Attached files
| file | filename |
|---|---|
| EX-32.2 - EXHIBIT - RSP Permian, Inc. | rspp20140930ex322.htm |
| EX-31.2 - EXHIBIT - RSP Permian, Inc. | rspp20140930ex312.htm |
| EX-31.1 - EXHIBIT - RSP Permian, Inc. | rspp20140930ex311.htm |
| EX-32.1 - EXHIBIT - RSP Permian, Inc. | rspp20140930ex321.htm |
| EXCEL - IDEA: XBRL DOCUMENT - RSP Permian, Inc. | Financial_Report.xls |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2014
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number: 001-36264
RSP Permian, Inc.
(Exact name of registrant as specified in its charter)
Delaware | 90-1022997 | |
State or other jurisdiction of incorporation or organization | (I.R.S. Employer Identification Number) | |
3141 Hood Street, Suite 500 Dallas, Texas | 75219 | |
(Address of principal executive offices) | (Zip code) | |
(214) 252-2700
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark whether the registrant has submitted electronically and posted to its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Registration S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | o | Accelerated filer o |
Non-accelerated filer | x (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.): Yes o No ý
The registrant had 77,291,667 shares of common stock outstanding at November 7, 2014.
TABLE OF CONTENTS
Page | ||
GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN
The following are abbreviations and definitions of certain terms used in this Quarterly Report on Form 10-Q:
“Bbl.” A standard barrel containing 42 U.S. gallons.
“Bbls/d.” Bbls per day.
“Boe.” One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
“Boe/d.” One Boe per day.
“Btu.” One British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Differential.” An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
“Dry natural gas.” A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
“Dry hole” or “dry well.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Exploitation.” A development or other project that may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock that has distinct characteristics that differs from nearby rock.
“Gross acres” or “gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
“MBbl.” One thousand barrels.
“MBoe.” One thousand Boe.
“Mcf.” One thousand cubic feet.
“Mcf/d.” One Mcf per day.
“MMBbls.” One million barrels.
“MMBoe.” One million Boe.
“MMBtu.” One million British thermal units.
“MMcf.” One million cubic feet.
“Net production.” Production that is owned by us less royalties and production due others.
1
“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.
“NYMEX.” The New York Mercantile Exchange.
“Operator.” The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
“Plugging.” The sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.
“Realized price.” The cash market price less all expected quality, transportation and demand adjustments.
“Recompletion.” The completion for production of an existing wellbore in another formation from which the well has been previously completed.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“SEC.” The United States Securities and Exchange Commission.
“Spot market price.” The cash market price without reduction for expected quality, transportation and demand adjustments.
“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“We,” “our,” “us” or like terms and the “Company” refer to RSP Permian, Inc. and its subsidiary, RSP Permian, L.L.C.
“Wellbore.” The hole drilled by the bit that is equipped for oil and natural gas production on a completed well. Also called well or borehole.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
“WTI.” West Texas Intermediate.
The terms “development project,” “development well,” “exploratory well,” “proved developed reserves,” “proved reserves” and “reserves” are defined by the SEC.
Information presented in this Quarterly Report on Form 10-Q on a pro forma basis gives effect to the completion of the corporate reorganization and acquisitions in connection with our initial public offering completed in January 2014, each as described under “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation—The IPO and Related Transactions.”
2
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Certain statements in this Quarterly Report on Form 10-Q, including, without limitation, statements containing the words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” "will," "may," “should,” “would,” “could” or other similar expressions, and statements regarding the Company's business strategy and plans, constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, the volatility of commodity prices, product supply and demand, competition, access to and cost of capital, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, the quality of technical data, environmental and weather risks, including the possible impacts of climate change, the ability to obtain environmental and other permits and the timing thereof, government regulation or action, the costs and results of drilling and operations, the availability of equipment, services, resources and personnel required to complete the Company’s operating activities, access to and availability of transportation, processing and refining facilities, the financial strength of counterparties to the Company’s credit facility and derivative contracts and the purchasers of the Company’s production and acts of war or terrorism. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
RSP PERMIAN, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, 2014 | December 31, 2013 | |||||||
(In thousands) | ||||||||
ASSETS | ||||||||
CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 151,472 | $ | 13,234 | ||||
Accounts receivable | 34,508 | 26,346 | ||||||
Accounts receivable, related party | 1,085 | 3,672 | ||||||
Escrow receivable | — | 3,197 | ||||||
Escrow deposit | 24 | 15 | ||||||
Derivative instruments | 9,356 | 671 | ||||||
Total current assets | 196,445 | 47,135 | ||||||
PROPERTY, PLANT AND EQUIPMENT | ||||||||
Oil and natural gas properties, successful efforts method | 2,061,414 | 595,486 | ||||||
Accumulated depletion | (136,273 | ) | (88,514 | ) | ||||
Total oil and natural gas properties, net | 1,925,141 | 506,972 | ||||||
Other property and equipment, net | 17,732 | 9,316 | ||||||
Total property, plant and equipment | 1,942,873 | 516,288 | ||||||
OTHER LONG-TERM ASSETS | ||||||||
Derivative instruments | 2,868 | 1,078 | ||||||
Restricted cash | 150 | 150 | ||||||
Other assets | 28,218 | 23,004 | ||||||
Total long-term assets | 31,236 | 24,232 | ||||||
TOTAL ASSETS | $ | 2,170,554 | $ | 587,655 | ||||
LIABILITIES AND STOCKHOLDERS’/MEMBERS’ EQUITY | ||||||||
CURRENT LIABILITIES | ||||||||
Accounts payable | $ | 35,852 | $ | 18,548 | ||||
Accrued expenses | 37,431 | 10,460 | ||||||
Interest payable | 929 | 296 | ||||||
Derivative instruments | 4,920 | 1,562 | ||||||
Total current liabilities | 79,132 | 30,866 | ||||||
LONG-TERM LIABILITIES | ||||||||
Asset retirement obligations | 4,131 | 2,584 | ||||||
Derivative instruments | 1,743 | 43 | ||||||
Long-term debt | 500,000 | 128,155 | ||||||
NPI payable | — | 36,931 | ||||||
Deferred taxes | 353,787 | 2,195 | ||||||
Total long-term liabilities | 859,661 | 169,908 | ||||||
Total liabilities | 938,793 | 200,774 | ||||||
STOCKHOLDERS’/MEMBERS’ EQUITY | ||||||||
Members’ equity | — | 386,881 | ||||||
Common stock, $.01 par value; 300,000,000 shares authorized, 77,291,667 shares issued and outstanding at September 30, 2014; no shares authorized, issued or outstanding at December 31, 2013 | 773 | — | ||||||
Additional paid-in capital | 1,317,992 | — | ||||||
Accumulated deficit | (87,004 | ) | — | |||||
Total stockholders’/members’ equity | 1,231,761 | 386,881 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS’/MEMBERS’ EQUITY | $ | 2,170,554 | $ | 587,655 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
4
RSP PERMIAN, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In thousands, except per share data) | ||||||||||||||||
REVENUES | ||||||||||||||||
Oil sales | $ | 64,119 | $ | 33,139 | $ | 181,725 | $ | 77,504 | ||||||||
Natural gas sales | 2,297 | 1,400 | 7,620 | 3,962 | ||||||||||||
NGL sales | 4,229 | 2,321 | 13,121 | 5,197 | ||||||||||||
Total revenues | 70,645 | 36,860 | 202,466 | 86,663 | ||||||||||||
OPERATING EXPENSES | ||||||||||||||||
Lease operating expenses | $ | 7,140 | $ | 3,785 | $ | 23,482 | $ | 9,993 | ||||||||
Production and ad valorem taxes | 5,137 | 2,413 | 14,977 | 5,923 | ||||||||||||
Depreciation, depletion and amortization | 18,991 | 18,879 | 57,086 | 41,113 | ||||||||||||
Asset retirement obligation accretion | 38 | 32 | 104 | 83 | ||||||||||||
Exploration | 967 | 320 | 2,955 | 477 | ||||||||||||
General and administrative expenses | 5,214 | 1,048 | 27,468 | 2,672 | ||||||||||||
Total operating expenses | 37,487 | 26,477 | 126,072 | 60,261 | ||||||||||||
Gain on sale of assets | (2 | ) | (16,655 | ) | (2 | ) | (22,700 | ) | ||||||||
OPERATING INCOME | $ | 33,160 | $ | 27,038 | $ | 76,396 | $ | 49,102 | ||||||||
OTHER INCOME (EXPENSE) | ||||||||||||||||
Other income | $ | 23 | $ | 298 | $ | 31 | $ | 863 | ||||||||
Gain (loss) on derivative instruments | 22,059 | (2,630 | ) | 1,948 | (3,365 | ) | ||||||||||
Interest expense | (2,241 | ) | (669 | ) | (4,513 | ) | (1,770 | ) | ||||||||
Total other income (expense) | 19,841 | (3,001 | ) | (2,534 | ) | (4,272 | ) | |||||||||
INCOME BEFORE TAXES | 53,001 | 24,037 | 73,862 | 44,830 | ||||||||||||
INCOME TAX EXPENSE | (20,704 | ) | — | (160,866 | ) | (68 | ) | |||||||||
NET INCOME (LOSS) | $ | 32,297 | $ | 24,037 | $ | (87,004 | ) | $ | 44,762 | |||||||
Income (loss) per common share: | ||||||||||||||||
Basic | $ | 0.43 | $ | (1.24 | ) | |||||||||||
Diluted | $ | 0.43 | $ | (1.24 | ) | |||||||||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 74,896 | 70,100 | ||||||||||||||
Diluted | 74,896 | 70,100 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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RSP PERMIAN, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’/ MEMBERS’ EQUITY
(Unaudited)
Members’ Equity | Issued Shares of Common Stock | Common Stock | Additional Paid-in Capital | Accumulated Deficit | Total Stockholders’ Equity/ Members’ Equity | ||||||||||||||||||
(In thousands) | |||||||||||||||||||||||
BALANCE AT DECEMBER 31, 2013 | $ | 386,881 | — | $ | — | $ | — | $ | — | $ | 386,881 | ||||||||||||
Distribution of net assets to predecessor owner, including cash of $1,663 | (21,147 | ) | — | — | 14,168 | — | (6,979 | ) | |||||||||||||||
The corporate reorganization | (365,734 | ) | — | — | 365,734 | — | — | ||||||||||||||||
RSP Permian Holdco, L.L.C.’s contributions of interests in RSP Permian, L.L.C. in exchange for RSP Permian, Inc.’s common stock | — | 63,275 | 633 | (633 | ) | — | — | ||||||||||||||||
Ted Collins, Jr., Wallace Family Partnership, LP, Collins & Wallace Holdings, LLC, Pecos Energy Partners, L.P. and ACTOIL LLC’s contributions in exchange for RSP Permian, Inc.’s common stock | — | — | — | 642,436 | — | 642,436 | |||||||||||||||||
Shares of common stock issued in public offerings net of offering costs | — | 14,017 | 140 | 280,688 | — | 280,828 | |||||||||||||||||
Equity-based compensation | — | — | — | 15,599 | — | 15,599 | |||||||||||||||||
Net loss | — | — | — | — | (87,004 | ) | (87,004 | ) | |||||||||||||||
BALANCE AT SEPTEMBER 30, 2014 | $ | — | 77,292 | $ | 773 | $ | 1,317,992 | $ | (87,004 | ) | $ | 1,231,761 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
6
RSP PERMIAN, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
(In thousands) | ||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
Net income (loss) | $ | (87,004 | ) | $ | 44,762 | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 57,086 | 39,540 | ||||||
Abandoned equipment and intangibles | — | 45 | ||||||
Accretion of asset retirement obligations | 104 | 83 | ||||||
Equity based compensation | 15,599 | — | ||||||
Amortization of loan fees | 728 | 1,579 | ||||||
Deferred income taxes | 155,815 | — | ||||||
Equity in earnings of investment | — | (13 | ) | |||||
Gain on sale of assets | (2 | ) | (22,700 | ) | ||||
(Gain) loss on derivative instruments | (1,948 | ) | 3,365 | |||||
Net cash payments on settled derivatives | (3,469 | ) | (542 | ) | ||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable and accounts receivable from related parties | (5,584 | ) | (11,994 | ) | ||||
Other assets | 8,145 | (10,389 | ) | |||||
Interest payable | 633 | (15 | ) | |||||
Accounts payable | 17,304 | (9,825 | ) | |||||
Accrued expenses | (126 | ) | 4,706 | |||||
Net cash provided by operating activities | $ | 157,281 | $ | 38,602 | ||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
Proceeds from sale of assets | 2 | 115,339 | ||||||
Additions to other property and equipment | (3,823 | ) | 57 | |||||
Additions to oil and natural gas properties | (652,145 | ) | (195,583 | ) | ||||
Net cash used in investing activities | $ | (655,966 | ) | $ | (80,187 | ) | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
Contributions | — | 300 | ||||||
Issuance of common stock | 280,828 | — | ||||||
Distributions | (1,663 | ) | (30,000 | ) | ||||
Payment of deferred loan costs | (14,087 | ) | — | |||||
Borrowings under long-term debt | 440,512 | 101,569 | ||||||
Restricted short-term investment | — | 1,031 | ||||||
Payments on long-term debt | (568,667 | ) | (85,000 | ) | ||||
Issuance of senior unsecured notes | 500,000 | — | ||||||
NPI payable | — | 20,349 | ||||||
Net cash provided by financing activities | $ | 636,923 | $ | 8,249 | ||||
NET CHANGE IN CASH | $ | 138,238 | $ | (33,336 | ) | |||
CASH AT BEGINNING OF PERIOD | $ | 13,234 | $ | 51,232 | ||||
CASH AT END OF PERIOD | $ | 151,472 | $ | 17,896 | ||||
SUPPLEMENTAL CASH FLOW INFORMATION | ||||||||
Cash paid for interest | $ | 3,147 | $ | 1,677 | ||||
Cash paid for taxes | $ | 1,800 | $ | — | ||||
NON-CASH ACTIVITIES | ||||||||
Asset retirement obligation acquired | $ | 1,672 | $ | — | ||||
Common stock issued for oil and gas properties | $ | 677,402 | $ | — | ||||
Deferred tax liabilities recorded for oil and gas property acquisitions | $ | 195,777 | $ | — | ||||
Elimination of NPI payable | $ | 36,931 | $ | — | ||||
The accompanying notes are an integral part of these consolidated financial statements.
7
NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Organization and Description of the Business
RSP Permian, Inc. ("RSP Inc." or "the Company") was formed on September 30, 2013, pursuant to the laws of the state of Delaware as a holding company for RSP Permian, L.L.C., a Delaware limited liability company (“RSP LLC”). RSP LLC was formed on October 18, 2010 by its management team and an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds (“NGP”). The Company is engaged in the acquisition, development and operation of oil and natural gas properties. Additional background on and details of the ownership of the Company and RSP LLC are available in the Company's Annual Report on Form 10-K for the year ended December 31, 2013.
On January 17, 2014, RSP Inc. sold 23 million shares at $19.50 per share to the public in an initial public offering ("IPO") and began trading on the New York Stock Exchange under the ticker symbol "RSPP." Of the 23 million shares, 9.2 million were shares sold by RSP Inc., resulting in approximately $180 million of gross proceeds, which were used to fully repay the Company’s $70 million term loan, repay outstanding borrowings of $56 million under its revolving credit facility, make cash payments to certain existing investors as partial consideration for the properties contributed to the Company by such persons, pay cash bonuses to certain of the Company’s employees in connection with the successful completion of the IPO, and fund a portion of its capital expenditure plan. The remaining 13.8 million shares sold in the IPO were sold by selling stockholders, and the Company did not receive any proceeds from the sale of those shares. On August 12, 2014, RSP Inc. completed an underwritten public offering, by RSP Inc. and certain of its shareholders, of 11.5 million shares of RSP Inc. common stock at $25.65 per share, raising $123 million in net proceeds to RSP Inc.
In connection with the IPO, several transactions occurred that changed the structure and scope of the Company:
• Corporate Reorganization: RSP LLC was contributed to RSP Permian Holdco, L.L.C., a newly formed limited liability company, which contributed all of its interests in RSP LLC to RSP Inc. in exchange for shares of RSP Inc.’s common stock, an assignment of RSP LLC’s pro rata share of an escrow related to the Resolute Sale (as defined and described in Note 3) and cash. As a result of this reorganization, RSP LLC became a wholly owned subsidiary of RSP Inc.
•The Rising Star Acquisition: RSP Inc. acquired from Rising Star Energy Development Co., L.L.C., a Texas limited liability company (“Rising Star”), working interests in certain acreage and wells in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc.’s common stock and cash.
•The Collins and Wallace Contributions: Ted Collins, Jr. (“Collins”), Wallace Family Partnership, LP (“Wallace LP”) and Collins & Wallace Holdings, LLC, a newly formed entity that is jointly owned by Collins and Wallace LP, contributed certain working interests in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc.’s common stock and, in the case of Collins and Wallace LP, cash (such contributions, the “Collins and Wallace Contributions”). See Note 3 for additional information.
•The Pecos Contribution: Pecos Energy Partners, L.P. (“Pecos”), an entity owned by certain members of the Company’s management team, contributed certain working interests in acreage and wells in the Permian Basin in which RSP LLC already had a working interest in exchange for shares of RSP Inc.’s common stock.
•The ACTOIL NPI Repurchase: ACTOIL, LLC (“ACTOIL”), the owner of a 25% net profits interest (“NPI”) in substantially all of RSP LLC’s oil and natural gas properties taken as a whole, contributed their 25% NPI in exchange for shares of RSP Inc.’s common stock (such contribution, the “ACTOIL NPI Repurchase”). See Note 3 for more information.
Basis of Presentation
These financial statements have been prepared by the Company pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the audited annual financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. These financial statements should be read together with the financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013.
Subsequent Events
The Company has evaluated subsequent events of its consolidated financial statements. In October 2014, the Company invested $0.6 million, and committed to invest $5 million in the aggregate, in an entity that will develop, own and operate an
8
integrated water management system to gather, store, process, treat, distribute and dispose of water on behalf of exploration and production companies operating in Midland, Martin, Andrews, and other counties in Texas approved by the board of this entity. Under the terms of the agreement, the Company owns a minority interest and will account for this investment using the equity method of accounting.
NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively. Significant assumptions are required in the valuation of proved oil and natural gas reserves that may affect the amount at which oil and natural gas properties are recorded. Estimation of asset retirement obligations (“AROs”) and valuations of derivative instruments and the fair value of incentive unit compensation also require significant assumptions. It is possible that these estimates could be revised at future dates and these revisions could be material. Depletion of oil and natural gas properties are determined using estimates of proved oil and natural gas reserves. There are 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. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price estimates.
Reclassifications
Certain reclassifications have been made to prior periods to conform to current period presentation.
Related Party Receivable and Asset Purchase
The Company’s accounts receivable from related parties as of September 30, 2014 was $1.1 million and was owed by Collins, Wallace LP, Collins & Wallace Holdings, LLC, and Pecos. The balance as of December 31, 2013 was $3.7 million and was owed by Wallace LP.
Prior to the IPO, Collins, Wallace LP and Collins & Wallace Holdings, LLC had non-operated working interests in substantially all of the oil and natural gas assets that the Company operates. The Company considers the accounts receivable from these related parties to be fully collectible.
In August 2014, the Company acquired from Pecos working interests in certain acreage and wells in Glasscock County, Texas for $4.5 million.
Oil and Natural Gas Properties
The Company uses the successful efforts method of accounting for its oil and natural gas exploration and production activities. Costs incurred by the Company related to the acquisition of oil and natural gas properties and the cost of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when determined to be unsuccessful.
The Company capitalizes interest on expenditures while activities are in progress to bring the assets to their intended use for significant exploration and development projects that last more than six months. The Company did not capitalize any interest in the nine months ended September 30, 2014 and 2013 as no projects lasted more than six months. Costs incurred to maintain wells and related equipment, lease and well operating costs and other exploration costs are expensed as incurred. Gains and losses arising from the sale of properties are generally included in operating income. Unproved properties are assessed periodically for possible impairment.
Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted on a field basis based on proved reserves using the unit-of-production method. Capitalized exploration well costs and development costs, including AROs, are depleted on a field basis, based on proved developed reserves. For the three months ended September 30, 2014 and 2013, depletion expense for oil and natural gas producing property was $18.8 million and $17.4 million, respectively. For the nine months ended September 30, 2014 and 2013, depletion expense for oil and natural gas producing property was
9
$56.7 million and $39.1 million, respectively. Depletion expense is included in depreciation, depletion and amortization in the accompanying consolidated statements of operations.
The Company’s oil and natural gas properties as of September 30, 2014 and December 31, 2013 consisted of the following:
September 30, 2014 | December 31, 2013 | |||||||
(In thousands) | ||||||||
Proved oil and natural gas properties | $ | 1,407,753 | $ | 562,019 | ||||
Unproved oil and natural gas properties | 653,661 | 33,467 | ||||||
Total oil and natural gas properties | 2,061,414 | 595,486 | ||||||
Less: accumulated depletion | (136,273 | ) | (88,514 | ) | ||||
Total oil and natural gas properties, net | $ | 1,925,141 | $ | 506,972 | ||||
In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of September 30, 2014 and December 31, 2013, there were no costs capitalized in connection with exploratory wells in progress.
Capitalized costs are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a depletable unit (field) is impaired, the Company compares the carrying value of the depletable unit to the undiscounted future net cash flows by applying estimates of future oil and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves.
For a property determined to be impaired, an impairment loss equal to the difference between the property’s carrying value and estimated fair value is recognized. Fair value, on a field basis, is estimated to be the present value of the aforementioned expected future net cash flows. Unproved properties are assessed periodically to determine whether they have been impaired. An impairment allowance is provided on an unproved property when the Company determines that the property will not be developed. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value. No impairment of proved property was recorded for the three or nine months ended September 30, 2014 or 2013.
Natural gas volumes are converted to Boe at the rate of six Mcf of natural gas to one Bbl of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas. NGL volumes are stated in barrels.
Asset Retirement Obligation
The Company records AROs related to the retirement of long-lived assets at the time a legal obligation is incurred and the liability can be reasonably estimated. AROs are recorded as long-term liabilities with a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.
The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future down-hole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of a field’s surface to a condition similar to that existing before oil and natural gas extraction began.
In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
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After recording these amounts, the ARO is accreted to its future estimated value using the same assumed credit adjusted rate and the associated capitalized costs are depreciated on a unit-of-production basis.
The ARO consisted of the following for the period indicated:
Nine Months Ended September 30, 2014 | |||
(In thousands) | |||
Asset retirement obligation at beginning of period | $ | 2,584 | |
Liabilities assumed | 1,443 | ||
Accretion expense | 104 | ||
Asset retirement obligation at end of period | $ | 4,131 | |
Income Taxes
RSP LLC was organized as a limited liability company and treated as a flow-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of RSP Inc. from January 23, 2014 through September 30, 2014 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the conversion from a limited liability company to a corporation on January 23, 2014, the Company established a $132 million provision for deferred income taxes, which was recognized as tax expense from continuing operations. The primary upward adjustments in the effective tax rate above the U.S. statutory rate are the adjustment related to converting from a limited liability company to a corporation noted above along with non-deductible incentive unit compensation.
The following is an analysis of the Company’s consolidated income tax expense:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
Current | $ | 3,375 | $ | — | $ | 5,051 | $ | 68 | ||||||||
Deferred | 17,329 | — | 155,815 | — | ||||||||||||
Income Tax Expense | $ | 20,704 | $ | — | $ | 160,866 | $ | 68 | ||||||||
Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2014, the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
The Company’s U.S. federal income tax returns and Texas franchise tax returns for 2010 and beyond remain subject to examination by the taxing authorities. There are no material unresolved items related to periods previously audited by these taxing authorities. No other jurisdiction’s returns are significant to the Company’s financial position.
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific guidance. An entity is required to apply ASU 2014-09 for annual and interim reporting periods beginning after December 15, 2016. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in
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the financial statements. The Company is evaluating the impact that this new guidance will have on its consolidated financial statements.
NOTE 3—ACQUISITIONS AND SALES OF OIL AND NATURAL GAS PROPERTY INTERESTS
Pro Forma Results
The Company’s summary pro forma results for the three and nine months ended September 30, 2013 were derived from the actual results of the Company’s accounting predecessor, which reflects the combined results of RSP LLC and Rising Star, and have been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2013. Additionally, the pro forma results for the 2013 periods include the estimated activity associated with the Spanish Trail Acquisition (as defined below), which was completed in September 2013, and the Resolute Sale, which was completed in March 2013, as if each of these transactions had occurred on January 1, 2013.
Our pro forma results for the nine months ended September 30, 2014 were derived from our actual results and have been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2013. There were no pro forma adjustments required for the three months ended September 30, 2014.
The pro forma financial information included below does not give effect to certain acquisitions that were immaterial to our actual and pro forma results for the periods reflected below and does not make any adjustments for non-recurring expenses associated with the IPO.
The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | |||||||||||||||
Actual | Pro Forma | Actual | Pro Forma | |||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
Revenues | $ | 70,645 | $ | 70,645 | $ | 36,860 | $ | 62,803 | ||||||||
Net income | $ | 32,297 | $ | 32,297 | $ | 24,037 | $ | 21,736 | ||||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | |||||||||||||||
Actual | Pro Forma | Actual | Pro Forma | |||||||||||||
(In thousands) | (In thousands) | |||||||||||||||
Revenues | $ | 202,466 | $ | 207,451 | $ | 86,663 | $ | 143,370 | ||||||||
Net income (loss) | $ | (87,004 | ) | $ | (86,761 | ) | $ | 44,762 | $ | 46,645 | ||||||
Recent Acquisitions
During the first quarter of 2014, the Company acquired additional acreage prospective for horizontal development in Martin, Glasscock and Dawson counties for an aggregate purchase price of approximately $79 million in three separate transactions with approximately $45 million recorded as proved oil and natural gas properties. The transactions were financed with borrowings under the Company’s revolving credit facility.
In August 2014, in separate transactions with multiple sellers, the Company acquired predominantly undeveloped acreage and certain oil and gas producing properties located in Glasscock County, Texas, for an aggregate price of $257 million, with approximately $124 million recorded as proved oil and natural gas properties. The transactions were financed with borrowings under the Company’s revolving credit facility, and the amount of historical revenues and cash flow were immaterial compared to our historical results.
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Collins and Wallace Contributions
Collins, Wallace LP and Collins & Wallace Holdings, LLC contributed to RSP Inc. certain working interests in the Permian Basin in which RSP LLC already had working interests. In exchange, (i) Collins received shares of RSP Inc.’s common stock and the right to receive approximately $1.6 million in cash, (ii) Wallace LP received shares of RSP Inc.’s common stock and the right to receive $0.6 million in cash, and (iii) Collins & Wallace Holdings, LLC received shares of RSP Inc.’s common stock. The Collins and Wallace Contributions occurred in connection with the IPO.
These contributed working interests consist of the following: (i) Collins’ non-operated working interest in substantially all of the oil and natural gas properties that RSP LLC owned prior to the Spanish Trail Acquisition; (ii) Wallace LP’s non-operated working interest in substantially all of the oil and natural gas properties that RSP LLC owned prior to the Spanish Trail Acquisition; and (iii) Collins & Wallace Holdings, LLC’s non-operated working interest in the Spanish Trail Assets (as defined below).
A summary of the consideration transferred and the fair value of assets and liabilities acquired in connection with the Collins and Wallace Contributions is as follows (in thousands):
Value of the 22,023,654 shares of the Company’s common stock issued in the Collins and Wallace Contributions | $ | 429,461 | |
Cash paid in the Collins and Wallace Contributions | 2,219 | ||
Total consideration for the assets contributed in the Collins and Wallace Contributions | $ | 431,680 | |
Fair value of oil and natural gas properties | $ | 644,052 | |
Asset retirement obligation | (1,063 | ) | |
Deferred tax liability* | (211,309 | ) | |
Total net assets acquired | $ | 431,680 | |
_______________________________________
* Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 35%.
ACTOIL NPI Repurchase
In July 2011, RSP LLC sold to ACTOIL a 25% NPI in substantially all of its oil and natural gas properties taken as a whole. In addition, RSP LLC sold to ACTOIL a 25% NPI in the oil and natural gas properties acquired by RSP LLC in the Spanish Trail Acquisition. In connection with the IPO, ACTOIL contributed both 25% NPIs to the Company in exchange for shares of RSP Inc.’s common stock. The 25% NPIs exchanged for shares in the Company had a value of approximately $210.9 million and were accounted for as asset acquisitions.
The Company’s predecessor’s sale of properties to Resolute Natural Resources Southwest LLC (“Resolute”) in December 2012 and March 2013 resulted in ACTOIL earning cash proceeds through its NPI in the properties sold. ACTOIL reduced its NPI account cumulative deficit balance with these proceeds, rather than receiving a cash distribution. As such, the Company’s predecessor applied the NPI proceeds dollar-for-dollar to reduce the NPI deficit balance and recorded the amount as a long-term NPI payable on its balance sheet. This amount was eliminated upon ACTOIL contributing its NPI in exchange for common shares.
A summary of the consideration transferred and the assets acquired and liabilities acquired in connection with the ACTOIL NPI Repurchase is as follows (in thousands):
Value of the 10,816,626 shares of the Company’s common stock issued in the ACTOIL NPI Repurchase | $ | 210,924 | |
Elimination of NPI payable | (36,931 | ) | |
Total consideration for the assets contributed in the ACTOIL NPI Repurchase | $ | 173,993 | |
Oil and natural gas properties cost | $ | 158,115 | |
Asset retirement obligation | (639 | ) | |
Deferred tax asset* | 16,517 | ||
Total net assets acquired | $ | 173,993 | |
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_______________________________________
* Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 35%.
Spanish Trail Acquisition
On September 10, 2013, RSP LLC acquired additional working interests in certain of its existing properties in the Permian Basin (the “Spanish Trail Acquisition”) from Summit Petroleum, LLC (“Summit”) and EGL Resources, Inc. (“EGL”). The aggregate purchase price for the assets acquired in the Spanish Trail Acquisition (the “Spanish Trail Assets”) agreed to by RSP LLC and the sellers was $155 million.
Subsequent to the signing of the purchase agreement and prior to the closing of the Spanish Trail Acquisition, Collins and Wallace LP, non-operating working interest owners in the Spanish Trail Assets, exercised preferential purchase rights granted under a joint operating agreement among the working interest owners in the Spanish Trail Assets. The preferential purchase rights gave Collins and Wallace LP the right to purchase a portion of the working interests sold by Summit and EGL. Collins and Wallace LP completed this acquisition through Collins & Wallace Holdings, LLC, a newly formed entity that is jointly owned by Collins and Wallace LP, which contributed these acquired assets to RSP Inc. in exchange for shares of RSP Inc.’s common stock in connection with the IPO. The exercise of the preferential purchase rights reduced RSP LLC’s purchase price from $155 million to $121 million.
Simultaneously with the closing of the Spanish Trail Acquisition, pursuant to ACTOIL’s exercise of a right of first refusal granted by RSP LLC in the agreement that governs ACTOIL’s NPI investment, RSP LLC conveyed a 25% NPI in the Spanish Trail Assets taken as a whole, excluding the portion acquired by Collins & Wallace Holdings, LLC, to ACTOIL in exchange for cash equal to 25% of RSP LLC’s $121 million purchase price. The exercise of the right of first refusal by ACTOIL and issuance of the 25% NPI reduced RSP LLC's purchase price from $121 million to $91 million.
RSP LLC allocated the net purchase price to the oil and natural gas properties acquired and asset retirement obligation assumed as follows (in thousands):
Net purchase price | $ | 120,521 | |
25% NPI Sale to ACTOIL | (30,131 | ) | |
Oil and natural gas properties acquired | $ | 90,390 | |
Asset retirement obligation assumed | 296 | ||
Oil and natural gas properties | $ | 90,686 | |
The Spanish Trail Acquisition was funded with a $70 million term loan, borrowings under the Company’s revolving credit facility (described below in Note 6) and the issuance of the NPI to ACTOIL described above.
Resolute Sale
Effective October 1, 2012, RSP LLC, ACTOIL and other minority non-operating working interest owners entered into a Purchase, Sale, and Option Agreement (“PSA”) to sell an undivided 32.35% interest in certain assets for an aggregate purchase price of $110 million to Resolute (the “Resolute Sale”). The Company’s share of the purchase price was $69 million and was recorded as a reduction to the basis of the underlying oil and natural gas properties. To the extent that the proceeds received exceeded the cost basis of the oil and natural gas properties, the Company recorded a gain on the sale. In addition, RSP LLC and the other sellers sold Resolute an option (the “Option”) for $5 million, $2.4 million of which was the Company’s share. The Option allowed Resolute to acquire the remaining 67.65% interest in these certain assets. The Option was non-refundable and only entitled Resolute to a limited time period during which it could exercise the right to acquire the remaining interest in these certain assets, and therefore the Option fee was included in the consideration transferred in computing the gain on disposition of the assets described above. The Company recorded a gain in connection with the sale of the 32.35% interest in these assets and the option fee in the amount of $6.7 million for the year ended December 31, 2012.
In March 2013, Resolute exercised the right to acquire the 67.65% remaining interest in these assets from RSP LLC, ACTOIL and other working interest owners for an additional purchase price of approximately $230 million. RSP LLC’s share of the purchase price was $144.2 million. In connection with the transaction closing in March 2013, RSP LLC recorded a gain of approximately $6 million.
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The PSA contained customary closing conditions and included a $5 million title and environmental escrow (net to RSP LLC) and an $11 million indemnity escrow (net to RSP LLC) which were held back from the initial purchase price to provide for these contingencies. Amounts held in escrow for potential indemnity matters were not initially considered in the computation of the gain in connection with the sale of these certain assets because the Company could not reasonably estimate the potential outcome of any such matters at the time of the initial closing of the transaction.
Subsequent to the initial closing, in October 2013, RSP LLC received the first two scheduled escrow payments under the terms of the PSA totaling approximately $12 million. The receipt of these funds substantially resolved any uncertainty associated with the ability to collect the remaining portion of the amounts held in escrow and, therefore, the Company recorded the gain associated with all funds received and the remaining escrow amounts not yet received as collectability of such amounts was deemed probable. For the twelve months ended December 31, 2013, the total gain recognized on the Resolute Sale was approximately $22.7 million.
NOTE 4—DERIVATIVE INSTRUMENTS
Commodity Derivative Instruments
The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its crude oil and natural gas production. These include over-the-counter (“OTC”) swaps and collars. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings.
Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.
The following table summarizes all open positions as of September 30, 2014:
For the Year-Ended December 31, 2014 | For the Year-Ended December 31, 2015 | |||||||
Crude Oil Swaps: | ||||||||
Notional volume (Bbl) | 60,000 | 120,000 | ||||||
Weighted average price ($/Bbl)(1) | $ | 94.50 | $ | 92.60 | ||||
Crude Oil Collars: | ||||||||
Notional volume (Bbl) | 561,000 | 2,337,000 | ||||||
Weighted average ceiling price ($/Bbl)(1) | $ | 100.73 | $ | 94.64 | ||||
Weighted average floor price ($/Bbl)(1) | $ | 87.49 | $ | 86.42 | ||||
Natural Gas Collars: | ||||||||
Notional volume (Mmbtu) | 300,000 | — | ||||||
Weighted average ceiling price ($/Mmbtu)(2) | 4.78 | — | ||||||
Weighted average floor price ($/Mmbtu)(2) | 4.00 | — | ||||||
_______________________________________
(1) The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.
(2) The natural gas derivative contracts are settled based on the NYMEX Henry Hub closing settlement price.
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Derivative Fair Values and Gains (Losses)
The following table presents the fair value of derivative instruments. The Company’s derivatives are presented as separate line items in its consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of the Company’s master netting arrangements. See Note 5 for further discussion related to the fair value of the Company's derivatives.
Assets | Liabilities | |||||||||||||||
September 30, 2014 | December 31, 2013 | September 30, 2014 | December 31, 2013 | |||||||||||||
(In thousands) | ||||||||||||||||
Derivative Instruments: | ||||||||||||||||
Current amounts | ||||||||||||||||
Commodity contracts | $ | 9,356 | $ | 671 | $ | (4,920 | ) | $ | (1,562 | ) | ||||||
Noncurrent amounts | ||||||||||||||||
Commodity contracts | 2,868 | 1,078 | (1,743 | ) | (43 | ) | ||||||||||
Total derivative instruments | $ | 12,224 | $ | 1,749 | $ | (6,663 | ) | $ | (1,605 | ) | ||||||
Gains and losses on derivatives are reported in the consolidated statements of operations.
The following represents the Company’s reported gains and losses on derivative instruments for the periods presented:
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
(In thousands) | ||||||||
Gain (loss) on derivative instruments: | ||||||||
Commodity derivative instruments | $ | 22,059 | $ | (2,623 | ) | |||
Interest rate derivative instruments | — | (7 | ) | |||||
Total | $ | 22,059 | $ | (2,630 | ) | |||
Nine Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
(In thousands) | ||||||||
Gain (loss) on derivative instruments: | ||||||||
Commodity derivative instruments | $ | 1,948 | $ | (3,342 | ) | |||
Interest rate derivative instruments | — | (23 | ) | |||||
Total | $ | 1,948 | $ | (3,365 | ) | |||
Offsetting of Derivative Assets and Liabilities
The following table presents the Company’s gross and net derivative assets and liabilities.
Gross Amount Presented on Balance Sheet | Netting Adjustments(a) | Net Amount | ||||||||||
(In thousands) | ||||||||||||
September 30, 2014 | ||||||||||||
Derivative instrument assets with right of offset or master netting agreements | $ | 12,224 | $ | (6,663 | ) | $ | 5,561 | |||||
Derivative instrument liabilities with right of offset or master netting agreements | $ | (6,663 | ) | $ | 6,663 | $ | — | |||||
December 31, 2013 | ||||||||||||
Derivative instrument assets with right of offset or master netting agreements | $ | 1,749 | $ | (1,332 | ) | $ | 417 | |||||
Derivative instrument liabilities with right of offset or master netting agreements | $ | (1,605 | ) | $ | 1,332 | $ | (273 | ) | ||||
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_______________________________________
(a) With all of the Company’s financial trading counterparties, the Company has agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
Credit-Risk Related Contingent Features in Derivatives
None of the Company’s derivative instruments contains credit-risk related contingent features. No amounts of collateral were posted by the Company related to net positions as of September 30, 2014 and December 31, 2013.
NOTE 5—FAIR VALUE MEASUREMENTS
The book values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. The book value of the Company’s credit facilities approximate fair value as the interest rates are variable. The book value of the Company's senior notes approximates the fair value as the current trading value of the notes approximates par value. If we recorded the notes at fair value they would be Level 1 in our fair value hierarchy as they are traded in an active market with quoted prices for identical instruments. The fair value of derivative financial instruments is determined utilizing 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 Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
•Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered 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—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
•Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data. These inputs 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.
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Fair Value Measurement on a Recurring Basis
The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis.
Level 1 | Level 2 | Level 3 | Total fair value | |||||||||||||
(In thousands) | ||||||||||||||||
As of September 30, 2014: | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | 5,561 | $ | — | $ | 5,561 | ||||||||
Total | $ | — | $ | 5,561 | $ | — | $ | 5,561 | ||||||||
Level 1 | Level 2 | Level 3 | Total fair value | |||||||||||||
(In thousands) | ||||||||||||||||
As of December 31, 2013: | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | 144 | $ | — | $ | 144 | ||||||||
Total | $ | — | $ | 144 | $ | — | $ | 144 | ||||||||
Significant Level 2 assumptions used to measure the fair value of the commodity derivative instruments include current market and contractual commodity prices, implied volatility factors, appropriate risk adjusted discount rates, as well as other relevant data.
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. There were no transfers between Level 1, Level 2 or Level 3 during the three or nine months ended September 30, 2014 and the year ended December 31, 2013.
Nonfinancial Assets and Liabilities
Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s AROs represent a nonrecurring Level 3 measurement.
The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.
NOTE 6—LONG-TERM DEBT
Long-term debt consists of the following:
September 30, 2014 | December 31, 2013 | ||||||||
(In millions) | |||||||||
Term loan | $ | — | $ | 70.0 | |||||
Revolving credit facility | — | 58.2 | |||||||
6.625% Senior notes | 500.0 | — | |||||||
Total long-term debt | $ | 500.0 | $ | 128.2 | |||||
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Credit Agreement
On September 10, 2013, in conjunction with the Spanish Trail Acquisition, RSP LLC amended and restated its credit agreement, dated December 15, 2010, with Comerica Bank, as administrative agent providing for a revolving credit facility of up to $500 million, and expanded its syndicated bank group to 11 lenders. In addition, RSP LLC entered into a new term loan in the amount of $70 million to partially finance the Spanish Trail Acquisition. On June 9, 2014, the borrowing base under the revolving credit facility was increased from $300 million to $375 million as a result of the semiannual borrowing base redetermination under the revolving credit facility. In conjunction with the closing of our acquisitions in Glasscock County, on August 29, 2014, RSP LLC amended the revolving credit facility to increase the borrowing base to $500 million, to increase the lenders’ maximum facility commitments to $1.0 billion, to extend the maturity date to August 29, 2019 and to allow the Company to issue the senior unsecured notes described below. In connection with the Company's issuance of its senior unsecured notes, on September 24, 2014, RSP LLC amended the revolving credit facility to permit RSP LLC to make payment to the Company to enable it to pay principal, premium (if any) and interest on the unsecured notes provided no default has occurred and to allow RSP LLC to guaranty the unsecured notes.
RSP LLC's revolving credit facility requires it to maintain the following three financial ratios:
•a working capital ratio, which is the ratio of consolidated current assets (includes unused commitments under its revolving credit facility and excludes restricted cash and derivative assets) to consolidated current liabilities (excluding the current portion of long-term debt under the credit facility and derivative liabilities), of not less than 1.0 to 1.0;
•a leverage ratio, which is the ratio of the sum of all of the Company’s debt to the consolidated EBITDAX (as defined in the credit agreement) for the four fiscal quarters then ended, of not greater than 4.5 to 1.0,
•a senior secured leverage ratio, which is the ratio of the sum of all the Company's debt that is (i) secured and (ii) not subordinated to obligations under the revolving credit facility to the consolidated EBITDAX (as defined in the credit agreement) for for the four fiscal quarters then ended, of not greater than 3.5 to 1.0.
The RSP LLC's revolving credit facility contains restrictive covenants that may limit its ability to, among other things, incur additional indebtedness, make loans to others, make investments, enter into mergers, make or declare dividends, enter into commodity hedges exceeding a specified percentage or its expected production, enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness, incur liens, sell assets or engage in certain other transactions without the prior consent of the lenders.
RSP LLC was in compliance with such covenants and ratios as of September 30, 2014.
Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. RSP LLC has a choice of borrowing in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to the quotient of: (i) the LIBOR Rate divided by (ii) a percentage equal to 100% minus the maximum rate 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 100 to 200 basis points, depending on the percentage of its 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 100 basis points; and (iii) the adjusted LIBOR rate plus 100 basis points, plus an applicable margin ranging from 0 to 100 basis points, depending on the percentage of its borrowing base utilized, plus a facility fee of 0.50% charged on the borrowing base amount. At September 30, 2014, the prime borrowing rate of interest under the Company’s revolving credit facility was 3.50%. RSP LLC may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. As of September 30, 2014, the revolving credit facility has a margin of 1.00% to 2.00% plus LIBOR, plus a facility fee of 0.50% charged on the borrowing base amount.
The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is re-determined semiannually each May and November and depends on the volumes of proved oil and natural gas reserves and estimated cash flows from these reserves and commodity hedge positions. The borrowing base under RSP LLC’s amended and restated credit agreement is $500 million as of September 30, 2014, with lender commitments of $1 billion. The maturity date of RSP LLC’s revolving credit facility is August 29, 2019.
On January 23, 2014, RSP LLC repaid the term loan in full, and has no contractual obligations with respect to the term loan.
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Senior Notes Due 2022
On September 26, 2014, we issued $500.0 million of 6.625% senior unsecured notes at par through a private placement. The notes will mature on October 1, 2022. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under RSP LLC's revolving credit facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on these notes is payable semi-annually on April 1 and October 1 and commences on April 1, 2015. On or after October 1, 2017, we may redeem some or all of the notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 104.969% of principal, declining in twelve-month intervals to 100% in 2020 and thereafter. In addition, prior to October 1, 2017, we may redeem up to 35% of the principal amount of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 106.625% of the principal amount of the notes, plus accrued and unpaid interest. We incurred approximately $11.4 million of debt issuance costs related to the notes, which is included in “Other assets” on the Company's consolidated balance sheets and will be amortized to interest expense, net over the life of the notes using the effective interest method. In the event of certain changes in control of the Company, each holder of notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. RSP LLC, our 100% owned and only subsidiary, has fully and unconditionally guaranteed the notes. RSP Inc. does not have independent assets or operations. The terms of the notes include, among other restrictions, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. We were in compliance with the provisions of the indenture governing the senior unsecured notes as of September 30, 2014.
NOTE 7—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. Environmental expenditures are expensed as incurred. 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 and readily determinable. At September 30, 2014 and December 31, 2013, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Leases
In January 2011, RSP LLC entered into a 49-month lease agreement for office space in Midland, Texas. In February 2014, RSP LLC entered into a 64-month lease agreement through May 2019 for office space in Dallas, Texas. Rent expense for the three months ended September 30, 2014 and 2013 was $0.1 million and less than $0.1 million, respectively. Rent expense for the nine months ended September 30, 2014 and 2013 was $0.3 million and $0.2 million, respectively.
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NOTE 8—EQUITY-BASED COMPENSATION
Share-based compensation expense, which was recorded in "General and administrative expenses" in the accompanying consolidated statements of operations, was $1.9 million and $15.6 million for the three and nine months ended September 30, 2014. Share-based compensation expense includes certain costs which are non-recurring; expense for restricted shares which were issued as a bonus related to our IPO along with expense related to incentive units.
Restricted Stock Awards
In connection with the IPO, the Company adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (the “LTIP”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company. Refer to “Part III, Item 11. Executive Compensation” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 for additional information related to these equity-based compensation plans.
Share-based compensation expense for these awards was $1.3 million for the three months and $3.5 million for the nine months ended September 30, 2014. The Company views restricted stock awards with graded vesting as single awards with an expected life equal to the average expected life and amortize the awards on a straight-line basis over the life of the awards.
The compensation expense for these awards was determined based on the market price of the Company’s common stock at the date of grant applied to the total number of shares that were anticipated to fully vest. As of September 30, 2014, the Company had unrecognized compensation expense of $8.0 million related to restricted stock awards which is expected to be recognized over a weighted average period of 1.8 years.
The following table represents restricted stock award activity for the nine months ended September 30, 2014:
Shares | Wtd. Avg. Grant Price | ||||||
Restricted shares outstanding, beginning of period | — | $ | — | ||||
Restricted shares granted | 482,252 | 23.68 | |||||
Restricted shares canceled | (4,950 | ) | 24.96 | ||||
Restricted shares outstanding, end of period | 477,302 | $ | 23.67 | ||||
Performance-Based Restricted Stock Awards
In June 2014, performance-based restricted stock awards were granted containing predetermined market conditions with a cliff vesting period of 2.75 years. We granted 134,400 of these shares at a 100% of target payout while the conditions of the grants allow for a payout ranging between no payout and 200% of target.
Share-based compensation for these awards was $0.3 million and $0.5 million for the three months and nine months ended September 30, 2014, respectively. The compensation expense for the market condition is based on a grant date valuation of $28.14 per share using a Monte-Carlo simulation. The unrecognized compensation expense related to these shares is approximately $3.3 million as of September 30, 2014 and is expected to be recognized over the next 2.42 years. The payout level is calculated based on actual performance achieved during the performance period compared to a defined peer group.
Incentive Units
Pursuant to the LLC Agreement of RSP LLC, certain incentive units are available to be issued to the Company’s management and employees, consisting of Tier I, Tier I A, Tier II, Tier III and Tier IV units. The incentive units are intended to be compensation for services rendered to the Company. All incentive units, whether vested or not, are forfeited if payouts are not achieved by a specified date. Tier I and Tier I A incentive units vest ratably over three years but are subject to forfeiture if payout is not achieved. Tier I and Tier I A payout is realized upon the return of members’ invested capital and a specified rate of return. Tiers II, III and IV incentive units vest only upon the achievement of certain distribution thresholds for each such Tier and each Tier of the incentive units is subject to forfeiture if the applicable required payouts are not achieved. In addition, vested and unvested units will be forfeited if an incentive unit holder’s employment is terminated for cause or if the unitholder voluntarily terminates his or her employment.
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In connection with the IPO, the incentive units of RSP LLC became incentive units in RSP Permian Holdco, L.L.C. and therefore based upon distributions to members of RSP Permian Holdco, L.L.C. rather than members of RSP LLC. The terms and conditions of the profits interest awards remained substantially similar to the terms applicable to the incentive unit awards prior to the IPO, including the retention of existing vesting schedules. See “Part III, Item 11. Executive Compensation” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 for additional information regarding the incentive units.
The achievement of payout conditions is a performance condition that requires the Company to assess, at each reporting period, the probability that an event of payout will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. At the grant dates and subsequent reporting periods prior to the IPO, the Company did not deem as probable that such payouts would be achieved for any Tier of incentive units.
At such time that the occurrence of the performance conditions associated with these incentive units are deemed probable, the Company will record a non-cash compensation expense based upon the grant date fair value of the incentive units that are probable of reaching payout as a result of reaching established distribution thresholds. As of December 31, 2013, the unrecognized non-cash compensation expense associated with all tiers of the incentive units was approximately $16.3 million. After successful completion of the IPO, the performance conditions associated with the Tier I, Tier I A and Tier II incentive units were deemed probable of reaching payout, which resulted in the recognition of non-cash compensation expense of $0.2 million for the three months and $11.7 million for the nine months ended September 30, 2014, respectively. The Tier I A and Tier II incentive units have a remaining unrecognized non-cash compensation expense of approximately $1.0 million which will be amortized over the remaining service period and result in a $0.2 million non-cash compensation expense in the remainder of 2014 and $0.8 million in 2015. The remaining unrecognized non-cash compensation expense related to the Tier III and Tier IV incentive units is approximately $3.5 million and will be recognized when it is deemed that the Tier III and Tier IV incentive units are probable of reaching payout as a result of reaching the established distribution thresholds.
NOTE 9—EARNINGS PER SHARE & PRO FORMA EARNINGS PER SHARE
Earnings per Share
The Company’s basic earnings per share amounts have been computed using the two-class method based on the weighted-average number of shares of common stock outstanding for the period. Because the Company recognized a net loss for the nine months ended September 30, 2014, unvested restricted share awards were not recognized in dilutive earnings per share calculations as they would be antidilutive. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
Three Months Ended September 30, 2014 | Nine Months Ended September 30, 2014 | |||||||
(In thousands) | ||||||||
Numerator: | ||||||||
Net income (loss) available to stockholders | $ | 32,297 | $ | (87,004 | ) | |||
Basic net income (loss) allocable to participating securities (1) | 194 | — | ||||||
Income (loss) available to stockholders | $ | 32,103 | $ | (87,004 | ) | |||
Denominator: | ||||||||
Weighted average number of common shares outstanding - basic | 74,896 | 70,100 | ||||||
Effect of dilutive securities: | ||||||||
Restricted stock | — | — | ||||||
Weighted average number of common shares outstanding - diluted (2) | 74,896 | 70,100 | ||||||
Net loss per share: | ||||||||
Basic | $ | 0.43 | $ | (1.24 | ) | |||
Diluted | $ | 0.43 | $ | (1.24 | ) | |||
_______________________________________
(1) Restricted share awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.
(2) Approximately 0.1 million shares related to performance-based restricted stock units that could be converted to common shares in the future based on predetermined performance and market goals were not included in the computation of Diluted earnings per share for the three months ended September 30, 2014, because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the contingency period.
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Pro Forma Earnings per Share
The Company computed a pro forma income tax provision as if the Company was subject to income taxes since January 1, 2014. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, and excludes the non-recurring tax adjustment related to the conversion of the Company from an LLC to a corporation on January 23, 2014, as further described in Note 2 under “Income Taxes.”
The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued in the IPO were outstanding for the entire year. A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below:
Nine Months Ended September 30, 2014 | |||
Numerator: | |||
Income before taxes, as reported | $ | 73,862 | |
Pro forma provision for income taxes | 26,590 | ||
Pro forma net income available to stockholders | 47,272 | ||
Basic net income allocable to participating securities | 271 | ||
Pro forma net income available to stockholders | $ | 47,001 | |
Denominator: | |||
Weighted average number of common shares outstanding - basic | 73,299 | ||
Effect of dilutive securities: | |||
Restricted stock | — | ||
Weighted average number of common shares outstanding - diluted | 73,299 | ||
Net income per share: | |||
Basic | $ | 0.64 | |
Diluted | $ | 0.64 | |
For the three months ended September 30, 2014, our actual earnings per share are equal to our pro forma earnings per share.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes in “Part I, Item 1. Financial Statements.” The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Please see “Cautionary Statement Concerning Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q and “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.
Our Predecessor and RSP Permian, Inc.
RSP Inc. was formed in September 2013 as a holding company for RSP LLC and does not have historical financial operating results. For purposes of this Quarterly Report on Form 10-Q, our accounting predecessor reflects the combined results of RSP LLC and Rising Star.
The company is engaged in the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of our acreage is located on large, contiguous acreage blocks in the core of the Midland Basin, a sub-basin of the Permian Basin, primarily in the counties of Midland, Andrews, Glasscock, Dawson, and Ector. In connection with the IPO, pursuant to the terms of a corporate reorganization, RSP LLC became a wholly owned subsidiary of RSP Inc. See “The IPO and Related Transactions—Corporate Reorganization” for more information. Also in connection with the IPO, Rising Star contributed to RSP Inc. certain assets that represent substantially all of Rising Star’s production and revenues for each of the years ended December 31, 2013 and 2012 in exchange for shares of RSP Inc.’s common stock and cash. See “The IPO and Related Transactions—The Rising Star Acquisition” for more information.
The IPO and Related Transactions
In January 2014, we successfully completed our IPO, selling 23 million shares at $19.50 per share and raising $449 million in gross proceeds. Of the 23 million shares, 9.2 million were shares sold by RSP Inc., resulting in approximately $163 million of net proceeds. The remaining 13.8 million shares sold in the IPO were sold by selling shareholders, and the Company did not receive any proceeds from the sale of these shares. In connection with the IPO, we completed the transactions described below.
Corporate Reorganization. Pursuant to the terms of a corporate reorganization, (i) the members of RSP LLC contributed all of their interests in RSP LLC to RSP Permian Holdco, L.L.C., a newly formed entity that is wholly owned by such members, and (ii) RSP Permian Holdco, L.L.C. contributed all of its interests in RSP LLC to RSP Inc. in exchange for shares of common stock of RSP Inc., an assignment of RSP LLC’s pro rata share of an escrow related to the Resolute Sale (which escrow is described in Note 3 to the consolidated financial statements) and the right to receive approximately $27.7 million in cash. As a result of the reorganization, RSP LLC became a wholly owned subsidiary of RSP Inc.
The Rising Star Acquisition. We acquired from Rising Star working interests in certain acreage and wells in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc. common stock and the right to receive approximately $1.7 million in cash.
The Collins and Wallace Contributions. Collins, Wallace LP and Collins & Wallace Holdings, LLC, a newly formed entity that is owned equally by Collins and Wallace LP, contributed to RSP Inc. certain working interests in the Permian Basin in which RSP LLC already had working interests. In exchange, (i) Collins received shares of RSP Inc.’s common stock and the right to receive approximately $1.6 million in cash, (ii) Wallace LP received shares of RSP Inc.’s common stock and the right to receive $0.6 million in cash and (iii) Collins & Wallace Holdings, LLC received shares of RSP Inc.’s common stock.
The Pecos Contribution. Pecos, an entity owned by certain members of our management team, contributed to RSP Inc. certain working interests in certain acreage and wells in the Permian Basin in which RSP LLC already has working interests (the “Pecos Contribution”). In exchange, Pecos received shares of RSP Inc.’s common stock.
The ACTOIL NPI Repurchase. In July 2011, RSP LLC sold to ACTOIL a 25% NPI in substantially all of its oil and natural gas properties taken as a whole, and in September 2013, RSP LLC sold to ACTOIL a 25% NPI in the Spanish Trail Assets acquired by RSP LLC. ACTOIL contributed both 25% NPIs to RSP Inc. in exchange for shares of RSP Inc.’s common stock.
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Recent Developments
Acquisitions
During the first quarter of 2014, the Company acquired additional acreage prospective for horizontal development located in Martin, Glasscock and Dawson counties in Texas for an aggregate purchase price of approximately $79 million in three separate transactions, which are described below in more detail, with approximately $45 million recorded as proved oil and natural gas properties. These transactions were financed with borrowings under the Company’s revolving credit facility and include:
•In Martin County, the Company acquired a 17.5% non-operated working interest totaling 1,125 net acres in producing properties located between the Company’s operated leasehold positions.
• In Glasscock County, the Company acquired a 100% operated working interest in 961 acres of undeveloped leasehold.
• In Dawson County, the Company also acquired an additional 3,766 gross (3,230 net) undeveloped acres in the area where RSP LLC acquired leasehold interests in October 2013.
In August 2014, in separate transactions with multiple sellers, we acquired predominantly undeveloped acreage and certain oil and gas producing properties located in Glasscock County, Texas, for an aggregate price of $257 million, with approximately $124 million recorded as proved oil and natural gas properties. The Company acquired an 87 % average operated working interest in 7,680 gross (6,652 net) surface acres and included net production, on a three stream basis of approximately 1,106 Boe/d (47% oil, 27% NGLs, 26% natural gas) at the time of the acquisition. The properties acquired have approximately 156 net horizontal and 132 net vertical locations. The horizontal intervals included in our inventory include the Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp D (Cline) formations. The transactions were financed with borrowings under RSP LLC's revolving credit facility.
August 2014 Equity Offering
On August 12, 2014, we completed an underwritten public offering by us and certain of our stockholders of 11,500,000 shares of our common stock at a price to the public of $25.65 per share (the ‘‘August 2014 Offering’’). We issued and sold 4,791,667 shares of our common stock, and the selling stockholders sold 6,708,333 shares. Immediately following the closing of the August 2014 Offering, common stock held by public holders represented 45% of our outstanding common stock. The net proceeds received by us from the August 2014 Offering were approximately $117.7 million. We used these proceeds to reduce outstanding borrowings under our revolving credit facility. We did not receive any proceeds from the sale of shares by the selling stockholders in the August 2014 Offering.
Amendments to Revolving Credit Facility
On August 29, 2014, in conjunction with the Glasscock Acquisitions, RSP LLC, as borrower, Comerica Bank, as administrative agent, and the lenders party thereto entered into the Second Amendment to Amended and Restated Credit Agreement (the ‘‘Second Amendment’’). Among other things, the Second Amendment (i) increased the borrowing base under the Credit Agreement from $375 million to $500 million, (ii) increased the maximum commitment from $500 million to $1 billion, and (iii) extended the maturity date from September 10, 2017 to August 29, 2019. Most recently, RSP LLC, Comerica Bank, as administrative agent, and the lenders party thereto entered into the Third Amendment to Amended and Restated Credit Agreement to expressly permit RSP LLC to make distributions to the issuer for payments of principal, premium, if any, and interest on the notes, provided that there is no existing event of default under the credit agreement.
Notes Offering
On September 26, 2014, we issued $500.0 million of 6.625% of senior unsecured notes at par through a private placement. The notes will mature on October 1, 2022. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under RSP LLC's revolving credit facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on these notes is payable semi-annually on April 1 and October 1 and commences on April 1, 2015. On or after October 1, 2017, we may redeem some or all of the notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 104.969% of principal, declining in twelve-month intervals to 100% in 2020 and thereafter. In addition, prior to October 1, 2017, we may redeem up to 35% of the principal amount of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 106.625% of the principal amount of the notes, plus accrued and unpaid interest. We incurred approximately $11.4 million of debt issuance costs related to the notes, which is included in “Other assets” on the Company's consolidated balance sheets and will be amortized to
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interest expense, net over the life of the notes using the effective interest method. In the event of certain changes in control of the Company, each holder of notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of the notes include, among other restrictions, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. We were in compliance with the provisions of the indenture governing the senior unsecured notes as of September 30, 2014.
Pro Forma Quarterly Financial Data
The below pro forma information for the nine months ended September 30, 2014 was derived from our actual results and has been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2014. The below pro forma information for both the three and nine months ended September 30, 2014 also reflects adjustments for non-recurring expenses associated with the IPO.
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The pro forma financial information included below does not give effect to certain acquisitions that were immaterial to our actual and pro forma results for the periods reflected below.
RSP Permian, Inc. | RSP Permian, Inc. Pro Forma | |||||||||||||||
Three months ended September 30, 2014 | Nine months ended September 30, 2014 | Three months ended September 30, 2014 | Nine months ended September 30, 2014 | |||||||||||||
Production data: | ||||||||||||||||
Oil (MBbls) | 738 | 1,969 | 738 | 2,019 | ||||||||||||
Natural gas (MMcf) | 750 | 2,035 | 750 | 2,083 | ||||||||||||
NGLs (MBbls) | 169 | 470 | 169 | 481 | ||||||||||||
Total (MBoe) | 1,032 | 2,778 | 1,032 | 2,847 | ||||||||||||
Average net daily production (Boe/d) | 11,217 | 10,176 | 11,217 | 10,429 | ||||||||||||
Average prices before effects of hedges(1)(2): | ||||||||||||||||
Oil (per Bbl) | $ | 86.88 | $ | 92.29 | $ | 86.88 | $ | 92.22 | ||||||||
Natural gas (per Mcf) | 3.06 | 3.74 | 3.06 | 3.75 | ||||||||||||
NGLs (per Bbl) | 25.02 | 27.92 | 25.02 | 27.98 | ||||||||||||
Total (per Boe) | $ | 68.45 | $ | 72.88 | $ | 68.45 | $ | 72.87 | ||||||||
Average realized prices after effects of hedges(1)(2): | ||||||||||||||||
Oil (per Bbl) | $ | 84.59 | $ | 90.47 | $ | 84.59 | $ | 90.44 | ||||||||
Natural gas (per Mcf) | 3.13 | 3.77 | 3.13 | 3.77 | ||||||||||||
NGLs (per Bbl) | 25.02 | 27.92 | 25.02 | 27.98 | ||||||||||||
Total (per Boe) | $ | 66.86 | $ | 71.61 | $ | 66.86 | $ | 71.62 | ||||||||
Average costs (per Boe): | ||||||||||||||||
Lease operating expenses (excluding gathering and transportation) | $ | 6.31 | $ | 7.75 | $ | 6.31 | $ | 7.79 | ||||||||
Gathering and transportation | 0.61 | 0.70 | 0.61 | 0.70 | ||||||||||||
Production and ad valorem taxes | 4.98 | 5.39 | 4.98 | 5.35 | ||||||||||||
Depreciation, depletion and amortization | 18.40 | 20.55 | 18.40 | 21.33 | ||||||||||||
General and administrative expenses(3) | 5.05 | 9.89 | 4.08 | 3.69 | ||||||||||||
Components of general and administrative expense: | ||||||||||||||||
General and administrative - cash component | $ | 3.19 | $ | 4.27 | $ | 3.19 | $ | 3.03 | ||||||||
General and administrative - (non IPO stock comp) | 0.88 | 0.67 | 0.88 | 0.66 | ||||||||||||
General and administrative - (IPO stock comp) | 0.98 | 4.94 | — | — | ||||||||||||
_______________________________________
(1) Average prices shown in the table reflect prices both before and after the effects of our cash payments/receipts on our commodity derivative transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period if applicable.
(2) Average realized prices for oil are net of transportation costs. Average realized prices for natural gas do not include transportation costs; instead, transportation costs related to our gas production and sales are included in our lease operating expenses. No transportation costs are associated with NGL production and sales.
(3) Pro forma general and administrative expenses do not include additional expenses we would have incurred as a result of being a public company for the entire period presented. In addition, non-recurring general and administrative expenses associated with non-cash compensation expense were excluded from the pro forma general and administrative expenses.
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RSP Permian, Inc. | RSP Permian, Inc. Pro Forma | |||||||||||||||
Three months ended September 30, 2014 | Nine months ended September 30, 2014 | Three months ended September 30, 2014 | Nine months ended September 30, 2014 | |||||||||||||
(In thousands) | ||||||||||||||||
Revenues: | ||||||||||||||||
Oil sales | $ | 64,119 | $ | 181,725 | $ | 64,119 | $ | 186,184 | ||||||||
Natural gas sales | 2,297 | 7,620 | 2,297 | 7,811 | ||||||||||||
NGL sales | 4,229 | 13,121 | 4,229 | 13,456 | ||||||||||||
Total revenues | 70,645 | 202,466 | 70,645 | 207,451 | ||||||||||||
Operating expenses: | ||||||||||||||||
Lease operating expenses | 7,140 | 23,482 | 7,140 | 24,176 | ||||||||||||
Production and ad valorem taxes | 5,137 | 14,977 | 5,137 | 15,228 | ||||||||||||
Depreciation, depletion and amortization | 18,991 | 57,086 | 18,991 | 60,719 | ||||||||||||
Asset retirement obligation accretion | 38 | 104 | 38 | 113 | ||||||||||||
Exploration | 967 | 2,955 | 967 | 2,955 | ||||||||||||
General and administrative expenses | 5,214 | 27,468 | 4,207 | 10,501 | ||||||||||||
Total operating expenses | 37,487 | 126,072 | 36,480 | 113,692 | ||||||||||||
Gain on sale of assets | (2 | ) | (2 | ) | (2 | ) | (2 | ) | ||||||||
Operating income | 33,160 | 76,396 | 34,167 | 93,761 | ||||||||||||
Other income (expense): | ||||||||||||||||
Other income | 23 | 31 | 23 | 31 | ||||||||||||
Gain on derivative instruments | 22,059 | 1,948 | 22,059 | 1,948 | ||||||||||||
Interest expense | (2,241 | ) | (4,513 | ) | (2,241 | ) | (4,513 | ) | ||||||||
Total other income (expense) | 19,841 | (2,534 | ) | 19,841 | (2,534 | ) | ||||||||||
Income before taxes | 53,001 | 73,862 | 54,008 | 91,227 | ||||||||||||
Income tax (expense) benefit | (20,704 | ) | (160,866 | ) | (19,444 | ) | (32,842 | ) | ||||||||
Net income | $ | 32,297 | $ | (87,004 | ) | $ | 34,564 | $ | 58,385 | |||||||
Overview
The Company’s financial and operating performance for the nine months ended September 30, 2014 included the following highlights:
•Completed the IPO in January 2014, selling 9.2 million shares at $19.50 per share for gross proceeds to the Company of $180 million, we also completed a secondary offering in August 2014, issuing 4.8 million shares at $25.65 per share for gross proceeds to the Company of $123 million;
•Acquired oil and gas properties in the Company’s core area for approximately $800 million through the Collins and Wallace Contributions, the ACTOIL NPI Repurchase, the Pecos Contribution and the acquisition from Rising Star;
•Acquired oil and gas properties in Martin, Glasscock and Dawson counties in Texas in the first quarter for approximately $79 million and acquired predominantly undeveloped acreage and certain oil and gas producing properties located in Glasscock County, Texas in the third quarter of 2014 for approximately $257 million; and
•Issued $500 million of senior unsecured notes at an interest rate of 6.625% that mature in 2022. After repaying amounts under our revolving credit facility, we ended the third quarter with approximately $151 million of cash on hand.
•Added our fourth operated horizontal rig and our second operated vertical rig, tripling our total rig count compared to the beginning of the year. We have also contracted a fifth and sixth horizontal rig, which are expected to arrive in late fourth quarter 2014 and late first quarter 2015, respectively; and
•Expanded our borrowing base under the revolving credit facility from $140 million at the beginning of the year to $500 million at September 30, 2014.
28
During the third quarter of 2014, our average daily production was 11,217 Boe/d, a 5% increase from our second quarter of 2014 average daily production of 10,714 Boe/d. Our third quarter exit rate was approximately 14.6 MBoe/d. Oil production was 72% of total production on a volumetric basis and 91% of our total revenues for the third quarter of 2014. Both third quarter and year to date 2014 production totals were significantly higher than production in the corresponding periods of 2013.
During the third quarter of 2014, the Company drilled 23 horizontal wells (13 operated) and completed 19 horizontal wells (11 operated). In our vertical drilling program, the Company completed 18 vertical wells (12 operated). We are operating four horizontal rigs and three vertical rigs, and intend to add a fifth horizontal rig in the fourth quarter of 2014 and a sixth horizontal rig by the end of the first quarter of 2015. We are currently determining our budget for 2015, and have the flexibility to reduce the number of operated horizontal and vertical rigs in 2015 if the decline in oil prices persists.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
•production volumes;
•realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts on our production; and
•lease operating expenses.
Due to the inherent volatility in commodity prices, we have historically used commodity derivative instruments, such as collars, swaps and puts, to hedge price risk associated with a significant portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in commodity prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in commodity prices and may partially limit our potential gains from future increases in prices. None of our instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge a portion of our physical production in order to protect our returns. Our revolving credit facility limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated projected production volume.
We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our production.
Our open positions as of September 30, 2014 were as follows:
Description & Production Period | Volume (Bbls) | Weighted Average Floor price ($/Bbl)(1) | Weighted Average Ceiling price ($/Bbl)(1) | Weighted Average Swap price ($/Bbl)(1) | |||||||||||
Crude Oil Swaps: | |||||||||||||||
October 2014 — December 2014 | 30,000 | $ | 96.40 | ||||||||||||
October 2014 — December 2015 | 150,000 | $ | 92.60 | ||||||||||||
Crude Oil Collars: | |||||||||||||||
October 2014 — December 2014 | 486,000 | $ | 87.87 | $ | 101.61 | ||||||||||
October 2014 — December 2015 | 375,000 | $ | 85.00 | $ | 95.00 | ||||||||||
January 2015 — March 2015 | 195,000 | $ | 90.00 | $ | 94.89 | ||||||||||
January 2015 — June 2015 | 240,000 | $ | 90.00 | $ | 96.00 | ||||||||||
January 2015 — December 2015 | 1,332,000 | $ | 85.86 | $ | 94.64 | ||||||||||
April 2015 — June 2015 | 90,000 | $ | 85.00 | $ | 93.67 | ||||||||||
July 2015 — September 2015 | 90,000 | $ | 85.00 | $ | 92.60 | ||||||||||
October 2015 — December 2015 | 90,000 | $ | 85.00 | $ | 92.33 | ||||||||||
_______________________________________
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(1) The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.
Description & Production Period | Volume (MMBtu) | Weighted Average Floor price ($/MMBtu)(1) | Weighted Average Ceiling price ($/MMBtu)(1) | Weighted Average Swap price ($/MMBtu)(1) | |||||||||||
Natural Gas Collars: | |||||||||||||||
November 2014 — December 2014 | 300,000 | $ | 4.00 | $ | 4.78 | $ | — | ||||||||
_______________________________________
(1) The natural gas derivative contracts are settled based on the NYMEX closing settlement price.
Factors Affecting the Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:
Recent and Formation Transactions
The historical results of operations through January 22, 2014 are based on the financial statements of our accounting predecessor, which reflects the combined results of RSP LLC and Rising Star, prior to the corporate reorganization and the transactions described above under “The IPO and Related Transactions,” which increased the scope of our operations.
Public Company Expenses
We incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, increased scope of our operations as a result of recent activities and costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations prior to the IPO.
Income Taxes
Our predecessor was not subject to federal income taxes and the tax liability with respect to our taxable income was passed through to our predecessor’s members. Accordingly, the financial data attributable to our predecessor contain no provision for federal income taxes. Our predecessor was subject to State of Texas franchise taxes at less than 1% of modified pre-tax earnings. We are taxed as a subchapter C corporation under the Internal Revenue Code of 1986, as amended, and subject to income taxes at a blended statutory rate of 35% of pre-tax earnings.
30
Results of Operations
Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013
Oil, Natural Gas and NGL Sales Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes:
Three Months Ended September 30, | |||||||||||||||
2014 | 2013 | Change | % Change | ||||||||||||
Revenues (in thousands, except percentages): | |||||||||||||||
Oil sales | $ | 64,119 | $ | 33,139 | $ | 30,980 | 93 | % | |||||||
Natural gas sales | 2,297 | 1,400 | 897 | 64 | % | ||||||||||
NGL sales | 4,229 | 2,321 | 1,908 | 82 | % | ||||||||||
Total revenues | $ | 70,645 | $ | 36,860 | $ | 33,785 | 92 | % | |||||||
Average sales prices: | |||||||||||||||
Oil (per Bbl) (excluding impact of cash settled derivatives) | $ | 86.88 | $ | 107.25 | $ | (20.37 | ) | (19 | )% | ||||||
Oil (per Bbl) (after impact of cash settled derivatives) | 84.59 | 106.46 | (21.87 | ) | (21 | )% | |||||||||
Natural gas (per Mcf) | 3.06 | 3.67 | (0.61 | ) | (17 | )% | |||||||||
Natural gas (per Mcf) (after impact of cash settled derivatives) | 3.13 | 3.67 | (0.54 | ) | (15 | )% | |||||||||
NGLs (per Bbl) | 25.02 | 38.68 | (13.66 | ) | (35 | )% | |||||||||
Total (per Boe) (excluding impact of cash settled derivatives) | $ | 68.45 | $ | 85.13 | $ | (16.68 | ) | (20 | )% | ||||||
Total (per Boe) (after impact of cash settled derivatives) | $ | 66.86 | $ | 84.57 | $ | (17.71 | ) | (21 | )% | ||||||
Production: | |||||||||||||||
Oil (MBbls) | 738 | 309 | 429 | 139 | % | ||||||||||
Natural gas (MMcf) | 750 | 381 | 369 | 97 | % | ||||||||||
NGLs (MBbls) | 169 | 60 | 109 | 182 | % | ||||||||||
Total (MBoe) | 1,032 | 433 | 599 | 138 | % | ||||||||||
Average daily production volume: | |||||||||||||||
Total (Boe/d) | 11,217 | 4,707 | 6,510 | 138 | % | ||||||||||
31
The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price and the relationship between our average realized natural gas price as a percentage of the average NYMEX price for the periods indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Average realized oil price ($/Bbl) | $ | 86.88 | $ | 107.25 | ||||
Average NYMEX ($/Bbl) | 97.25 | 105.94 | ||||||
Differential to NYMEX | (10.37 | ) | 1.31 | |||||
Average realized oil price to NYMEX percentage | 89 | % | 101 | % | ||||
Average realized natural gas price ($/Mcf) | $ | 3.06 | $ | 3.67 | ||||
Average NYMEX ($/Mcf) | 3.95 | 3.55 | ||||||
Differential to NYMEX | (0.89 | ) | 0.12 | |||||
Average realized natural gas price to NYMEX percentage | 77 | % | 103 | % | ||||
Average realized NGL price ($/Bbl) | $ | 25.02 | $ | 38.68 | ||||
Average NYMEX ($/Bbl) | 97.25 | 105.94 | ||||||
Average realized NGL price to NYMEX percentage | 26 | % | 37 | % | ||||
Our average realized oil price as a percentage of the average NYMEX price decreased to 89% for the three months ended September, 30, 2014 as compared to 101% for the three months ended September 30, 2013. The WTI - Cushing to WTI - Midland spread widened in the third quarter of 2014 over 2013 levels, which is the primary reason for the lower realized oil price as a percentage of the NYMEX price in 2014 as compared to 2013. The widening of the spread is due to the pipeline constraint issue that has developed as additional crude supply has exceeded the infrastructure needed to move the supply to other regional markets.
Oil revenues increased 93% from $33.1 million for the three months ended September 30, 2013 to $64.1 million for the three months ended September 30, 2014 as a result of an increase in our oil production volumes of 429 MBbls partially offset by a $20.37 per Bbl decrease in our average realized price for oil.
Natural gas revenues increased 64% from $1.4 million for the three months ended September 30, 2013 to $2.3 million for the three months ended September 30, 2014 as a result of an increase in natural gas production volumes of 369 MMcf partially offset by a $0.61 per Mcf decrease in our average realized natural gas price.
NGL revenues increased 82% from $2.3 million for the three months ended September 30, 2013 to $4.2 million for the three months ended September 30, 2014 as a result of a 109 MBbls increase in production partially offset by a $13.66 per Bbl decrease in our average realized NGL price.
Our higher production volumes for all products was a result of increased production from our horizontal drilling program, the Spanish Trail Acquisition in September 2013, the Collins and Wallace Contributions in January 2014 and the acquisition of producing properties in Martin County in February 2014.
32
Operating Expenses. The following table summarizes our expenses for the periods indicated:
Three Months Ended September 30, | |||||||||||||||
2014 | 2013 | $ Change | % Change | ||||||||||||
Operating expenses (in thousands, except percentages): | |||||||||||||||
Lease operating expenses | $ | 7,140 | $ | 3,785 | $ | 3,355 | 89 | % | |||||||
Production and ad valorem taxes | 5,137 | 2,413 | 2,724 | 113 | % | ||||||||||
Depreciation, depletion and amortization | 18,991 | 18,879 | 112 | 1 | % | ||||||||||
Asset retirement obligation accretion | 38 | 32 | 6 | 19 | % | ||||||||||
Exploration expense | 967 | 320 | 647 | 202 | % | ||||||||||
General and administrative expenses | 5,214 | 1,048 | 4,166 | 398 | % | ||||||||||
Total operating expenses | $ | 37,487 | $ | 26,477 | $ | 11,010 | 42 | % | |||||||
Expenses per Boe: | |||||||||||||||
Lease operating expenses | $ | 6.92 | $ | 8.74 | (1.82 | ) | (21 | )% | |||||||
Production and ad valorem taxes | 4.98 | 5.57 | (0.59 | ) | (11 | )% | |||||||||
Depreciation, depletion and amortization | 18.40 | 43.60 | (25.20 | ) | (58 | )% | |||||||||
Asset retirement obligation accretion | 0.04 | 0.07 | (0.03 | ) | (43 | )% | |||||||||
Exploration expense | 0.94 | 0.74 | 0.20 | 27 | % | ||||||||||
General and administrative expenses | 5.05 | 2.42 | 2.63 | 109 | % | ||||||||||
Total operating expenses per Boe | $ | 36.33 | $ | 61.14 | $ | (24.81 | ) | (41 | )% | ||||||
Lease Operating Expenses. Lease operating expenses increased 89% from $3.8 million for the three months ended September 30, 2013 to $7.1 million for the three months ended September 30, 2014. The increase in our lease operating expense was attributable to the significant increase in production volumes in the 2014 period. On a per Boe basis, our lease operating expense decreased to $6.92 from $8.74 as a result of an increase in our production rate that was greater than an increase in our costs. Gathering and transportation costs, which are included in lease operating expenses, were $0.3 million and $0.6 million for the three months ended September 30, 2013 and 2014, respectively. On a per Boe basis, our gathering and transportation costs were $0.74 and $0.61 for the three months ended September 30, 2013 and 2014, respectively.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased from $2.4 million for the three months ended September 30, 2013 to $5.1 million for the three months ended September 30, 2014 primarily as a result of higher revenues as production volumes increased.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased 1% to $19.0 million for the three months ended September 30, 2014 from $18.9 million for the three months ended September 30, 2013. The DD&A rate decreased 58% to $18.40 per Boe for the three months ended September 30, 2014 from $43.60 per Boe for the three months ended September 30, 2013 due to increased reserves volumes in the 2014 period. Proved reserves increased relative to our capitalized costs as a result of our successful drilling program and through acquisitions. The increased proved reserve volumes from these activities relative to the increase in capitalized costs served to reduce our DD&A rate in the 2014 period compared to the 2013 period. Therefore, as a result of this lower DD&A rate, the increase in our production for the three months ended September 30, 2014 relative to the comparable period in 2013 had a relatively negligible effect on our total DD&A expense recorded in the current period.
Exploration Expenses. Exploration expense increased by $0.6 million from $0.3 million for the three months ended September 30, 2013 to $1.0 million for the three months ended September 30, 2014 due to additional activity in the 2014 period.
General and Administrative Expenses. General and administrative (“G&A”) expenses increased from $1.0 million for the three months ended September 30, 2013 to $5.2 million for the three months ended September 30, 2014 primarily due to increases in expensing non-cash equity-based compensation and increases in compensation expense associated with additions to personnel.
33
Gain on Sale of Assets. Gain on sale of assets was $16.7 million for the three months ended September 30, 2013 as a result of the property sale to Resolute in 2013. There were no material asset sales in the three months ended September 30, 2014.
Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:
Three Months Ended September 30, | |||||||||||||||
2014 | 2013 | $ Change | % Change | ||||||||||||
Other income (expense) (in thousands, except percentages): | |||||||||||||||
Other income (expense) | $ | 23 | $ | 298 | $ | (275 | ) | (92 | )% | ||||||
Gain (loss) on derivative instruments | 22,059 | (2,630 | ) | 24,689 | NM | ||||||||||
Interest expense | (2,241 | ) | (669 | ) | (1,572 | ) | 235 | % | |||||||
Total other income (expense) | $ | 19,841 | $ | (3,001 | ) | $ | 22,842 | NM | |||||||
Other Income. Other income was $0.3 million for the three months ended September 30, 2013 primarily due to water we sourced and sold to other working interest partners for use in completion activities in the 2013 period.
Gain (loss) on Derivative Instruments. During the three months ended September 30, 2013, we recorded a $2.6 million loss as compared to a $22.1 million gain in the three months ended September 30, 2014. The change was a result of the future commodity price outlook for crude oil as of September 30, 2014 as compared to September 30, 2013, along with additional notional amounts of derivative contracts entered into during the current year.
Interest Expense. During the three months ended September 30, 2013, we recorded $0.7 million of interest expense as compared to $2.2 million in the three months ended September 30, 2014. The change was primarily the result of additional borrowings under our revolving credit facility in the 2014 period.
Results of Operations
Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
34
Oil, Natural Gas and NGL Sales Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes:
Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | Change | % Change | ||||||||||||
Revenues (in thousands, except percentages): | |||||||||||||||
Oil sales | $ | 181,725 | $ | 77,504 | $ | 104,221 | 134 | % | |||||||
Natural gas sales | 7,620 | 3,962 | 3,658 | 92 | % | ||||||||||
NGL sales | 13,121 | 5,197 | 7,924 | 152 | % | ||||||||||
Total revenues | $ | 202,466 | $ | 86,663 | $ | 115,803 | 134 | % | |||||||
Average sales prices: | |||||||||||||||
Oil (per Bbl) (excluding impact of cash settled derivatives) | $ | 92.29 | $ | 94.52 | $ | (2.23 | ) | (2 | )% | ||||||
Oil (per Bbl) (after impact of cash settled derivatives) | 90.47 | 94.33 | (3.86 | ) | (4 | )% | |||||||||
Natural gas (per Mcf) | 3.74 | 3.34 | 0.40 | 12 | % | ||||||||||
Natural gas (per Mcf) (after impact of cash settled derivatives) | 3.77 | 3.34 | 0.43 | 13 | % | ||||||||||
NGLs (per Bbl) | 27.92 | 29.20 | (1.28 | ) | (4 | )% | |||||||||
Total (per Boe) (excluding impact of cash settled derivatives) | $ | 72.88 | $ | 72.46 | $ | 0.42 | 1 | % | |||||||
Total (per Boe) (after impact of cash settled derivatives) | $ | 71.61 | $ | 72.33 | $ | (0.72 | ) | (1 | )% | ||||||
Production: | |||||||||||||||
Oil (MBbls) | 1,969 | 820 | 1,149 | 140 | % | ||||||||||
Natural gas (MMcf) | 2,035 | 1,188 | 847 | 71 | % | ||||||||||
NGLs (MBbls) | 470 | 178 | 292 | 164 | % | ||||||||||
Total (MBoe) | 2,778 | 1,196 | 1,582 | 132 | % | ||||||||||
Average daily production volume: | |||||||||||||||
Total (Boe/d) | 10,176 | 4,381 | 5,795 | 132 | % | ||||||||||
The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price and the relationship between our average realized natural gas price as a percentage of the average NYMEX price for the periods indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.
Nine Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Average realized oil price ($/Bbl) | $ | 92.29 | $ | 94.52 | ||||
Average NYMEX ($/Bbl) | 99.62 | 98.19 | ||||||
Differential to NYMEX | (7.33 | ) | (3.67 | ) | ||||
Average realized oil price to NYMEX percentage | 93 | % | 96 | % | ||||
Average realized natural gas price ($/Mcf) | $ | 3.74 | $ | 3.34 | ||||
Average NYMEX ($/Mcf) | 4.41 | 3.69 | ||||||
Differential to NYMEX | (0.67 | ) | (0.35 | ) | ||||
Average realized natural gas price to NYMEX percentage | 85 | % | 91 | % | ||||
Average realized NGL price ($/Bbl) | $ | 27.92 | $ | 29.20 | ||||
Average NYMEX ($/Bbl) | 99.62 | 98.19 | ||||||
Average realized NGL price to NYMEX percentage | 28 | % | 30 | % | ||||
35
Our average realized oil price as a percentage of the average NYMEX price decreased to 93% for the nine months ended September 30, 2014 as compared to 96% for the nine months ended September 30, 2013. All of our oil contracts are impacted by the NYMEX differential, which was negative $7.33 per Bbl for the nine months ended September 30, 2014 as compared to negative $3.67 per Bbl for the nine months ended September 30, 2013.
Oil revenues increased 134% from $77.5 million for the nine months ended September 30, 2013 to $181.7 million for the nine months ended September 30, 2014 as a result of an increase in oil production volumes of 1,149 MBbls partially offset by a $2.23 per Bbl decrease in our average realized price for oil .
Natural gas revenues increased 92% from $4.0 million for the nine months ended September 30, 2013 to $7.6 million for the nine months ended September 30, 2014 as a result of an increase in natural gas production volumes of 847 MMcf and a $0.40 per Mcf increase in our average realized natural gas price.
NGL revenues increased 152% from $5.2 million for the nine months ended September 30, 2013 to $13.1 million for the nine months ended September 30, 2014 as a result of an increase in NGL production volumes of 292 MBbls partially offset by a $1.28 per Bbl decrease in our average realized NGL price.
Our higher production volumes for all products was a result of increased production from our horizontal drilling program, the Spanish Trail Acquisition in September 2013, the Collins and Wallace Contributions in January 2014 and the acquisition of producing properties in Martin County in February 2014.
Operating Expenses. The following table summarizes our expenses for the periods indicated:
Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | $ Change | % Change | ||||||||||||
Operating expenses (in thousands, except percentages): | |||||||||||||||
Lease operating expenses | $ | 23,482 | $ | 9,993 | $ | 13,489 | 135 | % | |||||||
Production and ad valorem taxes | 14,977 | 5,923 | 9,054 | 153 | % | ||||||||||
Depreciation, depletion and amortization | 57,086 | 41,113 | 15,973 | 39 | % | ||||||||||
Asset retirement obligation accretion | 104 | 83 | 21 | 25 | % | ||||||||||
Exploration expense | 2,955 | 477 | 2,478 | 519 | % | ||||||||||
General and administrative expenses | 27,468 | 2,672 | 24,796 | 928 | % | ||||||||||
Total operating expenses before gain on sale of assets | $ | 126,072 | $ | 60,261 | $ | 65,811 | 109 | % | |||||||
(Gain) on sale of assets | (2 | ) | (22,700 | ) | 22,698 | NM | |||||||||
Total operating expenses after gain on sale of assets | $ | 126,070 | $ | 37,561 | $ | 88,509 | 236 | % | |||||||
Expenses per Boe: | |||||||||||||||
Lease operating expenses | $ | 8.45 | $ | 8.36 | 0.09 | 1 | % | ||||||||
Production and ad valorem taxes | 5.39 | 4.95 | 0.44 | 9 | % | ||||||||||
Depreciation, depletion and amortization | 20.55 | 34.38 | (13.83 | ) | (40 | )% | |||||||||
Asset retirement obligation accretion | 0.04 | 0.07 | (0.03 | ) | (43 | )% | |||||||||
Exploration expense | 1.06 | 0.40 | 0.66 | 165 | % | ||||||||||
General and administrative expenses | 9.89 | 2.23 | 7.66 | 343 | % | ||||||||||
Total operating expenses per Boe | $ | 45.38 | $ | 50.39 | $ | (5.01 | ) | (10 | )% | ||||||
Lease Operating Expenses. Lease operating expenses increased 135% from $10.0 million for the nine months ended September 30, 2013 to $23.5 million for the nine months ended September 30, 2014. The increase in our lease operating expense was attributable to the increase in production in the 2014 period along with higher workover costs, as we performed more workovers in the current period primarily related to wells affected by severe winter weather in the early 2014 period. Gathering and transportation costs, which are included in lease operating expenses, were $0.8 million and $2.0 million for the nine months ended September 30, 2013 and 2014, respectively. On a per Boe basis, our gathering and transportation costs were $0.66 and $0.70 for the nine months ended September 30, 2013 and 2014, respectively.
36
Production and Ad Valorem Taxes. Production and ad valorem taxes increased 153% from $5.9 million for the nine months ended September 30, 2013 to $15.0 million for the nine months ended September 30, 2014 primarily as a result of higher wellhead revenues.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased 39% to $57.1 million for the nine months ended September 30, 2014 from $41.1 million for the nine months ended September 30, 2013 mainly due to increased production and costs related to property acquisitions. The DD&A rate decreased 40% to $20.55 per Boe for the nine months ended September 30, 2014 from $34.38 per Boe for the nine months ended September 30, 2013 due to increased reserves volumes in the 2014 period, both from our successful drilling program and through acquisitions. These increased reserves volumes more than offset additional capitalized costs incurred from these activities, which reduced our DD&A rate in the 2014 period when compared to the 2013 period.
Exploration Expenses. Exploration expense increased from $0.5 million for the nine months ended September 30, 2013 to $3.0 million for the nine months ended September 30, 2014 due to additional activity in the 2014 period.
General and Administrative Expenses. General and administrative (“G&A”) expenses increased from $2.7 million for the nine months ended September 30, 2013 to $27.5 million for the nine months ended September 30, 2014 primarily due to increases in expensing non-cash incentive unit compensation and equity-based compensation and increases in compensation expense associated with additions to personnel. Share-based compensation expense, which was recorded in "General and administrative expenses" in the accompanying consolidated statements of operations, was $15.6 for the nine months ended September 30, 2014.
Gain on Sale of Assets. Gain on sale of assets was $22.7 million for the nine months ended September 30, 2013 as a result of the property sale to Resolute in 2013. There were no material asset sales in the nine months ended September 30, 2014.
Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:
Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | $ Change | % Change | ||||||||||||
Other income (expense) (in thousands, except percentages): | |||||||||||||||
Other income | $ | 31 | $ | 863 | $ | (832 | ) | (96 | )% | ||||||
Gain (loss) on derivative instruments | 1,948 | (3,365 | ) | 5,313 | 158 | % | |||||||||
Interest expense | (4,513 | ) | (1,770 | ) | (2,743 | ) | (155 | )% | |||||||
Total other income (expense) | $ | (2,534 | ) | $ | (4,272 | ) | $ | 1,738 | 41 | % | |||||
Other Income. Other income decreased from $0.9 million for the nine months ended September 30, 2013 to less than $0.1 million for the nine months ended September 30, 2014 primarily due to an decrease in income related to water we sourced and sold to other working interest partners for use in completion activities.
Gain (loss) on Derivative Instruments. During the nine months ended September 30, 2013, we recorded a $3.4 million loss as compared to a $1.9 million gain in the nine months ended September 30, 2014. The change was a result of the future commodity price outlook as of September 30, 2014 as compared to September 30, 2013 along with additional hedges entered into during the 2014 period.
Interest Expense. During the nine months ended September 30, 2013, we recorded $1.8 million of interest expense as compared to $4.5 million in the nine months ended September 30, 2014. The change was primarily the result of additional borrowings under our revolving credit facility in the 2014 period.
Capital Requirements and Sources of Liquidity
The Company’s primary sources of liquidity have been capital contributions from its equity sponsor (prior to the IPO), proceeds from the IPO and secondary stock offering, borrowings under its revolving credit facility, term loan borrowings, issuance of senior notes, proceeds from asset dispositions, proceeds from the issuance of net profits interests and cash flows from operations. To date, the Company’s primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties.
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Our updated 2014 capital budget for drilling, completion, recompletion and infrastructure is approximately $425 million. We intend to allocate our 2014 capital budget approximately as follows:
•$400 million, or 94%, for the drilling and completion activities;
•$25 million, or 6%, for infrastructure and other.
During the nine months of 2014, we spent approximately $293 million on capital expenditures excluding acquisitions.
Because we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures are largely discretionary. We could choose to defer a portion of these planned 2014 capital expenditures depending on a variety of factors, including: the success of our drilling activities; prevailing and anticipated prices for oil, natural gas and NGLs; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the level of participation by other working interest owners.
We used a portion of the net proceeds from the IPO to fully repay our term loan and outstanding borrowings under our revolving credit facility. Later in August and September 2014, we used the proceeds from our secondary stock offering and senior unsecured notes offering to repay all borrowings under our revolving credit facility. At September 30, 2014, we had no borrowings outstanding under our revolving credit facility and our borrowing base was $500 million.
Based upon current oil and natural gas price expectations for 2014, we believe that our cash flow from operations and additional borrowings under our revolving credit facility will provide us with sufficient liquidity to execute our current capital program excluding any acquisitions we may enter into. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other needed capital will be available on acceptable terms or at all. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.
Working Capital
Our working capital, which we define as current assets minus current liabilities, totaled $117.3 million and $16.3 million at September 30, 2014 and December 31, 2013, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $151.5 million and $13.2 million at September 30, 2014 and December 31, 2013, respectively. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our revolving credit facility will be sufficient to fund our working capital needs excluding any acquisitions we may enter into. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.
Contractual Obligations
We had no other material changes in our contractual commitments and obligations from amounts listed under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements and Sources of Liquidity—Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2013.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
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Nine Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
(In thousands) | ||||||||
Net cash provided by operating activities | $ | 157,281 | $ | 38,602 | ||||
Net cash used in investing activities | (655,966 | ) | (80,187 | ) | ||||
Net cash provided by financing activities | 636,923 | 8,249 | ||||||
Net cash provided by operating activities was approximately $157.3 million and $38.6 million for the nine months ended September 30, 2014 and 2013, respectively. Revenues and related cash flows from operations increased in the 2014 period as compared to the 2013 period due to increased production from our horizontal drilling program, the Spanish Trail Acquisition in September 2013, the Collins and Wallace Contributions in January 2014 and the acquisition of producing properties in Martin County in February 2014.
Net cash used in investing activities was approximately $656.0 million and $80.2 million for the nine months ended September 30, 2014 and 2013, respectively. The increase in the amount of cash used in investing activities in the 2014 period compared to the 2013 period was due to capital expenditures for drilling and completing wells along with additional acquisition activity in the 2014 period. Capital expenditures during 2013 were offset by proceeds received from the sale of properties to Resolute.
Net cash provided by financing activities was approximately $636.9 million and $8.2 million for the nine months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014, the increased cash provided by financing activities was primarily the result of capital contributions received in connection with the IPO, the secondary stock offering, along with the issuance of $500.0 million of senior notes in 2014.
Debt
On September 26, 2014, we issued $500.0 million of 6.625% of senior unsecured notes at par through a private placement. The notes will mature on October 1, 2022. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under RSP LLC's revolving credit facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on these notes is payable semi-annually on April 1 and October 1 and commences on April 1, 2015. We incurred approximately $11.4 million of debt issuance costs related to the notes, which is included in “Other assets” on the Company's consolidated balance sheets and will be amortized to interest expense, net over the life of the notes using the effective interest method. The terms of the notes include, among other restrictions, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. We were in compliance with the provisions of the indenture governing the senior unsecured notes as of September 30, 2014.
In conjunction with the closing of our acquisitions in Glasscock County, on August 29, 2014, RSP LLC amended the revolving credit facility to increase the borrowing base to $500 million, to increase the lenders’ maximum facility commitments to $1.0 billion, extending the maturity date to August 29, 2019 and to allow the Company to issue the senior unsecured notes described below. In connection with the Company's issuance of its senior unsecured notes, on September 24, 2014, RSP LLC amended the revolving credit facility to permit RSP LLC to make payment to the Company to enable it to pay principal, premium (if any) and interest on the unsecured notes provided no default has occurred and to allow RSP LLC to guaranty the unsecured notes.
Our revolving credit facility is secured by liens on substantially all of our properties and guarantees from our subsidiaries other than any subsidiary that we have designated as an unrestricted subsidiary. The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semiannually each May and November and depends on the volumes of our proved oil and natural gas reserves, estimated cash flows from these reserves and our commodity hedge positions. Our revolving credit facility contains restrictive covenants and minimum financial ratios, which are described in Note 6 to the consolidated financial statements. We were in compliance with such covenants and ratios as of September 30, 2014 and our revolving credit facility matures August 29, 2019.
On September 10, 2013, in conjunction with the Spanish Trail Acquisition, the Company amended and restated its credit agreement, dated December 15, 2010, with Comerica Bank, as administrative agent, and expanded its syndicated bank group to
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11 lenders and entered into a new term loan in the amount of $70 million, which was fully repaid in January 2014 with proceeds from the IPO.
Subsequent Events
The Company has evaluated subsequent events of its consolidated financial statements. In October 2014, the Company invested $0.6 million, and committed to invest $5 million in the aggregate, in an entity that will develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water on behalf of exploration and production companies operating in Midland, Martin, Andrews, and other counties in Texas approved by the board of this entity. Under the terms of the agreement, the Company owns a minority interest and will account for this investment using the equity method of accounting.
Critical Accounting Policies and Estimates
Please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2013 for a description of the Company’s critical accounting policies.
Equity-Based Compensation
In connection with the IPO, the Company adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (the “LTIP”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company. See “Part III, Item 11. Executive Compensation” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 for additional information related to the LTIP. The valuation and expense recognition of equity-based compensation requires the use of estimates.
Income Taxes
The Company became a taxable entity as a result of its conversion from a limited liability company to a corporation on January 23, 2014. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2014, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
Off-Balance Sheet Arrangements
As of September 30, 2014, we did not have any off-balance sheet arrangements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our revenues are subject to market risk and are dependent on the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. Our realized prices are primarily driven by the prevailing prices for oil and the prevailing spot prices for natural gas and NGLs. We use derivative contracts to reduce our exposure to the changes in the prices of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price
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volatility associated with projected production levels. We do not use these instruments to engage in trading activities, and we do not speculate on commodity prices.
Our open positions as of September 30, 2014 were as follows:
Description & Production Period | Volume (Bbls) | Weighted Average Floor price ($/Bbl)(1) | Weighted Average Ceiling price ($/Bbl)(1) | Weighted Average Swap price ($/Bbl)(1) | |||||||||||
Crude Oil Swaps: | |||||||||||||||
October 2014 — December 2014 | 30,000 | $ | 96.40 | ||||||||||||
October 2014 — December 2015 | 150,000 | $ | 92.60 | ||||||||||||
Crude Oil Collars: | |||||||||||||||
October 2014 — December 2014 | 486,000 | $ | 87.87 | $ | 101.61 | ||||||||||
October 2014 — December 2015 | 375,000 | $ | 85.00 | $ | 95.00 | ||||||||||
January 2015 — March 2015 | 195,000 | $ | 90.00 | $ | 94.89 | ||||||||||
January 2015 — June 2015 | 240,000 | $ | 90.00 | $ | 96.00 | ||||||||||
January 2015 — December 2015 | 1,332,000 | $ | 85.86 | $ | 94.64 | ||||||||||
April 2015 — June 2015 | 90,000 | $ | 85.00 | $ | 93.67 | ||||||||||
July 2015 — September 2015 | 90,000 | $ | 85.00 | $ | 92.60 | ||||||||||
October 2015 — December 2015 | 90,000 | $ | 85.00 | $ | 92.33 | ||||||||||
(1) The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.
Description & Production Period | Volume (MMBtu) | Weighted Average Floor price ($/MMBtu)(1) | Weighted Average Ceiling price ($/MMBtu)(1) | Weighted Average Swap price ($/MMBtu)(1) | |||||||||||
Natural Gas Collars: | |||||||||||||||
November 2014 — December 2014 | 300,000 | $ | 4.00 | $ | 4.78 | $ | — | ||||||||
(1) The natural gas derivative contracts are settled based on the NYMEX closing settlement price.
The fair value of our derivative contracts as of September 30, 2014 was a net asset of $5.6 million. For information regarding the terms of these hedges, see “Part I, Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations—How We Evaluate Our Operations—Realized Prices on the Sale of Oil, Natural Gas and NGLs” above.
Counterparty and Customer Credit Risk
Our commodity derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as it deems appropriate. We plan to continue to evaluate the credit standings of our counterparties in a similar manner. The counterparties to our derivative contracts currently in place have investment grade ratings.
Our principal exposures to credit risk are through receivables arising from joint operations and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.
Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.
Interest Rate Risk
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At September 30, 2014, we had no borrowings outstanding that are subject to interest rate risk. We currently do not engage in any interest rate hedging activity.
Item 4. Controls And Procedures.
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2014. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2014 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
As described above, there were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
From time to time, we are party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment related disputes. While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.
Item 1A. Risk Factors.
In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.
Item 6. Exhibits.
See Exhibit Index on page 45 of this Quarterly Report on Form 10-Q.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
RSP PERMIAN, INC. | ||
By: | /s/ Scott McNeill | |
Scott McNeill | ||
Chief Financial Officer and Director | ||
(Principal Financial Officer) | ||
Date: | November 10, 2014 | |
By: | /s/ Barry S. Turcotte | |
Barry S. Turcotte | ||
Chief Accounting Officer | ||
(Principal Accounting Officer) | ||
Date: | November 10, 2014 | |
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EXHIBIT INDEX
Exhibit No. | Description | |
3.1 | Amended and Restated Certificate of Incorporation of RSP Permian, Inc. (incorporated by reference to Exhibit 3.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014). | |
3.2 | Amended and Restated Bylaws of RSP Permian, Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014). | |
4.1 | Specimen Common Stock Certificate (incorporated by reference to Exhibit 3.2 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on January 29, 2014). | |
4.2 | Registration Rights Agreement, dated as of January 23, 2014, among RSP Permian, Inc., RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace Family Partnership, LP, ACTOIL, LLC, Rising Star Energy Development Co., L.L.C. and Pecos Energy Partners, L.P. (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on January 29, 2014). | |
4.3 | Stockholders’ Agreement, dated as of January 23, 2014, among RSP Permian, Inc., RSP Permian Holdco, L.L.C., Ted Collins, Jr., Wallace Family Partnership, LP, Rising Star Energy Development Co., L.L.C. and Pecos Energy Partners, L.P. (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on January 29, 2014). | |
4.4 | Indenture, dated as of September 26, 2014, by and among the Company, RSP Permian, L.L.C. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on October 2, 2014). | |
4.5 | Form of Senior Note due 2022 (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on October 2, 2014). | |
4.6 | Registration Rights Agreement, dated as of September 26, 2014, by and among the Company, RSP Permian, L.L.C. and Barclays Capital Inc. and RBC Capital Markets, LLC, as representatives of the initial purchasers named in therein (incorporated by reference to Exhibit 4.2 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on October 2, 2014). | |
10.1 | Form of Restricted Stock Grant and Award Agreement. | |
10.2 | Amended and Restated Credit Agreement, dated September 10, 2013, by and between RSP Permian, L.L.C., as borrower, Comerica Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's Registration Statement on Form S-1 (File No. 377-00338) filed with the Commission on October 8, 2013). | |
10.3 | First Amendment to Amended and Restated Credit Agreement, dated June 9, 2014, by and among RSP Permian, L.L.C., as borrower, Comerica Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on June 9, 2014). | |
10.4 | Second Amendment to Amended and Restated Credit Agreement, dated August 29, 2014, by and among RSP Permian, L.L.C., as borrower, Comerica Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on September 4, 2014). | |
10.5 | Third Amendment to Amended and Restated Credit Agreement, dated September 12, 2014, by and among RSP Permian, L.L.C., as borrower, Comerica Bank, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-36264) filed with the Commission on September 18, 2014). | |
31.1(a) | Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a)/15d-14(a), by Chief Executive Officer. | |
31.2(a) | Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, Rule 13a-14(a)/15d-14(a), by Chief Financial Officer. | |
32.1(b) | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Executive Officer. | |
32.2(b) | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Financial Officer. | |
101.INS(c) | XBRL Instance Document. | |
101.SCH(c) | XBRL Taxonomy Extension Schema Document. | |
101.CAL(c) | XBRL Taxonomy Extension Calculation Linkbase Document. | |
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101.DEF(c) | XBRL Taxonomy Extension Definition Linkbase Document. | |
101.LAB(c) | XBRL Taxonomy Extension Label Linkbase Document. | |
101.PRE(c) | XBRL Taxonomy Extension Presentation Linkbase Document. | |
_______________________________________
(a) Filed herewith.
(b) Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.
(c) Furnished herewith. Pursuant to Rule 406T of Regulation S-T, these interactive data files are being furnished herewith and are not deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are not deemed filed for purposes of Section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.
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