, acquisition of unproved oil and gas properties | 2,893,434,000 | 1,072,250,000 | 57,385,000 | |
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves | 482,160,000 | 273,940,000 | 16,422,000 | |
Acquisition from Unaffiliated Individuals and Entities | ||||
Business Acquisition [Line Items] | ||||
Total consideration for acquisition | 3,181,100,000 | 1,267,100,000 | 35,000,000 | |
Depletion expense on capitalized oil and gas property | 261,400,000 | 16,400,000 | ||
Costs incurred, acquisition of unproved oil and gas properties | 2,716,900,000 | 1,005,700,000 | 18,600,000 | |
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves | 464,200,000 | |||
Double Eagle Acquisition | ||||
Business Acquisition [Line Items] | ||||
Business Acquisition, Pro Forma Revenue | 986,168 | 494,073 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents | 2,469,000 | |||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | 75,900,000 | |||
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual | 25,900,000 | |||
Total consideration for acquisition | $ 1,395,600,000 | |||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables | 20,413,000 | |||
BusinessCombinationRecognizedIdentifiableAssetsAcquiredandLiabilitiesAssumedDerivatives | 3,970,000 | |||
BusinessCombinationRecognizedIdentifiableAssetsAcquiredandLiabilitiesAssumedProvedOilandNaturalGasProperties | 353,000,000 | |||
BusinessCombinationRecognizedIdentifiableAssetsAcquiredandLiabilitiesAssumedUnprovedOilandNaturalGasProperties | 2,257,289,000 | |||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 2,637,141,000 | |||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable | (47,859,000) | |||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent | (10,167,000) | |||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | (58,026,000) | |||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | 2,579,115,000 | |||
Payments to Acquire Businesses, Gross | $ 172,300,000 | |||
Business Acquisition, Pro Forma Income (Loss) from Continuing Operations, Net of Tax | 276,015 | 19,284 | ||
Business Acquisition, Pro Forma Net Income (Loss) | 138,912 | (116,696) | ||
Business Acquisitions, Pro Forma Net Income (Loss) Attributable to Parent | $ 105,629 | $ (86,280) | ||
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ 0.43 | $ (0.44) | ||
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ 0.41 | $ (0.44) | ||
Leasehold Improvements | ||||
Business Acquisition [Line Items] | ||||
Acquisition costs | $ 194,500,000 | $ 79,100,000 | $ 38,800,000 | |
Costs incurred, acquisition of unproved oil and gas properties | 176,500,000 | |||
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves | $ 18,000,000 | |||
PE Units | Double Eagle Acquisition | ||||
Business Acquisition [Line Items] | ||||
Consideration transferred (shares) | 39,848,518 | |||
Business Combination, Equity Interests Issued or Issuable, Held in Escrow, Shares | 4,921,557 | |||
Class B Common Stock | Common Stock | Double Eagle Acquisition | ||||
Business Acquisition [Line Items] | ||||
Consideration transferred (shares) | 39,848,518 | |||
Business Combination, Equity Interests Issued or Issuable, Held in Escrow, Shares | 4,921,557 |
Sales of Oil and Natural Gas 50
Sales of Oil and Natural Gas Properties (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)a | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($)aWell | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Number of operated wells sold | Well | 91 | ||
Oil and natural gas properties sold, gross | a | 21,939 | 25,077 | |
Oil and natural gas properties sold | a | 7,476 | 16,319 | |
Proceeds from Sale of Property, Plant, and Equipment | $ 30,537 | $ 0 | $ 51,355 |
Proceeds from sale of property | 48,700 | ||
Loss on sale of oil and natural gas properties | 14,300 | $ 33,500 | |
Accounts receivable, net | 1,790 | 0 | |
Proved oil and natural gas properties | 8,551,314 | 4,063,417 | |
Less: Accumulated depreciation, depletion and amortization | (822,459) | (506,175) | |
Oil and natural gas properties, net | 14,985 | 0 | |
Total liabilities related to assets held for sale | 405 | $ 0 | |
Assets held for sale | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Accounts receivable, net | 1,790 | ||
Proved oil and natural gas properties | 18,435 | ||
Less: Accumulated depreciation, depletion and amortization | (3,450) | ||
Oil and natural gas properties, net | 14,985 | ||
Total assets held for sale, net | 16,775 | ||
Asset retirement obligations | 405 | ||
Total liabilities related to assets held for sale | $ 405 |
Debt - Schedule of Debt (Detail
Debt - Schedule of Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 13, 2016 | Aug. 19, 2016 | May 27, 2016 |
Debt Instrument [Line Items] | |||||
Revolving Credit Agreement | $ 0 | $ 0 | |||
Capital leases | 4,906 | 3,752 | |||
Other | 0 | 3,500 | |||
Total debt | 2,204,906 | 1,119,098 | |||
Debt issuance costs on senior unsecured notes | (26,341) | (14,388) | |||
Premium on senior unsecured notes | 3,312 | 3,828 | |||
Less: current portion | (2,352) | (67,214) | |||
Total long-term debt | $ 2,179,525 | 1,041,324 | |||
7.500% senior unsecured notes due 2022 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 7.50% | ||||
6.250% senior unsecured notes due 2024 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 6.25% | ||||
5.375% senior unsecured notes due 2025 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 5.375% | ||||
5.250% senior unsecured notes due 2025 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 5.25% | ||||
5.625% senior unsecured notes due 2027 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 5.625% | ||||
Senior Notes | 7.500% senior unsecured notes due 2022 | |||||
Debt Instrument [Line Items] | |||||
Senior unsecured notes | $ 0 | 61,846 | |||
Senior Notes | 6.250% senior unsecured notes due 2024 | |||||
Debt Instrument [Line Items] | |||||
Senior unsecured notes | $ 400,000 | 400,000 | |||
Premium on senior unsecured notes | $ 4,000 | ||||
Stated interest rate | 6.25% | 6.25% | 6.25% | ||
Senior Notes | 5.375% senior unsecured notes due 2025 | |||||
Debt Instrument [Line Items] | |||||
Senior unsecured notes | $ 650,000 | 650,000 | |||
Stated interest rate | 5.375% | 5.375% | |||
Senior Notes | 5.250% senior unsecured notes due 2025 | |||||
Debt Instrument [Line Items] | |||||
Senior unsecured notes | $ 450,000 | 0 | |||
Stated interest rate | 5.25% | ||||
Senior Notes | 5.625% senior unsecured notes due 2027 | |||||
Debt Instrument [Line Items] | |||||
Senior unsecured notes | $ 700,000 | $ 0 | |||
Stated interest rate | 5.625% |
Debt - Revolving Credit Agreeme
Debt - Revolving Credit Agreement (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Oct. 28, 2016USD ($) | |
Debt Instrument [Line Items] | |||
Revolving credit agreement | $ 0 | $ 0 | |
Revolving Credit Agreement | Maximum | |||
Debt Instrument [Line Items] | |||
Revolving credit agreement, commitment fee | 0.50% | ||
Revolving Credit Agreement | Minimum | |||
Debt Instrument [Line Items] | |||
Revolving credit agreement, commitment fee | 0.375% | ||
Revolving Credit Agreement | Weighted Average | |||
Debt Instrument [Line Items] | |||
Revolving credit agreement, weighted average interest rate | 1.50% | ||
Line of Credit | |||
Debt Instrument [Line Items] | |||
Revolving credit agreement, borrowing base | $ 2,500,000,000 | ||
Revolving credit agreement, current borrowing base | $ 1,800,000,000 | 900,000,000 | |
Aggregate elected borrowing capacity | 1,000,000,000 | $ 600,000,000 | |
Revolving credit agreement, borrowing remaining | $ 997,300,000 | ||
Line of Credit | Revolving Credit Agreement | |||
Debt Instrument [Line Items] | |||
Term | 5 years | ||
Revolving credit agreement | $ 0 | ||
Current ratio | 1.00% | ||
Maximum permitted consolidated leverage ratio | 0.04 | ||
Line of Credit | Revolving Credit Agreement | Eurodollar | |||
Debt Instrument [Line Items] | |||
Alternate margin basis rate if consolidated leverage ratio is greater than 3.5 | 0.50% | ||
Line of Credit | Letter of Credit [Member] | |||
Debt Instrument [Line Items] | |||
Revolving credit agreement | $ 2,700,000 | ||
Eurodollar Loans | Line of Credit | Revolving Credit Agreement | Maximum | LIBOR | |||
Debt Instrument [Line Items] | |||
Applicable margin basis rate | 2.50% | ||
Eurodollar Loans | Line of Credit | Revolving Credit Agreement | Minimum | LIBOR | |||
Debt Instrument [Line Items] | |||
Applicable margin basis rate | 1.50% | ||
Alternate Base Rate Loans | Line of Credit | Revolving Credit Agreement | LIBOR | |||
Debt Instrument [Line Items] | |||
Applicable margin basis rate | 1.00% | ||
Alternate Base Rate Loans | Line of Credit | Revolving Credit Agreement | Federal Funds Effective Swap Rate | |||
Debt Instrument [Line Items] | |||
Applicable margin basis rate | 0.50% | ||
Alternate Base Rate Loans | Line of Credit | Revolving Credit Agreement | Maximum | LIBOR | |||
Debt Instrument [Line Items] | |||
Applicable margin basis rate | 1.50% | ||
Alternate Base Rate Loans | Line of Credit | Revolving Credit Agreement | Minimum | LIBOR | |||
Debt Instrument [Line Items] | |||
Applicable margin basis rate | 0.50% |
Debt - Redemption of 2022 Notes
Debt - Redemption of 2022 Notes (Details) - USD ($) $ in Thousands | Jan. 05, 2017 | Dec. 15, 2016 | Dec. 13, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||||||
Payments of debt issuance costs | $ 17,371 | $ 18,097 | $ 1,138 | |||
Loss on early extinguishment of debt | $ (3,891) | (36,335) | $ 0 | |||
7.500% senior unsecured notes due 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 7.50% | |||||
Senior Notes | 7.500% senior unsecured notes due 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Extinguishment of debt, amount | $ 61,800 | |||||
Face amount, subject to guaranteed delivery procedures | 61,800 | |||||
Repayments of debt | 67,500 | |||||
Extinguishment of debt, prepayment expense | 3,900 | |||||
Extinguishment of debt, accrued interest | $ 1,800 | $ 12,000 | ||||
Parsley LLC | Senior Notes | 7.500% senior unsecured notes due 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Extinguishment of debt, amount | $ 400 | 487,700 | ||||
Face amount, subject to guaranteed delivery procedures | 1,200 | |||||
Repayments of debt | 500 | 537,100 | ||||
Extinguishment of debt, prepayment expense | $ 100 | 32,500 | ||||
Payments of debt issuance costs | $ 4,900 | |||||
Loss on early extinguishment of debt | $ (3,900) | $ (36,300) |
Debt - 6.250% Senior Unsecured
Debt - 6.250% Senior Unsecured Notes Due 2024 (Details) - USD ($) | Aug. 19, 2016 | May 27, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | |||||
Premium on senior unsecured notes | $ 3,312,000 | $ 3,828,000 | |||
Cash paid for interest | $ 63,170,000 | $ 65,513,000 | $ 43,993,000 | ||
6.250% senior unsecured notes due 2024 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 6.25% | ||||
Senior Notes | 6.250% senior unsecured notes due 2024 | |||||
Debt Instrument [Line Items] | |||||
Gross proceeds from note issuance | $ 200,000,000 | $ 200,000,000 | |||
Stated interest rate | 6.25% | 6.25% | 6.25% | ||
Net proceeds from note issuance | $ 206,800,000 | ||||
Proceeds from debt issuance, net | $ 199,600,000 | $ 195,400,000 | |||
Offering price percentage of par | 102.00% | ||||
Premium on senior unsecured notes | $ 4,000,000 | ||||
Cash paid for interest | $ 2,800,000 | ||||
Maximum percent of aggregate principal amount redeemable | 35.00% | ||||
Redemption price, expressed as percentage of principal amount | 106.25% | ||||
Number of days within closing date redemption can occur | 120 days | ||||
Minimum required principal amount to remain outstanding subsequent to redemption | 65.00% | ||||
Senior Notes | 6.250% senior unsecured notes due 2024 | Period Prior to June 1, 2019 | |||||
Debt Instrument [Line Items] | |||||
Redemption price, expressed as percentage of principal amount | 100.00% | ||||
Senior Notes | 6.250% senior unsecured notes due 2024 | 12-month period beginning June 1, 2019 | |||||
Debt Instrument [Line Items] | |||||
Redemption price, expressed as percentage of principal amount | 104.688% | ||||
Senior Notes | 6.250% senior unsecured notes due 2024 | 12-month period beginning June 1, 2020 | |||||
Debt Instrument [Line Items] | |||||
Redemption price, expressed as percentage of principal amount | 103.125% | ||||
Senior Notes | 6.250% senior unsecured notes due 2024 | 12-month period beginning June 1, 2021 | |||||
Debt Instrument [Line Items] | |||||
Redemption price, expressed as percentage of principal amount | 101.563% | ||||
Senior Notes | 6.250% senior unsecured notes due 2024 | 12-month period beginning June 1, 2022 | |||||
Debt Instrument [Line Items] | |||||
Redemption price, expressed as percentage of principal amount | 100.00% |
Debt - 5.375% Senior Unsecured
Debt - 5.375% Senior Unsecured Notes due 2025 (Details) - 5.375% senior unsecured notes due 2025 - USD ($) | Dec. 13, 2016 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Stated interest rate | 5.375% | |
Senior Notes | ||
Debt Instrument [Line Items] | ||
Gross proceeds from note issuance | $ 650,000,000 | |
Stated interest rate | 5.375% | 5.375% |
Net proceeds from note issuance | $ 650,000,000 | |
Proceeds from debt issuance, net | $ 644,100,000 | |
Maximum percent of aggregate principal amount redeemable | 35.00% | |
Redemption price, expressed as percentage of principal amount | 105.375% | |
Minimum required principal amount to remain outstanding subsequent to redemption | 65.00% | |
Number of days within closing date redemption can occur | 120 days | |
Senior Notes | Period Prior to January 15, 2020 | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 100.00% | |
Senior Notes | 12-month period beginning January 15, 2020 | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 104.031% | |
Senior Notes | 12-month period beginning January 15, 2021 | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 103.75% | |
Senior Notes | 12-month period beginning January 15, 2022 | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 101.344% | |
Senior Notes | 12-month period beginning January 15, 2023 | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 100.00% |
Debt - 5.250% Senior Unsecured
Debt - 5.250% Senior Unsecured Notes due 2025 (Details) - 5.250% senior unsecured notes due 2025 - USD ($) | Feb. 13, 2017 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Stated interest rate | 5.25% | |
Senior Notes | ||
Debt Instrument [Line Items] | ||
Gross proceeds from note issuance | $ 450,000,000 | |
Stated interest rate | 5.25% | |
Proceeds from debt issuance, net | $ 444,100,000 | |
Maximum percent of aggregate principal amount redeemable | 35.00% | |
Redemption price, expressed as percentage of principal amount | 105.25% | |
Minimum required principal amount to remain outstanding subsequent to redemption | 65.00% | |
Number of days within closing date redemption can occur | 120 days | |
Senior Notes | Debt Instrument, Redemption, Period Five [Member] | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 100.00% | |
Senior Notes | Debt Instrument, Redemption, Period One [Member] | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 103.938% | |
Senior Notes | Debt Instrument, Redemption, Period Two [Member] | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 102.625% | |
Senior Notes | Debt Instrument, Redemption, Period Three [Member] | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 101.313% | |
Senior Notes | Debt Instrument, Redemption, Period Four [Member] | ||
Debt Instrument [Line Items] | ||
Redemption price, expressed as percentage of principal amount | 100.00% |
Debt - 5.625% Senior Unsecured
Debt - 5.625% Senior Unsecured Notes due 2027 (Details) - USD ($) | Oct. 11, 2017 | Feb. 13, 2017 | Dec. 31, 2017 |
5.625% senior unsecured notes due 2027 | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 5.625% | ||
5.250% senior unsecured notes due 2025 | |||
Debt Instrument [Line Items] | |||
Stated interest rate | 5.25% | ||
Senior Notes | 5.625% senior unsecured notes due 2027 | |||
Debt Instrument [Line Items] | |||
Gross proceeds from note issuance | $ 700,000,000 | ||
Stated interest rate | 5.625% | ||
Proceeds from Issuance of Debt | 700,000,000 | ||
Proceeds from debt issuance, net | $ 692,100,000 | ||
Maximum percent of aggregate principal amount redeemable | 35.00% | ||
Redemption price, expressed as percentage of principal amount | 105.625% | ||
Minimum required principal amount to remain outstanding subsequent to redemption | 65.00% | ||
Senior Notes | 5.625% senior unsecured notes due 2027 | Debt Instrument, Redemption, Period Five [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 100.00% | ||
Senior Notes | 5.625% senior unsecured notes due 2027 | Debt Instrument, Redemption, Period One [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 102.813% | ||
Senior Notes | 5.625% senior unsecured notes due 2027 | Debt Instrument, Redemption, Period Two [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 101.875% | ||
Senior Notes | 5.625% senior unsecured notes due 2027 | Debt Instrument, Redemption, Period Three [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 100.938% | ||
Senior Notes | 5.625% senior unsecured notes due 2027 | Debt Instrument, Redemption, Period Four [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 100.00% | ||
Senior Notes | 5.250% senior unsecured notes due 2025 | |||
Debt Instrument [Line Items] | |||
Gross proceeds from note issuance | $ 450,000,000 | ||
Stated interest rate | 5.25% | ||
Proceeds from debt issuance, net | $ 444,100,000 | ||
Maximum percent of aggregate principal amount redeemable | 35.00% | ||
Redemption price, expressed as percentage of principal amount | 105.25% | ||
Minimum required principal amount to remain outstanding subsequent to redemption | 65.00% | ||
Senior Notes | 5.250% senior unsecured notes due 2025 | Debt Instrument, Redemption, Period Five [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 100.00% | ||
Senior Notes | 5.250% senior unsecured notes due 2025 | Debt Instrument, Redemption, Period One [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 103.938% | ||
Senior Notes | 5.250% senior unsecured notes due 2025 | Debt Instrument, Redemption, Period Two [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 102.625% | ||
Senior Notes | 5.250% senior unsecured notes due 2025 | Debt Instrument, Redemption, Period Three [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 101.313% | ||
Senior Notes | 5.250% senior unsecured notes due 2025 | Debt Instrument, Redemption, Period Four [Member] | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 100.00% |
Debt - Schedule of Principal Ma
Debt - Schedule of Principal Maturities of Long-term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Disclosure [Abstract] | ||
2,018 | $ 2,352 | |
2,019 | 1,906 | |
2,020 | 617 | |
2,021 | 17 | |
2,022 | 14 | |
Thereafter | 2,200,000 | |
Total debt | $ 2,204,906 | $ 1,119,098 |
Debt - Schedule of Interest Exp
Debt - Schedule of Interest Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |||
Cash payments for interest | $ 63,170 | $ 65,513 | $ 43,993 |
Change in interest accrual | 30,007 | (11,604) | (350) |
Amortization of deferred loan origination costs | 3,985 | 2,739 | 2,170 |
Write-off of deferred loan origination costs | 735 | 451 | 532 |
Amortization of bond premium | (516) | (874) | (764) |
Total interest expense, net | $ 97,381 | $ 56,225 | $ 45,581 |
Equity - Additional Information
Equity - Additional Information (Details) | 12 Months Ended | |
Dec. 31, 2017vote$ / sharesshares | Dec. 31, 2016$ / sharesshares | |
Equity [Line Items] | ||
Preferred stock, par value (in dollars per share) | $ / shares | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred stock, shares outstanding | 0 | 0 |
Class A Common Stock | ||
Equity [Line Items] | ||
Common stock, shares outstanding | 252,260,300 | 179,590,617 |
Number of votes per share | vote | 1 | |
Class B Common Stock | ||
Equity [Line Items] | ||
Common stock, shares outstanding | 62,128,257 | 28,008,573 |
Number of votes per share | vote | 1 | |
Time-based restricted stock | Class A Common Stock | ||
Equity [Line Items] | ||
Common stock, shares outstanding | 800,000 |
Equity - Allocation of Net Inco
Equity - Allocation of Net Income to Common Stockholders and EPS Computations (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Numerator: | |||||||||||
Net income (loss) attributable to Parsley Energy, Inc. Stockholders | $ 49,919 | $ (13,333) | $ 40,746 | $ 29,442 | $ (30,745) | $ (2,706) | $ (21,377) | $ (19,354) | $ 106,774 | $ (74,182) | $ (50,484) |
Denominator: | |||||||||||
Basic weighted average shares outstanding (shares) | 240,733 | 161,793 | 111,271 | ||||||||
Basic EPS attributable to Parsley Energy, Inc. Stockholders (in dollars per share) | $ 0.20 | $ (0.05) | $ 0.17 | $ 0.13 | $ (0.17) | $ (0.02) | $ (0.13) | $ (0.14) | $ 0.44 | $ (0.46) | $ (0.45) |
Numerator: | |||||||||||
Net (loss) income attributable to Parsley Energy, Inc. Stockholders | $ 49,919 | $ (13,333) | $ 40,746 | $ 29,442 | $ (30,745) | $ (2,706) | $ (21,377) | $ (19,354) | $ 106,774 | $ (74,182) | $ (50,484) |
Effect of conversion of the shares of Company’s Class B Common Stock to shares of the Company’s Class A Common Stock | 17,646 | 0 | 0 | ||||||||
Diluted net income (loss) attributable to Parsley Energy, Inc. Stockholders | $ 124,420 | $ (74,182) | $ (50,484) | ||||||||
Denominator: | |||||||||||
Basic weighted average shares outstanding (shares) | 240,733 | 161,793 | 111,271 | ||||||||
Effect of dilutive securities: | |||||||||||
Class B Common Stock (shares) | 54,665 | 0 | 0 | ||||||||
Restricted Stock and Restricted Stock Units (shares) | 1,114 | 0 | 0 | ||||||||
Diluted weighted average shares outstanding (shares) | 296,512 | 161,793 | 111,271 | ||||||||
Diluted EPS attributable to Parsley Energy, Inc. Stockholders (in dollars per share) | $ 0.16 | $ (0.05) | $ 0.17 | $ 0.13 | $ (0.17) | $ (0.02) | $ (0.13) | $ (0.14) | $ 0.42 | $ (0.46) | $ (0.45) |
Equity - Shares Excluded in Com
Equity - Shares Excluded in Computation of EPS (Details) - shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Performance-based restricted stock units | |||
Class Of Stock [Line Items] | |||
Shares related to performance based restricted stock units | 640,062 | 453,863 | 211,935 |
Equity - Noncontrolling Interes
Equity - Noncontrolling Interest - Additional Information (Details) - shares | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pacesetter Acquisition | Pacesetter Drilling, LLC | ||||
Minority Interest [Line Items] | ||||
Percentage of shares held by Parent | 63.00% | |||
Pacesetter Acquisition | Pacesetter Drilling, LLC | President | ||||
Minority Interest [Line Items] | ||||
Percentage of ownership interest, Noncontrolling owners | 37.00% | |||
Parsley LLC | ||||
Minority Interest [Line Items] | ||||
Percentage of ownership interest, Noncontrolling owners | 10.20% | 13.50% | 19.00% | 25.70% |
Percentage of shares held by Parent | 89.80% | 86.50% | 81.00% | 74.30% |
Exchange Rights During 2016 | Parsley LLC | ||||
Minority Interest [Line Items] | ||||
Percentage of ownership interest, Noncontrolling owners | 13.50% | 19.00% | ||
Percentage of shares held by Parent | 86.50% | 81.00% | ||
Exchange Rights During 2016 | PE Units | ||||
Minority Interest [Line Items] | ||||
Conversion of stock, shares converted | 4,100,000 | |||
Exchange Rights During 2016 | Class A Common Stock | ||||
Minority Interest [Line Items] | ||||
Conversion of stock, shares issued | 4,100,000 | |||
Exchange Rights During 2017 | Parsley LLC | ||||
Minority Interest [Line Items] | ||||
Percentage of ownership interest, Noncontrolling owners | 19.80% | 21.60% | ||
Percentage of shares held by Parent | 80.20% | 78.40% | ||
Exchange Rights During 2017 | PE Units | ||||
Minority Interest [Line Items] | ||||
Conversion of stock, shares converted | 5,700,000 | |||
Exchange Rights During 2017 | Class A Common Stock | ||||
Minority Interest [Line Items] | ||||
Conversion of stock, shares issued | 5,700,000 |
Equity - Summary of Noncontroll
Equity - Summary of Noncontrolling Interest Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Total net income (loss) attributable to noncontrolling interests | $ (39,214) | $ (1,828) | $ 15,048 | $ 8,848 | $ (3,352) | $ 1,065 | $ (6,111) | $ (6,337) | $ 17,146 | $ (14,735) | $ (22,547) |
Parsley LLC | |||||||||||
Total net income (loss) attributable to noncontrolling interests | 17,645 | (14,953) | (21,870) | ||||||||
Pacesetter Drilling, LLC | |||||||||||
Total net income (loss) attributable to noncontrolling interests | $ (499) | $ 218 | $ (677) |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock based compensation expense | $ 19,619 | $ 12,871 | $ 8,133 |
Time-based restricted stock | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Awards granted (shares) | 227,564 | ||
Stock based compensation expense | $ 5,492 | 3,523 | 3,856 |
Time-based restricted stock units | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Awards granted (shares) | 209,186 | ||
Stock based compensation expense | $ 7,778 | $ 5,677 | $ 2,710 |
Performance-based restricted stock units | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Performance unit awards granted period | 3 years | 3 years | 3 years |
Awards granted (shares) | 186,199 | ||
Stock based compensation expense | $ 6,349 | $ 3,671 | $ 1,567 |
Performance-based restricted stock units | Minimum | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Performance share awards actual payout percentage | 0.00% | ||
Performance-based restricted stock units | Maximum | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Performance share awards actual payout percentage | 200.00% | ||
Incentive units | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Class A Common Stock | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Number of shares authorized | 12,700,000 | ||
Number of shares available for grant | 10,000,000 |
Stock-Based Compensation - Summ
Stock-Based Compensation - Summary of Restricted Stock, Restricted Stock Unit and Performance Unit Activity (Details) | 12 Months Ended |
Dec. 31, 2017$ / sharesshares | |
Time-based restricted stock | |
Outstanding Awards | |
Outstanding, beginning balance (shares) | shares | 600,761 |
Awards granted (shares) | shares | 227,564 |
Forfeited (shares) | shares | (41,014) |
Vested (shares) | shares | (7,965) |
Outstanding, ending balance (shares) | shares | 779,346 |
Grant Date Fair Value | |
Weighted average grant date fair value, beginning balance (in dollars per share) | $ / shares | $ 19.02 |
Awards granted, grant date fair value (in dollars per share) | $ / shares | 31.55 |
Forfeited, grant date fair value (in dollars per share) | $ / shares | 26.84 |
Vested, grant date fair value (in dollars per share) | $ / shares | 18.14 |
Weighted average grant date fair value, ending balance (in dollars per share) | $ / shares | $ 22.30 |
Time-based restricted stock units | |
Outstanding Awards | |
Outstanding, beginning balance (shares) | shares | 1,045,786 |
Awards granted (shares) | shares | 209,186 |
Forfeited (shares) | shares | (33,170) |
Vested (shares) | shares | (22,083) |
Outstanding, ending balance (shares) | shares | 1,199,719 |
Grant Date Fair Value | |
Weighted average grant date fair value, beginning balance (in dollars per share) | $ / shares | $ 16.96 |
Awards granted, grant date fair value (in dollars per share) | $ / shares | 31.86 |
Forfeited, grant date fair value (in dollars per share) | $ / shares | 22.69 |
Vested, grant date fair value (in dollars per share) | $ / shares | 22.77 |
Weighted average grant date fair value, ending balance (in dollars per share) | $ / shares | $ 19.36 |
Performance-based restricted stock units | |
Outstanding Awards | |
Outstanding, beginning balance (shares) | shares | 453,863 |
Awards granted (shares) | shares | 186,199 |
Outstanding, ending balance (shares) | shares | 640,062 |
Grant Date Fair Value | |
Weighted average grant date fair value, beginning balance (in dollars per share) | $ / shares | $ 25.06 |
Awards granted, grant date fair value (in dollars per share) | $ / shares | 42.40 |
Weighted average grant date fair value, ending balance (in dollars per share) | $ / shares | $ 30.11 |
Stock-Based Compensation - Fair
Stock-Based Compensation - Fair Value Assumptions Performance Based Restricted Stock Units (Details) - Performance-based restricted stock units | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Risk-free interest rate | 1.45% | 0.88% | 1.05% |
Expected volatility, minimum | 37.70% | 35.00% | 42.20% |
Expected volatility, maximum | 79.50% | 65.10% | 84.80% |
Stock-Based Compensation - Expe
Stock-Based Compensation - Expected Stock-Based Compensation (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Time-Based Restricted Stock | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
2,018 | $ 3,537 |
2,019 | 1,977 |
2,020 | 255 |
Total | 5,769 |
Time-based restricted stock units | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
2,018 | 5,292 |
2,019 | 2,403 |
2,020 | 259 |
Total | 7,954 |
Performance-based restricted stock units | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
2,018 | 4,923 |
2,019 | 2,753 |
2,020 | 8 |
Total | 7,684 |
Restricted Stock | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
2,018 | 13,752 |
2,019 | 7,133 |
2,020 | 522 |
Total | $ 21,407 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Line Items] | |||||||||||
Tax Cuts And Jobs Act Of 2017, Incomplete Accounting, Provisional Income Tax Expense | $ 23,900 | ||||||||||
Tax Cuts And Jobs Act Of 2017, Incomplete Accounting, Change In Tax Rate, Deferred Tax Asset, Provisional Income Tax Expense | 23,900 | ||||||||||
Tax Cuts And Jobs Act Of 2017, Incomplete Accounting, Change In Tax Rate, Deferred Tax Asset Valuation Allowance, Provisional Income Tax Expense | $ 24,300 | ||||||||||
Effective income tax rate | 4.40% | 16.40% | 24.50% | ||||||||
Income tax (benefit) expense | $ (19,830) | $ (5,080) | $ 12,216 | $ 18,402 | $ 4,341 | $ (1,279) | $ (10,918) | $ (9,568) | $ 5,708 | $ (17,424) | $ (23,755) |
Alternative minimum tax credits | 400 | 400 | |||||||||
Valuation allowance | 9,264 | $ 32,215 | 9,264 | $ 32,215 | |||||||
Federal | |||||||||||
Income Tax Disclosure [Line Items] | |||||||||||
Net operating loss carryovers | $ 229,100 | $ 229,100 |
Income Taxes - Components of th
Income Taxes - Components of the Income Tax (Benefit) Provision (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Federal: | |||||||||||
Current | $ (44) | $ 158 | $ 286 | ||||||||
Deferred | (423) | (18,461) | (27,535) | ||||||||
Total federal | (467) | (18,303) | (27,249) | ||||||||
State, net of federal benefit: | |||||||||||
Deferred | 6,175 | 879 | 3,494 | ||||||||
Total state | 6,175 | 879 | 3,494 | ||||||||
Income tax expense (benefit) | $ (19,830) | $ (5,080) | $ 12,216 | $ 18,402 | $ 4,341 | $ (1,279) | $ (10,918) | $ (9,568) | $ 5,708 | $ (17,424) | $ (23,755) |
Income Taxes - Schedule of Reco
Income Taxes - Schedule of Reconciliation of Income Tax (Benefit) Provision with Income Tax Expense at Federal Statutory Rate (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||||||||||
Income (loss) before income taxes | $ 129,628 | $ (106,341) | $ (96,785) | ||||||||
Less: net loss (income) before income taxes attributable to noncontrolling interest | (18,725) | 14,579 | 22,438 | ||||||||
Income (loss) attributable to Parsley Energy, Inc. Stockholders before income taxes | 110,903 | (91,762) | (74,347) | ||||||||
Income taxes at the federal statutory rate | 38,816 | (32,120) | (26,022) | ||||||||
State income taxes, net of federal benefit | 6,175 | 879 | 3,494 | ||||||||
Provision to return adjustment | 178 | (237) | (1,217) | ||||||||
Permanent and other | 166 | (61) | (10) | ||||||||
Change in TRA Liability | (12,547) | (2,573) | 0 | ||||||||
Valuation allowance | (26,657) | 32,215 | 0 | ||||||||
Valuation allowance charged to equity | 0 | (15,527) | 0 | ||||||||
Valuation allowance due to the reduction in federal statutory rate | (24,356) | 0 | 0 | ||||||||
Income tax provision due to change in federal statutory rate | 23,933 | 0 | 0 | ||||||||
Income tax expense (benefit) | $ (19,830) | $ (5,080) | $ 12,216 | $ 18,402 | $ 4,341 | $ (1,279) | $ (10,918) | $ (9,568) | 5,708 | (17,424) | (23,755) |
Net income (loss) attributable to Parsley Energy, Inc. Stockholders | 49,919 | (13,333) | 40,746 | 29,442 | (30,745) | (2,706) | (21,377) | (19,354) | 106,774 | (74,182) | (50,484) |
Net income (loss) attributable to noncontrolling interest | $ (39,214) | $ (1,828) | $ 15,048 | $ 8,848 | $ (3,352) | $ 1,065 | $ (6,111) | $ (6,337) | $ 17,146 | $ (14,735) | $ (22,547) |
Income Taxes - Schedule of Tax
Income Taxes - Schedule of Tax Effects of Significant Portions of the Deferred Tax Assets and Deferred Tax Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Assets: | ||
Asset retirement obligations | $ 4,854 | $ 3,535 |
Deferred stock-based compensation | 7,874 | 6,868 |
Derivative fair value loss | 12,493 | 8,252 |
Accrued compensation | 4,241 | 3,398 |
Net operating loss carryforward | 48,666 | 44,407 |
Other | 78 | 166 |
Total deferred tax assets | 78,206 | 66,626 |
Less: Valuation allowance | (9,264) | (32,215) |
Net deferred tax assets | 68,942 | 34,411 |
Liabilities: | ||
Book basis of oil and natural gas properties in excess of tax basis | (89,299) | (38,489) |
Earnings in investment in subsidiary | (828) | (1,116) |
Other | (218) | (289) |
Total deferred tax liabilities | (90,345) | (39,894) |
Net deferred tax liability | $ (21,403) | $ (5,483) |
Income Taxes - Tax Receivable A
Income Taxes - Tax Receivable Agreement (Details) - USD ($) $ in Thousands | May 29, 2014 | Dec. 31, 2017 | Dec. 31, 2016 |
Operating Loss Carryforwards [Line Items] | |||
Payable pursuant to tax receivable agreement | $ 58,479 | $ 94,326 | |
Valuation allowance | (9,264) | (32,215) | |
Deferred tax assets, net of valuation allowance | 68,942 | 34,411 | |
Tax Receivable Agreement | IPO | |||
Operating Loss Carryforwards [Line Items] | |||
Payment of net cash savings from tax, percent | 85.00% | ||
Payable pursuant to tax receivable agreement | 58,500 | 94,300 | |
Deferred tax assets, net of valuation allowance | 68,800 | $ 111,000 | |
TRA Liability [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Deferred tax asset valuation increase (decrease) | 35,800 | ||
TRA Liability, Corporate Rate Reduction [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Deferred tax asset valuation increase (decrease) | 55,900 | ||
TRA Liability, Change In Valuation [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Deferred tax asset valuation increase (decrease) | $ 20,100 |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)aBoe | Dec. 31, 2015USD ($) | |
Related Party Transaction [Line Items] | |||
Amounts disbursed to related parties | $ 1,500 | $ 2,500 | $ 5,200 |
Depletion expense on capitalized oil and gas property | 340,800 | 227,200 | 173,600 |
Costs incurred, acquisition of unproved oil and gas properties | $ 2,893,434 | 1,072,250 | 57,385 |
SPS | |||
Related Party Transaction [Line Items] | |||
Equity method investment, ownership percentage | 42.50% | ||
Company incurred charges for services performed | $ 10,200 | 4,400 | 4,800 |
Lone Star Well Service, LLC | |||
Related Party Transaction [Line Items] | |||
Company incurred charges for services performed | 6,500 | 6,300 | 5,000 |
Davis, Gerald, and Cremer | |||
Related Party Transaction [Line Items] | |||
Legal service charges | $ 0 | 500 | $ 200 |
Randolph J. Newcomer, Jr. Former Member Of Board Of Directors | Riverbend Acquisition | |||
Related Party Transaction [Line Items] | |||
Total consideration for acquisition | $ 177,100 | ||
Acres of oil and gas property, gross | a | 8,800 | ||
Acres of oil and gas property, net | a | 6,269 | ||
Production (in Boe/d) | Boe | 900 | ||
Depletion expense on capitalized oil and gas property | $ 37,900 | ||
Costs incurred, acquisition of unproved oil and gas properties | $ 139,200 |
Commitments and Contingencies -
Commitments and Contingencies - Asset Retirement Obligations (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Other Commitments [Line Items] | |
2,018 | $ 49,601 |
2,019 | 14,730 |
2,020 | 0 |
2,021 | 0 |
2,022 | 0 |
Thereafter | 0 |
Total | 64,331 |
Asset retirement obligations | |
Other Commitments [Line Items] | |
2,018 | 6,297 |
2,019 | 774 |
2,020 | 824 |
2,021 | 834 |
2,022 | 929 |
Thereafter | 17,512 |
Total | $ 27,170 |
Commitments and Contingencies76
Commitments and Contingencies - Schedule of Company Drilling and Derivative Commitments (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Commitment And Contingencies [Line Items] | |
2,018 | $ 49,601 |
2,019 | 14,730 |
2,020 | 0 |
2,021 | 0 |
2,022 | 0 |
Thereafter | 0 |
Total | 64,331 |
Drilling Commitments | |
Commitment And Contingencies [Line Items] | |
2,018 | 30,752 |
2,019 | 46,150 |
2,020 | 0 |
2,021 | 0 |
2,022 | 0 |
Thereafter | 0 |
Total | $ 76,902 |
Commitments and Contingencies77
Commitments and Contingencies - Schedule of Future Minimum Lease Payments under Long Term Operating Lease Agreements (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Operating Leased Assets [Line Items] | |
2,018 | $ 8,965 |
2,019 | 9,702 |
2,020 | 9,644 |
2,021 | 9,220 |
2,022 | 9,102 |
Thereafter | 20,219 |
Total | 66,852 |
Office Leases | |
Operating Leased Assets [Line Items] | |
2,018 | 8,810 |
2,019 | 9,626 |
2,020 | 9,640 |
2,021 | 9,219 |
2,022 | 9,102 |
Thereafter | 20,219 |
Total | 66,616 |
Office Equipment | |
Operating Leased Assets [Line Items] | |
2,018 | 155 |
2,019 | 76 |
2,020 | 4 |
2,021 | 1 |
2,022 | 0 |
Thereafter | 0 |
Total | $ 236 |
Commitments and Contingencies78
Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Rent expense | $ 9.5 | $ 7.1 | $ 4.7 |
Percentage Of Oil Production Being Transported Under Agreements | 69.00% |
Disclosures about Fair Value 79
Disclosures about Fair Value of Financial Instruments - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Fair Value, Net Asset (Liability) | $ 428,765,000 | $ 93,436,000 | |
Interest income | (97,381,000) | (56,225,000) | $ (45,581,000) |
Level 2 | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Fair Value, Net Asset (Liability) | (47,854,000) | (844,000) | |
Impairment of oil and gas properties | 1,100,000 | 0 | |
Upton County | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Impairment of oil and gas properties | 0 | ||
Money market funds | |||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Interest income | $ 7,600,000 | $ 900,000 |
Disclosures about Fair Value 80
Disclosures about Fair Value of Financial Instruments - Schedule of Financial Assets and Liabilities Measured at Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Assets: | ||
Money market funds | $ 554,189 | $ 133,379 |
Total assets | 534,308 | 150,404 |
Liabilities: | ||
Total liabilities | (105,543) | (56,968) |
Net asset | 428,765 | 93,436 |
Level 1 | ||
Assets: | ||
Total assets | 476,619 | 94,280 |
Liabilities: | ||
Total liabilities | 0 | 0 |
Net asset | 476,619 | 94,280 |
Level 2 | ||
Assets: | ||
Total assets | 57,689 | 56,124 |
Liabilities: | ||
Total liabilities | (105,543) | (56,968) |
Net asset | (47,854) | (844) |
Level 3 | ||
Assets: | ||
Total assets | 0 | 0 |
Liabilities: | ||
Total liabilities | 0 | 0 |
Net asset | 0 | 0 |
Commodity derivative contracts | ||
Assets: | ||
Commodity derivative contracts | 57,689 | 56,124 |
Liabilities: | ||
Commodity derivative contracts | (105,543) | (56,968) |
Commodity derivative contracts | Level 1 | ||
Assets: | ||
Commodity derivative contracts | 0 | 0 |
Liabilities: | ||
Commodity derivative contracts | 0 | 0 |
Commodity derivative contracts | Level 2 | ||
Assets: | ||
Commodity derivative contracts | 57,689 | 56,124 |
Liabilities: | ||
Commodity derivative contracts | (105,543) | (56,968) |
Commodity derivative contracts | Level 3 | ||
Assets: | ||
Commodity derivative contracts | 0 | 0 |
Liabilities: | ||
Commodity derivative contracts | 0 | 0 |
Money market funds | ||
Assets: | ||
Money market funds | 476,619 | 94,280 |
Money market funds | Level 1 | ||
Assets: | ||
Money market funds | 476,619 | 94,280 |
Money market funds | Level 2 | ||
Assets: | ||
Money market funds | 0 | 0 |
Money market funds | Level 3 | ||
Assets: | ||
Money market funds | $ 0 | $ 0 |
Disclosures about Fair Value 81
Disclosures about Fair Value of Financial Instruments - Financial Instruments Not Carried at Fair Value (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 13, 2016 | Aug. 19, 2016 | May 27, 2016 |
Debt Instrument [Line Items] | |||||
Cash and cash equivalents | $ 554,189 | $ 133,379 | |||
Short-term investments | 149,283 | ||||
Carrying Amount | |||||
Debt Instrument [Line Items] | |||||
Revolving Credit Agreement | 0 | 0 | |||
Fair Value | |||||
Debt Instrument [Line Items] | |||||
Revolving Credit Agreement | $ 0 | 0 | |||
7.500% senior unsecured notes due 2022 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 7.50% | ||||
6.250% senior unsecured notes due 2024 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 6.25% | ||||
5.375% senior unsecured notes due 2025 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 5.375% | ||||
5.250% senior unsecured notes due 2025 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 5.25% | ||||
5.625% senior unsecured notes due 2027 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 5.625% | ||||
Senior Notes | 6.250% senior unsecured notes due 2024 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 6.25% | 6.25% | 6.25% | ||
Senior Notes | 6.250% senior unsecured notes due 2024 | Carrying Amount | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | $ 400,000 | 400,000 | |||
Senior Notes | 6.250% senior unsecured notes due 2024 | Fair Value | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | $ 423,824 | 422,548 | |||
Senior Notes | 5.375% senior unsecured notes due 2025 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 5.375% | 5.375% | |||
Senior Notes | 5.375% senior unsecured notes due 2025 | Carrying Amount | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | $ 650,000 | 650,000 | |||
Senior Notes | 5.375% senior unsecured notes due 2025 | Fair Value | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | $ 658,483 | 654,531 | |||
Senior Notes | 5.250% senior unsecured notes due 2025 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 5.25% | ||||
Senior Notes | 5.250% senior unsecured notes due 2025 | Carrying Amount | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | $ 450,000 | 0 | |||
Senior Notes | 5.250% senior unsecured notes due 2025 | Fair Value | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | $ 454,010 | 0 | |||
Senior Notes | 5.625% senior unsecured notes due 2027 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 5.625% | ||||
Senior Notes | 5.625% senior unsecured notes due 2027 | Carrying Amount | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | $ 700,000 | 0 | |||
Senior Notes | 5.625% senior unsecured notes due 2027 | Fair Value | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | $ 715,169 | 0 | |||
Senior Notes | 7.500% senior unsecured notes due 2022 | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 7.50% | ||||
Senior Notes | 7.500% senior unsecured notes due 2022 | Carrying Amount | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | $ 0 | 61,846 | |||
Senior Notes | 7.500% senior unsecured notes due 2022 | Fair Value | |||||
Debt Instrument [Line Items] | |||||
Senior notes, fair value | 0 | 65,737 | |||
Commercial Paper | |||||
Debt Instrument [Line Items] | |||||
Cash and cash equivalents | 24,939 | 0 | |||
Commercial Paper | Carrying Amount | |||||
Debt Instrument [Line Items] | |||||
Cash and cash equivalents | 24,939 | 0 | |||
Commercial Paper | Fair Value | |||||
Debt Instrument [Line Items] | |||||
Cash and cash equivalents | 24,918 | 0 | |||
Commercial Paper | |||||
Debt Instrument [Line Items] | |||||
Short-term investments | 149,283 | ||||
Commercial Paper | Carrying Amount | |||||
Debt Instrument [Line Items] | |||||
Short-term investments | 149,283 | 0 | |||
Commercial Paper | Fair Value | |||||
Debt Instrument [Line Items] | |||||
Short-term investments | $ 149,151 | $ 0 |
Disclosures about Fair Value 82
Disclosures about Fair Value of Financial Instruments - Cash And Cash Equivalents (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Cash and Cash Equivalents [Line Items] | ||
Cash and cash equivalents | $ 554,189 | $ 133,379 |
Short-term investments | 149,283 | |
Cash | ||
Cash and Cash Equivalents [Line Items] | ||
Cash and cash equivalents | 52,631 | 39,099 |
Commercial Paper | ||
Cash and Cash Equivalents [Line Items] | ||
Cash and cash equivalents | 24,939 | 0 |
Money market funds | ||
Cash and Cash Equivalents [Line Items] | ||
Cash and cash equivalents | 476,619 | $ 94,280 |
Cash | ||
Cash and Cash Equivalents [Line Items] | ||
Short-term investments | 0 | |
Commercial Paper | ||
Cash and Cash Equivalents [Line Items] | ||
Short-term investments | 149,283 | |
Money market funds | ||
Cash and Cash Equivalents [Line Items] | ||
Short-term investments | $ 0 |
Subsequent Events - Additional
Subsequent Events - Additional Information (Details) - Subsequent Event - Martin, Howard, Reagan, Irion, Dawson, and Pecos Counties [Member] $ in Millions | Feb. 27, 2018USD ($)a |
Subsequent Event [Line Items] | |
Acres of oil and gas property, gross | 42,852 |
Acres of oil and gas property, net | 3,710 |
Proceeds from divestiture | $ | $ 39.4 |
Supplemental Disclosure of Oi84
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Capitalized Costs (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Oil and natural gas properties: | ||
Proved properties | $ 4,492,802 | $ 2,376,712 |
Unproved properties | 4,058,512 | 1,686,705 |
Total oil and natural gas properties | 8,551,314 | 4,063,417 |
Less accumulated depreciation, depletion and amortization | (822,459) | (506,175) |
Net oil and natural gas properties capitalized | $ 7,728,855 | $ 3,557,242 |
Supplemental Disclosure of Oi85
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Costs Incurred for Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Acquisition costs: | |||
Proved properties | $ 482,160 | $ 273,940 | $ 16,422 |
Unproved properties | 2,893,434 | 1,072,250 | 57,385 |
Development costs | 1,207,401 | 495,971 | 404,291 |
Total | $ 4,582,995 | $ 1,842,161 | $ 478,098 |
Supplemental Disclosure of Oi86
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Reserve Quantity Information Average Sales Price (Details) | 12 Months Ended | ||
Dec. 31, 2017$ / Mcf$ / bbl | Dec. 31, 2016$ / Mcf$ / bbl | Dec. 31, 2015$ / Mcf$ / bbl | |
Oil | |||
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |||
Average sales price | 49.17 | 39.36 | 46.54 |
Natural Gas Liquids | |||
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |||
Average sales price | 22.20 | 15.04 | 16.42 |
Natural Gas | |||
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |||
Average sales price | $ / Mcf | 2.53 | 2.23 | 2.53 |
Supplemental Disclosure of Oi87
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Proved Developed and Proved Undeveloped Reserves (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands, Boe in Thousands | 12 Months Ended | ||||||||||||
Dec. 31, 2017MBoeMBblsMMcf | Dec. 31, 2017MBoeMBblsMMcf | Dec. 31, 2017BoeMBoeMBblsMMcf | Dec. 31, 2017MBoeMBblsMMcf | Dec. 31, 2016MBoeMBblsMMcf | Dec. 31, 2016MBoeMBblsMMcf | Dec. 31, 2016BoeMBoeMBblsMMcf | Dec. 31, 2016MBoeMBblsMMcf | Dec. 31, 2015MBoeMBblsMMcf | Dec. 31, 2015MBoeMBblsMMcf | Dec. 31, 2015BoeMBoeMBblsMMcf | Dec. 31, 2015MBoeMBblsMMcf | Dec. 31, 2014MBoeMBblsMMcf | |
Proved Developed and Undeveloped Reserves: | |||||||||||||
Production | (24,792) | ||||||||||||
Proved Developed and Undeveloped Reserves: | |||||||||||||
Beginning of the year | MBoe | 222,347 | 123,811 | 90,891 | ||||||||||
Extensions and discoveries | MBoe | 160,340 | 98,672 | 56,217 | ||||||||||
Revisions of previous estimates | MBoe | 9,205 | (3,750) | (17,201) | ||||||||||
Purchases of reserves in place | 55,814 | 55,814 | 24,235 | 24,235 | 3,976 | 3,976 | |||||||
Divestures of reserves in place | (6,467) | (6,467) | (6,619) | (6,619) | (2,042) | (2,042) | |||||||
End of the year | MBoe | 416,447 | 222,347 | 123,811 | ||||||||||
Proved developed reserves (energy) | MBoe | 209,399 | 209,399 | 209,399 | 209,399 | 106,097 | 106,097 | 106,097 | 106,097 | 51,453 | 51,453 | 51,453 | 51,453 | 45,952 |
Proved undeveloped reserves (energy) | MBoe | 207,048 | 207,048 | 207,048 | 207,048 | 116,250 | 116,250 | 116,250 | 116,250 | 72,358 | 72,358 | 72,358 | 72,358 | 44,939 |
Crude Oil (MBbls) | |||||||||||||
Proved Developed and Undeveloped Reserves: | |||||||||||||
Beginning of the year | 136,536 | 73,877 | 47,617 | ||||||||||
Extensions and discoveries | 99,916 | 64,005 | 38,282 | ||||||||||
Revisions of previous estimates | (709) | (4,476) | (7,493) | ||||||||||
Purchases of reserves in place | 33,017 | 16,041 | 1,897 | ||||||||||
Divestures of reserves in place | (3,839) | (3,543) | (1,619) | ||||||||||
Production | (16,390) | (9,368) | (4,807) | ||||||||||
End of the year | 248,531 | 136,536 | 73,877 | ||||||||||
Proved developed reserves (volume) | 119,591 | 119,591 | 119,591 | 119,591 | 61,133 | 61,133 | 61,133 | 61,133 | 27,628 | 27,628 | 27,628 | 27,628 | 23,547 |
Proved undeveloped reserves (volume) | 128,940 | 128,940 | 128,940 | 128,940 | 75,403 | 75,403 | 75,403 | 75,403 | 46,249 | 46,249 | 46,249 | 46,249 | 24,070 |
Natural Gas (MMcf) | |||||||||||||
Proved Developed and Undeveloped Reserves: | |||||||||||||
Beginning of the year | 48,543 | 23,738 | 22,667 | ||||||||||
Extensions and discoveries | 33,426 | 20,698 | 9,163 | ||||||||||
Revisions of previous estimates | 4,522 | 3,898 | (7,278) | ||||||||||
Purchases of reserves in place | 12,121 | 4,023 | 921 | ||||||||||
Divestures of reserves in place | (1,468) | (1,424) | (235) | ||||||||||
Production | (4,512) | (2,390) | (1,500) | ||||||||||
End of the year | 92,632 | 48,543 | 23,738 | ||||||||||
Proved developed reserves (volume) | 49,751 | 49,751 | 49,751 | 49,751 | 24,306 | 24,306 | 24,306 | 24,306 | 10,890 | 10,890 | 10,890 | 10,890 | 11,491 |
Proved undeveloped reserves (volume) | 42,880 | 42,880 | 42,880 | 42,880 | 24,237 | 24,237 | 24,237 | 24,237 | 12,848 | 12,848 | 12,848 | 12,848 | 11,176 |
Liquids (MBbls) | |||||||||||||
Proved Developed and Undeveloped Reserves: | |||||||||||||
Beginning of the year | MMcf | 223,605 | 157,175 | 123,645 | ||||||||||
Extensions and discoveries | MMcf | 161,989 | 83,815 | 52,629 | ||||||||||
Revisions of previous estimates | MMcf | 32,342 | (19,032) | (14,572) | ||||||||||
Purchases of reserves in place | MMcf | 64,055 | 25,024 | 6,946 | ||||||||||
Divestures of reserves in place | MMcf | (6,962) | (9,914) | (1,134) | ||||||||||
Production | MMcf | (23,326) | (13,463) | (10,339) | ||||||||||
End of the year | MMcf | 451,703 | 223,605 | 157,175 | ||||||||||
Proved developed reserves (volume) | MMcf | 240,337 | 240,337 | 240,337 | 240,337 | 123,946 | 123,946 | 123,946 | 123,946 | 77,612 | 77,612 | 77,612 | 77,612 | 65,484 |
Proved undeveloped reserves (volume) | MMcf | 211,366 | 211,366 | 211,366 | 211,366 | 99,659 | 99,659 | 99,659 | 99,659 | 79,563 | 79,563 | 79,563 | 79,563 | 58,161 |
Supplemental Disclosure of Oi88
Supplemental Disclosure of Oil and Natural Gas Operations - Additional Information (Details) MBoe in Thousands, Boe in Thousands | 12 Months Ended | |||||
Dec. 31, 2017Boe | Dec. 31, 2017MBoe | Dec. 31, 2016Boe | Dec. 31, 2016MBoe | Dec. 31, 2015Boe | Dec. 31, 2015MBoe | |
Reserve Quantities [Line Items] | ||||||
Extensions and discoveries | 160,340 | 98,672 | 56,217 | |||
Revisions of previous estimates | 9,205 | (3,750) | (17,201) | |||
Reclassification of proved undeveloped reserves to unproved reserves | (26,597) | |||||
Revision of previous estimates, better than expected performance | 8,134 | 25,720 | 7,574 | |||
Revision of previous estimates, removal of reserve locations | (4,725) | 18,532 | (11,688) | |||
Revision of estimates, increase (decrease) due to oil prices | 2,752 | (2,873) | (13,087) | |||
Revision of previous estimates, production | 3,044 | 14,002 | 8,030 | |||
Purchases of reserves in place | 55,814 | 55,814 | 24,235 | 24,235 | 3,976 | 3,976 |
Divestures of reserves in place | 6,467 | 6,467 | 6,619 | 6,619 | 2,042 | 2,042 |
Midland Basin | ||||||
Reserve Quantities [Line Items] | ||||||
Purchases of reserves in place | Boe | 53,105 | 19,184 | ||||
Divestures of reserves in place | Boe | 5,936 | 6,588 | ||||
Delaware Basin | ||||||
Reserve Quantities [Line Items] | ||||||
Purchases of reserves in place | Boe | 2,709 | 5,051 | ||||
Divestures of reserves in place | Boe | 531 | 31 |
Supplemental Disclosure of Oi89
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Extractive Industries [Abstract] | ||||
Future cash inflows | $ 15,421,590 | $ 6,603,206 | $ 4,225,912 | |
Future development costs | (2,181,447) | (1,019,823) | (829,560) | |
Future production costs | (4,536,530) | (2,176,081) | (1,534,011) | |
Future income tax expenses | (1,102,385) | (370,337) | (240,203) | |
Future net cash flows | 7,601,228 | 3,036,965 | 1,622,138 | |
10% discount to reflect timing of cash flows | (4,585,723) | (1,852,653) | (1,024,290) | |
Standardized measure of discounted future net cash flows | $ 3,015,505 | $ 1,184,312 | $ 597,848 | $ 955,629 |
Supplemental Disclosure of Oi90
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure of discounted future net cash flows at the beginning of the year | $ 1,184,312 | $ 597,848 | $ 955,629 |
Sales of oil and natural gas, net of production costs | (800,553) | (369,295) | (185,344) |
Purchase of minerals in place | 489,910 | 118,795 | 4,872 |
Divestiture of minerals in place | (50,257) | (14,591) | (53,018) |
Extensions and discoveries, net of future development costs | 1,864,041 | 770,947 | 485,380 |
Previously estimated development costs incurred during the period | 58,377 | 61,756 | 12,560 |
Net changes in prices and production costs | 525,693 | (80,492) | (821,783) |
Changes in estimated future development costs | (150,028) | 118,930 | 77,621 |
Revisions of previous quantity estimates | 142,510 | 84,309 | (225,485) |
Accretion of discount | 148,314 | 69,731 | 131,442 |
Net change in income taxes | (603,696) | (199,368) | 249,065 |
Net changes in timing of production and other | 206,882 | 25,742 | (33,091) |
Standardized measure of discounted future net cash flows at the end of the year | $ 3,015,505 | $ 1,184,312 | $ 597,848 |
Summary of Quarterly Financia91
Summary of Quarterly Financial Results (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||
Revenues | $ 3,600 | $ 311,488 | $ 241,021 | $ 213,677 | $ 200,858 | $ 155,876 | $ 132,537 | $ 106,872 | $ 62,488 | $ 967,044 | $ 457,773 | $ 266,474 |
Operating income (loss) | 85,939 | 63,072 | 45,259 | 72,531 | 43,213 | 12,340 | 1,636 | (26,042) | 266,801 | 31,147 | (74,121) | |
Income tax (benefit) expense | (19,830) | (5,080) | 12,216 | 18,402 | 4,341 | (1,279) | (10,918) | (9,568) | 5,708 | (17,424) | (23,755) | |
Net income (loss) | 44,997 | (15,161) | 55,794 | 38,290 | (34,097) | (1,641) | (27,488) | (25,691) | 123,920 | (88,917) | (73,031) | |
Net income (loss) attributable to noncontrolling interest | (39,214) | (1,828) | 15,048 | 8,848 | (3,352) | 1,065 | (6,111) | (6,337) | 17,146 | (14,735) | (22,547) | |
Net (loss) income attributable to Parsley Energy, Inc. Stockholders | $ 49,919 | $ (13,333) | $ 40,746 | $ 29,442 | $ (30,745) | $ (2,706) | $ (21,377) | $ (19,354) | $ 106,774 | $ (74,182) | $ (50,484) | |
Basic (in dollars per share) | $ 0.20 | $ (0.05) | $ 0.17 | $ 0.13 | $ (0.17) | $ (0.02) | $ (0.13) | $ (0.14) | $ 0.44 | $ (0.46) | $ (0.45) | |
Diluted (in dollars per share) | $ 0.16 | $ (0.05) | $ 0.17 | $ 0.13 | $ (0.17) | $ (0.02) | $ (0.13) | $ (0.14) | $ 0.42 | $ (0.46) | $ (0.45) |