Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Jun. 30, 2014 | Mar. 11, 2015 | |
Document And Entity Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | PE | ||
Entity Registrant Name | Parsley Energy, Inc. | ||
Entity Central Index Key | 1594466 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Public Float | $1,795,805,293 | ||
Common Stock, Class A | |||
Document And Entity Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 108,780,734 | ||
Common Stock, Class B | |||
Document And Entity Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 32,145,296 |
CONSOLIDATED_AND_COMBINED_BALA
CONSOLIDATED AND COMBINED BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
CURRENT ASSETS | ||
Cash and cash equivalents | $50,550 | $19,393 |
Accounts receivable: | ||
Joint interest owners and other | 37,620 | 90,490 |
Oil and gas | 22,700 | 15,202 |
Related parties | 4,065 | 1,041 |
Short-term derivative instruments | 80,911 | 6,999 |
Materials and supplies | 3,767 | 3,078 |
Other current assets | 4,548 | 1,123 |
Total current assets | 204,161 | 137,326 |
PROPERTY, PLANT AND EQUIPMENT, AT COST | ||
Oil and natural gas properties, successful efforts method | 1,872,616 | 614,315 |
Accumulated depreciation, depletion and amortization | -128,044 | -34,957 |
Total oil and natural gas properties, net | 1,744,572 | 579,358 |
Other property, plant and equipment, net | 16,290 | 7,525 |
Total property, plant and equipment, net | 1,760,862 | 586,883 |
NONCURRENT ASSETS | ||
Long-term derivative instruments | 70,805 | 13,850 |
Equity investment | 2,121 | 1,774 |
Deferred loan costs, net | 12,943 | 2,723 |
Other noncurrent assets | 187 | |
Total noncurrent assets | 86,056 | 18,347 |
TOTAL ASSETS | 2,051,079 | 742,556 |
CURRENT LIABILITIES | ||
Accounts payable and accrued expenses | 139,922 | 158,385 |
Revenue and severance taxes payable | 38,366 | 28,419 |
Current portion of long-term debt | 650 | 227 |
Short-term derivative instruments | 29,326 | 4,435 |
Current deferred tax liability | 12,601 | |
Amounts due related parties | 31 | |
Total current liabilities | 220,865 | 191,497 |
NONCURRENT LIABILITIES | ||
Long-term debt | 676,845 | 429,970 |
Asset retirement obligations | 16,207 | 8,277 |
Deferred tax liability | 62,334 | 2,572 |
Payable pursuant to tax receivable agreement | 50,689 | |
Long-term derivative instruments | 31,275 | 2,208 |
Other noncurrent liabilities | 375 | |
Total noncurrent liabilities | 837,725 | 443,027 |
COMMITMENTS AND CONTINGENCIES | ||
MEMBERS' EQUITY | 30,874 | |
MEZZANINE EQUITY | 77,158 | |
STOCKHOLDERS' EQUITY | ||
Preferred Stock, $.01 par value, 50,000,000 shares authorized, none issued and outstanding | ||
Additional paid in capital | 644,636 | |
Retained earnings | 61,352 | |
Total stockholders' equity | 707,241 | |
Noncontrolling interest | 285,248 | |
Total equity | 992,489 | 108,032 |
TOTAL LIABILITIES AND EQUITY | 2,051,079 | 742,556 |
Common Stock, Class A | ||
STOCKHOLDERS' EQUITY | ||
Common stock | 932 | |
Total equity | 932 | |
Common Stock, Class B | ||
STOCKHOLDERS' EQUITY | ||
Common stock | 321 | |
Total equity | $321 |
CONSOLIDATED_AND_COMBINED_BALA1
CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Preferred stock, par value | $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 | 36,739 | 0 |
Common Stock, Class A | ||
Common stock, par value | $0.01 | $0.01 |
Common stock, shares authorized | 600,000,000 | 600,000,000 |
Common stock, shares issued | 93,937,947 | 1,000 |
Common stock, shares outstanding | 93,901,208 | 1,000 |
Common Stock, Class B | ||
Common stock, par value | $0.01 | $0.01 |
Common stock, shares authorized | 125,000,000 | 125,000,000 |
Common stock, shares issued | 32,145,296 | 0 |
Common stock, shares outstanding | 32,145,296 | 0 |
CONSOLIDATED_AND_COMBINED_STAT
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
REVENUES | |||
Oil sales | $232,554 | $97,839 | $30,443 |
Natural gas and natural gas liquids sales | 69,203 | 23,179 | 7,236 |
Total revenues | 301,757 | 121,018 | 37,679 |
OPERATING EXPENSES | |||
Lease operating expenses | 38,071 | 16,572 | 4,646 |
Production and ad valorem taxes | 18,941 | 7,081 | 2,412 |
Depreciation, depletion and amortization | 94,297 | 28,152 | 6,406 |
General and administrative expenses | 34,997 | 15,248 | 3,629 |
Exploration costs | 3,136 | ||
Acquisition costs | 2,527 | ||
Incentive unit compensation | 51,088 | 1,233 | |
Stock based compensation | 2,209 | ||
Accretion of asset retirement obligations | 512 | 181 | 66 |
Total operating expenses | 245,778 | 68,467 | 17,159 |
(Loss) gain on sale of property | -2,097 | 36 | 7,819 |
OPERATING INCOME | 53,882 | 52,587 | 28,339 |
OTHER INCOME (EXPENSE) | |||
Interest expense, net | -38,607 | -13,714 | -6,285 |
Rig termination costs | -765 | ||
Prepayment premium on extinguishment of debt | -5,107 | -6,597 | |
Income from equity investment | 348 | 184 | 267 |
Derivative income (loss) | 83,858 | -9,800 | -2,190 |
Other income (expense) | -419 | 159 | -81 |
Total other income (expense), net | 39,308 | -23,171 | -14,886 |
INCOME BEFORE INCOME TAXES | 93,190 | 29,416 | 13,453 |
INCOME TAX EXPENSE | -36,468 | -1,906 | -554 |
NET INCOME | 56,722 | 27,510 | 12,899 |
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS | -33,293 | ||
NET INCOME ATTRIBUTABLE TO PARSLEY ENERGY INC. STOCKHOLDERS | $23,429 | $27,510 | $12,899 |
Net income per common share: | |||
Basic | $0.42 | ||
Diluted | $0.42 | ||
Weighted average common shares outstanding: | |||
Basic | 55,136 | ||
Diluted | 55,239 |
CONSOLIDATED_AND_COMBINED_STAT1
CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY (USD $) | Total | Common Stock, Class A | Common Stock, Class B | Members' Equity | Mezzanine Equity | Issued Shares Of Class A Common Stock | Issued Shares Of Class B Common Stock | Additional Paid-in Capital | Retained Earnings | Treasury Stock | Parent | Noncontrolling Interest |
In Thousands, except Share data, unless otherwise specified | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | |||
Balance at Dec. 31, 2011 | $9,053 | $9,053 | ||||||||||
Distributions | -15,935 | -15,935 | ||||||||||
Reorganization Transactions : | ||||||||||||
Net income | 12,899 | 12,899 | ||||||||||
Balance at Dec. 31, 2012 | 6,017 | 6,017 | ||||||||||
LLC Interest Issuance | 77,158 | 77,158 | ||||||||||
Preferred Return On Redeemable L L C Interests | -3,886 | -3,886 | ||||||||||
Reorganization Transactions : | ||||||||||||
Deemed contribution - incentive unit compensation | 1,233 | 1,233 | ||||||||||
Net income | 27,510 | 27,510 | ||||||||||
Balance at Dec. 31, 2013 | 77,158 | 77,158 | ||||||||||
Balance at Dec. 31, 2013 | 108,032 | |||||||||||
Balance at Dec. 31, 2013 | 30,874 | |||||||||||
Balance (in shares) at Dec. 31, 2013 | 1,000 | 0 | ||||||||||
Preferred Return On Redeemable L L C Interests | -1,723 | 1,723 | ||||||||||
Net loss prior to corporate reorganization | -37,923 | -37,923 | ||||||||||
Balance prior to Corporate Reorganization and Offering | 70,109 | -8,772 | 78,881 | |||||||||
Reorganization Transactions : | ||||||||||||
Payment of Preferred Return | -6,726 | -6,726 | ||||||||||
Conversion of PE Units for class A Common Stock and Class B Common Stock | 432 | 321 | -42,316 | -72,155 | 113,718 | 114,471 | ||||||
Conversion of PE Units for class A Common Stock and Class B Common Stock (In Shares) | 43,204,000 | 32,145,000 | ||||||||||
Net deferred tax Liability due to corporate reorganization | -95,530 | -95,530 | -95,530 | |||||||||
Deemed contribution - incentive unit compensation | 51,088 | 51,088 | ||||||||||
Net income | 23,429 | |||||||||||
Offering Transactions: | ||||||||||||
Issuance of Class A Common Stock, net of underwriters discount and expenses | 867,750 | 500 | 867,250 | 867,750 | ||||||||
Issuance of Class A Common Stock, net of underwriters discount and expenses (in shares) | 49,963,000 | |||||||||||
Initial allocation of noncontrolling interest of Parsley LLC effective on the date of the Offering | -251,955 | -251,955 | 251,955 | |||||||||
Tax benefit from tax receivable agreement | 59,633 | 59,633 | 59,633 | |||||||||
Liability due to tax receivable agreement | -50,689 | -50,689 | -50,689 | |||||||||
Issuance of restricted stock and restricted stock units | 770,000 | |||||||||||
Restricted stock forfeited | -41 | -41 | -41 | |||||||||
Restricted stock forfeited (in shares) | 37,000 | |||||||||||
Stock based compensation | 2,250 | 2,250 | 2,250 | |||||||||
Consolidated net income subsequent to the Corporate Reorganization and the Offering | 94,645 | 61,352 | 61,352 | 33,293 | ||||||||
Balance at Dec. 31, 2014 | $992,489 | $932 | $321 | $644,636 | $61,352 | $707,241 | $285,248 | |||||
Balance (in shares) at Dec. 31, 2014 | 93,937,947 | 32,145,296 | 93,937,000 | 32,145,000 | 37,000 |
CONSOLIDATED_AND_COMBINED_STAT2
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income | $56,722 | $27,510 | $12,899 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 94,297 | 28,152 | 6,406 |
Unproved leasehold impairment | 742 | ||
Accretion of asset retirement obligations | 512 | 181 | 66 |
Loss (gain) on sale of oil and natural gas properties | 2,097 | -36 | -7,819 |
Amortization of debt issue costs | 2,327 | 1,225 | 853 |
Amortization of bond premium | -574 | ||
Interest not paid in cash | 234 | 2,597 | 1,845 |
Income from equity investment | -348 | -184 | -267 |
Provision for deferred income taxes | 36,468 | 1,906 | 548 |
Deemed contribution - incentive unit compensation | 51,088 | 1,233 | |
Stock based compensation | 2,209 | ||
Derivative (income) loss | -83,858 | 9,800 | 2,190 |
Net cash received (paid) for derivative settlements | 3,311 | -198 | 179 |
Net cash received (paid) for option premiums | -193 | 16,342 | 9,318 |
Net cash paid to margin account | -320 | -462 | -35 |
Changes in operating assets and liabilities, net of acquisitions: | |||
Accounts receivable | 45,372 | -77,086 | -18,040 |
Other current assets | 241 | -348 | 212 |
Materials and supplies | -689 | -867 | -1,866 |
Other noncurrent assets | -187 | ||
Accounts payable and accrued expenses | -32,121 | 57,532 | 14,726 |
Revenue and severance taxes payable | 9,947 | 19,243 | 3,653 |
Amounts due to/from related parties | -3,055 | -621 | -1,207 |
Other noncurrent liabilities | 375 | ||
Net cash provided by operating activities | 184,983 | 53,235 | 5,025 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Development of oil and natural gas properties | -477,681 | -209,859 | -66,352 |
Acquisitions of oil and natural gas properties | -762,244 | -208,381 | -31,954 |
Additions to other property and equipment | -7,924 | -8,121 | -328 |
Proceeds from sales of oil and natural gas properties | 172 | 750 | 9,295 |
Investment in equity investment | -200 | ||
Net cash used in investing activities | -1,247,677 | -425,611 | -89,539 |
CASH FLOWS FROM FINANCING ACTIVITIES: | |||
Borrowings under long-term debt | 946,140 | 561,218 | 128,298 |
Payments on long-term debt | -700,766 | -254,100 | -37,012 |
Debt issue costs | -12,547 | -2,294 | -871 |
Proceeds from issuance of common stock, net | 867,750 | ||
Payment of Preferred Return | -6,726 | ||
Proceeds from issuance of LLC interests | 73,540 | ||
Equity issue costs | -268 | -235 | |
Distributions | -15,935 | ||
Net cash provided by financing activities | 1,093,851 | 378,096 | 74,245 |
Net increase in cash and cash equivalents | 31,157 | 5,720 | -10,269 |
Cash and cash equivalents at beginning of period | 19,393 | 13,673 | 23,942 |
Cash and cash equivalents at end of period | 50,550 | 19,393 | 13,673 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | |||
Cash paid for interest | 26,235 | 13,536 | 4,661 |
Cash paid for income taxes | 6 | ||
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES: | |||
Asset retirement obligations incurred, including changes in estimate | 7,498 | 6,238 | 1,040 |
Additions to oil and natural gas properties - change in capital accruals | 13,658 | 58,540 | 5,593 |
Additions to other property and equipment funded by capital lease borrowings | $2,263 |
Organization_and_Nature_of_Ope
Organization and Nature of Operations | 12 Months Ended | |
Dec. 31, 2014 | ||
Organization Consolidation And Presentation Of Financial Statements [Abstract] | ||
Organization and Nature of Operations | NOTE 1. | ORGANIZATION AND NATURE OF OPERATIONS |
Parsley Energy, Inc. (together with its subsidiaries, the “Company”) was formed on December 11, 2013, pursuant to the laws of the State of Delaware, as a wholly-owned subsidiary of Parsley Energy, LLC (“Parsley LLC”), a Delaware limited liability company formed on June 11, 2013 and is engaged in the acquisition, development, production, exploration, and sale of crude oil and natural gas properties located primarily in the Permian Basin, which is located in West Texas and Southeastern New Mexico. Concurrent with the formation of Parsley Energy, LLC, all of the interest holders of Parsley Energy, L.P. (“Parsley LP”), Parsley Energy Management, LLC (“PEM”) and Parsley Energy Operations, LLC (“PEO”) exchanged their interest in each entity in return for interest in Parsley Energy, LLC (the “Exchange”). Prior to the formation of Parsley Energy, LLC, 67.8% of Parsley LP, 100% of PEM and 100% of PEO were held by Mr. Bryan Sheffield, Parsley Energy, LLC’s President and Chief Executive Officer (“Sheffield”). Subsequent to Parsley Energy, LLC’s formation, Sheffield controlled 53.7% of Parsley Energy, LLC. As such, as all power and authority to control the core functions of Parsley LP, PEM and PEO were, and continue to be, controlled by Sheffield, the Exchange has been treated as a reorganization of entities under common control and the results of Parsley LP, PEM and PEO have been consolidated and combined for all periods. | ||
Parsley LP was formed on February 29, 2008, as a Texas limited partnership and is primarily engaged in the acquisition, development, production, exploration, and sale of crude oil and natural gas properties located in the Permian Basin in West Texas. On September 9, 2011, Parsley LP formed, and held all of the interest in, Spraberry Energy, LLC (“Spraberry”), a Texas limited liability company. On November 20, 2012, Spraberry merged with and into Parsley LP, thereby terminating Spraberry’s corporate existence. | ||
PEM was formed on February 19, 2008, as a Texas limited liability company and was formed to be the general partner of Parsley LP. | ||
PEO was formed on February 19, 2008, as a Texas limited liability company and is primarily engaged in the operation of crude oil and natural gas properties located in the Permian Basin in West Texas. | ||
Parsley LP also owns a noncontrolling 42.5% investment in Spraberry Production Services LLC (“SPS”). SPS was formed on August 27, 2010, as a Texas limited liability company and is primarily engaged in the oilfield services business servicing properties located in the Permian Basin in West Texas. | ||
Initial Public Offering | ||
On May 29, 2014, the Company completed its initial public offering (the “Offering”) of 57.5 million shares of the Company’s Class A common stock, par value $0.01 per share (“Class A Common Stock”) at a price of $18.50 per share. Approximately 7.5 million of the shares were sold by selling stockholders and the Company did not receive any proceeds from the sale of those shares. The remaining approximately 50 million shares of the Company’s Class A Common Stock that were sold resulted in gross proceeds of approximately $924.3 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $867.8 million. The material terms of the Offering are described in the Company’s final prospectus, dated May 22, 2014 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended, on May 27, 2014. | ||
A portion of the proceeds from the Offering were used to repay all outstanding borrowings under the Revolving Credit Agreement (as defined herein), to make a cash payment in settlement of the Preferred Return (as defined herein), to fund the OGX Acquisition (as defined herein), and to pay fees and expenses related to the Offering. The remaining proceeds will be used to fund a portion of the Company’s exploration and development program and for general corporate purposes. | ||
Corporate Reorganization | ||
On May 29, 2014, in connection with the Offering, Parsley LLC underwent a corporate reorganization (“Corporate Reorganization”) whereby (a) all of the membership interests (including outstanding incentive units) in Parsley LLC held by its then existing owners (the “Existing Owners”) were converted into a single class of units in Parsley LLC (“PE Units”), (b) certain of the Existing Owners contributed all of their PE Units to the Company in exchange for an equal number of shares of the Company’s Class A Common Stock, (c) certain of the Existing Owners contributed only a portion of their PE Units to the Company in exchange for an equal number of shares of the Company’s Class A Common Stock and continue to own a portion of the PE Units and (d) Parsley Energy Employee Holdings, LLC (“PEEH”), an entity owned by certain of Parsley LLC’s officers and employees that was formed to hold a portion of the incentive units in Parsley LLC, was merged with and into the Company, with the Company surviving the merger and the members of PEEH receiving shares of the Company’s Class A Common Stock. As a result of the above transactions, the Company issued a total of 43.2 million shares of its Class A Common Stock. | ||
Upon completion of the Offering, the Company issued and contributed 32.1 million shares of its Class B common stock, par value $0.01 per share (“Class B Common Stock”) and all of the net proceeds of the Offering to Parsley LLC in exchange for 93.2 million PE Units. Parsley LLC distributed to each of the Existing Owners that continued to own PE Units following the Corporate Reorganization and the Offering (collectively, the “PE Unit Holders”), one share of Class B Common Stock for each PE Unit such PE Unit Holder held. After giving effect to these transactions the Company owns an approximate 74.3% interest in Parsley LLC and Parsley LLC became a majority-owned subsidiary of the Company. The PE Unit Holders own an approximate 25.7% interest in Parsley LLC. | ||
Basis_of_Presentation
Basis of Presentation | 12 Months Ended | |
Dec. 31, 2014 | ||
Accounting Policies [Abstract] | ||
Basis of Presentation | NOTE 2. | BASIS OF PRESENTATION |
These consolidated and combined financial statements include the accounts of Parsley Energy, Inc. and its majority-owned subsidiary, Parsley LLC, and its wholly-owned subsidiaries: (i) Parsley LP, (ii) PEM, (iii) PEO, and its wholly-owned subsidiary, Parsley Energy Aviation, LLC, and (iv) Parsley Finance Corp. Parsley LP owns a 42.5% noncontrolling interest in 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. | ||
Transfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. As discussed above, the Corporate Reorganization has been accounted for as transactions between entities under common control thus the accompanying consolidated and combined financial statements and related notes of the Company have been retrospectively re-cast to include the historical results of the entities involved at historical carrying values and their operations as if they were consolidated and combined for all periods presented. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Summary of Significant Accounting Policies | NOTE 3. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||||
Use of Estimates | ||||||||||||
These consolidated and combined financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the SEC and (2) 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. Our management believes the major estimates and assumptions impacting our consolidated and combined 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 of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells; | |||||||||||
— | 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 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 include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. | ||||||||||||
Accounts Receivable | ||||||||||||
Accounts receivable consist of receivables from joint interest owners on properties the Company operates and crude oil, NGLs, and natural gas 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, 2014 or December 31, 2013. | ||||||||||||
For the years ended December 31, 2014, 2013 and 2012, each of the following purchasers accounted for more than 10% of our revenue: | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Atlas Pipeline Mid-Continent WestTex, LLC | 20% | 16% | 14% | |||||||||
Plains Marketing, L.P. | 15% | 22% | 16% | |||||||||
BML, Inc. | 14% | 2% | —% | |||||||||
Permian Transport & Trading | 11% | 25% | 20% | |||||||||
Enterprise Crude Oil, LLC | 10% | 20% | 26% | |||||||||
Shell Trading (US) Company | 4% | 7% | 17% | |||||||||
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. | ||||||||||||
Material and Supplies | ||||||||||||
Materials and supplies are stated at the lower of cost or market and consists of oil and gas drilling or repair items such as 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 accounts under joint operating agreements to which the Company is a party. As of December 31, 2014, the Company estimated that all of its tubular goods and equipment will be utilized within one year. | ||||||||||||
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 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. At December 31, 2014, 2013 and 2012, the Company had excluded $624.2 million, $68.2 million and $14.0 million, respectively, of capitalized costs from depletion. Depreciation and depletion expense on capitalized oil and gas property was $92.8 million, $27.1 million and $6.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Company had no exploratory wells in progress at December 31, 2014, 2013 or 2012. | ||||||||||||
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. During the years ended December 31, 2014, 2013, and 2012, the Company capitalized interest of $2.7 million, $3.4 million and $1.0 million, respectively. | ||||||||||||
On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization 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 and combined 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 12-month average price 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 reservoir 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, future gross revenues, 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 oil and natural gas properties. | ||||||||||||
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: | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Asset retirement obligations, January 1 | $ | 8,277 | $ | 1,858 | ||||||||
Additional liabilities incurred | 6,604 | 3,915 | ||||||||||
Liabilities assumed | — | 2,420 | ||||||||||
Disposition of wells | (80 | ) | (45 | ) | ||||||||
Accretion expense | 512 | 181 | ||||||||||
Liabilities settled upon plugging and abandoning wells | (7 | ) | (3 | ) | ||||||||
Revision of estimates | 901 | (49 | ) | |||||||||
Asset retirement obligations, December 31 | $ | 16,207 | $ | 8,277 | ||||||||
Allocation of Purchase Price in Business Combinations | ||||||||||||
As part of our business strategy, we periodically pursue 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. Our most significant estimates in our 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 Long-Lived Assets | ||||||||||||
The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties by reservoir. 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 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 and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. The Company recognized no impairment expense on proved oil and natural gas properties during the years ended December 31, 2014, 2013, or 2012. | ||||||||||||
Exploration costs | ||||||||||||
Exploration 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 twelve-month period after drilling is complete. | ||||||||||||
The Company recorded $2.4 million of geological and geophysical costs during the year ended December 31, 2014 and no such expenses for the years ended December 31, 2013 and 2012. | ||||||||||||
Unproved oil and natural gas properties are each periodically assessed 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 Company recorded $0.7 million of impairment charges related to unproved oil and natural gas properties during the year ended December 31, 2014 and no impairment charges for the years ended December 31, 2013, or 2012. All of these expenses are included in “exploration costs” on the Consolidated and Combined Statement of Operations. | ||||||||||||
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 and combined 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 to fifteen years. Construction in process includes costs related to the construction of the new office space. All construction in process is expected to be completed during 2015 and will be depreciated using the straight-line-method once construction is complete and the assets are placed in use. Depreciation expense on other property and equipment was $1.5 million, $1.1 million and $0.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Buildings | $ | 2,660 | $ | 2,117 | ||||||||
Computers, software, and equipment | 4,011 | 325 | ||||||||||
Airplane | 4,533 | 3,729 | ||||||||||
Vehicles | 2,611 | 102 | ||||||||||
Furniture and fixtures | 1,734 | 676 | ||||||||||
Land | 1,189 | 1,299 | ||||||||||
Leasehold improvements | 439 | 545 | ||||||||||
Machinery and equipment | 188 | 97 | ||||||||||
Construction in process | 1,812 | — | ||||||||||
Property and equipment | 19,177 | 8,890 | ||||||||||
Accumulated depreciation | (2,887 | ) | (1,365 | ) | ||||||||
Property and equipment, net | $ | 16,290 | $ | 7,525 | ||||||||
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 and combined 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, 2014, 2013, or 2012. | ||||||||||||
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 and Combined 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 and Combined Statements of Operations in the period of change. Gains and losses from 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 measurements are obtained using unadjusted quoted prices in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities as of the reporting date. | |||||||||||
— | Level 2 measurements use as inputs market prices which are either directly or indirectly observable as of the reporting date for similar commodity derivative contracts. The Company valued its level 2 assets and liabilities using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, time value, volatility factors, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. | |||||||||||
— | Level 3 measurements are based on process or valuation models that use inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little of no market activity). These inputs generally reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. | |||||||||||
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, NGLs, and natural gas 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, 2013 and 2012, 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 substantially all employees at their date of hire. The plan allow 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 year ended December 31, 2014, 2013, and 2012, the Company made contributions to the plan of $0.8 million, $0.2 million, and $0.1 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 carry forwards. 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 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. The Company believes it is more likely than not that certain net operating losses can be carried forward and utilized. | ||||||||||||
Parsley LLC, the Company’s accounting predecessor, is a limited liability company that is not subject to U.S. federal income tax. | ||||||||||||
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 | ||||||||||||
The Company operates in only one industry segment: the oil and natural gas exploration and production industry in the United States. All revenues are derived from customers located in the United States. | ||||||||||||
Reclassifications | ||||||||||||
Certain reclassifications have been made to prior period amounts to conform to the current presentation | ||||||||||||
Recent Accounting Pronouncements | ||||||||||||
In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period. This ASU provides more explicit guidance for treating share-based payment awards that require a specific performance target that affects vesting and that could be achieved after the requisite service period as a performance condition. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2015. The Company does not expect the adoption of this guidance to have a material impact on the consolidated and combined financial statements. | ||||||||||||
On May 28, 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard will be effective for the Company on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated and combined financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting. | ||||||||||||
Derivative_Financial_Instrumen
Derivative Financial Instruments | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||||||||||||||||
Derivative Financial Instruments | NOTE 4. | DERIVATIVE FINANCIAL INSTRUMENTS | ||||||||||||||
Commodity Derivative Instruments and Concentration of Risk | ||||||||||||||||
Objective and Strategy | ||||||||||||||||
The Company uses derivative financial instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its exploration and production activities. These include exchange traded and over-the-counter (OTC) crude put spread options and three way collars with the underlying contract and settlement pricings based on NYMEX West Texas Intermediate (WTI) and Henry Hub. Options and collars are used to establish a floor price, or floor and ceiling prices, for expected future oil and natural gas sales. | ||||||||||||||||
The Company uses put spread options to manage commodity price risk for 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. | ||||||||||||||||
The Company uses three way collars to manage commodity price risk for both oil and natural gas production. A three way collar is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. 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. | ||||||||||||||||
As of December 31, 2014, the Company had entered into derivative contracts through June 2017 covering a total of approximately 9,680 MBbls of our projected oil production through the purchases of put spreads and three way collars. The Company also entered into three way collars through December 2015 covering approximately 3,300 MMBtu of our projected natural gas production. | ||||||||||||||||
Derivative Activities | ||||||||||||||||
The following table summarizes the open positions for the commodity derivative instruments held by the Company at December 31, 2014: | ||||||||||||||||
Notional | Weighted Average | |||||||||||||||
Crude Options | (MBbl) | Strike Price | ||||||||||||||
Purchased | ||||||||||||||||
Puts | 9,680 | $ | 67.91 | |||||||||||||
Calls | — | $ | — | |||||||||||||
Sold | ||||||||||||||||
Puts | (9,680 | ) | $ | 50.86 | ||||||||||||
Calls | (2,405 | ) | $ | 114.69 | ||||||||||||
Notional | Weighted Average | |||||||||||||||
Natural Gas | (MMBtu) | Strike Price | ||||||||||||||
Purchased | ||||||||||||||||
Puts | 3,300 | $ | 4.5 | |||||||||||||
Calls | — | $ | — | |||||||||||||
Sold | ||||||||||||||||
Puts | (3,300 | ) | $ | 3.75 | ||||||||||||
Calls | (3,300 | ) | $ | 5.25 | ||||||||||||
During the fourth quarter 2014, Parsley elected to lower certain strike prices for both long and short put positions. The Company primarily focused on positions in late 2015 and 2016. In lowering the strike prices for the put spreads, the Company collected approximately $45.5 million of cash which is reflected in our year-end cash balance. | ||||||||||||||||
The Company excluded from the table above 6,700 notional MBbls with a fair value of $144.9 million relating to amounts recognized under the master netting agreement with the derivative counterparty. | ||||||||||||||||
Effect of Derivative Instruments on the Consolidated and Combined Financial Statements | ||||||||||||||||
Consolidated and Combined Balance Sheets | ||||||||||||||||
The following table summarizes the gross fair values of the Company’s commodity derivative instruments as of the reporting dates indicated (in thousands): | ||||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Short-term derivative instruments | $ | 80,911 | $ | 6,999 | ||||||||||||
Long-term derivative instruments | 70,805 | 13,850 | ||||||||||||||
Total derivative instruments - asset | 151,716 | 20,849 | ||||||||||||||
Short-term derivative instruments | (29,326 | ) | (4,435 | ) | ||||||||||||
Long-term derivative instruments | (31,275 | ) | (2,208 | ) | ||||||||||||
Total derivative instruments - liability | (60,601 | ) | (6,643 | ) | ||||||||||||
Net commodity derivative asset | $ | 91,115 | $ | 14,206 | ||||||||||||
Consolidated and Combined Statements of Operation | ||||||||||||||||
The Company recognized a gain from its derivative activities of $83.9 million for the year ended December 31, 2014 and losses of $9.8 million and $2.2 million for the years ended December 31, 2013, and 2012, respectively. These gains and losses are included in the Consolidated and Combined Statements of Operations line item, Derivative income (loss), as they were not designated as hedges for accounting purposes for any of the periods presented. The fair value of the derivative instruments is discussed in Note 14—Disclosures about Fair Value of Financial Instruments. | ||||||||||||||||
Offsetting of Derivative Assets and Liabilities | ||||||||||||||||
The Company has agreements in place with all 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 2014, the Company did not post margins with any of its counterparties. During 2013, the Company posted margins with some of its counterparties to collateralize certain derivative positions. | ||||||||||||||||
The following table presents the Company’s net exposure from its offsetting derivative asset and liability positions, as well as cash collateral on deposit with the brokers as of the reporting dates indicated (in thousands): | ||||||||||||||||
Gross Amount | Cash | |||||||||||||||
Presented on | Netting | Collateral | Net | |||||||||||||
Balance Sheet | Adjustments | Posted (Received) | Exposure | |||||||||||||
31-Dec-14 | ||||||||||||||||
Derivative assets with right of offset or | $ | 151,716 | $ | (60,601 | ) | $ | — | $ | 91,115 | |||||||
master netting agreements | ||||||||||||||||
Derivative liabilities with right of offset or | (60,601 | ) | 60,601 | — | — | |||||||||||
master netting agreements | ||||||||||||||||
31-Dec-13 | ||||||||||||||||
Derivative assets with right of offset or | $ | 20,849 | $ | (6,643 | ) | $ | 524 | $ | 14,730 | |||||||
master netting agreements | ||||||||||||||||
Derivative liabilities with right of offset or | (6,643 | ) | 6,643 | — | — | |||||||||||
master netting agreements | ||||||||||||||||
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 OTC 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 our commodity derivative contracts as of December 31, 2014 and 2013 is summarized in the table above. | ||||||||||||||||
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 has netting agreements with its counterparties and brokers that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities, and 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, 2014, 2013 or 2012. | ||||||||||||||||
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 were in a net liability position with respect to any individual counterparty at December 31, 2014 and 2013. During 2013, the Company received and posted margins with some of its counterparties to collateralize certain derivative positions. | ||||||||||||||||
Oil_and_Natural_Gas_Properties
Oil and Natural Gas Properties | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | ||||||||
Oil and Natural Gas Properties | NOTE 5. | OIL AND NATURAL GAS PROPERTIES | ||||||
Oil and natural gas properties includes the following (in thousands): | ||||||||
31-Dec-14 | 31-Dec-13 | |||||||
Oil and natural gas properties: | ||||||||
Subject to depletion | $ | 1,248,376 | $ | 546,072 | ||||
Not subject to depletion-acquisition costs | ||||||||
Incurred in 2014 | 562,046 | — | ||||||
Incurred in 2013 | 62,194 | 65,666 | ||||||
Incurred in 2012 | — | 2,577 | ||||||
Total not subject to depletion | 624,240 | 68,243 | ||||||
Gross oil and natural gas properties | 1,872,616 | 614,315 | ||||||
Less accumulated depreciation and depletion | (128,044 | ) | (34,957 | ) | ||||
Oil and natural gas properties, net | 1,744,572 | 579,358 | ||||||
Other property and equipment | 19,177 | 8,890 | ||||||
Less accumulated depreciation | (2,887 | ) | (1,365 | ) | ||||
Other property and equipment, net | 16,290 | 7,525 | ||||||
Property and equipment, net | $ | 1,760,862 | $ | 586,883 | ||||
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 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. Costs subject to depletion are proved costs and costs not subject to depletion are unproved costs. At December 31, 2014, the Company had excluded $624.2 million of capitalized costs from depletion. Depletion expense on capitalized oil and gas property was $92.8 million, $27.1, and $6.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Company had no exploratory wells in progress at December 31, 2014 and December 31, 2013. | ||||||||
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. During the years ended December 31, 2014, 2013, and 2012, the Company capitalized interest of $2.7 million, $3.4 million, and $1.0 million, respectively. | ||||||||
Depreciation expense on other property and equipment was $1.5 million, $1.1 million, and $0.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||
Acquisitions_of_Oil_and_Gas_Pr
Acquisitions of Oil and Gas Properties | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
Business Combinations [Abstract] | |||||||
Acquisitions of Oil and Gas Properties | NOTE 6. | ACQUISITIONS OF OIL AND GAS PROPERTIES | |||||
The following acquisitions were accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the assets acquired and liabilities assumed to be recorded at fair values as of the respective acquisition dates. | |||||||
During 2012, the Company acquired, from unaffiliated individuals and entities, additional working interests in wells it operates through a number of separate, individually negotiated transactions for an aggregate total cash consideration of $9.7 million. The Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties. | |||||||
In October 2012, the Company acquired, from Diamond K Production, LLC, an entity owned by Diamond K Interests, LP, a member of Parsley LLC, additional working interests in wells it operates for an aggregate cash consideration of $8.2 million. The Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties. | |||||||
During 2013, the Company acquired, from certain of its directors and officers, additional working interests in wells it operates through a number of separate, individually negotiated transactions for an aggregate cash consideration of $19.4 million. The Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties. The revenues and operating expenses attributable to the individual acquisitions during the years ended December 31, 2014 and 2013 were not material. | |||||||
During 2013, the Company acquired, from unaffiliated individuals and entities, additional working interests in wells it operates through a number of separate, individually negotiated transactions for an aggregate total cash consideration of $25.1 million. The Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties. The revenues and operating expenses attributable to the individual acquisitions during the years ended December 31, 2014 and 2013 were not material. | |||||||
In October 2013, the Company acquired oil and gas properties including 5,818 gross (5,330 net) acres primarily in Upton and Reagan Counties, Texas. The Company’s total consideration paid was $18.0 million. The revenues and operating expenses attributable to the acquisition during the years ended December 31, 2014 and 2013 were not material. The following table summarizes the purchase price and the value of assets acquired and liabilities assumed (in thousands): | |||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 14,734 | |||||
Unproved oil and gas properties | 4,729 | ||||||
Total fair value of oil and gas properties acquired | 19,463 | ||||||
Asset retirement obligation | (1,462 | ) | |||||
Fair value of net assets acquired | $ | 18,001 | |||||
In December 2013, the Company acquired oil and gas properties including 3,250 gross (2,595 net) acres in Upton and Reagan Counties, Texas. The Company’s total consideration paid was $32.3 million. The revenues and operating expenses attributable to the acquisition during the years ended December 31, 2014 and 2013 were not material. The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | |||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 24,365 | |||||
Unproved oil and gas properties | 8,062 | ||||||
Total fair value of oil and gas properties acquired | 32,427 | ||||||
Asset retirement obligation | (167 | ) | |||||
Fair value of net assets acquired | $ | 32,260 | |||||
On December 30, 2013, the Company acquired non-operated working interests in a number of wells which it currently operates for $80.0 million (the “Merit Acquisition”). The transaction did not increase The Company’s gross acreage position, but increases its net acreage by 637 acres in Upton County, Texas. The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | |||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 54,440 | |||||
Unproved oil and gas properties | 26,358 | ||||||
Total fair value of oil and gas properties acquired | 80,798 | ||||||
Asset retirement obligation | (792 | ) | |||||
Fair value of net assets acquired | $ | 80,006 | |||||
The following table presents operating revenues and net earnings included in the Company’s Consolidated and Combined Statements of Operations for the year ended December 31, 2014 as a result of the Merit Acquisition described above. The revenues and operating expenses attributable to the Merit Acquisition during the year ended December 31, 2013 were not material. | |||||||
Year Ended | |||||||
31-Dec-14 | |||||||
(in thousands) | |||||||
Total operating revenues | $ | 39,324 | |||||
Total operating expenses | 7,001 | ||||||
Operating income | $ | 32,323 | |||||
On March 27, 2014, the Company entered into a purchase and sale agreement, effective May 1, 2014, pursuant to which it agreed to acquire 2,240 gross (2,005 net) acres in its Midland Basin-Core area and seven gross (6.3 net) wells for total consideration of $165.3 million (the “Pacer Acquisition”), including purchase price adjustments. The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | |||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 56,870 | |||||
Unproved oil and gas properties | 108,583 | ||||||
Total fair value of oil and gas properties acquired | 165,453 | ||||||
Asset retirement obligation | (172 | ) | |||||
Fair value of net assets acquired | $ | 165,281 | |||||
The following table presents operating revenues and net earnings included in the Company’s Consolidated and Combined Statements of Operations for the year ended December 31, 2014 as a result of the Pacer Acquisition described above. There were no earnings included in the Consolidated and Combined Statements of Operations for the year ended December 31, 2013. | |||||||
Year Ended | |||||||
31-Dec-14 | |||||||
(in thousands) | |||||||
Total operating revenues | $ | 19,401 | |||||
Total operating expenses | 3,111 | ||||||
Operating income | $ | 16,290 | |||||
On May 30, 2014, the Company entered into the First Amendment to Option Agreement to which the Company acquired an option to purchase 4,640 gross (4,640 net) acres in its Midland Basin-Core area for total consideration of $127.6 million (the “OGX Acquisition”, net of purchase price adjustments. On June 4, 2014, the option was exercised. The revenues and operating expenses attributable to the OGX Acquisition during the years ended December 31, 2014 and 2013 were not material. The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | |||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 10,747 | |||||
Unproved oil and gas properties | 116,919 | ||||||
Total fair value of oil and gas properties acquired | 127,666 | ||||||
Asset retirement obligation | (38 | ) | |||||
Fair value of net assets acquired | 127,628 | ||||||
On September 30, 2014, the Company entered into a purchase and sale agreement, effective September 1, 2014, pursuant to which it agreed to acquire 4,320 gross (4,228 net) acres and 9 gross (9 net) wells in its Midland Basin-Core area for total consideration of $239.5 million (the “Cimarex Acquisition”), net of purchase price adjustments. The revenues and operating expenses attributable to the Cimarex Acquisition during the years ended December 31, 2014 and 2013 were not material. The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | |||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 111,003 | |||||
Unproved oil and gas properties | 128,756 | ||||||
Total fair value of oil and gas properties acquired | 239,759 | ||||||
Asset retirement obligation | (219 | ) | |||||
Fair value of net assets acquired | 239,540 | ||||||
On December 16, 2014, the Company purchased 8,643 gross (7,128 net) unproved acres in our Midland Basin – Core area for total consideration of $120.0 million from unaffiliated third parties (the “APC Acquisition”). | |||||||
The Company incurred a total of $54.0 million and $32.7 million of leasehold acquisition costs during 2014 and 2013, which are included as part of costs not subject to depletion. | |||||||
During 2014, the Company acquired, from unaffiliated individuals and entities, additional working interests in wells it operates through a number of separate, individually negotiated transactions for an aggregate total cash consideration of $55.2 million. The Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties. | |||||||
Pro forma for information for material acquisitions (unaudited) | |||||||
The Merit Acquisition and the Pacer acquisition (collectively, the "Material Acquisitions") were deemed material for purposes of the following pro forma disclosures. The Material Acquisitions were not included in the Company’s consolidated results until their closing dates. For the periods after the closing date of each Material Acquisition to December 31, 2014, the Material Acquisitions contributed revenue of $58.7 million and operating income of $48.6 million for the year ended December 31, 2014. | |||||||
The operating income attributable to the Material Acquisitions does not reflect certain expenses, such as general and administrative and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. The financial information was derived from the Company's audited historical consolidated financial statements for the years ended December 31, 2014 and 2013, the Material Acquisitions' audited and historical financial statements for the year ended December 31, 2013 and the Material Acquisitions' unaudited interim financial statements from January 1, 2013 to each closing date. The following unaudited pro forma consolidated financial information has been prepared as if the Material Acquisitions occurred on January 1, 2013 for the years ending December 31, (in thousands, except per share data). | |||||||
Pro Forma | |||||||
2014 | 2013 | ||||||
Revenue | |||||||
As reported | $ | 301,757 | $ | 121,018 | |||
Pro forma | $ | 307,999 | $ | 143,443 | |||
Net Income | |||||||
As reported | $ | 23,429 | $ | 27,510 | |||
Pro forma | $ | 24,894 | $ | 29,452 | |||
Basic net income per share | |||||||
As reported | $ | 0.42 | $ | 0.32 | |||
Pro forma | $ | 0.45 | $ | 0.34 | |||
Diluted net income per share | |||||||
As reported | $ | 0.42 | $ | 0.23 | |||
Pro forma | $ | 0.45 | $ | 0.25 | |||
These pro-forma adjustments have been calculated after applying the Company's accounting policies and adjusting the results to reflect additional depreciation and amortization that would have been charged assuming the properties were acquired and fair value adjustments to property and equipment had been applied. In addition, pro forma adjustments have been made for the interest that would have been incurred for financing the acquisitions with the Company's credit facility. These pro forma results of operations have been prepared for comparative purposes only and they do not purport to be indicative of the results of operations that actually would have resulted had the acquisitions occurred on the date indicated or that may result in the future. |
Sales_of_Oil_and_Natural_Gas_P
Sales of Oil and Natural Gas Properties | 12 Months Ended | |
Dec. 31, 2014 | ||
Sale Of Oil And Natural Gas Properties Disclosure [Abstract] | ||
Sale of Oil And Natural Gas Properties | NOTE 7. | SALES OF OIL AND NATURAL GAS PROPERTIES |
In April 2012, The Company sold 2,652 net unevaluated acres in Dawson, Glasscock, Howard, Martin and Upton Counties, Texas for $8.6 million and realized a $7.5 million gain on the sale. | ||
In November 2012, The Company sold 960 net unevaluated acres in Howard County, Texas for total proceeds of $0.7 million and realized a $0.3 million gain on the sale. | ||
In August 2013, The Company sold its interest in seven non-operated wells and 190 net acres for total proceeds of $0.8 million and realized a $36,000 gain on the sale. | ||
In August 2014, the Company sold its interest in one operated well and 38 net acres for total proceeds of $0.2 million and realized a $2.1 million loss on the sale. |
Equity_Investment
Equity Investment | 12 Months Ended | |
Dec. 31, 2014 | ||
Equity Method Investments And Joint Ventures [Abstract] | ||
Equity Investment | NOTE 8. | EQUITY INVESTMENT |
The Company uses the equity method of accounting for the investment in SPS, with earnings or losses, after adjustment for intra-company profits and losses, reported in the income (loss) from equity investment line on the Consolidated and Combined Statements of Operations. | ||
In November 2014, SPS underwent a corporate reorganization, effective January 1, 2014, in which two nonrelated parties were admitted as members, each obtaining a 7.5% interest in exchange for a capital contributions. As a result of the reorganization, the Company’s interest in SPS was decreased to 42.5% | ||
As of December 31, 2014 and December 31, 2013, the balance of the Company’s investment in SPS was $2.2 million and $1.8 million, respectively. The investment balance increased by $1.1 million and $0.7 million for the years ended December 31, 2014 and 2013, for the Company’s share of SPS’ net income, before adjustment for intra-company profits and losses, respectively. During the years ended December 31, 2014 and 2013, SPS provided services to the Company in its oil and natural gas field development operations, which the Company capitalized as part of its oil and gas properties. As such, that portion of the Company’s share of SPS’ gross profit from these services totaling $0.7 million and $0.5 million for the years ended December 31, 2014 and 2013, was subsequently eliminated from its share of SPS’s net income and a corresponding reduction was made to the carrying value of its investment. |
Debt
Debt | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Debt Disclosure [Abstract] | ||||||||||||
Debt | NOTE 9. | DEBT | ||||||||||
The Company’s debt consists of the following (in thousands): | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Revolving credit agreement | $ | 120,000 | $ | 234,750 | ||||||||
Senior unsecured notes | 550,000 | — | ||||||||||
Capital leases | 2,069 | — | ||||||||||
Second lien term loan | — | 192,854 | ||||||||||
Aircraft term loan | — | 2,593 | ||||||||||
Total debt | 672,069 | 430,197 | ||||||||||
Premium on senior unsecured notes | 5,426 | — | ||||||||||
Less: current portion | (650 | ) | (227 | ) | ||||||||
Total long-term debt | $ | 676,845 | $ | 429,970 | ||||||||
First Lien Obligations | ||||||||||||
Western National Bank Facility | ||||||||||||
On July 26, 2010, the Company entered into a loan agreement with Western National Bank which was subsequently amended and extended multiple times. On September 10, 2013, the Company repaid all amounts outstanding plus accrued interest associated the the Western National Bank facility. | ||||||||||||
Revolving Credit Agreement | ||||||||||||
On September 10, 2013, the Company entered into the Revolving Credit Agreement with Wells Fargo Bank National Association as the administrative agent. The Revolving Credit Agreement provides a revolving credit facility with a borrowing capacity up to the lesser of (i) the borrowing base (as defined in the Revolving Credit Agreement), (ii) aggregate lender commitments, and (iii) $750.0 million. The Revolving Credit Agreement matures on September 10, 2018. The Revolving Credit Agreement is secured by substantially all of the Company’s assets. | ||||||||||||
The Revolving Credit Agreement provided for an initial borrowing base of $175.0 million based on the Company’s proved producing reserves and a portion of its proved undeveloped reserves. The borrowing base will be redetermined by the lenders at least semi-annually on each April 1 and October 1, with the next redetermination on April 1, 2015. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Revolving Credit Agreement. | ||||||||||||
On October 21, 2013, the Company entered into an amended and restated credit agreement (as amended, the “Revolving Credit Agreement”), whereby the borrowing base was reduced from $175.0 million to $143.8 million. On December 20, 2013, The Company entered into the First Amendment to the Amended and Restated Credit Agreement which increased the borrowing base from $143.8 million to $240 million. In addition, the amendment provided that the borrowing base would automatically increase from $240 million to $280 million upon the closing of the Merit Acquisition, which closed on December 30, 2013. | ||||||||||||
On April 15, 2014, in connection with the issuance of the Notes (as defined herein) offering, the Company entered into the Third Amendment to the Amended and Restated Credit Agreement whereby the borrowing base was increased from $227.5 million to $365.0 million. Immediately following the Notes offering, the borrowing base was reduced to $327.5 million. | ||||||||||||
On May 2, 2014, the Company entered into the Fourth Amendment to the Revolving Credit Agreement whereby the expiration date of any letter of credit was increased from fifteen months to eighteen months. | ||||||||||||
On May 9, 2014, the Company entered into the Fifth Amendment to the Revolving Credit Agreement whereby certain terms were amended permitting the Corporate Reorganization to occur. | ||||||||||||
On May 29, 2014, the Company used proceeds from the Offering to repay the outstanding borrowings under the Revolving Credit Agreement. | ||||||||||||
On September 4, 2014, the Company entered into the Sixth Amendment to the Revolving Credit Agreement (the “Sixth Amendment”.) The Sixth Amendment changed the reporting requirements and deliverables in response to the Company becoming a public company. | ||||||||||||
In November 2014, the Company entered into the Seventh Amendment to the Amended and Restated Credit Agreement whereby the borrowing base was increased to $575.0 million, with a commitment level of $365.0 million. | ||||||||||||
In December 2014, the Company’s borrowing base was decreased to $562.0 million, with a commitment level of $365.0 million, resulting from a restructuring of commodity price hedges. In February 2015, the borrowing base was decreased to $560.8, with a commitment level of $365.0 also resulting from restructuring of commodity price hedges. | ||||||||||||
As of December 31, 2014 there were $120.0 million of borrowings outstanding and $0.3 million in letters of credit outstanding, resulting in availability of $244.7 million. | ||||||||||||
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 (equal to the product of: (a) the LIBO rate, multiplied by (b) a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (expressed as a decimal) on such date at which the Administrative Agent is required to maintain reserves on ‘Eurocurrency Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the adjusted LIBO rate (as calculated above) plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of our 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 our borrowing base utilized. As of December 31, 2014, letters of credit outstanding under the Revolving Credit Agreement had a weighted average interest rate of 1.75%. 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 requires the Company to maintain the following two financial ratios: | ||||||||||||
— | a current ratio, which is the ratio of consolidated current assets (including unused availability under its revolving credit facility) to consolidated current liabilities of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and | |||||||||||
— | a minimum interest coverage ratio, which is the ratio of EBITDAX to interest expense, of not less than 2.5 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 also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters. | ||||||||||||
At December 31, 2014, the Company was in compliance with all required covenants. 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 Majority Lenders (as defined in the Revolving Credit Agreement) may accelerate any amounts outstanding. | ||||||||||||
7.500% Senior Notes due 2022 | ||||||||||||
On February 5, 2014, Parsley LLC and Finance Corp. issued $400 million of 7.500% senior notes due 2022 (the “Notes”). Interest is payable on the Notes semi-annually in arrears on each February 15 and August 15, and commenced August 15, 2014. These notes are guaranteed on a senior unsecured basis by all of our subsidiaries, other than Parsley LLC and Finance Corp. The issuance of the Notes resulted in net proceeds, after discounts and offering expenses, of approximately $391.4 million, $198.5 million of which was used repay all outstanding term debt, accrued interest and a prepayment penalty under a second lien credit facility (which was terminated concurrently with such repayment) and $175.1 million of which was used to partially repay amounts outstanding, plus accrued interest, under the Revolving Credit Agreement. | ||||||||||||
On April 14, 2014, Parsley LLC and Finance Corp. issued an additional $150 million of the Notes at 104% of par for gross proceeds of $156 million. The issuance of these notes resulted in net proceeds of approximately $152.8 million, after deducting the initial purchasers’ discount and estimated offering expenses, $145 million of which was used to repay borrowings under the Revolving Credit Agreement. | ||||||||||||
At any time prior to February 15, 2017, the Company may redeem up to 35% of the Notes at a redemption price of 107.5% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 120 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to February 15, 2017, the Company may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after February 15, 2017, the Company may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 105.625% for the twelve-month period beginning on February 15, 2017, 103.750% for the twelve-month period beginning February 15, 2018, 101.875% for the twelve-month period beginning on February 15, 2019 and 100.00% beginning on February 15, 2020, plus accrued and unpaid interest to the redemption date. | ||||||||||||
The indenture governing the Notes restricts our ability and the ability of certain of our subsidiaries to, among other things: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire our 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 our restricted subsidiaries to us; (vii) consolidate, merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. At December 31, 2014, the Company was in compliance with all of these covenants. 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 Indenture) 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 will be reinstated. | ||||||||||||
Second Lien Agreement | ||||||||||||
On November 20, 2012, The Company entered into a second lien credit agreement (the “Second Lien Agreement”) providing for term loans up to an aggregate principal amount of $75.0 million and an original maturity date of December 31, 2016. Obligations under the Second Lien Agreement were secured by a second lien on substantially all of the Company’s oil and natural gas properties. | ||||||||||||
The Second Lien Agreement may be prepaid at any time. If prepaid prior to November 20, 2014, The Company will be obligated to pay a prepayment premium equal to 7.5% of the principal amount being prepaid. As a condition to entering into the Second Lien Agreement, The Company was required to enter into certain derivative instruments to hedge not less than 80% of the anticipated projected production from proved, developed, producing oil and natural gas properties. | ||||||||||||
On June 10, 2013, the Company entered into a First Amendment and Waiver to the Second Lien Agreement (the “First Amendment”). The First Amendment: (1) reduced the Consolidated Current Ratio, as at June 30, 2013, to be not less than 0.75:1.00, and as at the last day of any quarter thereafter, to be not less than 1.00:1.00; (2) provided a waiver of the Lenders’ right to assert an Event of Default with respect to the Consolidated Current Ratio covenant as of March 31, 2013; and (3) extended the deadline of delivery of required financial statements from 120 days to 180 days after The Company’s year-end (each of the capitalized terms used in the foregoing clauses (1) through (4) being as defined in the Second Lien Term Agreement). | ||||||||||||
On September 10, 2013, the Company entered into a Second Amendment and Waiver to the Second Lien Agreement (the “Second Amendment”). The Second Amendment: (1) amended the definition of the Consolidated Current Ratio to allow for the inclusion, in the numerator, of unused borrowing capacity under the Syndicated Credit Agreement; and (2) waived the Lenders’ right to assert an Event of Default with respect to the Consolidated Current Ratio covenant as of June 30, 2013 (each of the capitalized terms used in the foregoing clauses (1) through (4) being as defined in the Second Lien Agreement agreement). | ||||||||||||
On October 21, 2013, the Company entered into an amended and restated second lien credit agreement (the “Amended Second Lien Agreement”). The Amended Second Lien Agreement created two tranches of loan commitments, the Tranche A Commitment totaling $75.0 million and the Tranche B Commitment, totaling $125.0 million. The maturity date remains December 31, 2016. | ||||||||||||
Tranche A borrowings bore interest at the combined rate equal to (i) the greater of 1.0%, and the three- month LIBO rate, plus 10.0%, paid in cash, plus (ii) 4.0% paid-in-kind by adding to the principal balance outstanding. Tranche B borrowings bore interest at the greater of 1.0%, and the three-month LIBO rate, plus 11.0%, paid in cash. | ||||||||||||
The Second Lien Agreement was repaid in full in February 2014. The Company paid a prepayment penalty equal to 7.5% of the principal amount being repaid. | ||||||||||||
Aircraft Term Loan | ||||||||||||
On April 2, 2013, the Company entered into a $2.8 million term loan (“Aircraft Term Loan”) in connection with the purchase of a corporate aircraft. The Company repaid the Aircraft Term Loan in full in August 2014. | ||||||||||||
Capital Lease | ||||||||||||
During the year ended December 31, 2014, the Company entered into an aggregate of $2.3 million in capital lease agreements payable (“Capital Leases”) in connection with the lease of vehicles for operations and field personnel. The Capital Leases bear interest at annual rates ranging from 5.0% to 6.7% with varying maturities between March 2017 and August 2018. The Capital Leases require monthly payments of $58,426 of principal and interest. | ||||||||||||
Principal maturities of long-term debt | ||||||||||||
Principal maturities of long-term debt outstanding, excluding the premium on the Notes, at December 31, 2014 are as follows (in thousands): | ||||||||||||
2015 | $ | 650 | ||||||||||
2016 | 688 | |||||||||||
2017 | 705 | |||||||||||
2018 | 120,026 | |||||||||||
2019 | — | |||||||||||
Thereafter | 550,000 | |||||||||||
Total | $ | 672,069 | ||||||||||
Interest expense | ||||||||||||
The following amounts have been incurred and charged to interest expense for the year ended December 31, 2014, 2013, and 2012 (in thousands): | ||||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Cash payments for interest | $ | 26,235 | $ | 13,536 | $ | 4,661 | ||||||
Change in interest accrual | 13,390 | — | — | |||||||||
Payment-in-kind interest | 234 | 2,597 | 1,845 | |||||||||
Amortization of deferred loan origination costs | 1,941 | 405 | 80 | |||||||||
Amortization of original issue discount | — | — | 158 | |||||||||
Write-off of deferred loan origination costs | 386 | 820 | 615 | |||||||||
Amortization of bond premium | (574 | ) | — | — | ||||||||
Interest income | (316 | ) | (235 | ) | (75 | ) | ||||||
Interest costs incurred | 41,296 | 17,123 | 7,284 | |||||||||
Less: capitalized interest | (2,689 | ) | (3,409 | ) | (999 | ) | ||||||
Total interest expense | $ | 38,607 | $ | 13,714 | $ | 6,285 | ||||||
Equity
Equity | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Equity [Abstract] | ||||||||
Equity | NOTE 10. | EQUITY | ||||||
Preferred Stock | ||||||||
Pursuant to the Company’s 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, 2014. | ||||||||
Class A Common Stock | ||||||||
As a result of the Offering and the Corporate Reorganization, the Company has a total of 93.9 million shares of its Class A Common Stock outstanding as of December 31, 2014, which includes 0.8 million shares of restricted stock and restricted stock units. 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 our outstanding shares of preferred stock. | ||||||||
Class B Common Stock | ||||||||
As a result of the Corporate Reorganization, the Company has a total of 32.1 million shares of its Class B Common Stock outstanding as of December 31, 2014. 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. | ||||||||
The PE Unit Holders generally have the right to exchange (the “Exchange Right”) their PE Units (and a corresponding number of shares of Class B Common Stock), for shares of the Company’s Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each PE Unit (and a corresponding number of shares of Class B Common Stock) exchanged, (subject to conversion rate adjustments for stock splits, stock dividends, and reclassifications) or cash at the Company’s or Parsley LLC’s election (the “Cash Option”). During the year ended December 31, 2014, no PE Unit Holders elected to exchange pursuant to their Exchange Right. | ||||||||
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 its Class B Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and restricted stock units. For the year ended December 31, 2014, Class B Common Stock was not recognized in dilutive earnings per share as the effect would be antidilutive. | ||||||||
The following table reflects the allocation of net income to common stockholders and EPS computations for the periods indicated based on a weighted average number of common stock outstanding for the period: | ||||||||
31-Dec-14 | ||||||||
Basic EPS (in thousands, except per share data) | ||||||||
Numerator: | ||||||||
Basic net income attributable to Parsley Energy Inc. | $ | 23,429 | ||||||
Stockholders | ||||||||
Denominator: | ||||||||
Basic weighted average shares outstanding | 55,136 | |||||||
Basic EPS attributable to Parsley Energy Inc. Stockholders | $ | 0.42 | ||||||
Diluted EPS | ||||||||
Numerator: | ||||||||
Net income attributable to Parsley Energy Inc. Stockholders | 23,429 | |||||||
Effect of conversion of the shares of Company's Class B | — | |||||||
Common stock to shares of the Company's Class A | ||||||||
common stock | ||||||||
Diluted net income attributable to Parsley Energy Inc. | $ | 23,429 | ||||||
Stockholders | ||||||||
Denominator: | ||||||||
Basic weighted average shares outstanding | 55,136 | |||||||
Effect of dilutive securities: | ||||||||
Class B Common Stock | — | |||||||
Restricted Stock and Restricted Stock Units | 103 | |||||||
Diluted weighted average shares outstanding | 55,239 | |||||||
Diluted EPS attributable to Parsley Energy Inc. | $ | 0.42 | ||||||
Stockholders | ||||||||
LLC Interest Issuance | ||||||||
On June 11, 2013, Parsley LLC issued membership interests to NGP X US Holdings, L.P. and other investors for total consideration of $73.5 million. These interest holders were designated as “Preferred Holders” and granted certain rights in the limited liability agreement of Parsley LLC (the “Parsley LLC Agreement”). Included with these rights were (1) the right to receive a 9.5% return on their invested capital prior to any distribution to any other unit holders (the “Preferred Return”) and (2) the right to require Parsley LLC to redeem all, but not less than all, of each Preferred Holder’s interest in Parsley LLC after the seventh anniversary, but before the eighth anniversary, of the date of their investment, or if Bryan Sheffield ceased to be Parsley LLC’s Chief Executive Officer. | ||||||||
As the investment by the Preferred Holders was redeemable at their option, the Company reflected this investment outside of permanent equity, under the heading “Mezzanine Equity—Redeemable LLC Units” in Parsley LLC’s Consolidated and Combined Balance Sheet at December 31, 2013, in accordance with ASC Topic 480, “Distinguishing Liabilities from Equity”. | ||||||||
On May 29, 2014, in connection with the Corporate Reorganization, the Preferred Holders’ interests were converted to PE Units. A portion of such PE Units were redeemed by Parsley LLC in exchange for the Preferred Return payment of approximately $6.7 million and the remainder of such PE Units were contributed to the Company in exchange for an equal number of shares of Class A Common Stock. | ||||||||
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. | ||||||||
In connection with the Corporate Reorganization, all of the incentive units were immediately vested and converted into PE Units and, subsequently, a portion of such PE Units were exchanged on a one for one basis for shares of Class A Common Stock. As a result, Parsley LLC was required to recognize, as a non-cash charge, the unrecognized cumulative incentive unit compensation expense of approximately $50.6 million on May 29, 2014, in addition to the $0.5 million recognized during the period from January 1, 2014 through May 29, 2014. | ||||||||
Restricted Stock and Restricted Stock Unit Awards | ||||||||
Restricted stock awards are awards of Class A Common Stock that 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. Restricted stock unit awards are awards of restricted stock units that 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 restriction. Each restricted stock unit represents the right to receive one share of Class A Common Stock. The fair value of such restricted stock and restricted stock units was determined using the weighted average closing price on the grant date and compensation expense, net of estimated forfeitures, is recorded over the applicable vesting periods. | ||||||||
The following table summarized the Company’s restricted stock and restricted stock unit award activity for the year ended December 31, 2014: | ||||||||
Number of Shares | Weighted - Average Grant Date | |||||||
(in thousands) | Fair Value | |||||||
Outstanding at January 1, 2014 | — | $ | — | |||||
Restricted Stock Granted | 770 | $ | 18.54 | |||||
Restricted Stock Units Granted | 24 | $ | 18.5 | |||||
Vested | — | $ | — | |||||
Forfeited | (37 | ) | $ | 18.5 | ||||
Outstanding at December 31, 2014 | 757 | $ | 18.54 | |||||
Stock based compensation expense related to restricted stock and restricted stock units was $2.2 million for the year ended December 31, 2014, respectively. There was approximately $11.8 million of unamortized compensation expense relating to outstanding restricted stock and restricted stock units at December 31, 2014. | ||||||||
Noncontrolling Interest | ||||||||
As a result of the Corporate Reorganization and the Offering, the Company acquired 74.3% of Parsley LLC, with the Existing Owners retaining ownership of 25.7% of Parsley LLC. As a result, the Company has consolidated the financial position and results of operations of Parsley LLC and reflected that portion retained by the Existing Owners as a noncontrolling interest. | ||||||||
Net income attributable to noncontrolling interest for the year ended December 31, 2014 of approximately $33.3 million represents the net income of Parsley LLC attributable to the Existing Owners’ retained interest since May 29, 2014. |
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Income Tax Disclosure [Abstract] | ||||||||||
Income Taxes | NOTE 11. | 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 carry forwards. 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 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. The Company believes it is more likely than not that certain net operating losses can be carried forward and utilized. | ||||||||||
Parsley LLC, the Company’s accounting predecessor, is a limited liability company that is not subject to U.S. federal income tax. As part of the Corporate Reorganization, certain of the Existing Owners exchanged all or part of their PE Units for shares of the Company’s common stock, as discussed in Note 1 – Organization and Nature of Operations. On the date of the Corporate Reorganization, a corresponding “first day” tax charge of approximately $95.5 million was recorded to establish a net deferred tax liability for differences between the tax and book basis of Parsley LLC’s assets and liabilities. In addition, the Company recorded a long term liability of $56.3 million to establish the TRA (as defined herein) and a corresponding deferred tax asset of $66.3 million. The offset of the deferred tax liability, TRA, and deferred tax asset was recorded to additional paid-in capital. Subsequently, in 2014, as part of the tax return preparation process, adjustments were made to reduce the TRA liability by $5.6 million and to reduce the deferred tax asset by $6.7 million with the offset recorded to additional paid in capital. As of December 31, 2014, the liability associated with the TRA was $50.7 million and the corresponding deferred tax asset was $59.6 million. | ||||||||||
The components of the income tax provision were as follows for the periods indicated (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Federal: | ||||||||||
Current | $ | — | $ | — | $ | — | ||||
Deferred | 31,968 | — | — | |||||||
Total federal | 31,968 | — | — | |||||||
State, net of federal benefit: | ||||||||||
Deferred | 4,500 | 1,906 | 554 | |||||||
Total state | 4,500 | 1,906 | 554 | |||||||
Income tax provision | $ | 36,468 | $ | 1,906 | $ | 554 | ||||
The following table reconciles the income tax provision with income tax expense at the federal statutory rate for the periods indicated (in thousands): | ||||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Income (loss) before income taxes | $ | 93,190 | $ | 29,416 | $ | 13,453 | ||||
Plus: net loss prior to corporate reorganization | 37,378 | — | — | |||||||
Less: net income attributable to noncontrolling | (33,293 | ) | — | — | ||||||
interest | ||||||||||
Income (loss) before income taxes and noncontrolling | 97,275 | 29,416 | 13,453 | |||||||
interest subsequent to corporate reorganization | ||||||||||
Income taxes at the federal statutory rate | 34,046 | — | — | |||||||
State income taxes, net of federal benefit | 967 | — | — | |||||||
State income taxes, prior to corporate reorganization | 1,246 | 1,906 | 554 | |||||||
Provision to return adjustment | 170 | — | — | |||||||
Permanent and other | 39 | — | — | |||||||
Income tax provision | 36,468 | 1,906 | 554 | |||||||
The Company has net operating loss carryforwards (“NOLs”) for United States income tax purposes that have been generated from our operations. Our NOLs are scheduled to expire if not utilized between 2033 and 2034. NOLs available for utilization as of December 31, 2014 were approximately $144 million. | ||||||||||
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, | ||||||||||
2014 | 2013 | |||||||||
Current: | ||||||||||
Liabilities: | ||||||||||
Derivative fair value gain | (12,601 | ) | — | |||||||
Total current deferred tax liability | (12,601 | ) | — | |||||||
Net current deferred tax liability | (12,601 | ) | — | |||||||
Noncurrent: | ||||||||||
Assets: | ||||||||||
Asset retirement obligations | 4,379 | — | ||||||||
Materials and supplies | 431 | — | ||||||||
Deferred stock based compensation | 644 | — | ||||||||
Net operating loss carryforward | 50,425 | — | ||||||||
Total noncurrent deferred tax assets | 55,879 | — | ||||||||
Liabilities: | ||||||||||
Book basis of oil and natural gas properties | (108,825 | ) | (2,572 | ) | ||||||
in excess of tax basis | ||||||||||
Derivative fair value gain | (8,874 | ) | — | |||||||
Earnings in investment in subsidiary | (514 | ) | — | |||||||
Total noncurrent deferred tax liabilities | (118,213 | ) | (2,572 | ) | ||||||
Net noncurrent deferred tax liability | (62,334 | ) | (2,572 | ) | ||||||
Related_Party_Transactions
Related Party Transactions | 12 Months Ended | |
Dec. 31, 2014 | ||
Related Party Transactions [Abstract] | ||
Related Party Transactions | NOTE 12. | RELATED PARTY TRANSACTIONS |
Well Operations | ||
During the years ended December 31, 2014, 2013, and 2012, several of the Company’s directors, officers, 5% stockholders, 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, 2014, 2013, and 2012, totaled $11.3 million, $14.4 million, and $10.8 million, respectively. The revenues disbursed to the Related Party Working Interest Owners for the year ended December 31, 2014 include $2.1 million of revenues for the five months ended May 29, 2014 for entities no longer considered a related party due to their direct relationship with Diamond K (defined herein.) | ||
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. | ||
Acquisitions | ||
On October 29, 2012, The Company acquired, from Diamond K Production, LLC, an entity owned by Diamond K (defined herein), additional working interests in wells it operates for an aggregate cash consideration of $8.2 million. The Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties. | ||
During the years ended December 31, 2013, The Company acquired, from certain of its directors and officers, additional working interests in wells it operates through a number of separate, individually negotiated transactions for an aggregate total of and $19.4 million, respectively. | ||
Tex-Isle Supply, Inc. Purchases | ||
The Company makes purchases of equipment used in its drilling operations from Tex-Isle Supply, Inc. (“Tex-Isle”). Tex-Isle is controlled by a party who is also the general partner of Diamond K Interests, LP (“Diamond K”), a former member of Parsley LLC. In connection with the Offering, Diamond K exchanged its membership interest for shares of Class A Common Stock. As of May 29, 2014, Diamond K is no longer considered a related party as their ownership interest fell below 5% due to this transaction, which results in Tex-Isle no longer being considered a related party. During the five months ended May 29, 2014, the Company made purchases of equipment used in its drilling operations totaling $29.3 million, from Tex-Isle. During the years ended December 31, 2013 and 2012, the Company made purchases of equipment used in its drilling operations totaling $68.1 million and $33.1 million from Tex-Isle. | ||
Spraberry Production Services LLC | ||
As defined in Note 8—Equity Investment, as of December 31, 2014, the Company owns a 42.5% interest in SPS. During the years ended December 31, 2014, 2013 and 2012, the Company incurred charges totaling $5.1 million, $3.3 million, and $2.0 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 year ended December 31, 2014, the Company incurred charges totaling $0.7 million, for services performed by Lone Star for the Company’s well operations and drilling activities. There were no such charges incurred during 2013 and 2012. | ||
Davis, Gerald, and Cremer | ||
During the years ended December 31, 2014, 2013, and 2012, we incurred charges totaling $0.2 million, $0.3 million, and $0.1 million, respectively, for legal services from Davis, Gerald & Cremer, PC, of which our director David H. Smith is a shareholder. | ||
Exchange Right | ||
In accordance with the terms of the amended Parsley LLC Agreement, the PE Unit Holders generally have the right to exchange their PE Units (and a corresponding number of shares of the Company’s Class B Common Stock), for shares of the Company’s 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 cash (pursuant to the Cash Option). As a PE Unit Holder exchanges its PE Units, the Company’s interest in Parsley LLC will be correspondingly increased. | ||
Tax Receivable Agreement | ||
In connection with the Offering, on May 29, 2014, the Company entered into a Tax Receivable Agreement (the “TRA”) with Parsley LLC, and certain holders of PE Units prior to the Offering (each such person a “TRA Holder”), including certain executive officers. This agreement 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 Offering as a result of (i) any tax basis increases resulting from the contribution in connection with the Offering 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 pursuant to the Exchange Right (or resulting from an exchange of PE Units for cash pursuant to the Cash Option) and (ii) 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 commences 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. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||
Commitments And Contingencies Disclosure [Abstract] | ||||||||||||||||||||||
Commitments and Contingencies | NOTE 13. | COMMITMENTS AND CONTINGENCIES | ||||||||||||||||||||
Legal Matters | ||||||||||||||||||||||
In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on The Company’s financial position, results of operations or cash flows. | ||||||||||||||||||||||
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, 2014 and 2013, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability. | ||||||||||||||||||||||
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, 2014: | ||||||||||||||||||||||
Payments Due by Period | ||||||||||||||||||||||
(in thousands) | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | |||||||||||||||
Drilling commitments | 39,466 | 27,911 | 10,039 | — | — | — | 77,416 | |||||||||||||||
Operating Leases | ||||||||||||||||||||||
The estimated future minimum lease payments under long term operating lease agreements as of December 31, 2014 was as follows (in thousands): | ||||||||||||||||||||||
For the years ended December 31, | ||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||
(in thousands) | ||||||||||||||||||||||
Office Leases | $ | 2,827 | $ | 2,831 | $ | 4,452 | $ | 4,865 | $ | 4,977 | $ | 21,005 | $ | 40,957 | ||||||||
Vehicle Operating Leases | 116 | 124 | — | — | — | — | 240 | |||||||||||||||
Office Equipment | 86 | 70 | 29 | 1 | — | — | 186 | |||||||||||||||
3,029 | 3,025 | 4,481 | 4,866 | 4,977 | 21,005 | 41,383 | ||||||||||||||||
Rent expense for the years ended December 31, 2014, 2013 and 2012 was $1.5 million, $0.7 million and $0.3 million, respectively. |
Disclosures_about_Fair_Value_o
Disclosures about Fair Value of Financial Instruments | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||
Disclosures about Fair Value of Financial Instruments | NOTE 14. | 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: | Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. | |||||||||||||||
Level 2: | Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. | |||||||||||||||
Level 3: | Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. | |||||||||||||||
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis | ||||||||||||||||
The book value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their fair value due to the short-term nature of these instruments. The book value of the Company’s Revolving Credit Agreement approximates its fair value as the interest rate is variable. | ||||||||||||||||
The estimated fair value of the Company’s $550 million of Notes at December 31, 2014, was approximately $521.1 million. The fair value of the Notes is classified as a level 1 measurement as it is calculated based on market quotes. | ||||||||||||||||
Impairments of long-lived assets – The Company 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, for instance when there are declines in commodity prices or well performance. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows 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 depletion base or by individual well for those wells not constituting part of a depletion 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 of the properties would be recognized at that time. | ||||||||||||||||
The Company calculates the estimated 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 further 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 appropriate risk-adjusted probable and possible 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 accompanying Consolidated and Combined Balance Sheets and in Note 4—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): | ||||||||||||||||
31-Dec-14 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Commodity derivative contracts | ||||||||||||||||
Assets: | ||||||||||||||||
Short-term derivative instruments | $ | — | $ | 80,911 | $ | — | $ | 80,911 | ||||||||
Long-term derivative instruments | — | 70,805 | — | 70,805 | ||||||||||||
Total derivative instrument - asset | $ | — | $ | 151,716 | $ | — | $ | 151,716 | ||||||||
Liabilities: | ||||||||||||||||
Short-term derivative instruments | $ | — | $ | (29,326 | ) | $ | — | $ | (29,326 | ) | ||||||
Long-term derivative instruments | — | (31,275 | ) | — | (31,275 | ) | ||||||||||
Total derivative instruments - liability | — | (60,601 | ) | — | (60,601 | ) | ||||||||||
Net commodity derivative asset | $ | — | $ | 91,115 | $ | — | $ | 91,115 | ||||||||
31-Dec-13 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Commodity derivative contracts | ||||||||||||||||
Assets: | ||||||||||||||||
Short-term derivative instruments | $ | — | $ | 6,999 | $ | — | $ | 6,999 | ||||||||
Long-term derivative instruments | — | 13,850 | — | 13,850 | ||||||||||||
Total derivative instrument - asset | $ | — | $ | 20,849 | $ | — | $ | 20,849 | ||||||||
Liabilities: | ||||||||||||||||
Short-term derivative instruments | $ | — | $ | (4,435 | ) | $ | — | $ | (4,435 | ) | ||||||
Long-term derivative instruments | — | (2,208 | ) | — | (2,208 | ) | ||||||||||
Total derivative instruments - liability | — | (6,643 | ) | — | (6,643 | ) | ||||||||||
Net commodity derivative asset | $ | — | $ | 14,206 | $ | — | $ | 14,206 | ||||||||
There were no transfers in to or out of level 2 during the years ended December 31, 2014 or 2013. |
Subsequent_Events
Subsequent Events | 12 Months Ended | |
Dec. 31, 2014 | ||
Subsequent Events [Abstract] | ||
Subsequent Events | NOTE 15. | 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. | ||
Private Placement of Common Stock | ||
On February 5, 2014, the Company entered into an agreement to sell 14,885,797 shares of Class A Common Stock in a private placement at a price of $15.50 per share to selected institutional investors. The Private Placement closed on February 11, 2015 and resulted in approximately $231 million of gross proceeds and approximately $224 million of net proceeds (after deducting placement agent commissions and the Company’s estimated expenses. The Company used the net proceeds from the private placement to repay borrowings under its Revolving Credit Agreement and for general corporate purposes. |
Supplemental_Disclosure_of_Oil
Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Extractive Industries [Abstract] | ||||||||||||||||
Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) | SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited) | |||||||||||||||
The Company’s oil and natural gas reserves are attributable solely to properties within the United States. | ||||||||||||||||
Capitalized Costs | ||||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Oil and natural gas properties: | (in thousands) | |||||||||||||||
Proved properties | $ | 1,248,376 | $ | 546,072 | ||||||||||||
Unproved properties | 624,240 | 68,243 | ||||||||||||||
Total oil and natural gas properties | 1,872,616 | 614,315 | ||||||||||||||
Less accumulated depreciation, depletion and amortization | (128,044 | ) | (34,957 | ) | ||||||||||||
Net oil and natural gas properties capitalized | $ | 1,744,572 | $ | 579,358 | ||||||||||||
Costs Incurred for Oil and Natural Gas Producing Activities | ||||||||||||||||
Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Acquisition costs: | (in thousands) | |||||||||||||||
Proved properties | $ | 233,899 | $ | 142,695 | $ | 17,932 | ||||||||||
Unproved properties | 528,301 | 65,686 | 14,022 | |||||||||||||
Development costs | 488,673 | 268,400 | 71,945 | |||||||||||||
Total | $ | 1,250,873 | $ | 476,781 | $ | 103,899 | ||||||||||
Reserve Quantity Information | ||||||||||||||||
The following information represents estimates of the Company’s proved reserves as of December 31, 2014, 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, 2014 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and NGLs, and a Henry Hub spot natural gas price per Mcf for natural gas, as set forth in the following table: | ||||||||||||||||
Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Oil (per Bbl) | $ | 85.99 | $ | 92.53 | $ | 89.71 | ||||||||||
Natural gas liquids (per Bbl) | $ | 35.27 | $ | 36.2 | $ | 35.02 | ||||||||||
Natural gas (per Mcf) | $ | 4.28 | $ | 3.46 | $ | 2.48 | ||||||||||
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, particularly as it develops its significant acreage in the Permian Basin of West Texas. 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 all located in the United States, primarily in the Permian Basin of West Texas. All of the estimates of the proved reserves at December 31, 2012 were estimated by the Company’s in-house petroleum engineers, taking into consideration the information and assumptions contained in the December 31, 2013 report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. 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 provides a roll forward of the total proved reserves for the years ended December 31, 2014, 2013, and 2012, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: | ||||||||||||||||
Year Ended December 31, 2014 | ||||||||||||||||
Crude Oil | Liquids | Natural Gas | ||||||||||||||
(Bbls) | (Bbls) | (Mcf) | Boe | |||||||||||||
(in thousands) | ||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 29,507 | 12,357 | 77,818 | 54,834 | ||||||||||||
Extensions and discoveries | 18,776 | 8,157 | 41,348 | 33,824 | ||||||||||||
Revisions of previous estimates | (7,832 | ) | (528 | ) | (6,714 | ) | (9,480 | ) | ||||||||
Purchases of reserves in place | 10,006 | 3,906 | 18,244 | 16,953 | ||||||||||||
Divestures of reserves in place | — | — | — | — | ||||||||||||
Production | (2,840 | ) | (1,225 | ) | (7,051 | ) | (5,240 | ) | ||||||||
End of the year | 47,617 | 22,667 | 123,645 | 90,891 | ||||||||||||
Proved Developed Reserves: | ||||||||||||||||
Beginning of the year | 13,560 | 4,762 | 31,301 | 23,539 | ||||||||||||
End of the year | 23,547 | 11,491 | 65,484 | 45,952 | ||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 15,947 | 7,595 | 46,517 | 31,295 | ||||||||||||
End of the year | 24,070 | 11,175 | 58,161 | 44,939 | ||||||||||||
Year Ended December 31, 2013 | ||||||||||||||||
Crude Oil | Liquids | Natural Gas | ||||||||||||||
(Bbls) | (Bbls) | (Mcf) | Boe | |||||||||||||
(in thousands) | ||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 12,987 | 4,732 | 30,214 | 22,755 | ||||||||||||
Extensions and discoveries | 10,378 | 4,840 | 29,489 | 20,132 | ||||||||||||
Revisions of previous estimates | (2,029 | ) | (796 | ) | (1,813 | ) | (3,127 | ) | ||||||||
Purchases of reserves in place | 9,223 | 3,695 | 23,937 | 16,908 | ||||||||||||
Divestures of reserves in place | (3 | ) | (1 | ) | (7 | ) | (5 | ) | ||||||||
Production | (1,049 | ) | (113 | ) | (4,002 | ) | (1,829 | ) | ||||||||
End of the year | 29,507 | 12,357 | 77,818 | 54,834 | ||||||||||||
Proved Developed Reserves: | ||||||||||||||||
Beginning of the year | 5,834 | 1,906 | 12,186 | 9,771 | ||||||||||||
End of the year | 13,560 | 4,762 | 31,301 | 23,539 | ||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 7,153 | 2,826 | 18,028 | 12,984 | ||||||||||||
End of the year | 15,947 | 7,595 | 46,517 | 31,295 | ||||||||||||
Year Ended December 31, 2012 | ||||||||||||||||
Crude Oil | Liquids | Natural Gas | ||||||||||||||
(Bbls) | (Bbls) | (Mcf) | Boe | |||||||||||||
(in thousands) | ||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 8,519 | 3,127 | 20,689 | 15,094 | ||||||||||||
Extensions and discoveries | 4,047 | 1,369 | 8,898 | 6,899 | ||||||||||||
Revisions of previous estimates | (39 | ) | (56 | ) | 274 | (49 | ) | |||||||||
Purchases of reserves in place | 816 | 294 | 1,833 | 1,416 | ||||||||||||
Production | (356 | ) | (2 | ) | (1,480 | ) | (605 | ) | ||||||||
End of the year | 12,987 | 4,732 | 30,214 | 22,755 | ||||||||||||
Proved Developed Reserves: | ||||||||||||||||
Beginning of the year | 2,070 | 623 | 4,230 | 3,398 | ||||||||||||
End of the year | 5,834 | 1,906 | 12,186 | 9,771 | ||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 6,449 | 2,504 | 16,459 | 11,696 | ||||||||||||
End of the year | 7,153 | 2,826 | 18,028 | 12,984 | ||||||||||||
The tables above include changes in estimated quantities of oil and natural gas reserves shown in Bbl equivalents (“Boe”) at a rate of six Mcf per one Bbls. | ||||||||||||||||
Extensions and discoveries of 33,824 MBoe, 20,132 MBoe and 6,899 MBoe during the years ended December 31, 2014, 2013 and 2012, result primarily from the drilling of new wells during each year and from new proved undeveloped locations added during each year. | ||||||||||||||||
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, 2014, 2013, and 2012 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, NGLs, and natural gas reserves is as follows: | ||||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Future cash inflows | $ | 5,423,551 | $ | 3,446,766 | $ | 1,405,580 | ||||||||||
Future development costs | (642,746 | ) | (515,247 | ) | (186,996 | ) | ||||||||||
Future production costs | (1,640,422 | ) | (1,097,734 | ) | (368,099 | ) | ||||||||||
Future income tax expenses | (903,354 | ) | (24,127 | ) | (9,839 | ) | ||||||||||
Future net cash flows | 2,237,029 | 1,809,658 | 840,646 | |||||||||||||
10% discount to reflect timing of cash flows | (1,281,400 | ) | (1,088,878 | ) | (544,598 | ) | ||||||||||
Standardized measure of discounted future net cash flows | $ | 955,629 | $ | 720,780 | $ | 296,048 | ||||||||||
-1 | Future net cash flows do not include the effects of U.S. federal income taxes on future results because the Company was a limited liability company not subject to entity-level federal income taxation as of December 31, 2013, and 2012. Accordingly, no provision for federal corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. However, the Company’s operations located in Texas are subject to an entity-level tax, the Texas Margin Tax, at a statutory rate of up to 1.0% of income that is apportioned to Texas. Following the Corporate Reorganization, the Company will be a subchapter C corporation subject to U.S. federal and state income taxes. If the Company had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2013 and 2012 would have been $562.5 million and $289.5 million, respectively. The unaudited standardized measure at December 31, 2013, 2012 would have been $497.7 million and $193.6 million, respectively. | |||||||||||||||
In the foregoing determination of future cash inflows, sales prices used for oil, NGLs, and natural gas for December 31, 2014, 2013, and 2012, 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, NGLs, and natural gas reserves are as follows: | ||||||||||||||||
Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Standardized measure of discounted future net cash flows at the | $ | 720,780 | $ | 296,048 | $ | 181,714 | ||||||||||
beginning of the year | ||||||||||||||||
Sales of oil and natural gas, net of production costs | (244,745 | ) | (97,365 | ) | (30,621 | ) | ||||||||||
Purchase of minerals in place | 279,725 | 227,937 | 20,222 | |||||||||||||
Divestiture of minerals in place | — | (122 | ) | — | ||||||||||||
Extensions and discoveries, net of future development costs | 537,241 | 204,135 | 82,517 | |||||||||||||
Previously estimated development costs incurred during the period | 96,881 | 57,158 | 36,423 | |||||||||||||
Net changes in prices and production costs | (74,080 | ) | 11,463 | (21,592 | ) | |||||||||||
Changes in estimated future development costs | (9,517 | ) | 2,793 | 1,627 | ||||||||||||
Revisions of previous quantity estimates | (126,395 | ) | (41,242 | ) | (625 | ) | ||||||||||
Accretion of discount | 73,107 | 30,010 | 18,443 | |||||||||||||
Net change in income taxes | (348,501 | ) | (6,240 | ) | (1,336 | ) | ||||||||||
Net changes in timing of production and other | 51,133 | 36,205 | 9,276 | |||||||||||||
Standardized measure of discounted future net cash flows at the | $ | 955,629 | $ | 720,780 | $ | 296,048 | ||||||||||
end of the year | ||||||||||||||||
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Use of Estimates | Use of Estimates | |||||||||||
These consolidated and combined financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the SEC and (2) 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. Our management believes the major estimates and assumptions impacting our consolidated and combined 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 of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells; | |||||||||||
— | 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 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 | |||||||||||
Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. | ||||||||||||
Accounts Receivable | Accounts Receivable | |||||||||||
Accounts receivable consist of receivables from joint interest owners on properties the Company operates and crude oil, NGLs, and natural gas 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, 2014 or December 31, 2013. | ||||||||||||
For the years ended December 31, 2014, 2013 and 2012, each of the following purchasers accounted for more than 10% of our revenue: | ||||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Atlas Pipeline Mid-Continent WestTex, LLC | 20% | 16% | 14% | |||||||||
Plains Marketing, L.P. | 15% | 22% | 16% | |||||||||
BML, Inc. | 14% | 2% | —% | |||||||||
Permian Transport & Trading | 11% | 25% | 20% | |||||||||
Enterprise Crude Oil, LLC | 10% | 20% | 26% | |||||||||
Shell Trading (US) Company | 4% | 7% | 17% | |||||||||
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. | ||||||||||||
Material and Supplies | Material and Supplies | |||||||||||
Materials and supplies are stated at the lower of cost or market and consists of oil and gas drilling or repair items such as 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 accounts under joint operating agreements to which the Company is a party. As of December 31, 2014, the Company estimated that all of its tubular goods and equipment will be utilized within one year. | ||||||||||||
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 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. At December 31, 2014, 2013 and 2012, the Company had excluded $624.2 million, $68.2 million and $14.0 million, respectively, of capitalized costs from depletion. Depreciation and depletion expense on capitalized oil and gas property was $92.8 million, $27.1 million and $6.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Company had no exploratory wells in progress at December 31, 2014, 2013 or 2012. | ||||||||||||
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. During the years ended December 31, 2014, 2013, and 2012, the Company capitalized interest of $2.7 million, $3.4 million and $1.0 million, respectively. | ||||||||||||
On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization 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 and combined 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 12-month average price 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 reservoir 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, future gross revenues, 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 oil and natural gas properties. | ||||||||||||
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: | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Asset retirement obligations, January 1 | $ | 8,277 | $ | 1,858 | ||||||||
Additional liabilities incurred | 6,604 | 3,915 | ||||||||||
Liabilities assumed | — | 2,420 | ||||||||||
Disposition of wells | (80 | ) | (45 | ) | ||||||||
Accretion expense | 512 | 181 | ||||||||||
Liabilities settled upon plugging and abandoning wells | (7 | ) | (3 | ) | ||||||||
Revision of estimates | 901 | (49 | ) | |||||||||
Asset retirement obligations, December 31 | $ | 16,207 | $ | 8,277 | ||||||||
Allocation of Purchase Price in Business Combinations | Allocation of Purchase Price in Business Combinations | |||||||||||
As part of our business strategy, we periodically pursue 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. Our most significant estimates in our 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 Long-Lived Assets | Impairment of Long-Lived Assets | |||||||||||
The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties by reservoir. 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 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 and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. The Company recognized no impairment expense on proved oil and natural gas properties during the years ended December 31, 2014, 2013, or 2012. | ||||||||||||
Exploration Costs | Exploration costs | |||||||||||
Exploration 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 twelve-month period after drilling is complete. | ||||||||||||
The Company recorded $2.4 million of geological and geophysical costs during the year ended December 31, 2014 and no such expenses for the years ended December 31, 2013 and 2012. | ||||||||||||
Unproved oil and natural gas properties are each periodically assessed 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 Company recorded $0.7 million of impairment charges related to unproved oil and natural gas properties during the year ended December 31, 2014 and no impairment charges for the years ended December 31, 2013, or 2012. All of these expenses are included in “exploration costs” on the Consolidated and Combined Statement of Operations. | ||||||||||||
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 and combined 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 to fifteen years. Construction in process includes costs related to the construction of the new office space. All construction in process is expected to be completed during 2015 and will be depreciated using the straight-line-method once construction is complete and the assets are placed in use. Depreciation expense on other property and equipment was $1.5 million, $1.1 million and $0.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Buildings | $ | 2,660 | $ | 2,117 | ||||||||
Computers, software, and equipment | 4,011 | 325 | ||||||||||
Airplane | 4,533 | 3,729 | ||||||||||
Vehicles | 2,611 | 102 | ||||||||||
Furniture and fixtures | 1,734 | 676 | ||||||||||
Land | 1,189 | 1,299 | ||||||||||
Leasehold improvements | 439 | 545 | ||||||||||
Machinery and equipment | 188 | 97 | ||||||||||
Construction in process | 1,812 | — | ||||||||||
Property and equipment | 19,177 | 8,890 | ||||||||||
Accumulated depreciation | (2,887 | ) | (1,365 | ) | ||||||||
Property and equipment, net | $ | 16,290 | $ | 7,525 | ||||||||
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 and combined 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, 2014, 2013, or 2012. | ||||||||||||
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 and Combined 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 and Combined Statements of Operations in the period of change. Gains and losses from 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 measurements are obtained using unadjusted quoted prices in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities as of the reporting date. | |||||||||||
— | Level 2 measurements use as inputs market prices which are either directly or indirectly observable as of the reporting date for similar commodity derivative contracts. The Company valued its level 2 assets and liabilities using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, time value, volatility factors, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. | |||||||||||
— | Level 3 measurements are based on process or valuation models that use inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little of no market activity). These inputs generally reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. | |||||||||||
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, NGLs, and natural gas 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, 2013 and 2012, 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 substantially all employees at their date of hire. The plan allow 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 year ended December 31, 2014, 2013, and 2012, the Company made contributions to the plan of $0.8 million, $0.2 million, and $0.1 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 carry forwards. 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 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. The Company believes it is more likely than not that certain net operating losses can be carried forward and utilized. | ||||||||||||
Parsley LLC, the Company’s accounting predecessor, is a limited liability company that is not subject to U.S. federal income tax. | ||||||||||||
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 | |||||||||||
The Company operates in only one industry segment: the oil and natural gas exploration and production industry in the United States. All revenues are derived from customers located in the United States. | ||||||||||||
Reclassifications | Reclassifications | |||||||||||
Certain reclassifications have been made to prior period amounts to conform to the current presentation | ||||||||||||
Recent Accounting Pronouncements | Recent Accounting Pronouncements | |||||||||||
In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period. This ASU provides more explicit guidance for treating share-based payment awards that require a specific performance target that affects vesting and that could be achieved after the requisite service period as a performance condition. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2015. The Company does not expect the adoption of this guidance to have a material impact on the consolidated and combined financial statements. | ||||||||||||
On May 28, 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard will be effective for the Company on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated and combined financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Summary of Revenue Percentage Accounted by Purchasers | For the years ended December 31, 2014, 2013 and 2012, each of the following purchasers accounted for more than 10% of our revenue: | |||||||||||
Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Atlas Pipeline Mid-Continent WestTex, LLC | 20% | 16% | 14% | |||||||||
Plains Marketing, L.P. | 15% | 22% | 16% | |||||||||
BML, Inc. | 14% | 2% | —% | |||||||||
Permian Transport & Trading | 11% | 25% | 20% | |||||||||
Enterprise Crude Oil, LLC | 10% | 20% | 26% | |||||||||
Shell Trading (US) Company | 4% | 7% | 17% | |||||||||
Summary of Changes in Asset Retirement Obligations | The following table summarizes the changes in the Company’s asset retirement obligation for the periods indicated: | |||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Asset retirement obligations, January 1 | $ | 8,277 | $ | 1,858 | ||||||||
Additional liabilities incurred | 6,604 | 3,915 | ||||||||||
Liabilities assumed | — | 2,420 | ||||||||||
Disposition of wells | (80 | ) | (45 | ) | ||||||||
Accretion expense | 512 | 181 | ||||||||||
Liabilities settled upon plugging and abandoning wells | (7 | ) | (3 | ) | ||||||||
Revision of estimates | 901 | (49 | ) | |||||||||
Asset retirement obligations, December 31 | $ | 16,207 | $ | 8,277 | ||||||||
Other Property and Equipment, net | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Buildings | $ | 2,660 | $ | 2,117 | ||||||||
Computers, software, and equipment | 4,011 | 325 | ||||||||||
Airplane | 4,533 | 3,729 | ||||||||||
Vehicles | 2,611 | 102 | ||||||||||
Furniture and fixtures | 1,734 | 676 | ||||||||||
Land | 1,189 | 1,299 | ||||||||||
Leasehold improvements | 439 | 545 | ||||||||||
Machinery and equipment | 188 | 97 | ||||||||||
Construction in process | 1,812 | — | ||||||||||
Property and equipment | 19,177 | 8,890 | ||||||||||
Accumulated depreciation | (2,887 | ) | (1,365 | ) | ||||||||
Property and equipment, net | $ | 16,290 | $ | 7,525 | ||||||||
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||||||||||||||||
Summary of Open Position for the Commodity Derivative Instruments | The following table summarizes the open positions for the commodity derivative instruments held by the Company at December 31, 2014: | |||||||||||||||
Notional | Weighted Average | |||||||||||||||
Crude Options | (MBbl) | Strike Price | ||||||||||||||
Purchased | ||||||||||||||||
Puts | 9,680 | $ | 67.91 | |||||||||||||
Calls | — | $ | — | |||||||||||||
Sold | ||||||||||||||||
Puts | (9,680 | ) | $ | 50.86 | ||||||||||||
Calls | (2,405 | ) | $ | 114.69 | ||||||||||||
Notional | Weighted Average | |||||||||||||||
Natural Gas | (MMBtu) | Strike Price | ||||||||||||||
Purchased | ||||||||||||||||
Puts | 3,300 | $ | 4.5 | |||||||||||||
Calls | — | $ | — | |||||||||||||
Sold | ||||||||||||||||
Puts | (3,300 | ) | $ | 3.75 | ||||||||||||
Calls | (3,300 | ) | $ | 5.25 | ||||||||||||
Summary of Gross Fair Values of the Commodity Derivative Instruments | The following table summarizes the gross fair values of the Company’s commodity derivative instruments as of the reporting dates indicated (in thousands): | |||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Short-term derivative instruments | $ | 80,911 | $ | 6,999 | ||||||||||||
Long-term derivative instruments | 70,805 | 13,850 | ||||||||||||||
Total derivative instruments - asset | 151,716 | 20,849 | ||||||||||||||
Short-term derivative instruments | (29,326 | ) | (4,435 | ) | ||||||||||||
Long-term derivative instruments | (31,275 | ) | (2,208 | ) | ||||||||||||
Total derivative instruments - liability | (60,601 | ) | (6,643 | ) | ||||||||||||
Net commodity derivative asset | $ | 91,115 | $ | 14,206 | ||||||||||||
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 cash collateral on deposit with the brokers as of the reporting dates indicated (in thousands): | |||||||||||||||
Gross Amount | Cash | |||||||||||||||
Presented on | Netting | Collateral | Net | |||||||||||||
Balance Sheet | Adjustments | Posted (Received) | Exposure | |||||||||||||
31-Dec-14 | ||||||||||||||||
Derivative assets with right of offset or | $ | 151,716 | $ | (60,601 | ) | $ | — | $ | 91,115 | |||||||
master netting agreements | ||||||||||||||||
Derivative liabilities with right of offset or | (60,601 | ) | 60,601 | — | — | |||||||||||
master netting agreements | ||||||||||||||||
31-Dec-13 | ||||||||||||||||
Derivative assets with right of offset or | $ | 20,849 | $ | (6,643 | ) | $ | 524 | $ | 14,730 | |||||||
master netting agreements | ||||||||||||||||
Derivative liabilities with right of offset or | (6,643 | ) | 6,643 | — | — | |||||||||||
master netting agreements | ||||||||||||||||
Oil_and_Natural_Gas_Properties1
Oil and Natural Gas Properties (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | ||||||||
Oil and Natural Gas Properties | Oil and natural gas properties includes the following (in thousands): | |||||||
31-Dec-14 | 31-Dec-13 | |||||||
Oil and natural gas properties: | ||||||||
Subject to depletion | $ | 1,248,376 | $ | 546,072 | ||||
Not subject to depletion-acquisition costs | ||||||||
Incurred in 2014 | 562,046 | — | ||||||
Incurred in 2013 | 62,194 | 65,666 | ||||||
Incurred in 2012 | — | 2,577 | ||||||
Total not subject to depletion | 624,240 | 68,243 | ||||||
Gross oil and natural gas properties | 1,872,616 | 614,315 | ||||||
Less accumulated depreciation and depletion | (128,044 | ) | (34,957 | ) | ||||
Oil and natural gas properties, net | 1,744,572 | 579,358 | ||||||
Other property and equipment | 19,177 | 8,890 | ||||||
Less accumulated depreciation | (2,887 | ) | (1,365 | ) | ||||
Other property and equipment, net | 16,290 | 7,525 | ||||||
Property and equipment, net | $ | 1,760,862 | $ | 586,883 | ||||
Acquisitions_of_Oil_and_Gas_Pr1
Acquisitions of Oil and Gas Properties (Tables) | 12 Months Ended | ||||||
Dec. 31, 2014 | |||||||
Merit Acquisition | |||||||
Summary of Purchase Price and Values of Assets Acquired and Liabilities Assumed | The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | ||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 54,440 | |||||
Unproved oil and gas properties | 26,358 | ||||||
Total fair value of oil and gas properties acquired | 80,798 | ||||||
Asset retirement obligation | (792 | ) | |||||
Fair value of net assets acquired | $ | 80,006 | |||||
Summary of Operating Revenues and Net Earnings | The following table presents operating revenues and net earnings included in the Company’s Consolidated and Combined Statements of Operations for the year ended December 31, 2014 as a result of the Merit Acquisition described above. The revenues and operating expenses attributable to the Merit Acquisition during the year ended December 31, 2013 were not material. | ||||||
Year Ended | |||||||
31-Dec-14 | |||||||
(in thousands) | |||||||
Total operating revenues | $ | 39,324 | |||||
Total operating expenses | 7,001 | ||||||
Operating income | $ | 32,323 | |||||
Pacer Acquisition | |||||||
Summary of Purchase Price and Values of Assets Acquired and Liabilities Assumed | The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | ||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 56,870 | |||||
Unproved oil and gas properties | 108,583 | ||||||
Total fair value of oil and gas properties acquired | 165,453 | ||||||
Asset retirement obligation | (172 | ) | |||||
Fair value of net assets acquired | $ | 165,281 | |||||
Summary of Operating Revenues and Net Earnings | The following table presents operating revenues and net earnings included in the Company’s Consolidated and Combined Statements of Operations for the year ended December 31, 2014 as a result of the Pacer Acquisition described above. There were no earnings included in the Consolidated and Combined Statements of Operations for the year ended December 31, 2013. | ||||||
Year Ended | |||||||
31-Dec-14 | |||||||
(in thousands) | |||||||
Total operating revenues | $ | 19,401 | |||||
Total operating expenses | 3,111 | ||||||
Operating income | $ | 16,290 | |||||
O G X Acquisition | |||||||
Summary of Purchase Price and Values of Assets Acquired and Liabilities Assumed | The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | ||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 10,747 | |||||
Unproved oil and gas properties | 116,919 | ||||||
Total fair value of oil and gas properties acquired | 127,666 | ||||||
Asset retirement obligation | (38 | ) | |||||
Fair value of net assets acquired | 127,628 | ||||||
Cimarex Acquisition | |||||||
Summary of Purchase Price and Values of Assets Acquired and Liabilities Assumed | The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | ||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 111,003 | |||||
Unproved oil and gas properties | 128,756 | ||||||
Total fair value of oil and gas properties acquired | 239,759 | ||||||
Asset retirement obligation | (219 | ) | |||||
Fair value of net assets acquired | 239,540 | ||||||
Material Acquisitions | |||||||
Schedule of Business Acquisition Pro Forma | The following unaudited pro forma consolidated financial information has been prepared as if the Material Acquisitions occurred on January 1, 2013 for the years ending December 31, (in thousands, except per share data). | ||||||
Pro Forma | |||||||
2014 | 2013 | ||||||
Revenue | |||||||
As reported | $ | 301,757 | $ | 121,018 | |||
Pro forma | $ | 307,999 | $ | 143,443 | |||
Net Income | |||||||
As reported | $ | 23,429 | $ | 27,510 | |||
Pro forma | $ | 24,894 | $ | 29,452 | |||
Basic net income per share | |||||||
As reported | $ | 0.42 | $ | 0.32 | |||
Pro forma | $ | 0.45 | $ | 0.34 | |||
Diluted net income per share | |||||||
As reported | $ | 0.42 | $ | 0.23 | |||
Pro forma | $ | 0.45 | $ | 0.25 | |||
TEXAS | |||||||
Summary of Purchase Price and Values of Assets Acquired and Liabilities Assumed | In October 2013, the Company acquired oil and gas properties including 5,818 gross (5,330 net) acres primarily in Upton and Reagan Counties, Texas. The Company’s total consideration paid was $18.0 million. The revenues and operating expenses attributable to the acquisition during the years ended December 31, 2014 and 2013 were not material. The following table summarizes the purchase price and the value of assets acquired and liabilities assumed (in thousands): | ||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 14,734 | |||||
Unproved oil and gas properties | 4,729 | ||||||
Total fair value of oil and gas properties acquired | 19,463 | ||||||
Asset retirement obligation | (1,462 | ) | |||||
Fair value of net assets acquired | $ | 18,001 | |||||
In December 2013, the Company acquired oil and gas properties including 3,250 gross (2,595 net) acres in Upton and Reagan Counties, Texas. The Company’s total consideration paid was $32.3 million. The revenues and operating expenses attributable to the acquisition during the years ended December 31, 2014 and 2013 were not material. The following table summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands): | |||||||
Consideration given | |||||||
Allocation of purchase price | |||||||
Proved oil and gas properties | $ | 24,365 | |||||
Unproved oil and gas properties | 8,062 | ||||||
Total fair value of oil and gas properties acquired | 32,427 | ||||||
Asset retirement obligation | (167 | ) | |||||
Fair value of net assets acquired | $ | 32,260 | |||||
Debt_Tables
Debt (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Debt Disclosure [Abstract] | ||||||||||||
Schedule of Debt | The Company’s debt consists of the following (in thousands): | |||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Revolving credit agreement | $ | 120,000 | $ | 234,750 | ||||||||
Senior unsecured notes | 550,000 | — | ||||||||||
Capital leases | 2,069 | — | ||||||||||
Second lien term loan | — | 192,854 | ||||||||||
Aircraft term loan | — | 2,593 | ||||||||||
Total debt | 672,069 | 430,197 | ||||||||||
Premium on senior unsecured notes | 5,426 | — | ||||||||||
Less: current portion | (650 | ) | (227 | ) | ||||||||
Total long-term debt | $ | 676,845 | $ | 429,970 | ||||||||
Schedule of Principal Maturities of Long-term Debt | Principal maturities of long-term debt outstanding, excluding the premium on the Notes, at December 31, 2014 are as follows (in thousands): | |||||||||||
2015 | $ | 650 | ||||||||||
2016 | 688 | |||||||||||
2017 | 705 | |||||||||||
2018 | 120,026 | |||||||||||
2019 | — | |||||||||||
Thereafter | 550,000 | |||||||||||
Total | $ | 672,069 | ||||||||||
Schedule of Interest Expense | The following amounts have been incurred and charged to interest expense for the year ended December 31, 2014, 2013, and 2012 (in thousands): | |||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Cash payments for interest | $ | 26,235 | $ | 13,536 | $ | 4,661 | ||||||
Change in interest accrual | 13,390 | — | — | |||||||||
Payment-in-kind interest | 234 | 2,597 | 1,845 | |||||||||
Amortization of deferred loan origination costs | 1,941 | 405 | 80 | |||||||||
Amortization of original issue discount | — | — | 158 | |||||||||
Write-off of deferred loan origination costs | 386 | 820 | 615 | |||||||||
Amortization of bond premium | (574 | ) | — | — | ||||||||
Interest income | (316 | ) | (235 | ) | (75 | ) | ||||||
Interest costs incurred | 41,296 | 17,123 | 7,284 | |||||||||
Less: capitalized interest | (2,689 | ) | (3,409 | ) | (999 | ) | ||||||
Total interest expense | $ | 38,607 | $ | 13,714 | $ | 6,285 | ||||||
Equity_Tables
Equity (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Equity [Abstract] | ||||||||
Allocation of Net Income to Common Stockholders and EPS Computations | The following table reflects the allocation of net income to common stockholders and EPS computations for the periods indicated based on a weighted average number of common stock outstanding for the period: | |||||||
31-Dec-14 | ||||||||
Basic EPS (in thousands, except per share data) | ||||||||
Numerator: | ||||||||
Basic net income attributable to Parsley Energy Inc. | $ | 23,429 | ||||||
Stockholders | ||||||||
Denominator: | ||||||||
Basic weighted average shares outstanding | 55,136 | |||||||
Basic EPS attributable to Parsley Energy Inc. Stockholders | $ | 0.42 | ||||||
Diluted EPS | ||||||||
Numerator: | ||||||||
Net income attributable to Parsley Energy Inc. Stockholders | 23,429 | |||||||
Effect of conversion of the shares of Company's Class B | — | |||||||
Common stock to shares of the Company's Class A | ||||||||
common stock | ||||||||
Diluted net income attributable to Parsley Energy Inc. | $ | 23,429 | ||||||
Stockholders | ||||||||
Denominator: | ||||||||
Basic weighted average shares outstanding | 55,136 | |||||||
Effect of dilutive securities: | ||||||||
Class B Common Stock | — | |||||||
Restricted Stock and Restricted Stock Units | 103 | |||||||
Diluted weighted average shares outstanding | 55,239 | |||||||
Diluted EPS attributable to Parsley Energy Inc. | $ | 0.42 | ||||||
Stockholders | ||||||||
Schedule of Restricted Stock Activity And Restricted Stock Units | The following table summarized the Company’s restricted stock and restricted stock unit award activity for the year ended December 31, 2014: | |||||||
Number of Shares | Weighted - Average Grant Date | |||||||
(in thousands) | Fair Value | |||||||
Outstanding at January 1, 2014 | — | $ | — | |||||
Restricted Stock Granted | 770 | $ | 18.54 | |||||
Restricted Stock Units Granted | 24 | $ | 18.5 | |||||
Vested | — | $ | — | |||||
Forfeited | (37 | ) | $ | 18.5 | ||||
Outstanding at December 31, 2014 | 757 | $ | 18.54 | |||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2014 | ||||||||||
Income Tax Disclosure [Abstract] | ||||||||||
Components of Income Tax Provision | The components of the income tax provision were as follows for the periods indicated (in thousands): | |||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Federal: | ||||||||||
Current | $ | — | $ | — | $ | — | ||||
Deferred | 31,968 | — | — | |||||||
Total federal | 31,968 | — | — | |||||||
State, net of federal benefit: | ||||||||||
Deferred | 4,500 | 1,906 | 554 | |||||||
Total state | 4,500 | 1,906 | 554 | |||||||
Income tax provision | $ | 36,468 | $ | 1,906 | $ | 554 | ||||
Schedule of Reconciliation of Income Tax Provision with Income Tax Expense at Federal Statutory Rate | The following table reconciles the income tax provision with income tax expense at the federal statutory rate for the periods indicated (in thousands): | |||||||||
Year Ended December 31, | ||||||||||
2014 | 2013 | 2012 | ||||||||
Income (loss) before income taxes | $ | 93,190 | $ | 29,416 | $ | 13,453 | ||||
Plus: net loss prior to corporate reorganization | 37,378 | — | — | |||||||
Less: net income attributable to noncontrolling | (33,293 | ) | — | — | ||||||
interest | ||||||||||
Income (loss) before income taxes and noncontrolling | 97,275 | 29,416 | 13,453 | |||||||
interest subsequent to corporate reorganization | ||||||||||
Income taxes at the federal statutory rate | 34,046 | — | — | |||||||
State income taxes, net of federal benefit | 967 | — | — | |||||||
State income taxes, prior to corporate reorganization | 1,246 | 1,906 | 554 | |||||||
Provision to return adjustment | 170 | — | — | |||||||
Permanent and other | 39 | — | — | |||||||
Income tax provision | 36,468 | 1,906 | 554 | |||||||
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, | ||||||||||
2014 | 2013 | |||||||||
Current: | ||||||||||
Liabilities: | ||||||||||
Derivative fair value gain | (12,601 | ) | — | |||||||
Total current deferred tax liability | (12,601 | ) | — | |||||||
Net current deferred tax liability | (12,601 | ) | — | |||||||
Noncurrent: | ||||||||||
Assets: | ||||||||||
Asset retirement obligations | 4,379 | — | ||||||||
Materials and supplies | 431 | — | ||||||||
Deferred stock based compensation | 644 | — | ||||||||
Net operating loss carryforward | 50,425 | — | ||||||||
Total noncurrent deferred tax assets | 55,879 | — | ||||||||
Liabilities: | ||||||||||
Book basis of oil and natural gas properties | (108,825 | ) | (2,572 | ) | ||||||
in excess of tax basis | ||||||||||
Derivative fair value gain | (8,874 | ) | — | |||||||
Earnings in investment in subsidiary | (514 | ) | — | |||||||
Total noncurrent deferred tax liabilities | (118,213 | ) | (2,572 | ) | ||||||
Net noncurrent deferred tax liability | (62,334 | ) | (2,572 | ) | ||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||
Commitments And Contingencies Disclosure [Abstract] | ||||||||||||||||||||||
Summary of 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, 2014: | |||||||||||||||||||||
Payments Due by Period | ||||||||||||||||||||||
(in thousands) | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | |||||||||||||||
Drilling commitments | 39,466 | 27,911 | 10,039 | — | — | — | 77,416 | |||||||||||||||
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, 2014 was as follows (in thousands): | |||||||||||||||||||||
For the years ended December 31, | ||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||
(in thousands) | ||||||||||||||||||||||
Office Leases | $ | 2,827 | $ | 2,831 | $ | 4,452 | $ | 4,865 | $ | 4,977 | $ | 21,005 | $ | 40,957 | ||||||||
Vehicle Operating Leases | 116 | 124 | — | — | — | — | 240 | |||||||||||||||
Office Equipment | 86 | 70 | 29 | 1 | — | — | 186 | |||||||||||||||
3,029 | 3,025 | 4,481 | 4,866 | 4,977 | 21,005 | 41,383 | ||||||||||||||||
Disclosures_about_Fair_Value_o1
Disclosures about Fair Value of Financial Instruments (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
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): | |||||||||||||||
31-Dec-14 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Commodity derivative contracts | ||||||||||||||||
Assets: | ||||||||||||||||
Short-term derivative instruments | $ | — | $ | 80,911 | $ | — | $ | 80,911 | ||||||||
Long-term derivative instruments | — | 70,805 | — | 70,805 | ||||||||||||
Total derivative instrument - asset | $ | — | $ | 151,716 | $ | — | $ | 151,716 | ||||||||
Liabilities: | ||||||||||||||||
Short-term derivative instruments | $ | — | $ | (29,326 | ) | $ | — | $ | (29,326 | ) | ||||||
Long-term derivative instruments | — | (31,275 | ) | — | (31,275 | ) | ||||||||||
Total derivative instruments - liability | — | (60,601 | ) | — | (60,601 | ) | ||||||||||
Net commodity derivative asset | $ | — | $ | 91,115 | $ | — | $ | 91,115 | ||||||||
31-Dec-13 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Commodity derivative contracts | ||||||||||||||||
Assets: | ||||||||||||||||
Short-term derivative instruments | $ | — | $ | 6,999 | $ | — | $ | 6,999 | ||||||||
Long-term derivative instruments | — | 13,850 | — | 13,850 | ||||||||||||
Total derivative instrument - asset | $ | — | $ | 20,849 | $ | — | $ | 20,849 | ||||||||
Liabilities: | ||||||||||||||||
Short-term derivative instruments | $ | — | $ | (4,435 | ) | $ | — | $ | (4,435 | ) | ||||||
Long-term derivative instruments | — | (2,208 | ) | — | (2,208 | ) | ||||||||||
Total derivative instruments - liability | — | (6,643 | ) | — | (6,643 | ) | ||||||||||
Net commodity derivative asset | $ | — | $ | 14,206 | $ | — | $ | 14,206 | ||||||||
Supplemental_Disclosure_of_Oil1
Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Extractive Industries [Abstract] | ||||||||||||||||
Schedule of Capitalized Costs | Capitalized Costs | |||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Oil and natural gas properties: | (in thousands) | |||||||||||||||
Proved properties | $ | 1,248,376 | $ | 546,072 | ||||||||||||
Unproved properties | 624,240 | 68,243 | ||||||||||||||
Total oil and natural gas properties | 1,872,616 | 614,315 | ||||||||||||||
Less accumulated depreciation, depletion and amortization | (128,044 | ) | (34,957 | ) | ||||||||||||
Net oil and natural gas properties capitalized | $ | 1,744,572 | $ | 579,358 | ||||||||||||
Schedule of Costs Incurred for Oil and Gas Producing Activities | Costs Incurred for Oil and Natural Gas Producing Activities | |||||||||||||||
Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Acquisition costs: | (in thousands) | |||||||||||||||
Proved properties | $ | 233,899 | $ | 142,695 | $ | 17,932 | ||||||||||
Unproved properties | 528,301 | 65,686 | 14,022 | |||||||||||||
Development costs | 488,673 | 268,400 | 71,945 | |||||||||||||
Total | $ | 1,250,873 | $ | 476,781 | $ | 103,899 | ||||||||||
Schedule of Reserve Quantity Information Average Sales Price | The pricing that was used for estimates of the Company’s reserves as of December 31, 2014 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and NGLs, and a Henry Hub spot natural gas price per Mcf for natural gas, as set forth in the following table: | |||||||||||||||
Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Oil (per Bbl) | $ | 85.99 | $ | 92.53 | $ | 89.71 | ||||||||||
Natural gas liquids (per Bbl) | $ | 35.27 | $ | 36.2 | $ | 35.02 | ||||||||||
Natural gas (per Mcf) | $ | 4.28 | $ | 3.46 | $ | 2.48 | ||||||||||
Schedule of Proved Developed and Proved Undeveloped Reserves | The following table provides a roll forward of the total proved reserves for the years ended December 31, 2014, 2013, and 2012, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: | |||||||||||||||
Year Ended December 31, 2014 | ||||||||||||||||
Crude Oil | Liquids | Natural Gas | ||||||||||||||
(Bbls) | (Bbls) | (Mcf) | Boe | |||||||||||||
(in thousands) | ||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 29,507 | 12,357 | 77,818 | 54,834 | ||||||||||||
Extensions and discoveries | 18,776 | 8,157 | 41,348 | 33,824 | ||||||||||||
Revisions of previous estimates | (7,832 | ) | (528 | ) | (6,714 | ) | (9,480 | ) | ||||||||
Purchases of reserves in place | 10,006 | 3,906 | 18,244 | 16,953 | ||||||||||||
Divestures of reserves in place | — | — | — | — | ||||||||||||
Production | (2,840 | ) | (1,225 | ) | (7,051 | ) | (5,240 | ) | ||||||||
End of the year | 47,617 | 22,667 | 123,645 | 90,891 | ||||||||||||
Proved Developed Reserves: | ||||||||||||||||
Beginning of the year | 13,560 | 4,762 | 31,301 | 23,539 | ||||||||||||
End of the year | 23,547 | 11,491 | 65,484 | 45,952 | ||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 15,947 | 7,595 | 46,517 | 31,295 | ||||||||||||
End of the year | 24,070 | 11,175 | 58,161 | 44,939 | ||||||||||||
Year Ended December 31, 2013 | ||||||||||||||||
Crude Oil | Liquids | Natural Gas | ||||||||||||||
(Bbls) | (Bbls) | (Mcf) | Boe | |||||||||||||
(in thousands) | ||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 12,987 | 4,732 | 30,214 | 22,755 | ||||||||||||
Extensions and discoveries | 10,378 | 4,840 | 29,489 | 20,132 | ||||||||||||
Revisions of previous estimates | (2,029 | ) | (796 | ) | (1,813 | ) | (3,127 | ) | ||||||||
Purchases of reserves in place | 9,223 | 3,695 | 23,937 | 16,908 | ||||||||||||
Divestures of reserves in place | (3 | ) | (1 | ) | (7 | ) | (5 | ) | ||||||||
Production | (1,049 | ) | (113 | ) | (4,002 | ) | (1,829 | ) | ||||||||
End of the year | 29,507 | 12,357 | 77,818 | 54,834 | ||||||||||||
Proved Developed Reserves: | ||||||||||||||||
Beginning of the year | 5,834 | 1,906 | 12,186 | 9,771 | ||||||||||||
End of the year | 13,560 | 4,762 | 31,301 | 23,539 | ||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 7,153 | 2,826 | 18,028 | 12,984 | ||||||||||||
End of the year | 15,947 | 7,595 | 46,517 | 31,295 | ||||||||||||
Year Ended December 31, 2012 | ||||||||||||||||
Crude Oil | Liquids | Natural Gas | ||||||||||||||
(Bbls) | (Bbls) | (Mcf) | Boe | |||||||||||||
(in thousands) | ||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 8,519 | 3,127 | 20,689 | 15,094 | ||||||||||||
Extensions and discoveries | 4,047 | 1,369 | 8,898 | 6,899 | ||||||||||||
Revisions of previous estimates | (39 | ) | (56 | ) | 274 | (49 | ) | |||||||||
Purchases of reserves in place | 816 | 294 | 1,833 | 1,416 | ||||||||||||
Production | (356 | ) | (2 | ) | (1,480 | ) | (605 | ) | ||||||||
End of the year | 12,987 | 4,732 | 30,214 | 22,755 | ||||||||||||
Proved Developed Reserves: | ||||||||||||||||
Beginning of the year | 2,070 | 623 | 4,230 | 3,398 | ||||||||||||
End of the year | 5,834 | 1,906 | 12,186 | 9,771 | ||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||
Beginning of the year | 6,449 | 2,504 | 16,459 | 11,696 | ||||||||||||
End of the year | 7,153 | 2,826 | 18,028 | 12,984 | ||||||||||||
Schedule of Standardized Measure of Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves is as follows: | |||||||||||||||
December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Future cash inflows | $ | 5,423,551 | $ | 3,446,766 | $ | 1,405,580 | ||||||||||
Future development costs | (642,746 | ) | (515,247 | ) | (186,996 | ) | ||||||||||
Future production costs | (1,640,422 | ) | (1,097,734 | ) | (368,099 | ) | ||||||||||
Future income tax expenses | (903,354 | ) | (24,127 | ) | (9,839 | ) | ||||||||||
Future net cash flows | 2,237,029 | 1,809,658 | 840,646 | |||||||||||||
10% discount to reflect timing of cash flows | (1,281,400 | ) | (1,088,878 | ) | (544,598 | ) | ||||||||||
Standardized measure of discounted future net cash flows | $ | 955,629 | $ | 720,780 | $ | 296,048 | ||||||||||
-1 | Future net cash flows do not include the effects of U.S. federal income taxes on future results because the Company was a limited liability company not subject to entity-level federal income taxation as of December 31, 2013, and 2012. Accordingly, no provision for federal corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. However, the Company’s operations located in Texas are subject to an entity-level tax, the Texas Margin Tax, at a statutory rate of up to 1.0% of income that is apportioned to Texas. Following the Corporate Reorganization, the Company will be a subchapter C corporation subject to U.S. federal and state income taxes. If the Company had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2013 and 2012 would have been $562.5 million and $289.5 million, respectively. The unaudited standardized measure at December 31, 2013, 2012 would have been $497.7 million and $193.6 million, respectively. | |||||||||||||||
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, NGLs, and natural gas reserves are as follows: | |||||||||||||||
Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Standardized measure of discounted future net cash flows at the | $ | 720,780 | $ | 296,048 | $ | 181,714 | ||||||||||
beginning of the year | ||||||||||||||||
Sales of oil and natural gas, net of production costs | (244,745 | ) | (97,365 | ) | (30,621 | ) | ||||||||||
Purchase of minerals in place | 279,725 | 227,937 | 20,222 | |||||||||||||
Divestiture of minerals in place | — | (122 | ) | — | ||||||||||||
Extensions and discoveries, net of future development costs | 537,241 | 204,135 | 82,517 | |||||||||||||
Previously estimated development costs incurred during the period | 96,881 | 57,158 | 36,423 | |||||||||||||
Net changes in prices and production costs | (74,080 | ) | 11,463 | (21,592 | ) | |||||||||||
Changes in estimated future development costs | (9,517 | ) | 2,793 | 1,627 | ||||||||||||
Revisions of previous quantity estimates | (126,395 | ) | (41,242 | ) | (625 | ) | ||||||||||
Accretion of discount | 73,107 | 30,010 | 18,443 | |||||||||||||
Net change in income taxes | (348,501 | ) | (6,240 | ) | (1,336 | ) | ||||||||||
Net changes in timing of production and other | 51,133 | 36,205 | 9,276 | |||||||||||||
Standardized measure of discounted future net cash flows at the | $ | 955,629 | $ | 720,780 | $ | 296,048 | ||||||||||
end of the year | ||||||||||||||||
Organization_and_Nature_of_Ope1
Organization and Nature of Operations - Additional Information (Details) (USD $) | 0 Months Ended | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | 29-May-14 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 11, 2013 |
Organization And Nature Of Operations [Line Items] | ||||
Equity method investment, ownership percentage | 42.50% | |||
Common Stock, Class A | ||||
Organization And Nature Of Operations [Line Items] | ||||
Common stock, par value | 0.01 | $0.01 | ||
Common stock, shares issued | 43,200,000 | 93,937,947 | 1,000 | |
Common Stock, Class A | Initial Public Offering | ||||
Organization And Nature Of Operations [Line Items] | ||||
Common stock sold in initial public offering net of offering costs (in shares) | 57,500,000 | |||
Stock price per share at public offering | $18.50 | |||
Gross proceeds received from public offering | $924.30 | |||
Common stock, par value | $0.01 | |||
Initial public offering period | 29-May-14 | |||
Net Proceeds after deducting underwriting discount and commission and offering expenses | $867.80 | |||
Common Stock, Class B | ||||
Organization And Nature Of Operations [Line Items] | ||||
Common stock, par value | 0.01 | $0.01 | ||
Common stock, shares issued | 32,145,296 | 0 | ||
Conversion of stock, shares issued | 93,200,000 | |||
Common stock exchange ratio | 0.01 | |||
Stockholders | Common Stock, Class A | Initial Public Offering | ||||
Organization And Nature Of Operations [Line Items] | ||||
Common stock sold in initial public offering net of offering costs (in shares) | 7,500,000 | |||
Underwriters | Common Stock, Class A | Initial Public Offering | ||||
Organization And Nature Of Operations [Line Items] | ||||
Common stock sold in initial public offering net of offering costs (in shares) | 50,000,000 | |||
PE Unit Holders | ||||
Organization And Nature Of Operations [Line Items] | ||||
Percentage of ownership interest, Noncontrolling owners | 25.70% | |||
Parsley LP | ||||
Organization And Nature Of Operations [Line Items] | ||||
Equity method investment, ownership percentage | 67.80% | |||
PEM | ||||
Organization And Nature Of Operations [Line Items] | ||||
Equity method investment, ownership percentage | 100.00% | |||
PEO | ||||
Organization And Nature Of Operations [Line Items] | ||||
Equity method investment, ownership percentage | 100.00% | |||
Sheffield | ||||
Organization And Nature Of Operations [Line Items] | ||||
Equity method investment, ownership percentage | 53.70% | |||
SPS | ||||
Organization And Nature Of Operations [Line Items] | ||||
Equity method investment, ownership percentage | 42.50% | |||
Parsley Energy LLC | ||||
Organization And Nature Of Operations [Line Items] | ||||
Percentage of ownership interest, parent | 74.30% |
Basis_of_Presentation_Addition
Basis of Presentation - Additional Information (Details) | Dec. 31, 2014 |
Accounting Policies [Abstract] | |
Equity method investment, ownership percentage | 42.50% |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Additional Information (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Segment | Well | Well | |
Well | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Allowance for doubtful accounts receivable | $0 | $0 | |
Capitalized costs excluded from depletion | 624,240,000 | 68,243,000 | 14,000,000 |
Depreciation and depletion expense on capitalized oil and gas property | 92,800,000 | 27,100,000 | 6,300,000 |
Number of exploratory wells in progress | 0 | 0 | 0 |
Interest costs capitalized | 2,689,000 | 3,409,000 | 999,000 |
Impairment expense on proved oil and natural gas properties | 0 | 0 | 0 |
Geological and geophysical cost | 2,400,000 | 0 | 0 |
Impairment charges on unproved oil and gas property | 700,000 | ||
Impairment charge | 0 | 0 | |
Depreciation expense | 1,500,000 | 1,100,000 | 100,000 |
Impairment of equity investments | 0 | 0 | 0 |
Contribution by company | $800,000 | $200,000 | $100,000 |
Number of segments | 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 |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies - Summary of Revenue Percentage Accounted by Purchasers (Details) (Customer Concentration Risk, Sales Revenue, Net) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Atlas Pipeline Mid-Continent WestTex, LLC | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 20.00% | 16.00% | 14.00% |
Plains Marketing, L.P. | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 15.00% | 22.00% | 16.00% |
BML, Inc. | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 14.00% | 2.00% | |
Permian Transport & Trading | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 11.00% | 25.00% | 20.00% |
Enterprise Crude Oil, LLC | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 10.00% | 20.00% | 26.00% |
Shell Trading (US) Company | |||
Concentration Risk [Line Items] | |||
Revenue percentage accounted by purchasers | 4.00% | 7.00% | 17.00% |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies - Summary of Changes in Asset Retirement Obligations (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation [Abstract] | |||
Asset retirement obligations, January 1 | $8,277 | $1,858 | |
Additional liabilities incurred | 6,604 | 3,915 | |
Liabilities assumed | 2,420 | ||
Disposition of wells | -80 | -45 | |
Accretion expense | 512 | 181 | 66 |
Liabilities settled upon plugging and abandoning wells | -7 | -3 | |
Revision of estimates | 901 | -49 | |
Asset retirement obligations, December 31 | $16,207 | $8,277 | $1,858 |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies -Other Property and Equipment, Net (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | $19,177 | $8,890 |
Accumulated depreciation | -2,887 | -1,365 |
Property and equipment, net | 16,290 | 7,525 |
Buildings | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | 2,660 | 2,117 |
Computers, software, and equipment | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | 4,011 | 325 |
Airplane | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | 4,533 | 3,729 |
Vehicles | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | 2,611 | 102 |
Furniture and fixtures | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | 1,734 | 676 |
Land | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | 1,189 | 1,299 |
Leasehold improvements | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | 439 | 545 |
Machinery and equipment | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | 188 | 97 |
Construction in process | ||
Property Plant And Equipment [Line Items] | ||
Property and equipment | $1,812 |
Derivative_Financial_Instrumen2
Derivative Financial Instruments - Additional Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Derivative [Line Items] | ||||
Proceeds due to decrease in strike prices of put spreads | $45,500,000 | |||
Derivative gain (loss) | 83,858,000 | -9,800,000 | -2,190,000 | |
Subject to Master Netting Agreement with Counter Party | ||||
Derivative [Line Items] | ||||
Notional (MBbl) | 6,700 | 6,700 | ||
Notional amount | $144,900,000 | $144,900,000 | ||
Purchase | Natural Gas Liquids | Put Option | ||||
Derivative [Line Items] | ||||
Notional (MBbl) | 3,300 | 3,300 | ||
Crude Oil | Purchase | Put Option | ||||
Derivative [Line Items] | ||||
Notional (MBbl) | 9,680 | 9,680 |
Derivative_Financial_Instrumen3
Derivative Financial Instruments - Summary of Open Position for the Commodity Derivative Instruments (Details) | Dec. 31, 2014 |
MMBTU | |
Put Option | Purchase | Natural Gas Liquids | |
Derivative [Line Items] | |
Notional (MBbl) | 3,300 |
Weighted Average Strike Price | 4.5 |
Put Option | Sold | Natural Gas Liquids | |
Derivative [Line Items] | |
Notional (MBbl) | -3,300 |
Weighted Average Strike Price | 3.75 |
Calls | Sold | Natural Gas Liquids | |
Derivative [Line Items] | |
Notional (MBbl) | -3,300 |
Weighted Average Strike Price | 5.25 |
Crude Oil | Put Option | Purchase | |
Derivative [Line Items] | |
Notional (MBbl) | 9,680 |
Weighted Average Strike Price | 67.91 |
Crude Oil | Put Option | Sold | |
Derivative [Line Items] | |
Notional (MBbl) | -9,680 |
Weighted Average Strike Price | 50.86 |
Crude Oil | Calls | Sold | |
Derivative [Line Items] | |
Notional (MBbl) | -2,405 |
Weighted Average Strike Price | 114.69 |
Derivative_Financial_Instrumen4
Derivative Financial Instruments - Summary of Gross Fair Values of the Commodity Derivative Instruments (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative [Line Items] | ||
Short-term derivative instruments | $80,911 | $6,999 |
Long-term derivative instruments | 70,805 | 13,850 |
Short-term derivative instruments | -29,326 | -4,435 |
Long-term derivative instruments | -31,275 | -2,208 |
Commodity Contract | ||
Derivative [Line Items] | ||
Short-term derivative instruments | 80,911 | 6,999 |
Long-term derivative instruments | 70,805 | 13,850 |
Total derivative instruments - asset | 151,716 | 20,849 |
Short-term derivative instruments | -29,326 | -4,435 |
Long-term derivative instruments | -31,275 | -2,208 |
Total derivative instruments - liability | -60,601 | -6,643 |
Net commodity derivative asset | $91,115 | $14,206 |
Derivative_Financial_Instrumen5
Derivative Financial Instruments - Schedule of Netting Offsets of Derivative Asset and Liability Positions (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Offsetting Derivative Assets [Abstract] | ||
Derivative asset, Gross Amount Presented on Balance Sheet | $151,716 | $20,849 |
Derivative asset, Netting Adjustments | -60,601 | -6,643 |
Derivative asset, Cash Collateral Posted (Received) | 524 | |
Derivative asset, Net Exposure | 91,115 | 14,730 |
Derivative liability, Gross Amount Presented on Balance Sheet | -60,601 | -6,643 |
Derivative liability, Netting Adjustments | $60,601 | $6,643 |
Oil_and_Natural_Gas_Properties2
Oil and Natural Gas Properties - Oil and Natural Gas Properties (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Oil and natural gas properties: | |||
Subject to depletion | $1,248,376 | $546,072 | |
Not subject to depletion-acquisition costs | 624,240 | 68,243 | 14,000 |
Gross oil and natural gas properties | 1,872,616 | 614,315 | |
Accumulated depreciation, depletion and amortization | -128,044 | -34,957 | |
Total oil and natural gas properties, net | 1,744,572 | 579,358 | |
Other property and equipment | 19,177 | 8,890 | |
Less accumulated depreciation | -2,887 | -1,365 | |
Property and equipment, net | 16,290 | 7,525 | |
Property and equipment, net | 1,760,862 | 586,883 | |
Incurred in 2014 | |||
Oil and natural gas properties: | |||
Not subject to depletion-acquisition costs | 562,046 | ||
Incurred in 2013 | |||
Oil and natural gas properties: | |||
Not subject to depletion-acquisition costs | 62,194 | 65,666 | |
Incurred in 2012 | |||
Oil and natural gas properties: | |||
Not subject to depletion-acquisition costs | $2,577 |
Oil_and_Natural_Gas_Properties3
Oil and Natural Gas Properties - Additional Information (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Well | Well | Well | |
Oil And Gas Exploration And Production Industries Disclosures [Abstract] | |||
Capitalized costs excluded from depletion | $624,240,000 | $68,243,000 | $14,000,000 |
Depletion expense on capitalized oil and gas property | 92,800,000 | 27,100,000 | 6,300,000 |
Number of exploratory wells in progress | 0 | 0 | 0 |
Interest costs capitalized | 2,689,000 | 3,409,000 | 999,000 |
Depreciation expense | $1,500,000 | $1,100,000 | $100,000 |
Acquisitions_of_Oil_and_Gas_Pr2
Acquisitions of Oil and Gas Properties - Additional Information (Details) (USD $) | 12 Months Ended | 1 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | ||||||
Dec. 31, 2014 | Oct. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 29, 2012 | Oct. 31, 2012 | Dec. 30, 2013 | 1-May-14 | 30-May-14 | Sep. 30, 2014 | Dec. 16, 2014 | |
acre | acre | acre | Well | acre | Well | acre | ||||||
acre | acre | |||||||||||
Business Acquisition [Line Items] | ||||||||||||
Acquisition costs | $2,527,000 | |||||||||||
Reagan County | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 18,000,000 | |||||||||||
Acres of oil and gas property, gross | 5,818 | |||||||||||
Acres of oil and gas property, net | 5,330 | |||||||||||
Upton County | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 32,300,000 | |||||||||||
Acres of oil and gas property, gross | 3,250 | 3,250 | ||||||||||
Acres of oil and gas property, net | 2,595 | 2,595 | ||||||||||
Acquisition from Unaffiliated Individuals and Entities | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 55,200,000 | 25,100,000 | 9,700,000 | |||||||||
Diamond K Production, LLC | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 8,200,000 | 8,200,000 | ||||||||||
Acquisitions from Directors and Officers | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 19,400,000 | |||||||||||
Merit Acquisition | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 80,000,000 | |||||||||||
Acres of oil and gas property, net | 637 | |||||||||||
Contributed revenue | 39,324,000 | |||||||||||
Operating income | 32,323,000 | |||||||||||
Pacer Acquisition | Midland Basin Core Area | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 165,300,000 | |||||||||||
Acres of oil and gas property, gross | 2,240 | |||||||||||
Acres of oil and gas property, net | 2,005 | |||||||||||
Date of acquisition agreement | 27-Mar-14 | |||||||||||
Number of wells, gross | 7 | |||||||||||
Number of wells, net | 6.3 | |||||||||||
O G X Acquisition | Midland Basin Core Area | Amended Option Agreement | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 127,600,000 | |||||||||||
Acres of oil and gas property, gross | 4,640 | |||||||||||
Acres of oil and gas property, net | 4,640 | |||||||||||
Cimarex Acquisition | Midland Basin Core Area | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 239,500,000 | |||||||||||
Acres of oil and gas property, gross | 4,320 | |||||||||||
Acres of oil and gas property, net | 4,228 | |||||||||||
Number of wells, gross | 9 | |||||||||||
Number of wells, net | 9 | |||||||||||
APC Acquisition | Midland Basin Core Area | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Total consideration for acquisition | 120,000,000 | |||||||||||
Acres of oil and gas property, gross | 8,643 | |||||||||||
Acres of oil and gas property, net | 7,128 | |||||||||||
Leasehold Acquisition | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Acquisition costs | 54,000,000 | 32,700,000 | ||||||||||
Material Acquisitions | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Contributed revenue | 58,700,000 | |||||||||||
Operating income | $48,600,000 |
Acquisitions_of_Oil_and_Gas_Pr3
Acquisitions of Oil and Gas Properties - Summary of Purchase Price and Values of Assets Acquired and Liabilities Assumed (Details) (USD $) | 12 Months Ended | 1 Months Ended | 0 Months Ended | ||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Oct. 31, 2013 | Dec. 30, 2013 | 1-May-14 | 30-May-14 | Sep. 30, 2014 |
Allocation of purchase price | |||||||||
Proved oil and gas properties | $233,899 | $142,695 | $17,932 | ||||||
Unproved oil and gas properties | 528,301 | 65,686 | 14,022 | ||||||
TEXAS | |||||||||
Allocation of purchase price | |||||||||
Proved oil and gas properties | 24,365 | 14,734 | |||||||
Unproved oil and gas properties | 8,062 | 4,729 | |||||||
Total fair value of oil and gas properties acquired | 32,427 | 19,463 | |||||||
Asset retirement obligation | -167 | -167 | -1,462 | ||||||
Fair value of net assets acquired | 32,260 | 18,001 | |||||||
Merit Acquisition | |||||||||
Allocation of purchase price | |||||||||
Proved oil and gas properties | 54,440 | ||||||||
Unproved oil and gas properties | 26,358 | ||||||||
Total fair value of oil and gas properties acquired | 80,798 | ||||||||
Asset retirement obligation | -792 | ||||||||
Fair value of net assets acquired | 80,006 | ||||||||
Pacer Acquisition | Midland Basin Core Area | |||||||||
Allocation of purchase price | |||||||||
Proved oil and gas properties | 56,870 | ||||||||
Unproved oil and gas properties | 108,583 | ||||||||
Total fair value of oil and gas properties acquired | 165,453 | ||||||||
Asset retirement obligation | -172 | ||||||||
Fair value of net assets acquired | 165,281 | ||||||||
O G X Acquisition | Midland Basin Core Area | Amended Option Agreement | |||||||||
Allocation of purchase price | |||||||||
Proved oil and gas properties | 10,747 | ||||||||
Unproved oil and gas properties | 116,919 | ||||||||
Total fair value of oil and gas properties acquired | 127,666 | ||||||||
Asset retirement obligation | -38 | ||||||||
Fair value of net assets acquired | 127,628 | ||||||||
Cimarex Acquisition | Midland Basin Core Area | |||||||||
Allocation of purchase price | |||||||||
Proved oil and gas properties | 111,003 | ||||||||
Unproved oil and gas properties | 128,756 | ||||||||
Total fair value of oil and gas properties acquired | 239,759 | ||||||||
Asset retirement obligation | -219 | ||||||||
Fair value of net assets acquired | $239,540 |
Acquisitions_of_Oil_and_Gas_Pr4
Acquisitions of Oil and Gas Properties - Summary of Operating Revenue and Net Earnings Included in Combined Statement of Operations (Details) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Merit Acquisition | |
Business Acquisition [Line Items] | |
Total operating revenues | $39,324 |
Total operating expenses | 7,001 |
Operating income | 32,323 |
Pacer | |
Business Acquisition [Line Items] | |
Total operating revenues | 19,401 |
Total operating expenses | 3,111 |
Operating income | $16,290 |
Acquisitions_of_Oil_and_Gas_Pr5
Acquisitions of Oil and Gas Properties - Schedule of Business Acquisition Pro Forma (Details) (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
REVENUES | |||
As reported | $301,757 | $121,018 | $37,679 |
Net Income | |||
As reported | 23,429 | 27,510 | 12,899 |
Basic net income per share | |||
As reported | $0.42 | ||
Diluted net income per share | |||
As reported | $0.42 | ||
Material Acquisitions | |||
REVENUES | |||
As reported | 301,757 | 121,018 | |
Pro forma | 307,999 | 143,443 | |
Net Income | |||
As reported | 23,429 | 27,510 | |
Pro forma | $24,894 | $29,452 | |
Basic net income per share | |||
As reported | $0.42 | $0.32 | |
Pro forma | $0.45 | $0.34 | |
Diluted net income per share | |||
As reported | $0.42 | $0.23 | |
Pro forma | $0.45 | $0.25 |
Sales_of_Oil_and_Natural_Gas_P1
Sales of Oil and Natural Gas Properties - Additional Information (Details) (USD $) | 0 Months Ended | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Aug. 31, 2014 | Aug. 31, 2013 | Nov. 30, 2012 | Apr. 30, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
acre | Well | acre | acre | ||||
Well | acre | ||||||
Gain Loss On Sale Of Oil And Gas Property [Abstract] | |||||||
Oil and natural gas properties sold | 38 | 190 | 960 | 2,652 | |||
Proceeds from sales of oil and natural gas properties | $200 | $800 | $700 | $8,600 | $172 | $750 | $9,295 |
Gain (loss) on sale of oil and natural gas properties | $2,100 | $36 | $300 | $7,500 | ($2,097) | $36 | $7,819 |
Number of non-operated wells sold | 7 | ||||||
Number of operated wells sold | 1 |
Equity_Investment_Additional_I
Equity Investment - Additional Information (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 30, 2014 | |
Members | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Equity method investment, ownership percentage | 42.50% | |||
Equity investment | $2,121,000 | $1,774,000 | ||
Increase (decrease) in equity method investment amount | 348,000 | 184,000 | 267,000 | |
SPS | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Number of nonrelated parties | 2 | |||
Decrease Equity method investment, ownership percentage | 7.50% | |||
Equity method investment, ownership percentage | 42.50% | |||
Equity investment | 2,200,000 | 1,800,000 | ||
Increase (decrease) in equity method investment amount | 1,100,000 | 700,000 | ||
Unrealized intercompany gross profit eliminated | $700,000 | $500,000 |
Debt_Schedule_of_Debt_Details
Debt - Schedule of Debt (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Apr. 02, 2013 |
In Thousands, unless otherwise specified | |||
Debt Instrument [Line Items] | |||
Revolving credit agreement | $120,000 | $234,750 | |
Senior unsecured notes | 550,000 | ||
Capital leases | 2,069 | ||
Total debt | 672,069 | 430,197 | |
Premium on senior unsecured notes | 5,426 | ||
Less: current portion | -650 | -227 | |
Long-term debt | 676,845 | 429,970 | |
Second Lien Term Loan | |||
Debt Instrument [Line Items] | |||
Term loan | 192,854 | ||
Aircraft Term Loan | |||
Debt Instrument [Line Items] | |||
Term loan | $2,593 | $2,800 |
Debt_Revolving_Credit_Agreemen
Debt - Revolving Credit Agreement (Details) (USD $) | 12 Months Ended | 0 Months Ended | ||||||||
Dec. 31, 2014 | Sep. 10, 2013 | 2-May-14 | Dec. 31, 2013 | Nov. 30, 2014 | Apr. 15, 2014 | Feb. 28, 2015 | Oct. 21, 2013 | Dec. 30, 2013 | Dec. 20, 2013 | |
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement | $120,000,000 | $234,750,000 | ||||||||
Revolving credit agreement covenants | The Revolving Credit Agreement requires the Company to maintain the following two financial ratios: a current ratio, which is the ratio of consolidated current assets (including unused availability under its revolving credit facility) to consolidated current liabilities of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and a minimum interest coverage ratio, which is the ratio of EBITDAX to interest expense, of not less than 2.5 to 1.0 as of the last day of any fiscal quarter for the four fiscal quarters ending on such date. | |||||||||
Current ratio | 1.00% | |||||||||
Interest coverage ratio | 2.50% | |||||||||
Revolving Credit Agreement | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, borrowing base | 750,000,000 | 575,000,000 | ||||||||
Revolving line of credit agreement maturity date | 10-Sep-18 | |||||||||
Revolving credit agreement, borrowing capacity description | The Revolving Credit Agreement provides a revolving credit facility with a borrowing capacity up to the lesser of (i) the borrowing base (as defined in the Revolving Credit Agreement), (ii) aggregate lender commitments, and (iii) $750.0 million. | |||||||||
Revolving credit agreement, current borrowing base | 562,000,000 | 175,000,000 | 327,500,000 | |||||||
Revolving credit agreement, commitment level | 365,000,000 | 365,000,000 | ||||||||
Letters of credit outstanding, Amount | 300,000 | |||||||||
Revolving credit agreement | 120,000,000 | |||||||||
Revolving credit agreement, remaining borrowing capacity | 244,700,000 | |||||||||
Line of credit facility interest rate description | Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBO rate (equal to the product of: (a) the LIBO rate, multiplied by (b) a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (expressed as a decimal) on such date at which the Administrative Agent is required to maintain reserves on bEurocurrency Liabilitiesb as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bankbs reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the adjusted LIBO rate (as calculated above) plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of our borrowing base utilized. | |||||||||
Revolving Credit Agreement | LIBO rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin basis rate | 1.00% | |||||||||
Revolving Credit Agreement | Federal funds | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin basis rate | 0.50% | |||||||||
Revolving Credit Agreement | Subsequent Event | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, current borrowing base | 560,800,000 | |||||||||
Revolving credit agreement, commitment level | 365,000,000 | |||||||||
Revolving Credit Agreement | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, current borrowing base | 175,000,000 | |||||||||
Revolving credit agreement, commitment fee | 0.50% | |||||||||
Revolving Credit Agreement | Maximum | LIBO rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin basis rate | 1.50% | |||||||||
Revolving Credit Agreement | Maximum | Federal funds | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin basis rate | 2.50% | |||||||||
Revolving Credit Agreement | Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, current borrowing base | 143,800,000 | |||||||||
Revolving credit agreement, commitment fee | 0.38% | |||||||||
Revolving Credit Agreement | Minimum | LIBO rate | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin basis rate | 0.50% | |||||||||
Revolving Credit Agreement | Minimum | Federal funds | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Applicable margin basis rate | 1.50% | |||||||||
Revolving Credit Agreement | Weighted Average | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, weighted average interest rate | 1.75% | |||||||||
Revolving Credit Agreement | Merit Acquisition | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, current borrowing base | 280,000,000 | |||||||||
Revolving Credit Agreement | Merit Acquisition | Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, current borrowing base | 240,000,000 | |||||||||
Revolving Credit Agreement | First Amendment | Maximum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, current borrowing base | 240,000,000 | |||||||||
Revolving Credit Agreement | First Amendment | Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, current borrowing base | 143,800,000 | |||||||||
Revolving Credit Agreement | Amended And Restated Credit Agreement | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, borrowing base | 227,500,000 | |||||||||
Amended and restated credit agreement, expiration date | 15 months | |||||||||
Revolving Credit Agreement | Third Amendment | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit agreement, borrowing base | $365,000,000 | |||||||||
Revolving Credit Agreement | Fourth Amendment | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Amended and restated credit agreement, expiration date | 18 months |
Debt_7500_Senior_Notes_due_202
Debt - 7.500% Senior Notes due 2022 (Details) (USD $) | 0 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Apr. 14, 2014 | Feb. 05, 2014 | Dec. 31, 2014 |
Debt Instrument [Line Items] | |||
Percentage of par value on issuance of senior notes | 104.00% | ||
7.500% Senior Notes due 2022 | |||
Debt Instrument [Line Items] | |||
Senior unsecured notes, issued amount | $150 | $400 | |
Senior unsecured notes, interest rate | 7.50% | ||
Senior unsecured notes, due year | 2022 | ||
Senior unsecured notes, interest payment term | Interest is payable on the Notes semi-annually in arrears on each February 15 and August 15, and commenced August 15, 2014. | ||
Net proceeds from note issuance | 152.8 | 391.4 | |
Repayment of outstanding borrowings | 198.5 | ||
Repayment of revolving credit agreement | 145 | 175.1 | |
Gross proceeds from note issuance | $156 | ||
7.500% Senior Notes due 2022 | Twelve-month period beginning February 15, 2017 | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 105.63% | ||
7.500% Senior Notes due 2022 | Twelve-month period beginning February 15, 2018 | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 103.75% | ||
7.500% Senior Notes due 2022 | Twelve-month period beginning February 15, 2019 | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 101.88% | ||
7.500% Senior Notes due 2022 | Twelve-month period beginning February 15, 2020 | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 100.00% | ||
7.500% Senior Notes due 2022 | Net Cash Proceeds of Certain Equity Offerings | |||
Debt Instrument [Line Items] | |||
Maximum percent of aggregate principal amount redeemable | 35.00% | ||
Redemption price, expressed as percentage of principal amount | 107.50% | ||
Number of days within closing date redemption can occur | 120 days | ||
Minimum required principal amount to remain outstanding subsequent to redemption | 65.00% | ||
7.500% Senior Notes due 2022 | Make-Whole Premium Option | |||
Debt Instrument [Line Items] | |||
Redemption price, expressed as percentage of principal amount | 100.00% |
Debt_Second_Lien_Agreement_Det
Debt - Second Lien Agreement (Details) (USD $) | 12 Months Ended | 0 Months Ended | 3 Months Ended | |||
Dec. 31, 2014 | Nov. 20, 2014 | Oct. 21, 2013 | Jun. 30, 2013 | Dec. 31, 2013 | Nov. 20, 2012 | |
Debt Instrument [Line Items] | ||||||
Current ratio | 1.00% | |||||
Amended Second Lien Agreement | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument maturity date | 31-Dec-16 | |||||
Amended Second Lien Agreement | Tranche A | ||||||
Debt Instrument [Line Items] | ||||||
Loans payable | 75,000,000 | |||||
Amended Second Lien Agreement | Tranche B | ||||||
Debt Instrument [Line Items] | ||||||
Loans payable | 125,000,000 | |||||
Second Lien Agreement | ||||||
Debt Instrument [Line Items] | ||||||
Prepayment penalty rate | 7.50% | |||||
Second Lien Term Loan | ||||||
Debt Instrument [Line Items] | ||||||
Gross proceeds from note issuance | 75,000,000 | |||||
Debt instrument maturity date | 31-Dec-16 | |||||
Prepayment premium rate | 7.50% | |||||
Loans payable | $192,854,000 | |||||
Debt instrument, description of variable rate basis | (i) the greater of 1.0%, and the three- month LIBO rate, plus 10.0%, paid in cash, plus (ii) 4.0% paid-in-kind by adding to the principal balance outstanding. Tranche B borrowings bore interest at the greater of 1.0%, and the three-month LIBO rate, plus 11.0%, paid in cash. | |||||
Second Lien Term Loan | Tranche A | ||||||
Debt Instrument [Line Items] | ||||||
Senior unsecured notes, interest rate | 1.00% | |||||
Debt instrument interest rate | 4.00% | |||||
Second Lien Term Loan | Tranche A | LIBO rate | ||||||
Debt Instrument [Line Items] | ||||||
Applicable margin basis rate | 10.00% | |||||
Second Lien Term Loan | Tranche B | ||||||
Debt Instrument [Line Items] | ||||||
Senior unsecured notes, interest rate | 1.00% | |||||
Second Lien Term Loan | Tranche B | LIBO rate | ||||||
Debt Instrument [Line Items] | ||||||
Applicable margin basis rate | 11.00% | |||||
Second Lien Term Loan | First Amendment | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument covenant description | (1) reduced the Consolidated Current Ratio, as at June 30, 2013, to be not less than 0.75:1.00, and as at the last day of any quarter thereafter, to be not less than 1.00:1.00; (2) provided a waiver of the Lendersb right to assert an Event of Default with respect to the Consolidated Current Ratio covenant as of March 31, 2013; and (3) extended the deadline of delivery of required financial statements from 120 days to 180 days after The Companybs year-end (each of the capitalized terms used in the foregoing clauses (1) through (4) being as defined in the Second Lien Term Agreement). | |||||
Current ratio | 1.00% | 0.75% | ||||
Second Lien Term Loan | Second Amendment | ||||||
Debt Instrument [Line Items] | ||||||
Debt instrument covenant description | (1) amended the definition of the Consolidated Current Ratio to allow for the inclusion, in the numerator, of unused borrowing capacity under the Syndicated Credit Agreement; and (2) waived the Lendersb right to assert an Event of Default with respect to the Consolidated Current Ratio covenant as of June 30, 2013 (each of the capitalized terms used in the foregoing clauses (1) through (4) being as defined in the Second Lien Agreement agreement). | |||||
Second Lien Term Loan | Minimum | ||||||
Debt Instrument [Line Items] | ||||||
Anticipated derivative hedging instrument on production | 80.00% | |||||
Second Lien Term Loan | Minimum | First Amendment | ||||||
Debt Instrument [Line Items] | ||||||
Delivery dead line of financial statements | 120 days | |||||
Second Lien Term Loan | Maximum | First Amendment | ||||||
Debt Instrument [Line Items] | ||||||
Delivery dead line of financial statements | 180 days |
Debt_Aircraft_Term_Loan_Detail
Debt - Aircraft Term Loan (Details) (Aircraft Term Loan, USD $) | Dec. 31, 2013 | Apr. 02, 2013 |
In Thousands, unless otherwise specified | ||
Aircraft Term Loan | ||
Debt Instrument [Line Items] | ||
Term loan | $2,593 | $2,800 |
Debt_Capital_Lease_Details
Debt - Capital Lease (Details) (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Debt Instrument [Line Items] | |
Capital leases | $2,263,000 |
Capital Lease Obligations | |
Debt Instrument [Line Items] | |
Annual percentage rates for capital leases, Minimum | 5.00% |
Annual percentage rates for capital leases, Maximum | 6.70% |
Monthly payments of principal and interest | $58,426 |
Debt_Schedule_of_Principal_Mat
Debt - Schedule of Principal Maturities of Long-term Debt (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Debt Disclosure [Abstract] | ||
2015 | $650 | |
2016 | 688 | |
2017 | 705 | |
2018 | 120,026 | |
Thereafter | 550,000 | |
Total debt | $672,069 | $430,197 |
Debt_Schedule_of_Interest_Expe
Debt - Schedule of Interest Expense (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Debt Disclosure [Abstract] | |||
Cash paid for interest | $26,235 | $13,536 | $4,661 |
Change in interest accrual | 13,390 | ||
Payment-in-kind interest | 234 | 2,597 | 1,845 |
Amortization of deferred loan origination costs | 1,941 | 405 | 80 |
Amortization of original issue discount | 158 | ||
Write-off of deferred loan origination costs | 386 | 820 | 615 |
Amortization of bond premium | -574 | ||
Interest income | -316 | -235 | -75 |
Interest costs incurred | 41,296 | 17,123 | 7,284 |
Less: capitalized interest | -2,689 | -3,409 | -999 |
Total interest expense | $38,607 | $13,714 | $6,285 |
Equity_Additional_Information_
Equity - Additional Information (Details) (USD $) | 0 Months Ended | 12 Months Ended | ||
29-May-14 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 11, 2013 | |
Equity [Line Items] | ||||
Preferred stock, par value | $0.01 | $0.01 | ||
Preferred stock, shares authorized | 50,000,000 | 50,000,000 | ||
Preferred stock, shares outstanding | 0 | 0 | ||
Common Stock, Conversion Basis | The PE Unit Holders generally have the right to exchange (the bExchange Rightb) their PE Units (and a corresponding number of shares of Class B Common Stock), for shares of the Companybs Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each PE Unit (and a corresponding number of shares of Class B Common Stock) exchanged, (subject to conversion rate adjustments for stock splits, stock dividends, and reclassifications) or cash at the Companybs or Parsley LLCbs election (the bCash Optionb). | |||
Conversion of Stock, Amount Converted | $6,700,000 | $6,726,000 | ||
Stock based compensation expense related to restricted stock and restricted stock units | 2,209,000 | |||
Percentage of shares acquired of Parsley LLC | 74.30% | |||
Net income attributable to noncontrolling interest | 33,300,000 | |||
LLC Interest Issuance | ||||
Equity [Line Items] | ||||
Issuance of membership interests for total consideration | 73,500,000 | |||
Return on equity percentage | 9.50% | |||
PE Unit Holders | ||||
Equity [Line Items] | ||||
Percentage of shares held by existing owners | 25.70% | |||
Common Stock, Class A | ||||
Equity [Line Items] | ||||
Common stock, shares outstanding | 93,901,208 | 1,000 | ||
Common stock, voting rights | 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 Companybs board of directors. | |||
Common Stock, Class B | ||||
Equity [Line Items] | ||||
Common stock, shares outstanding | 32,145,296 | 0 | ||
Common stock, voting rights | Holders of the Class B Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders. | |||
Restricted Stock | ||||
Equity [Line Items] | ||||
Unrecognized noncash compensation expense | $11,800,000 | |||
Restricted Stock | Common Stock, Class A | ||||
Equity [Line Items] | ||||
Common stock, shares outstanding | 800,000 |
Equity_Allocation_of_Net_Incom
Equity - Allocation of Net Income to Common Stockholders and EPS Computations (Details) (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Numerator: | |||
Basic net income attributable to Parsley Energy Inc. Stockholders | $23,429 | ||
Denominator: | |||
Basic weighted average shares outstanding | 55,136 | ||
Basic EPS attributable to Parsley Energy Inc. Stockholders | $0.42 | ||
Effect of dilutive securities: | |||
Restricted Stock and Restricted Stock Units | 103 | ||
Diluted weighted average shares outstanding | 55,239 | ||
Diluted EPS attributable to Parsley Energy Inc. Stockholders | $0.42 | ||
Numerator: | |||
Net income attributable to Parsley Energy Inc. Stockholders | 23,429 | 27,510 | 12,899 |
Diluted net income attributable to Parsley Energy Inc. Stockholders | $23,429 |
Equity_Schedule_of_Restricted_
Equity - Schedule of Restricted Stock Activity (Details) (Restricted Stock, USD $) | 12 Months Ended |
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 |
Restricted Stock | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Number of Shares Outstanding, Granted | 770 |
Number of Shares Outstanding, Units Granted | 24 |
Number of Shares Outstanding, Forfeited | -37 |
Ending balance, Number of Shares Outstanding | 757 |
Grant Date Fair Value Outstanding, Granted | $18.54 |
Grant Date Fair Value Outstanding, Units Granted | $18.50 |
Grant Date Fair Value Outstanding, Forfeited | $18.50 |
Ending balance, Grant Date Fair Value | $18.54 |
Income_Taxes_Additional_Inform
Income Taxes - Additional Information (Details) (USD $) | 0 Months Ended | 12 Months Ended |
29-May-14 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | ||
Deferred tax liability | $95,500,000 | $95,530,000 |
Payable pursuant to tax receivable agreement | 56,300,000 | 50,689,000 |
Tax benefit | 66,300,000 | 59,633,000 |
Increase (decrease) in payable pursuant to tax receivable agreement | -5,600,000 | |
Increase (decrease) in tax benefit | -6,700,000 | |
Net operating loss carryforwards | $144,000,000 |
Income_Taxes_Components_of_the
Income Taxes - Components of the Income Tax Provision (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Federal: | |||
Deferred | $31,968 | ||
Total federal | 31,968 | ||
State, net of federal benefit: | |||
Deferred | 4,500 | 1,906 | 554 |
Total state | 4,500 | 1,906 | 554 |
Income tax provision | $36,468 | $1,906 | $554 |
Income_Taxes_Schedule_of_Recon
Income Taxes - Schedule of Reconciliation of Income Tax Provision with Income Tax Expense at Federal Statutory Rate (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Tax Expense Benefit Continuing Operations Income Tax Reconciliation [Abstract] | |||
Income (loss) before income taxes | $93,190 | $29,416 | $13,453 |
Plus: net loss prior to corporate reorganization | 37,378 | ||
Less: net income attributable to noncontrolling interest | -33,293 | ||
Income (loss) before income taxes and noncontrolling interest subsequent to corporate reorganization | 97,275 | 29,416 | 13,453 |
Income taxes at the federal statutory rate | 34,046 | ||
State income taxes, net of federal benefit | 967 | ||
State income taxes, prior to corporate reorganization | 1,246 | 1,906 | 554 |
Provision to return adjustment | 170 | ||
Permanent and other | 39 | ||
Income tax provision | $36,468 | $1,906 | $554 |
Income_Taxes_Schedule_of_Tax_E
Income Taxes - Schedule of Tax Effects of Significant Portions of the Deferred Tax Assets and Deferred Tax Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current Liabilities: | ||
Derivative fair value gain | ($12,601) | |
Total current deferred tax liability | -12,601 | |
Net current deferred tax liability | -12,601 | |
Noncurrent Assets: | ||
Asset retirement obligations | 4,379 | |
Materials and supplies | 431 | |
Deferred stock based compensation | 644 | |
Net operating loss carryforward | 50,425 | |
Total noncurrent deferred tax assets | 55,879 | |
Noncurrent Liabilities: | ||
Book basis of oil and natural gas properties in excess of tax basis | -108,825 | -2,572 |
Derivative fair value gain | -8,874 | |
Earnings in investment in subsidiary | -514 | |
Total noncurrent deferred tax liabilities | -118,213 | -2,572 |
Net noncurrent deferred tax liability | ($62,334) | ($2,572) |
Related_Party_Transactions_Add
Related Party Transactions - Additional Information (Details) (USD $) | 5 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | ||
In Millions, unless otherwise specified | 29-May-14 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 29, 2012 | Oct. 31, 2012 |
Related Party Transaction [Line Items] | ||||||
Amounts disbursed to related parties | $2.10 | $11.30 | $14.40 | $10.80 | ||
Equity method investment, ownership percentage | 42.50% | |||||
Related party transaction percentage of income tax benefits from tax receivable agreement | 85.00% | |||||
SPS | ||||||
Related Party Transaction [Line Items] | ||||||
Equity method investment, ownership percentage | 42.50% | |||||
Company incurred charges for services performed | 5.1 | 3.3 | 2 | |||
Lone Star Well Service, LLC | ||||||
Related Party Transaction [Line Items] | ||||||
Company incurred charges for services performed | 0.7 | 0 | 0 | |||
Davis, Gerald, and Cremer | ||||||
Related Party Transaction [Line Items] | ||||||
Legal service charges | 0.2 | 0.3 | 0.1 | |||
Diamond K Production, LLC | ||||||
Related Party Transaction [Line Items] | ||||||
Total consideration for acquisition | 8.2 | 8.2 | ||||
Acquisitions from Directors and Officers | ||||||
Related Party Transaction [Line Items] | ||||||
Total consideration for acquisition | 19.4 | |||||
Tex-Isle | ||||||
Related Party Transaction [Line Items] | ||||||
Percentage of ownership interest, Noncontrolling owners | 5.00% | |||||
Related party ownership Description | Diamond K is no longer considered a related party as their ownership interest fell below 5% | |||||
Purchases of equipment used in drilling operations | $29.30 | $68.10 | $33.10 |
Commitments_and_Contingencies_1
Commitments and Contingencies - Schedule of Company Drilling Commitments (Details) (Drilling Commitments, USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Drilling Commitments | |
Commitment And Contingencies [Line Items] | |
2015 | $39,466 |
2016 | 27,911 |
2017 | 10,039 |
Total | $77,416 |
Commitments_and_Contingencies_2
Commitments and Contingencies - Schedule of Future Minimum Lease Payments under Long Term Operating Lease Agreements (Details) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Operating Leased Assets [Line Items] | |
2015 | $3,029 |
2016 | 3,025 |
2017 | 4,481 |
2018 | 4,866 |
2019 | 4,977 |
Thereafter | 21,005 |
Total | 41,383 |
Office Leases | |
Operating Leased Assets [Line Items] | |
2015 | 2,827 |
2016 | 2,831 |
2017 | 4,452 |
2018 | 4,865 |
2019 | 4,977 |
Thereafter | 21,005 |
Total | 40,957 |
Vehicle Operating Leases | |
Operating Leased Assets [Line Items] | |
2015 | 116 |
2016 | 124 |
Total | 240 |
Office Equipment | |
Operating Leased Assets [Line Items] | |
2015 | 86 |
2016 | 70 |
2017 | 29 |
2018 | 1 |
Total | $186 |
Commitments_and_Contingencies_3
Commitments and Contingencies - Additional Information (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Commitments And Contingencies Disclosure [Abstract] | |||
Rent expense | $1.50 | $0.70 | $0.30 |
Disclosures_about_Fair_Value_o2
Disclosures about Fair Value of Financial Instruments - Additional Information (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Senior Notes | $672,069,000 | $430,197,000 |
Senior Notes | ||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Senior Notes | 550,000,000 | |
Estimated fair value of Senior Notes | $521,100,000 |
Disclosures_about_Fair_Value_o3
Disclosures about Fair Value of Financial Instruments - Schedule of Financial Assets and Liabilities Measured at Fair Value (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Assets: | ||
Short-term derivative instruments | $80,911 | $6,999 |
Long-term derivative instruments | 70,805 | 13,850 |
Liabilities: | ||
Short-term derivative instruments | -29,326 | -4,435 |
Long-term derivative instruments | -31,275 | -2,208 |
Commodity Derivative Contracts | ||
Assets: | ||
Short-term derivative instruments | 80,911 | 6,999 |
Long-term derivative instruments | 70,805 | 13,850 |
Total derivative instruments - asset | 151,716 | 20,849 |
Liabilities: | ||
Short-term derivative instruments | -29,326 | -4,435 |
Long-term derivative instruments | -31,275 | -2,208 |
Total derivative instruments - liability | -60,601 | -6,643 |
Net commodity derivative asset | 91,115 | 14,206 |
Commodity Derivative Contracts | Level 2 | ||
Assets: | ||
Short-term derivative instruments | 80,911 | 6,999 |
Long-term derivative instruments | 70,805 | 13,850 |
Total derivative instruments - asset | 151,716 | 20,849 |
Liabilities: | ||
Short-term derivative instruments | -29,326 | -4,435 |
Long-term derivative instruments | -31,275 | -2,208 |
Total derivative instruments - liability | -60,601 | -6,643 |
Net commodity derivative asset | $91,115 | $14,206 |
Subsequent_Events_Additional_I
Subsequent Events - Additional Information (Details) (USD $) | 12 Months Ended | 0 Months Ended | ||
Dec. 31, 2014 | Feb. 05, 2014 | 29-May-14 | Dec. 31, 2013 | |
Subsequent Event [Line Items] | ||||
Proceeds from issuance of common stock, net | $867,750,000 | |||
Common Stock, Class A | ||||
Subsequent Event [Line Items] | ||||
Common stock, shares issued | 93,937,947 | 43,200,000 | 1,000 | |
Proceeds from issuance of common stock, gross | 231,000,000 | |||
Common Stock, Class A | Private Placement [Member] | ||||
Subsequent Event [Line Items] | ||||
Common stock, shares issued | 14,885,797 | |||
Common stock sale price per share | $15.50 | |||
Proceeds from issuance of common stock, net | $224,000,000 |
Supplemental_Disclosure_of_Oil2
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Capitalized Costs (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Oil and natural gas properties: | ||
Proved properties | $1,248,376 | $546,072 |
Unproved properties | 624,240 | 68,243 |
Total oil and natural gas properties | 1,872,616 | 614,315 |
Less accumulated depreciation, depletion and amortization | -128,044 | -34,957 |
Net oil and natural gas properties capitalized | $1,744,572 | $579,358 |
Supplemental_Disclosure_of_Oil3
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Costs Incurred for Oil and Natural Gas Producing Activities (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Acquisition costs: | |||
Proved properties | $233,899 | $142,695 | $17,932 |
Unproved properties | 528,301 | 65,686 | 14,022 |
Development costs | 488,673 | 268,400 | 71,945 |
Total | $1,250,873 | $476,781 | $103,899 |
Supplemental_Disclosure_of_Oil4
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Reserve Quantity Information Average Sales Price (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Oil | |||
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |||
Average sales price | 85.99 | 92.53 | 89.71 |
Natural Gas Liquids | |||
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |||
Average sales price | 35.27 | 36.2 | 35.02 |
Natural Gas | |||
Average Sales Price And Production Costs Per Unit Of Production [Line Items] | |||
Average sales price | 4.28 | 3.46 | 2.48 |
Supplemental_Disclosure_of_Oil5
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Proved Developed and Proved Undeveloped Reserves (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Boe | Boe | Boe | |
Proved Developed and Undeveloped Reserves: | |||
Beginning of the year | 54,834,000 | 22,755,000 | 15,094,000 |
Extensions and discoveries | 33,824,000 | 20,132,000 | 6,899,000 |
Revisions of previous estimates | -9,480,000 | -3,127,000 | -49,000 |
Purchases of reserves in place | 16,953,000 | 16,908,000 | 1,416,000 |
Divestures of reserves in place | -5,000 | ||
Production | -5,240,000 | -1,829,000 | -605,000 |
End of the year | 90,891,000 | 54,834,000 | 22,755,000 |
Beginning of the year | 23,539,000 | 9,771,000 | 3,398,000 |
End of the year | 45,952,000 | 23,539,000 | 9,771,000 |
Beginning of the year | 31,295,000 | 12,984,000 | 11,696,000 |
End of the year | 44,939,000 | 31,295,000 | 12,984,000 |
Crude Oil | |||
Proved Developed and Undeveloped Reserves: | |||
Beginning of the year | 29,507,000 | 12,987,000 | 8,519,000 |
Extensions and discoveries | 18,776,000 | 10,378,000 | 4,047,000 |
Revisions of previous estimates | -7,832,000 | -2,029,000 | -39,000 |
Purchases of reserves in place | 10,006,000 | 9,223,000 | 816,000 |
Divestures of reserves in place | -3,000 | ||
Production | -2,840,000 | -1,049,000 | -356,000 |
End of the year | 47,617,000 | 29,507,000 | 12,987,000 |
Beginning of the year | 13,560,000 | 5,834,000 | 2,070,000 |
End of the year | 23,547,000 | 13,560,000 | 5,834,000 |
Beginning of the year | 15,947,000 | 7,153,000 | 6,449,000 |
End of the year | 24,070,000 | 15,947,000 | 7,153,000 |
Liquids | |||
Proved Developed and Undeveloped Reserves: | |||
Beginning of the year | 12,357,000 | 4,732,000 | 3,127,000 |
Extensions and discoveries | 8,157,000 | 4,840,000 | 1,369,000 |
Revisions of previous estimates | -528,000 | -796,000 | -56,000 |
Purchases of reserves in place | 3,906,000 | 3,695,000 | 294,000 |
Divestures of reserves in place | -1,000 | ||
Production | -1,225,000 | -113,000 | -2,000 |
End of the year | 22,667,000 | 12,357,000 | 4,732,000 |
Beginning of the year | 4,762,000 | 1,906,000 | 623,000 |
End of the year | 11,491,000 | 4,762,000 | 1,906,000 |
Beginning of the year | 7,595,000 | 2,826,000 | 2,504,000 |
End of the year | 11,175,000 | 7,595,000 | 2,826,000 |
Natural Gas | |||
Proved Developed and Undeveloped Reserves: | |||
Beginning of the year | 77,818,000 | 30,214,000 | 20,689,000 |
Extensions and discoveries | 41,348,000 | 29,489,000 | 8,898,000 |
Revisions of previous estimates | -6,714,000 | -1,813,000 | 274,000 |
Purchases of reserves in place | 18,244,000 | 23,937,000 | 1,833,000 |
Divestures of reserves in place | -7,000 | ||
Production | -7,051,000 | -4,002,000 | -1,480,000 |
End of the year | 123,645,000 | 77,818,000 | 30,214,000 |
Beginning of the year | 31,301,000 | 12,186,000 | 4,230,000 |
End of the year | 65,484,000 | 31,301,000 | 12,186,000 |
Beginning of the year | 46,517,000 | 18,028,000 | 16,459,000 |
End of the year | 58,161,000 | 46,517,000 | 18,028,000 |
Supplemental_Disclosure_of_Oil6
Supplemental Disclosure of Oil and Natural Gas Operations - Additional Information (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Boe | Boe | Boe | |
Extractive Industries [Abstract] | |||
Extensions and discoveries | 33,824,000 | 20,132,000 | 6,899,000 |
Estimated future net cash flows, discount rate | 10.00% |
Supplemental_Disclosure_of_Oil7
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | ||||
Extractive Industries [Abstract] | ||||
Future cash inflows | $5,423,551 | $3,446,766 | $1,405,580 | |
Future development costs | -642,746 | -515,247 | -186,996 | |
Future production costs | -1,640,422 | -1,097,734 | -368,099 | |
Future income tax expenses | -903,354 | -24,127 | -9,839 | |
Future net cash flows | 2,237,029 | 1,809,658 | 840,646 | |
10% discount to reflect timing of cash flows | -1,281,400 | -1,088,878 | -544,598 | |
Standardized measure of discounted future net cash flows | $955,629 | $720,780 | $296,048 | $181,714 |
Supplemental_Disclosure_of_Oil8
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Details) (USD $) | 12 Months Ended | ||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Nov. 30, 2012 |
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||
Future income tax expense | 903,354 | $24,127 | $9,839 | ||
Standardized measure | 955,629 | 720,780 | 296,048 | 181,714 | |
Pro Forma | |||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||
Future income tax expense | 562,500 | 289,500 | |||
Standardized measure | $497,700 | $193,600 | |||
Texas | |||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||
Statutory rate | 1.00% |
Supplemental_Disclosure_of_Oil9
Supplemental Disclosure of Oil and Natural Gas Operations - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Extractive Industries [Abstract] | |||
Standardized measure of discounted future net cash flows at the beginning of the year | $720,780 | $296,048 | $181,714 |
Sales of oil and natural gas, net of production costs | -244,745 | -97,365 | -30,621 |
Purchase of minerals in place | 279,725 | 227,937 | 20,222 |
Divestiture of minerals in place | -122 | ||
Extensions and discoveries, net of future development costs | 537,241 | 204,135 | 82,517 |
Previously estimated development costs incurred during the period | 96,881 | 57,158 | 36,423 |
Net changes in prices and production costs | -74,080 | 11,463 | -21,592 |
Changes in estimated future development costs | -9,517 | 2,793 | 1,627 |
Revisions of previous quantity estimates | -126,395 | -41,242 | -625 |
Accretion of discount | 73,107 | 30,010 | 18,443 |
Net change in income taxes | -348,501 | -6,240 | -1,336 |
Net changes in timing of production and other | 51,133 | 36,205 | 9,276 |
Standardized measure of discounted future net cash flows at the end of the year | $955,629 | $720,780 | $296,048 |