Attached files
| file | filename |
|---|---|
| EX-99.1 - EXHIBIT 99.1 - RSP Permian, Inc. | a20171231ex991.htm |
| EX-32.2 - EXHIBIT 32.2 - RSP Permian, Inc. | a20171231ex322.htm |
| EX-32.1 - EXHIBIT 32.1 - RSP Permian, Inc. | a20171231ex321.htm |
| EX-31.2 - EXHIBIT 31.2 - RSP Permian, Inc. | a20171231ex312.htm |
| EX-31.1 - EXHIBIT 31.1 - RSP Permian, Inc. | a20171231ex311.htm |
| EX-23.2 - EXHIBIT 23.2 - RSP Permian, Inc. | a20171231ex232.htm |
| EX-23.1 - EXHIBIT 23.1 - RSP Permian, Inc. | a20171231ex231.htm |
| EX-21.1 - EXHIBIT 21.1 - RSP Permian, Inc. | a20171231ex211.htm |
| EX-12.1 - EXHIBIT 12.1 - RSP Permian, Inc. | a20171231ex121.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
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) |
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common stock, par value $0.01 per share | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý
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 Regulation S-T 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
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 “accelerated filer,” “large accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer | x | Accelerated filer o |
Non-accelerated filer | o (Do not check if a smaller reporting company) | Smaller reporting company o |
Emerging growth 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 aggregate market value of the common stock held by non-affiliates computed by reference to the price at which the common shares were last sold on the New York Stock Exchange as of June 30, 2017, was approximately $4.3 billion. In making the calculation, the registrant has assumed without adjusting for any other purpose, that all of its employees, directors, and entities controlled by or under common control with them, and no other parties, are affiliates.
The registrant had 159,441,447 shares of common stock outstanding at February 23, 2018.
DOCUMENTS INCORPORATED BY REFERENCE:
(1) Portions of the Definitive Proxy Statement for the Company’s Annual Meeting of Shareholders to be held during May 2018 are incorporated into Part III of this report.
TABLE OF CONTENTS
GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN
The following are abbreviations and definitions of certain terms used in this Annual Report on Form 10-K (this “Report”):
“Analogous Reservoir.” Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Bbl.” A standard barrel containing 42 U.S. gallons.
“Bcf.” One billion cubic feet of natural gas.
“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.
“Delineation.” The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.
“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development project.” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
“Development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“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.
“Downspacing.” Additional wells drilled between known producing wells to better exploit the reservoir.
“Drilled but uncompleted well.” A well that has been drilled but has not undergone the final steps of hydraulic fracturing and procedures necessary to place the well on production.
“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.
“Economically producible.” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
“Effective Horizontal Acreage.” The summation of our horizontal acreage across the multiple target zones. Although we believe this acreage metric more accurately conveys our horizontal drilling opportunities in our target zones, we cannot assure
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you that all, or any portion of our Effective Horizontal Acreage, is prospective for our target zones, that any portion of our Effective Horizontal Acreage will ever be drilled or that, if drilled, it will result in commercially productive wells.
“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.
“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
“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.
“LIBOR.” London Interbank Offered Rate, which is a market rate of interest.
“MBbl.” One thousand barrels.
“MBoe.” One thousand Boe.
“Mcf.” One thousand cubic feet.
“MMBbls.” One million barrels.
“MMBoe.” One million Boe.
“MMBtu.” One million British thermal units.
“MMcf.” One million cubic feet.
“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
“Net production.” Production that is owned by us less royalties and production due others.
“Net revenue interest.” A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.
“Net wells.” The total of fractional working interests owned in gross wells.
“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.
“PDP.” Proved developed producing.
“Play.” A geographic area with hydrocarbon potential.
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“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.
“Possible reserves.” Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. The SEC provides a complete definition of possible reserves in Rule 4-10(a)(17) of Regulation S-X.
“Probable reserves.” Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered. The SEC provides a complete definition of probable reserves in Rule 4-10(a)(18) of Regulation S-X.
“Production costs.” Costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Prospect.” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The SEC provides a complete definition of proved developed reserves in Rule 4-10(a)(6) of Regulation S-X.
“Proved reserves.” The estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. The SEC provides a complete definition of proved reserves in Rule 4-10(a)(22) of Regulation S-X.
“Proved undeveloped reserves” or “PUDs.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having PUDs only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years. The SEC provides a complete definition of proved undeveloped reserves in Rule 4-10(a)(31) of Regulation S-X.
“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.
“Reliable technology.” Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
“Reserves.” Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non‑productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
“Reserve life.” A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year‑end by production volumes. In our calculation of reserve life, production volumes are based on annualized fourth quarter production and are adjusted, if necessary, to reflect property acquisitions and dispositions.
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“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.
“Resources.” Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.
“SEC.” United States Securities and Exchange Commission.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40‑acre spacing, and is often established by regulatory agencies.
“Spot market price.” The cash market price without reduction for expected quality, transportation and demand adjustments.
“Standardized measure.” Discounted future net cash flows estimated by applying year‑end prices to the estimated future production of year‑end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period‑end costs to determine pre‑tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre‑tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate. The standardized measure does not purport to be the fair value of oil and gas reserves or properties; this would require consideration of expected future economic and operating conditions which are not taken into account in calculating the standardized measure.
“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” and “RSP” 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.
“Workover.” Operations on a producing well to restore or increase production.
“WTI.” West Texas Intermediate, a type of crude oil used as a benchmark in oil pricing and the underlying commodity of NYMEX oil futures contracts.
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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
Certain statements in this Report, 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, Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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 known 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 ability to successfully complete future acquisitions and to integrate them into our operations, 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 service providers to the Company, 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.”
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.
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PART I
ITEM 1. BUSINESS
General
RSP Permian, Inc., a Delaware corporation (“RSP Inc.,” the “Company,” “we,” “our,” or “us”), is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of the Company’s acreage is located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin, both sub-basins of the Permian Basin. The Midland Basin properties are primarily in the adjacent counties of Midland, Martin, Andrews, Ector, and Glasscock. The Delaware Basin properties are in Loving and Winkler counties. The Company’s common stock is listed and traded on the NYSE under the ticker symbol “RSPP.”
The Company’s executive offices are located at 3141 Hood St., Suite 500, Dallas, TX 75219, and the Company also maintains an office in Midland, Texas. The Company’s telephone number is 214-252-2700.
Business Activities
RSP Inc. is a leader in executing a multi-zone horizontal development program in the North Midland Basin with extensive industry knowledge relating to several productive zones on its properties. We target multiple oil and natural gas producing stratigraphic horizons, or stacked pay zones, on our properties. Since initiating our horizontal drilling program in the Midland Basin in late 2012, we have participated in the completion of 360 gross horizontal wells with wells completed in five different horizontal zones in the Midland Basin including the Middle Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp D. With the acquisition of Silver Hill, as defined below, we have acquired properties in which Silver Hill had horizontal wells completed in seven different zones in the Delaware Basin including the Brushy Canyon, 1st Bone Spring, 2nd Bone Spring, 3rd Bone Spring, Wolfcamp X/Y, Lower Wolfcamp A, and Wolfcamp B. As of December 31, 2017, we have participated in the completion of 29 gross horizontal wells in the Delaware Basin.
On October 13, 2016, the Company entered into definitive agreements to acquire 100% of Silver Hill Energy Partners, LLC (“SHEP I”) and Silver Hill E&P II, LLC (“SHEP II”, and together with SHEP I, “Silver Hill”) for $1.25 billion of cash and 31.0 million shares of RSP Inc. common stock in aggregate, implying a total purchase price of $2.4 billion (based on the 20-day volume weighted average price of RSP Inc. common stock). Substantially all of the purchase price was recorded to proved and unproved oil and natural gas properties on the Company’s balance sheet. The SHEP I acquisition closed on November 28, 2016 with a cash cost of $604.0 million, before purchase price adjustments, and 15.0 million shares of RSP Inc. common stock. The SHEP II acquisition closed on March 1, 2017, with cash consideration of $646.0 million, before purchase price adjustments, and approximately 16.0 million shares of RSP Inc. common stock.
Silver Hill was comprised of two privately held entities that collectively owned oil and gas producing properties and undeveloped acreage in Loving and Winkler counties in Texas. Silver Hill owned approximately 40,100 net acres with net production of approximately 15,000 Boe per day as of the acquisition announcement date. This highly contiguous acreage position in the core of the Delaware Basin was complementary to the Company’s existing asset base in the Midland Basin, and the acquisition created substantial scale from a production and acreage standpoint.
During 2017, our capital expenditures totaled $673.3 million, which included $610.6 million of drilling and completion activities and $62.7 million of infrastructure and other expenditures. The SHEP II acquisition closed on March 1, 2017 for a purchase price of $1.3 billion, before purchase price adjustments, that included cash consideration of $646.0 million, and approximately 16.0 million shares of RSP Inc. common stock, valued at $663.9 million based on our closing common share price of $41.44 per share on March 1, 2017. In addition, we spent $279.0 million on acquisitions of undeveloped acreage and additional mineral interests.
During 2016, our developmental capital expenditures, which includes drilling, completion, infrastructure and other and excludes acquisitions, totaled $294.2 million, which included approximately $275.5 million spent on drilling and completion activities and $18.7 million spent on infrastructure and other. The SHEP I acquisition closed on November 28, 2016 for a purchase price of $1.2 billion, before purchase price adjustments, that included cash consideration of $604.0 million, and approximately 15.0 million shares of RSP Inc. common stock valued at $595.9 million based on our closing common share price of $39.78 at the closing date. In addition, we spent $69.4 million on bolt-on acquisitions and additions to leasehold in the Midland Basin.
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For the year ended December 31, 2017, our average net daily production was 55,255 Boe/d (approximately 72% oil, 12% natural gas and 16% NGLs), and we operated and produced from 266 horizontal and 409 vertical wells.
As of December 31, 2017, our net proved reserves were approximately 375.9 MMBoe (70% oil, 17% NGLs and 13% natural gas), of which 42% were classified as PDP. Our estimated proved reserves were prepared by our internal engineers and audited by Netherland Sewell, our independent petroleum engineering firm, as of December 31, 2017.
Our board of directors has approved an initial capital budget for drilling, completion, and infrastructure and other for 2018 of approximately $815 million to $895 million which anticipates adding an eight rig and a third dedicated frac crew by the middle of the year. We continuously monitor commodity prices, our cash flow and returns to determine adjustments to our capital budget. We intend to allocate our 2018 capital budget approximately as follows:
•$725 million to $785 million for drilling and completion activities; approximately 10% of which is non-operated drilling and completion activities; and
•$90 million to $110 million for infrastructure and other.
Competition and Markets
General
As an operator, we design and manage the well development and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.
Marketing and Customers
We market the majority of the oil and natural gas production from properties we operate. We sell our oil, NGLs and natural gas production to purchasers at market prices. We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the year ended December 31, 2017, three purchasers individually accounted for more than 10% of our revenue: Enterprise Crude Oil, LLC (“Enterprise”) (21%), Western Refining (21%) and Shell Trading (US) Company (“Shell Trading”) (14%). For the year ended December 31, 2016, two purchasers individually accounted for more than 10% of our revenue: Enterprise (27%) and Shell Trading (23%). For the year ended December 31, 2015, four purchasers individually accounted for more than 10% of our revenue: Shell Trading (37%), Phillips 66 Company (22%), Diamondback E&P LLC (13%) and Enterprise (12%). Based on the current demand for oil, NGLs, and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations, as oil, NGLs, and natural gas are fungible products with well-established markets and numerous purchasers.
Transportation
During the initial development of our fields, we assess the gathering and delivery infrastructure in the areas of our production and then plan accordingly to arrange transportation to gathering systems or pipelines. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm or by pipeline. Our NGLs and natural gas are generally transported from the wellhead to the purchaser’s pipeline interconnection point through a third party gathering system.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Larger or more integrated competitors also may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer
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financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
There is also competition between oil and natural gas producers and other industries producing energy and fuel, such as nuclear, solar and wind. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil, NGLs and natural gas, and refinery turnaround and summer driving season affects demand for, and prices of oil. The prices of oil, NGLs and natural gas are heavily dependent on prevailing and expectations of future supply and demand factors, including current domestic and worldwide storage of each commodity and may not follow a seasonal pattern. Due to seasonal fluctuations or the other above factors impacting pricing, results of operations for individual periods may not be indicative of the results that may be realized on a long-term basis.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.
Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient right‑of‑way grants and permits from public authorities and private parties for us to operate our business.
Oil and Natural Gas Leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil, NGLs and natural gas produced from all wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 80%.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size
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of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective.
We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non‑compliance with environmental laws or regulations may be discovered.
Regulation of Production of Oil and Natural Gas
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Texas, which regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, NGLs and natural gas within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation of Transportation of Oil
Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost‑based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
In December 2015, H.R. 2029 was signed into law which lifted a ban on the export of oil from the United States. This will enable U.S. oil producers the flexibility to seek new markets and export oil into the global marketplace.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas
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Pipeline Act (the “NGPA”), and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (the “NGA”) and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.
The Domenici-Barton Energy Policy Act of 2005 (the “EPAct”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct amends the NGA to add an anti‑market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1,238,271 per day for each violation and disgorgement of profits associated with any violation. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti‑market manipulation provision of the EPAct, and subsequently denied rehearing. The rules make it unlawful: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti‑market manipulation rule does not apply to activities that relate only to intrastate or other non‑jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non‑jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti‑market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.
On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.
Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non‑jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by case basis, based on physical and geographic factors among others. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non‑jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC‑regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory‑take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti‑market manipulation laws and related regulations enforced by FERC under the EPAct and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission (the “CFTC”). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti‑market manipulation laws and regulations, we could also be subject to related third‑party damage claims by, among others, sellers, royalty owners and taxing authorities.
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FERC actively pursues anti-manipulation matters and has successfully upheld its actions in Federal Courts, and these enforcement actions may result in significant financial penalties or settlement payments. Also, additional policies, rules and legislation pertaining to those and other matters may be considered or adopted by FERC, Congress and the Courts from time to time. Failure to comply with FERC’s regulatory requirements in the future could subject us to civil penalty liability.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Our ability to access transportation options may also be impacted by FERC’s decision to review its long standing 1999 Pipeline Policy Statement on the certification of natural gas pipelines. On December 21, 2017 the current FERC Chairman, Kevin McIntyre issued a press release stating that the next steps in this process will be announced in the near future. This creates uncertainty regarding the development of future pipelines and FERC’s approval process for pipeline certifications. Any uncertainty in the availability of pipeline capacity or future pipeline capacity development could adversely affect our operations and costs.
Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.
Regulation of Environmental and Occupational Safety and Health Matters
Our oil and natural gas exploration and production operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; require notice to stakeholders of proposed and ongoing operations; require the installation of expensive pollution control equipment; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production. Federal, state, or local administrative decisions, developments in the federal or state court systems, or other governmental or judicial actions may influence the interpretation and/or enforcement of environmental laws and regulations and may thereby increase compliance costs. Environmental regulations have historically become more stringent over time and, thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation.
The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not
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uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We also generate materials in the course of our operations that may be regulated as hazardous substances. We are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.
The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency (the “EPA”) or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.
We currently own, lease or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off‑site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.
Water Discharges
The federal Water Pollution Control Act (the “Clean Water Act”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the EPA or, in some circumstances, the U.S. Army Corps of Engineers, or an analogous state agency. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.
Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on‑site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof.
In September 2015, new EPA and U.S. Army Corps of Engineers rules revising the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. To the extent the rule expands the scope of jurisdiction of the Clean Water Act, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Those regulations will be implemented as they were prior to the effective date of the new WOTUS rule. In January 2017, the U.S. Supreme Court accepted review of the WOTUS rule to determine whether jurisdiction to hear challenges to the rule rests with the federal district or appellate courts. In
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February 2017, the new Presidential administration issued an Executive Order directing the EPA and the Corps to review and, consistent with applicable law, to initiate a rule-making to rescind or revise the WOTUS rule. The EPA and the Corps published a notice of intent to review and rescind or revise the rule in March 2017. In addition, the U.S. Department of Justice filed a motion with the U.S. Supreme Court in March 2017 requesting that the U.S. Supreme Court stay the suit concerning which court should hear challenges to the rule. The U.S. Supreme Court denied the motion in April 2017. In June 2017, the EPA and the U.S. Army Corps proposed a rule that would initiate the first step in a two- step process intended to review and revise the definition of “waters of the United States” consistent with President Trump’s executive order. Under the proposal, the first step would be to rescind the May 2015 final rule and put back into effect the narrower language defining “waters of the United States” under the Clean Water Act that existed prior to the rule. The second step would be a notice-and- comment rule-making in which the agencies will conduct a substantive reevaluation of the definition of “waters of the United States.”
The primary federal law related specifically to oil spill liability is the Oil Pollution Act (“OPA”), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.
Air Emissions
The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre‑approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, the EPA has promulgated final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (the “NSPS”) and the Natural Emission Standards for Hazardous Air Pollutants (the “NESHAPS”) programs. With regards to production activities, these final rules have required, among other things, the reduction of volatile organic compound (“VOC”) emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non‑wildcat and non‑delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” wells must use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production‑related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. The rule is designed to limit emissions of VOC, sulfur dioxide, and hazardous air pollutants from a variety of sources within natural gas processing plants, oil and natural gas production facilities, and natural gas transmission compressor stations. In May 2016, the EPA issued new final rules that, among other things, imposed green completion requirements on all newly-fractured and refractured oil wells. This rule could require a number of modifications to our operations, including the installation of new equipment. However, in June 2017, the EPA proposed a two year stay of the fugitive emissions monitoring requirements, pneumatic pump standards, and closed vent system certification requirements in the 2016 New Source Performance Standards rule for the oil and gas industry while it reconsiders these aspects of the rule. The proposal is still under consideration. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.
Regulation of GHG Emissions
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to the public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best
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available control technology” standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis.
These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations. More recently, in May 2016, the EPA finalized a suite of regulations that established methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities.
The U.S. Bureau of Land Management (“BLM”) finalized similar rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements; however, in December 2017, the BLM temporarily suspended or delayed certain of these requirements set forth in its Venting and Flaring Rule until January 2019, pending administrate review of the rule. Increased regulation of methane and other GHGs have the potential to result in increased compliance costs and, consequently, adversely affect our operations.
On August 3, 2015, the EPA also issued new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this rule, nationwide carbon dioxide emissions would be reduced by approximately 30% from 2005 levels by 2030 with a flexible interim goal. Several industry groups and states challenged the rule. On February 9, 2016, the Supreme Court of the United States stayed the implementation of this rule pending judicial review. On March 28, 2017, President Trump signed an Executive Order directing the EPA to review the regulations, and on April 4, 2017, the EPA announced that it was reviewing the 2015 carbon dioxide regulations. On April 28, 2017, the U.S. Court of Appeals for the District of Columbia stayed the litigation pending the current administration’s review. That stay was extended for another 60 days on August 8, 2017. On October 10, 2017, the EPA initiated the formal rulemaking process to repeal the regulations. The EPA’s proposal will be subject to public comment and likely legal challenge, and as such we cannot predict at this time what impact the rulemaking will have on the demand for oil and natural gas production and our operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The number of allowances available for purchase is typically reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs and could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our exploration and production operations.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Federal Safe Drinking Water Act (the “SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in
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February 2014 addressing the performance of such activities using diesel fuels. Also, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Furthermore, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any federal disclosure requirements may affect our operations.
We may be subject to regulations that restrict our ability to discharge water produced as part of our production operations, and the ability to use injection wells as a disposal option not only will depend on federal or state regulations but also on whether available injection wells have sufficient storage capacities. For example, the EPA has issued a “no discharge” effluent limitation prohibiting oil and natural gas operators from transporting wastewater associated with hydraulic fracturing activities to publicly owned treatment works for disposal.
Certain governmental reviews have been conducted or are underway that focus on the potential environmental impacts of hydraulic fracturing. For example, the EPA has completed a study of the potential environmental effects of hydraulic fracturing on water resources and published a final report in December 2016. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Texas Railroad Commission issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. In 2013, the Texas Railroad Commission implemented its hydraulic fracturing disclosure rule, which requires oil and gas operators to disclose on the FracFocus website the chemical ingredients and water volumes used in hydraulic fracturing treatments. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Safe Drinking Water Act
Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The drilling and operation of these injection wells are regulated by the SDWA. The Underground Injection Well Program under the SDWA requires that we obtain permits from the EPA or delegated state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities of fluids that may be injected and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources, and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages, and personal injuries. Any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may adversely affect our ability to dispose of produced waters and could ultimately significantly increase the cost of our operations.
Endangered Species Act and Migratory Birds
The Endangered Species Act (the “ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service (the “FWS”) may designate
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critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially delay or prohibit land access for oil and natural gas development.
In addition, the federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non‑recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2016, nor do we anticipate that such expenditures will be material in 2017.
OSHA
We are subject to the requirements of the Occupation Health and Safety Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right‑to‑Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on‑going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long‑term pollution events.
Employees
As of December 31, 2017, we had 180 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe our employee relationships are satisfactory.
Available Information
We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file or furnish electronically with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov.
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We also make available free of charge through our website, www.rsppermian.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on or connected to our website is not incorporated by reference into this report and should not be considered part of this report or any other filing that we make with the SEC.
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ITEM 1A. RISK FACTORS
The nature of the business activities conducted by the Company subjects it to certain hazards and risks. The following is a summary of some of the material risks relating to the Company’s business activities. Other risks are described in “Part I. Item 1. Business—Competition and Markets” and “—Regulation of the Oil and Gas Industry,” and “Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” These risks are not the only risks facing the Company. The Company’s business could also be affected by additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial. If any of these risks actually occurs, it could materially harm the Company’s business, financial condition or results of operations and impair the Company’s ability to implement business plans or complete development activities as scheduled. In that case, the market price of the Company’s common stock could decline.
Oil, NGLs and natural gas prices are volatile. A reduction or sustained decline in commodity prices may adversely affect our operations, financial condition and level of expenditures for the development of oil, NGLs and natural gas reserves.
The prices we receive for our oil, NGLs and natural gas production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, NGLs and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor actual or expected changes in supply and demand for oil, NGLs and natural gas, market uncertainty and a variety of additional factors beyond our control. Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. Significant and sustained declines in the prices we receive for our oil, NGLs and natural gas production, such as the decline experienced from 2015 through 2017, could adversely affect our operations, financial condition, access to capital, future rate of growth, carrying value of our properties and level of expenditures. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control and include, but are not limited to, the following:
• | the level of global exploration and production; |
• | the level of global inventories; |
• | actions of the Organization of the Petroleum Exporting Countries, its members and other state-controlled oil companies relating to oil price and production controls; |
• | worldwide and regional economic conditions affecting the global supply and demand for oil, NGLs and natural gas; |
• | the price and quantity of imports of foreign oil, NGLs and natural gas; |
• | political and economic conditions in or affecting other producing countries, including U.S. sanctions on oil producing countries and conflicts in the Middle East, Africa, South America and Russia; |
• | prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices; |
• | the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices; |
• | localized and global supply and demand fundamentals and transportation availability; |
• | the cost of exploring for, developing, producing and transporting reserves; |
• | weather conditions and other natural disasters; |
• | technological advances affecting energy consumption; |
• | the price and availability of alternative fuels; |
• | expectations about future commodity prices; |
• | domestic, local and foreign governmental regulation and taxes; |
• | speculation as to the future price of oil, NGLs and natural gas and the speculative trading of oil, NGLs and natural gas and the trading prices of future contracts; and |
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• | effect of energy conservation efforts. |
The long-term effects of these and other conditions on the prices of oil, NGLs and natural gas are uncertain. Global economic and political conditions have driven oil and natural gas prices down from their highs significantly since 2014. These conditions may continue for an extended period.
Lower commodity prices may reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil, NGLs and natural gas that we can produce economically, and a significant portion of our exploitation, development and exploration projects could become unprofitable. This may result in us having to make significant downward adjustments to our estimated proved reserves and impair the carrying value of assets. As a result, if commodity prices remain depressed for a lengthy period of time or experience a further substantial or extended decline, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures may be materially and adversely affected.
Our derivative activities could result in financial losses or could reduce our earnings. Additionally, our hedging program may not protect us against continuing and prolonged declines in the price of oil, NGLs and natural gas.
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil, NGLs and natural gas, we enter into derivative instruments from time to time to hedge a portion of our production that could result in both realized and unrealized losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity derivative contracts. As of December 31, 2017, we had entered into hedging contracts covering approximately 10,707 MBbls and 2,555 MBbls of our projected oil production for 2018 and 2019, respectively. Subsequent to December 31, 2017, we entered into additional hedging contracts covering approximately 698 MBbls and 2,555 MBbls of our projected oil production for 2018 and 2019, respectively. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments may expose us to the risk of financial loss in some circumstances, including when:
• | production is less than the volume covered by the derivative instruments; |
• | the counterparty to the derivative instrument defaults on its contractual obligations; |
• | there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or |
• | there are issues with regard to legal enforceability of such instruments. |
The use of derivative instruments may, in some cases, require the posting of collateral, including cash collateral, with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.
As of December 31, 2017, the estimated fair value of our commodity derivative contracts was a net liability of approximately $42.2 million. Any default by the counterparties to these derivative contracts when they become due may have a material adverse effect on our financial condition and results of operations.
In addition, our actual future production may be significantly higher or lower than we estimate at the time we enter into commodity derivative contracts for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we projected. If the actual amount is lower than the notional amount of our commodity derivative contracts, we might be forced to satisfy all or a portion of our commodity derivative contracts without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, substantially diminishing our liquidity. There may be a change in the expected differential between the underlying commodity price in the commodity derivative contract and the actual price received, which may result in payments to our derivative counterparty that are not offset by our receipt of payments for our production in the field.
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Our exploitation, development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow reserves.
Our business is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development and acquisition of oil and natural gas reserves.
We expect to fund 2018 capital expenditures with cash generated by operations, borrowings under our revolving credit facility, as amended and restated (“Revolving Credit Facility”), our cash balance at year-end, and possibly offerings of our debt and equity securities. These funding methods could adversely impact our financial condition through increased leveraged or debt with restrictive covenants. Additional financing also may not be available on acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail drilling, development and other activities, which in turn could lead to a decline in our reserves and production or require us to sell some of our assets on an untimely or unfavorable basis.
Our cash flow from operations and access to other capital to finance our exploitation, development and exploration of near-term wells and our identified drilling locations over many years are subject to a number of variables, including:
• | the prices at which our production is sold; |
• | the level of hydrocarbons we are able to produce from existing wells; |
• | our proved reserves; |
• | our ability to acquire, locate and produce new reserves; |
• | the levels of our operating expenses; |
• | our ability to borrow under our Revolving Credit Facility and our ability to access the capital markets; and |
• | the scope, rate of progress and cost of our exploration, appraisal and development activities. |
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:
• | landing our wellbore in the desired drilling zone; |
• | staying in the desired drilling zone while drilling horizontally through the formation; |
• | running our casing the entire length of the wellbore; |
• | being able to run tools and other equipment consistently through the horizontal wellbore; and |
• | effectively controlling the level of pressure flowing from particular wells. |
Risks that we face while completing our wells include, but are not limited to, the following:
• | the ability to fracture stimulate the planned number of stages; |
• | the ability to run tools the entire length of the wellbore during completion operations; and |
• | the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage. |
In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of our drilling in new or emerging formations are initially more uncertain than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our
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drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, and we could incur material write‑downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future.
Drilling for and producing oil and natural gas are high‑risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.
Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including, but not limited to, the following:
• | delays imposed by or resulting from compliance with regulatory requirements including limitations resulting from wastewater disposal, discharge of GHGs and limitations on hydraulic fracturing; |
• | pressure or irregularities in geological formations; |
• | shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities; |
• | equipment failures, accidents or other unexpected operational events; |
• | lack of available gathering facilities or delays in construction of gathering facilities; |
• | lack of available capacity on interconnecting transmission pipelines; |
• | adverse weather conditions; |
• | issues related to compliance with environmental regulations; |
• | environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment; |
• | declines in oil and natural gas prices; |
• | limited availability of financing at acceptable terms; |
• | loss of title or other title problems; |
• | limitations in the market for oil and natural gas; and |
• | oil, NGLs or natural gas gathering, transportation and processing availability restrictions or limitations. |
We contract with third parties to conduct drilling and related services on our development projects and exploration prospects for us. Such third parties may not perform the services they provide us on schedule or within budget. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third parties we contract with is highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays, which could be substantial. Any delays in our drilling program caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs of drilling and adversely affect our business, financial position and results of operations.
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Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.
In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, NGLs and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. For instance, initial production rates reported by us or other operators may not be indicative of future or long‑term production rates. In addition, stated recovery efficiencies may vary from projected rates and production declines may deviate from current estimates and may be more rapid and irregular when compared to initial production rates. We may also adjust reserve estimates to reflect additional production history, results of exploration and development activities, current commodity prices and other existing factors.
You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.
Our operations are substantially dependent on the availability of water and sand, which may be hard or expensive to obtain.
Water and sand are essential components of deep shale oil and natural gas production processes. Our ability to obtain water and sand for our operations may be affected by the price of water and sand, the availability of transportation and other market conditions. Additionally, some governmental authorities have restricted the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. Other regulations may restrict our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. Furthermore, future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, which could have an adverse effect on our operations and financial performance. If we are unable to obtain water or sand to use in our operations, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area and reducing our realized price of oil.
All of our producing properties are geographically concentrated in the Permian Basin of West Texas. At December 31, 2017, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, NGLs or natural gas.
In addition, all of our oil contracts are impacted by the Midland-Cushing price differential, which reflects the difference between the price of crude at Midland, Texas, versus the price of crude at Cushing, Oklahoma, a major hub where production from Midland is often transported via pipeline. The price we currently realize on barrels of oil we sell is reduced by the value of the Midland-Cushing differential, which from 2014 to 2017 reached as high as $2.75 per barrel on August 13, 2015 and as low
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as negative $21.00 per barrel on August 19, 2014. If the Midland-Cushing differential, or other price differentials pursuant to which our production is subject, were to widen due to oversupply or other factors, our revenue could be negatively impacted.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable or become more costly, our operations could be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our own gathering systems as well as third party gathering systems. Our purchasers then transport the oil by truck or pipeline. Our natural gas production is generally transported by gathering lines from the wellhead to a gas processing facility. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities, or other production facilities, could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an increase in cost for delivery of the oil and natural gas produced from our fields, could materially and adversely affect our financial condition and results of operations.
We may incur losses as a result of title defects.
The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
The development of our estimated proved undeveloped reserves “PUDs” may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.
As of December 31, 2017, 58% of our total estimated proved reserves were classified as proved undeveloped. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Further, we may be required to write down our PUDs if we do not drill those wells within five years after their respective dates of booking.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write‑downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non‑cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
We periodically assess our unproved oil and natural gas properties for impairment and could be required to recognize non-cash charges to earnings in future periods.
At December 31, 2017, our unproved property costs totaled $2.9 billion. Unproved property costs are assessed quarterly for potential impairment and when industry conditions dictate an impairment may be possible. Our assessment considers lease expirations, future drilling and exploration plans, results of exploration activities and commodity price outlooks. Based on our assessments, we may determine that we are unable to fully recover the cost invested in each project, and we will recognize non-cash charges to earnings in future periods if such determination is made.
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Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, tax advantages and other subsidies to support alternative energy sources, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.
We depend upon several significant purchasers for the sale of most of our oil, NGLs and natural gas production.
Domestic and global economic conditions, especially in the energy industry, are volatile and there is the possibility that lenders could react by tightening credit. These conditions and factors may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.
Moreover, our contractual counterparties may be unable to satisfy their contractual obligations to us due to the volatile market or other reasons. If a counterparty is unable to satisfy its contractual obligation to purchase oil, NGLs or natural gas from us, we may be unable to sell such production to another customer on terms we consider acceptable. Furthermore, the inability of our contractual counterparties to pay amounts owed to us and to otherwise satisfy their contractual obligations to us and third parties may materially and adversely affect our business, financial condition, results of operations, and cash flows.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.
Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations on our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.
Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
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• | injury or loss of life; |
• | damage to and destruction of property, natural resources and equipment; |
• | pollution and other environmental damage; |
• | regulatory investigations and penalties; |
• | suspension of our operations; and |
• | repair and remediation costs. |
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
We must replace production but properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Producing oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserve base and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.
There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable, if at all. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. In addition, the use of micro‑seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. Even when properly used and interpreted, 2‑D and 3‑D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3‑D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.
Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:
• | unexpected drilling conditions; |
• | title problems; |
• | pressure or lost circulation in formations; |
• | equipment failure or accidents; |
• | adverse weather conditions; |
• | compliance with environmental and other governmental or contractual requirements; and |
• | increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services. |
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As a result, our drilling activities may not be successful or economical.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.
From time to time, we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may be unable to complete the acquisitions, or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, successfully completing acquisitions.
The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, our Revolving Credit Facility, the indenture governing our 6.625% senior notes due 2022 (“2022 Senior Notes”) and the indenture governing our 5.25% senior notes due 2025 (“2025 Senior Notes”, and collectively, the “senior notes”) impose certain limitations on our ability to enter into mergers or combination transactions. Our Revolving Credit Facility and the indentures also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses. If we desire to engage in an acquisition that is otherwise prohibited by our Revolving Credit Facility or the indentures governing our senior notes, we will be required to seek the consent of our lenders or the holders of the senior notes in accordance with the requirements of the credit facility or the indentures, which consent may be withheld by the lenders under our Revolving Credit Facility or such holders of senior notes at their sole discretion.
Any acquisition we complete is subject to risks that could adversely affect our business, including the risk that our acquisitions may prove to be worth less than what we paid because of uncertainties in evaluating recoverable reserves and could expose us to potentially significant liabilities.
We have obtained a significant portion of our current reserve base through acquisitions of producing properties and undeveloped acreage. The success of any acquisition involves potential risks, including among other things:
• | the inability to estimate accurately the costs to develop the reserves, recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves; |
• | the assumption of unknown liabilities, including environmental liabilities, and losses or costs for which the Company is not indemnified or for which the indemnity the Company receives is inadequate; |
• | the effect on our liquidity or financial leverage of using available cash or debt to finance acquisitions; and |
• | the diversion of management’s attention from other business concerns. |
Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact, and we cannot make these assessments with a high degree of accuracy. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation, accounting or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
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We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.
Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGLs prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon and increased demand for labor, services and materials as drilling activity increases. Decreased levels of drilling activity in the oil and natural gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise quickly if commodity prices, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget.
Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.
Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. These land use restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be precluded from the drilling of wells.
The unavailability of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages both in high and low price environments. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. Additionally, during periods of low prices, the labor pool may be reduced and equipment retired, causing shortages when activity levels pick up. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire. Equipment shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
Our business depends in part on pipelines, transportation and gathering systems and processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil, natural gas and NGLs production and could harm our business. In particular, the marketability of our oil, natural gas and NGLs production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, such as trucks, gathering systems and processing facilities owned by third parties. The amount of oil, natural gas and NGLs that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. Also, the transfer of our oil, natural gas and NGLs on third party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. Our access to transportation options, including trucks owned by third parties, can also be affected by U.S. federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation or processing facility capacity could reduce our ability to market our oil, natural gas and NGLs production and harm our business.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the EPAct, the FERC has civil penalty authority under the NGA and the Natural Gas Policy Act to impose penalties for current violations of up to $1,213,503 per day for each violation and disgorgement of profits associated with any violation. We believe our operations are exempt from regulation by FERC as a natural gas gathering and exploration company under the NGA. However, FERC has adopted regulations that may subject certain of our otherwise non‑FERC jurisdictional operations to FERC annual reporting and posting requirements. In addition, we must comply with the anti‑market manipulation rules and transparency rules and regulations enforced by FERC. FERC actively pursues anti-manipulation matters and has successfully upheld its actions in Federal Courts, and these enforcement actions may result in significant financial penalties or settlement
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payments. Also, additional policies, rules and legislation pertaining to those and other matters may be considered or adopted by FERC, Congress and the Courts from time to time. Failure to comply with FERC’s regulatory requirements in the future could subject us to civil penalty liability, as described in “Part I. Item 1. Business-Regulation of the Oil and Natural Gas Industry.”
Climate change laws and regulations could result in increased operating costs and reduced demand for the oil and natural gas that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, limit tailpipe emissions from motor vehicles and require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions must meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case‑by‑case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the United States, as well as onshore and offshore oil and natural gas production sources, on an annual basis, which include certain of our operations. Recent federal regulatory action with respect to climate change has focused on methane emissions. In 2016, the EPA finalized new air emission control requirements for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The final rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and also imposes leak detection and repair requirements on operators. The BLM adopted similar rules in January 2017 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. Operators generally had one year from rule’s effective date to come into compliance with the rule’s requirements. However, in December 2017, the BLM temporarily suspended or delayed certain of these requirements set forth in its Venting and Flaring Rule until January 2019, pending administrate review of the rule.
In the absence of additional federal climate legislation and the scaling back of environmental regulations under President Trump, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. It should also be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our exploration and production operations.
Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their GHGs. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
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Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. Also, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations.
We may be subject to regulations that restrict our ability to discharge water produced as part of our production operations, and the ability to use injection wells as a disposal option not only will depend on federal or state regulations but also on whether available injection wells have sufficient storage capacities. In June 2016, the EPA issued a final rule banning the disposal of wastewater from unconventional oil and gas wells to public wastewater and sewage treatment plants. Produced and other flowback water from our current operations in the Permian Basin is typically not discharged to wastewater treatment plants but is re-injected into underground formations that do not contain potable water.
Further, the EPA has promulgated final rules that subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the NSPS and NESHAPS programs. These rules include NSPS standards for completions of hydraulically‑fractured gas wells. The standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are applicable to newly drilled and fractured wells and wells that are refractured. Further, the rules under NESHAPS include Maximum Achievable Control Technology (“MACT”) for glycol dehydrators and storage vessels at major source of hazardous air pollutants not currently subject to MACT standards. On May 12, 2016, the EPA issued three additional rules for the oil and gas industry to reduce emissions of methane, VOCs and other compounds. These rules apply to all new, reconstructed, and modified processes and equipment since September 2015. Among other things, the new rules impose green completion requirements on new hydraulically fractured oil wells and reduce allowable emissions of methane and VOCs. In June 2017, the EPA proposed a two year stay of the fugitive emissions monitoring requirements, pneumatic pump standards, and closed vent system certification requirements in the 2016 New Source Performance Standards rule for the oil and gas industry while it reconsiders these aspects of the rule. The proposal is still under consideration.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, the Texas Railroad Commission has issued a “well integrity rule,” that includes requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. In 2013, the Texas Railroad Commission implemented its hydraulic fracturing disclosure rule, which requires oil and gas operators to disclose on the FracFocus website the chemical ingredients and water volumes used in hydraulic fracturing treatments. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas, and secure and maintain trained personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, market oil and natural gas and secure and maintain trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Our competitors may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our
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financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on favorable terms. These companies may have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the current commodity price environment, and to absorb the burden of current and future governmental regulations and taxation. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.
Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut‑in of production and difficulties in the transportation of our oil, NGLs and natural gas. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.
We are susceptible to the potential difficulties associated with rapid growth and expansion.
We have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:
• | increased responsibilities for our executive level personnel; |
• | increased administrative burden; |
• | increased capital requirements; and |
• | increased organizational challenges common to large, expansive operations. |
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future.
Increases in the cost of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Volatility, negative or uncertain economic and political conditions in our significant markets could undermine business confidence and may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
Recently enacted legislation will affect our tax position, and one day, certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated, and additional state taxes on oil and natural gas extraction may be imposed, as a result of future legislation.
In December 2017, Congress enacted the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (“Tax Act”). The law made significant changes to U.S. federal income tax laws, including reducing the corporate income tax rate to 21%, repeal of the corporate alternative minimum tax (“AMT”), partially limiting the deductibility of interest expense and net operating losses, eliminating the deduction for certain U.S. production activities, and allowing the immediate deduction of certain new investments in lieu of depreciation expense over time. As a result of the Tax Act, we recorded a one-time, non-cash adjustment to the income tax provision of $144.4 million for the quarter ended December 31, 2017. The ultimate impact of the Tax Act on our reported results in fiscal 2018 and beyond may differ from the estimates provided herein, possibly materially, due to, among other things, changes in interpretations and assumptions we have made, guidance that may be issued, and other actions we may take as a result of the Tax Act.
In recent years, lawmakers and Treasury have proposed certain significant changes to U.S. tax laws applicable to oil and gas companies. These changes include, but are not limited to: (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an
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extension of the amortization period for certain geological and geophysical expenditures. Although these changes were not included in the Tax Act, it is unclear whether any such changes will be enacted or if enacted, when such changes could be effective. If such proposed changes are ever made, as well as any similar changes in state law, it could eliminate or postpone certain tax deductions that are currently available to us with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations.
Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil, NGLs and natural gas.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material and adverse impact on our ability to develop and produce our reserves.
Derivatives legislation and implementing rules could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risk, interest rate risk and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd Frank Act”), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. While some of these rules have been finalized, some have not been finalized. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; however, this initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. The CFTC has subsequently issued proposals for new rules that would place position limits on certain core futures contracts and equivalent swap contracts for or linked to certain physical commodities, subject to certain exceptions, though these rules have not been finalized. The CFTC has designated certain interest rate swaps and credit default swaps subject to mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, subject to mandatory clearing. The full impact of the Dodd-Frank Act and related regulatory requirements upon the Company’s business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. When fully implemented, the Dodd-Frank Act and any new regulations could increase the operational and transactional cost of derivatives contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the ability of the Company to monetize and restructure its existing derivatives contracts and affect the number and/or creditworthiness of available counterparties. If the Company reduces its use of derivatives as a result of the Dodd-Frank Act and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, or if we are unable to use the most advanced commercially available technology, our business, financial condition or results of operations could be materially and adversely affected.
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We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.
Any significant reduction in our borrowing base under our Revolving Credit Facility as a result of the periodic borrowing base redeterminations, or otherwise, may negatively impact our ability to fund our operations.
Our Revolving Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi‑annual basis based, among other things, upon projected revenues from, and asset values of, the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Revolving Credit Facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. The borrowing base under our Revolving Credit Facility is currently $1.5 billion, with lender commitments of $2.5 billion.
In the future, we may not be able to access adequate funding under our Revolving Credit Facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in the lenders’ lowering the borrowing base. In such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base and revise our drilling plan to account for our access to less capital under our Revolving Credit Facility.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our Revolving Credit Facility and the senior notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Revolving Credit Facility and indentures governing the senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
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Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payments on our debt obligations.
As of December 31, 2017, we had $1.15 billion of senior unsecured notes outstanding, $1.9 million of letters of credit outstanding under our Revolving Credit Facility, and $523.1 million of borrowing capacity under our Revolving Credit Facility. Our level of indebtedness could affect our operations in several ways, including the following:
• | require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities; |
• | limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; |
• | increase our vulnerability to downturns and adverse developments in our business and the economy generally; |
• | limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness; |
• | place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations; |
• | make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then‑outstanding bank borrowings; |
• | make us vulnerable to increases in interest rates as our indebtedness under our Revolving Credit Facility may vary with prevailing interest rates; |
• | place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and |
• | make it more difficult for us to satisfy our obligations under our debt instruments and increase the risk that we may default on our debt obligations. |
Our Revolving Credit Facility and the indentures governing the senior notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in certain activities.
Our Revolving Credit Facility and the indentures governing the senior notes have restrictive covenants that could limit our growth, financial flexibility and our ability to engage in activities that may be in our long‑term best interests. Our Revolving Credit Facility and the indentures governing the senior notes contain covenants, that, among other things, limit our ability to:
• | incur additional indebtedness; |
• | make loans to others; |
• | make investments; |
• | merge or consolidate with another entity; |
• | make dividends and certain other payments; |
• | hedge future production or interest rates; |
• | incur liens that secure indebtedness; |
• | sell assets; |
• | enter into transactions with affiliates; and |
• | engage in certain other transactions without the prior consent of the lenders. |
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In addition, our Revolving Credit Facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios, which may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of these limitations.
If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed.
Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest, or special interest, if any, on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the agreements governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default:
• | the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest; |
• | the lenders under our Revolving Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and |
• | we could be forced into bankruptcy or liquidation. |
If our operating performance declines, we may in the future need to obtain waivers under our Revolving Credit Facility to avoid being in default. If we breach our covenants under our Revolving Credit Facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our Revolving Credit Facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.
A downgrade in our credit rating could negatively impact our cost of and ability to access capital.
We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular reviews. S&P and Moody’s consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels and asset and reserve mix.
A downgrade in our credit ratings could negatively impact our cost of capital and our ability to effectively execute aspects of our strategy. Further, a downgrade in our credit ratings could affect our ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt. These and other impacts of a downgrade in our credit ratings could have a material adverse effect on our business, financial condition and results of operations.
The Company’s business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations. For example, the industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. Our technologies, systems, networks, and those of our business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, misuse, loss or destruction of proprietary and other information, or other disruption of business operations that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage the Company’s reputation and lead to financial losses from remedial actions, loss of business or potential liability.
Other risk factors
Additional discussion of risks and uncertainties related to price and demand, litigation, environmental matters, oil and gas reserves estimation processes, impairments, derivatives, market risks and internal controls appear elsewhere in this report. The risks described in this report are not the only risks we face and other risks, including risks deemed immaterial, may have a material adverse effect on us, our financial condition and results of operations.
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ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Our properties as of December 31, 2017 include working interests in approximately 142,000 gross and 92,000 net surface acres located in the Permian Basin primarily in the Texas counties of Midland, Martin, Andrews, Ector, Glasscock, Loving and Winkler.
The Permian Basin consists of mature, legacy onshore oil and liquids-rich natural gas reservoirs that span approximately 86,000 square miles in West Texas and New Mexico. It is composed of three sub basins, the Delaware Basin, the Central Basin Platform and the Midland Basin. Both the Midland Basin and the Delaware Basin are characterized by extensive operating histories, favorable operating environments, available infrastructure and a well-developed network of oilfield service providers, long reserve lives, multiple producing horizons, and a large number of operators. The first commercial wells were drilled in both basins during the 1920’s. Advances in geologic understanding and production technology have highlighted the resource potential of these basins unconventional reservoirs that are productive after hydraulic-fracture stimulation. Technological advances in 3-D seismic imagery have demonstrated the larger geographic extent of the unconventional formations than originally estimated and, due to multiple stacked pay zones, significantly more oil in place as compared to other major U.S. shale oil plays. In recent years, drilling activity in the Permian Basin has shown a growing trend towards horizontal and directional drilling over vertical drilling.
The vast majority of our acreage is located on large, contiguous acreage blocks in the core of the Midland Basin and Delaware Basin. The Midland Basin properties are primarily in the adjacent Texas counties of Midland, Martin, Andrews, Ector, and Glasscock. The Delaware Basin properties are located in the adjacent Texas counties of Loving and Winkler. We believe that our properties are prospective for oil and liquids-rich natural gas from multiple producing stratigraphic horizons, which we refer to as stacked pay zones.
As of December 31, 2017, we had identified 6,970 gross horizontal drilling locations. We define identified drilling locations as locations specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant, such as easement restrictions and state and local regulations, are considered in determining such locations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, access to offtake systems, lease expirations, availability of service providers and materials and other factors.
Our contiguous acreage positions allow us to drill longer laterals, maximize our resource recovery on a per-section basis and increase our returns. In addition, our contiguous acreage positions allow us the flexibility to adjust our drilling and completion techniques, primarily the length of our horizontal laterals, in order to maximize our well results, drilling costs and returns. Our contiguous acreage positions and owning leases covering virtually all of the depths of our properties allow us to target multiple horizontal zones underneath our surface acreage. Our total Effective Horizontal Acreage is approximately 544,000 net acres when considering the multiple zones under the surface acreage in our core areas, which we believe more accurately conveys the extent of our horizontal drilling opportunities in our target zones.
Our estimated proved reserves and future net cash flows were prepared by our internal engineers and audited by Netherland, Sewell & Associates, Inc. (“Netherland Sewell”), our independent petroleum engineering firm, as of December 31, 2017. Our net proved reserves as of December 31, 2017 were approximately 375.9 MMBoe (70% oil, 17% NGLs and 13% natural gas), of which 42% were classified as PDP. The estimated proved reserves are generally characterized as long-lived, with predictable production profiles.
Production Status. For the year ended December 31, 2017, our average net daily production was 55,255 Boe/d (approximately 72% oil, 16% NGLs and 12% natural gas), and we operated and produced from 266 horizontal and 409 vertical wells. For the year ended December 31, 2016, our average net daily production was 29,161 Boe/d (approximately 73% oil, 16% NGLs and 11% natural gas).
Facilities. We strive to develop the necessary infrastructure to lower our costs and support our drilling schedule and production growth. We accomplish this goal through a combination of developing a portion of our own midstream assets as well as through contractual arrangements with third party service providers. Our facilities located on our properties are
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generally in close proximity to our well locations and include storage tank batteries, oil/gas/water separation equipment and pumping units.
In addition to standard well site surface equipment, we have invested our capital in building gathering lines and water infrastructure, including water pipelines, water source wells and water disposal wells to support our exploration and development activities. To secure adequate water supplies for our Midland Basin operations, we have drilled water source wells into the Santa Rosa formation that complement our purchase of fresh water. For our Delaware Basin operations, we source water from an aquifer that is adjacent to our operating area. We also operate saltwater disposal wells on our properties, including disposal wells purchased in the first quarter of 2017 that support our development activities in the Delaware Basin. We have a minority investment in a small private midstream company that engages in the building and operation of water infrastructure on our properties, and for third parties.
Oil and Natural Gas Data
Proved Reserves
Evaluation and Review of Proved Reserves. Our proved reserve estimates and future net cash flows were prepared by our internal engineers and audited by Netherland Sewell, our independent petroleum engineering firm, as of December 31, 2017 and December 31, 2015. Our estimated proved reserves and future net cash flows were prepared by Netherland Sewell as of December 31, 2016. The technical person primarily responsible for preparing or auditing our proved reserve estimates set forth in the Netherland Sewell letter meets the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Netherland Sewell does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of the independent petroleum engineering firm’s proved reserve audit letter as of December 31, 2017 is included as an exhibit to this Report.
We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to Netherland Sewell for our properties, such as ownership interest, oil, NGLs and natural gas production, well test data, commodity prices and operating and development costs. Our Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 14 years of reservoir and operations experience, and our geoscience staff has an average of approximately 20 years of energy industry experience per person.
The preparation of our proved reserve estimates is completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
• | review and verification of historical production data, which data is based on actual production as reported by us; |
• | preparation of reserve estimates by our Vice President of Reservoir Engineering or under his direct supervision; |
• | review by our Chief Executive Officer of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new PUDs additions; |
• | direct reporting responsibilities by our Vice President of Reservoir Engineering to our Chief Operating Officer; and |
• | verification of property ownership by our land department. |
Estimation of Proved Reserves. Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2017, 2016 and 2015 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil, NGLs and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil, NGLs and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These
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methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. Non-producing reserve estimates for undeveloped properties were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting PUDs for our properties due to the mature nature of the properties targeted for development and an abundance of subsurface control data.
To estimate economically recoverable proved reserves and related future net cash flows, many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates were considered.
Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.
Summary of Oil and Natural Gas Reserve Estimates. The following table presents our estimated net proved oil, NGLs and natural gas reserves as of December 31, 2017, 2016, and 2015 prepared in accordance with the rules and regulations of the SEC. All of our proved reserves are located in the United States.
Year ended December 31, | |||||||||
2017 | 2016 | 2015 | |||||||
Proved developed reserves: | |||||||||
Oil (MBbls) | 106,668 | 65,025 | 44,128 | ||||||
Natural gas (MMcf) | 133,116 | 76,255 | 56,640 | ||||||
NGLs (MBbls) | 30,162 | 18,759 | 11,020 | ||||||
Total (MBoe) | 159,016 | 96,493 | 64,588 | ||||||
Proved undeveloped reserves: | |||||||||
Oil (MBbls) | 154,667 | 99,703 | 67,007 | ||||||
Natural gas (MMcf) | 161,903 | 100,531 | 76,867 | ||||||
NGLs (MBbls) | 35,275 | 23,937 | 14,767 | ||||||
Total (MBoe) | 216,926 | 140,395 | 94,585 | ||||||
Total proved reserves: | |||||||||
Oil (MBbls) | 261,335 | 164,728 | 111,135 | ||||||
Natural gas (MMcf) | 295,019 | 176,786 | 133,507 | ||||||
NGLs (MBbls) | 65,437 | 42,696 | 25,787 | ||||||
Total (MBoe) | 375,942 | 236,888 | 159,173 | ||||||
The following discussion and analysis of our proved oil, NGLs and natural gas reserves and changes in our proved reserves is intended to provide additional guidance on the operational activities, transactions, economic and other factors which significantly impacted our estimate of proved reserves as of December 31, 2017 and changes in our proved reserves during 2017. This discussion and analysis should be read in conjunction with Note 12 in the notes to our consolidated financial statements. The following table summarizes the changes in our proved reserves from January 1, 2017 to December 31, 2017.
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Oil (MBbls) | Natural Gas (MMcf) | NGLs (MBbls) | MBoe | |||||||||
Proved developed and undeveloped reserves: | ||||||||||||
As of January 1, 2017 | 164,728 | 176,786 | 42,696 | 236,888 | ||||||||
Production | (14,445 | ) | (15,126 | ) | (3,202 | ) | (20,168 | ) | ||||
Extensions and discoveries | 64,925 | 73,698 | 16,009 | 93,217 | ||||||||
Purchases of minerals in place | 34,997 | 33,772 | 6,859 | 47,485 | ||||||||
Revisions of previous estimates | 11,130 | 25,889 | 3,075 | 18,520 | ||||||||
As of December 31, 2017 | 261,335 | 295,019 | 65,437 | 375,942 | ||||||||
For the year ended December 31, 2017, our extensions and discoveries of 93,217 Mboe were primarily the result of our continued horizontal drilling program in both the Midland Basin and the Delaware Basin. This includes 65,657 Mboe of new proved undeveloped locations added during the year. The purchases of minerals in place of 47,485 Mboe were primarily related to the SHEP II acquisition that closed in March 2017, as further described in Note 3 in the notes to our consolidated financial statements. Positive revisions of previous estimates of 18,520 Mboe were primarily related to modified spacing in certain sections, improved performance on certain wells based on additional historical results incorporated to our reserve estimates and higher prices.
Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Item 1. Risk Factors.”
PUDs
As of December 31, 2017, our PUDs comprised of 154,667 MBbls of oil, 35,275 MBbls of NGLs and 161,903 MMcf of natural gas, for a total of 216,926 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
The following table summarizes the changes in our PUDs for the year ended December 31, 2017:
MBoe | |||
As of January 1, 2017 | 140,395 | ||
Extensions and discoveries (1) | 65,657 | ||
Purchases of minerals in place (2) | 32,390 | ||
Conversion to proved developed reserves (3) | (20,054 | ) | |
Revisions of previous estimates (4) | (1,462 | ) | |
As of December 31, 2017 | 216,926 | ||
(1) Extensions and discoveries resulted from drilling of wells to delineate our acreage position.
(2) Purchases of PUDs were primarily attributable to the SHEP II acquisition that closed on March 1, 2017.
(3) Capital costs incurred to convert PUDs to proved developed reserves were $173.6 million.
(4) Revisions of previous estimates were primarily due to negative revisions of previous estimated quantities due to the reclassification of certain PUDs to unproved pursuant to the five-year development rule established by the SEC, partially offset by positive revisions due to performance and price.
All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.
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Oil and Natural Gas Production, Prices and Costs
Production and Price History
The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:
Years ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
Production data: | ||||||||||||
Oil (MBbls) | 14,445 | 7,790 | 5,805 | |||||||||
Natural gas (MMcf) | 15,126 | 7,188 | 4,991 | |||||||||
NGLs (MBbls) | 3,202 | 1,685 | 1,045 | |||||||||
Total (MBoe) | 20,168 | 10,673 | 7,682 | |||||||||
Average net daily production (Boe/d) | 55,255 | 29,161 | 21,047 | |||||||||
Average realized prices before effects of hedges(1)(2): | ||||||||||||
Oil (per Bbl) | $ | 48.79 | $ | 41.28 | $ | 45.36 | ||||||
Natural gas (per Mcf) | 2.39 | 1.94 | 2.11 | |||||||||
NGLs (per Bbl) | 19.57 | 10.87 | 9.75 | |||||||||
Total (per Boe) | $ | 39.85 | $ | 33.15 | $ | 36.97 | ||||||
Average realized prices after effects of hedges(1)(2): | ||||||||||||
Oil (per Bbl) | $ | 47.75 | $ | 41.06 | $ | 61.22 | ||||||
Natural gas (per Mcf) | 2.43 | 1.94 | 2.11 | |||||||||
NGLs (per Bbl) | 19.57 | 10.87 | 9.75 | |||||||||
Total (per Boe) | $ | 39.12 | $ | 32.99 | $ | 48.96 | ||||||
Average costs (per Boe): | ||||||||||||
Lease operating expenses (excluding gathering and transportation) | $ | 5.13 | $ | 4.93 | $ | 6.46 | ||||||
Gathering and transportation | 0.96 | 0.48 | 0.46 | |||||||||
Production and ad valorem taxes | 2.43 | 2.03 | 2.60 | |||||||||
Depreciation, depletion and amortization | 13.87 | 18.21 | 20.05 | |||||||||
Components of general and administrative expense: | ||||||||||||
General and administrative - cash component (3) | $ | 1.50 | $ | 2.10 | $ | 2.33 | ||||||
General and administrative - recurring stock comp (4) | 0.85 | 1.23 | 1.03 | |||||||||
General and administrative - (IPO stock comp) (5) | — | — | 0.19 | |||||||||
General and administrative - non-recurring stock comp (6) | — | 0.06 | — | |||||||||
Total general and administrative | $ | 2.35 | $ | 3.39 | $ | 3.55 | ||||||
(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 and NGLs do not include gathering and transportation costs; instead, gathering and transportation costs related to our gas and NGLs production and sales are included in our lease operating expenses.
(3) Amount includes all cash corporate general and administrative expenses, including cash compensation amounts.
(4) Represents compensation expense related to restricted stock awards and performance share awards granted as part of the Company’s ongoing compensation and retention program.
(5) IPO stock comp consists of two components. One component represents restricted stock awarded to certain employees as a result of the Company’s successful initial public offering (“IPO”). These one-time awards vest over time for retention purposes. The other component represents non-cash compensation expense associated with incentive units owned by certain members of management.
(6) The non-recurring 2016 amount is a compensation charge associated with the retirement of an officer of the Company.
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Productive Wells
As of December 31, 2017, we owned an interest in 1104 gross (649 net) productive wells. Our wells are oil wells which produce associated liquids-rich natural gas. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
Developed and Undeveloped Acreage
The following table sets forth information as of December 31, 2017 relating to our leasehold acreage:
Developed acreage(1) | Undeveloped acreage(2) | Total acreage | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
Midland Basin | 56,252 | 40,281 | 7,490 | 6,395 | 63,742 | 46,676 | ||||||||||||
Delaware Basin | 40,514 | 25,062 | 37,852 | 20,149 | 78,366 | 45,211 | ||||||||||||
Total | 96,766 | 65,343 | 45,342 | 26,544 | 142,108 | 91,887 | ||||||||||||
(1) Developed acres are acres that are allocated or assignable to productive wells or wells capable of production. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in multiple intervals with horizontal wells.
(2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, NGLs or natural gas.
Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2017, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.
2018 | 2019 | 2020 | 2021 | 2022 | ||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||
Midland Basin | 6,538 | 6,339 | 312 | 52 | 640 | 4 | — | — | — | — | ||||||||||||||||||||
Delaware Basin | 11,715 | 15,296 | 12,078 | 4,272 | 13,419 | 577 | 640 | 4 | — | — | ||||||||||||||||||||
Total | 18,253 | 21,635 | 12,390 | 4,324 | 14,059 | 581 | 640 | 4 | — | — | ||||||||||||||||||||
Drilling Results
The table below sets forth the results of our drilling activities for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return.
Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion. Although a well may be classified as productive upon completion, future changes in oil, NGLs and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.
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The following table summarizes our gross and net interests in the wells completed during the periods indicated.
For the Year Ended December 31, | ||||||||||||||||||
2017 (1) | 2016 | 2015 | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
Development Wells: | ||||||||||||||||||
Productive | 113.0 | 73.6 | 96.0 | 56.5 | 115.0 | 66.4 | ||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||
Total Development | 113.0 | 73.6 | 96.0 | 56.5 | 115.0 | 66.4 | ||||||||||||
Exploratory Wells: | ||||||||||||||||||
Productive | — | — | 1.0 | 0.9 | — | — | ||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||
Total Exploratory | — | — | 1.0 | 0.9 | — | — | ||||||||||||
Total Wells: | ||||||||||||||||||
Productive | 113.0 | 73.6 | 97.0 | 57.4 | 115.0 | 66.4 | ||||||||||||
Dry | — | — | — | — | — | — | ||||||||||||
Total | 113.0 | 73.6 | 97.0 | 57.4 | 115.0 | 66.4 | ||||||||||||
(1) At December 31, 2017, we operated seven horizontal drilling rigs and had 36 gross (31.9 net) operated wells being completed or waiting on completion.
ITEM 3. 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, if decided adversely against us will have a material adverse effect on our business, financial condition, results of operations or liquidity.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
The Company’s common stock is listed and traded on the NYSE under the symbol “RSPP.” The table below sets forth, for the periods indicated, the high and low sales prices per share of our common stock.
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
2017 | |||||||||||||||
Low | $ | 37.74 | $ | 29.67 | $ | 28.76 | $ | 31.08 | |||||||
High | $ | 46.92 | $ | 42.37 | $ | 35.58 | $ | 41.09 | |||||||
2016 | |||||||||||||||
Low | $ | 16.74 | $ | 27.19 | $ | 33.14 | $ | 34.93 | |||||||
High | $ | 30.14 | $ | 36.50 | $ | 40.74 | $ | 46.44 | |||||||
On February 23, 2018, the Company’s common stock was held by 4 shareholders of record. This number excludes owners for whom common stock may be held in “street” name.
Dividends
We have not paid any cash dividends since our inception. We currently intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our Revolving Credit Facility and the indenture governing the notes restrict our ability to pay cash dividends.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes the Company’s repurchase of our common stock during the three months ended December 31, 2017:
Period | Total Number of Shares Purchased (1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased under the Plans or Programs | ||||||||||
October 1, 2017 - October 31, 2017 | 553 | $ | 34.00 | — | $ | — | ||||||||
November 1, 2017 - November 30, 2017 | 49 | 35.45 | — | — | ||||||||||
December 1, 2017 - December 31, 2017 | 116 | 37.75 | — | — | ||||||||||
Total | 718 | $ | 34.70 | — | $ | — | ||||||||
(1) These shares were withheld from employees to satisfy statutory tax withholding obligations arising upon the vesting of restricted shares under the 2014 Long Term Incentive Plan (“LTIP”).
ITEM 6. SELECTED FINANCIAL DATA
The following tables set forth selected consolidated financial data of the Company. Our historical results are not necessarily indicative of future operating results. The selected financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, “Part II, Item 7. Management’s Discussion and Analysis of Financial
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Condition and Results of Operations” and the consolidated financial statements of the Company included in this Report. Certain reclassifications have been made to prior period information to conform to current period presentation.
RSP Permian, Inc. | ||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
(in thousands, except per share data) | 2017 | 2016 | 2015 | 2014 (2) | 2013 (2) | |||||||||||||||
Statement of Operations Data (1): | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil sales | $ | 704,838 | $ | 321,588 | $ | 263,286 | $ | 253,371 | $ | 110,345 | ||||||||||
Natural gas sales | 36,206 | 13,945 | 10,517 | 10,572 | 5,383 | |||||||||||||||
NGL sales | 62,664 | 18,324 | 10,189 | 17,982 | 7,314 | |||||||||||||||
Total revenues | 803,708 | 353,857 | 283,992 | 281,925 | 123,042 | |||||||||||||||
Operating expenses: | ||||||||||||||||||||
Lease operating expenses | 122,893 | 57,778 | 53,124 | 34,704 | 14,113 | |||||||||||||||
Production and ad valorem taxes | 48,908 | 21,615 | 19,995 | 19,758 | 8,326 | |||||||||||||||
Depreciation, depletion and amortization | 279,711 | 194,360 | 154,039 | 87,844 | 47,158 | |||||||||||||||
Asset retirement obligation accretion | 605 | 472 | 336 | 142 | 121 | |||||||||||||||
Impairments of oil and natural gas properties (3) | 59,077 | 4,901 | 34,269 | 4,344 | — | |||||||||||||||
Exploration expenses | 7,771 | 1,093 | 2,380 | 3,854 | 551 | |||||||||||||||
General and administrative expenses | 47,408 | 36,170 | 27,317 | 38,357 | 3,852 | |||||||||||||||
Acquisition costs | 4,525 | 6,374 | — | — | — | |||||||||||||||
Total operating expenses | 570,898 | 322,763 | 291,460 | 189,003 | 74,121 | |||||||||||||||
(Gain) loss on sale of assets | — | — | 306 | 13 | (22,700 | ) | ||||||||||||||
Operating income (loss) | 232,810 | 31,094 | (7,774 | ) | 92,909 | 71,621 | ||||||||||||||
Other income (expense): | ||||||||||||||||||||
Other income (expenses), net | 3,436 | 1,833 | 469 | (44 | ) | 1,202 | ||||||||||||||
Net gain (loss) on derivative instruments | (39,279 | ) | (23,760 | ) | 20,906 | 81,470 | (2,607 | ) | ||||||||||||
Interest expense | (82,459 | ) | (52,724 | ) | (43,538 | ) | (14,031 | ) | (5,216 | ) | ||||||||||
Total other income (expense) | (118,302 | ) | (74,651 | ) | (22,163 | ) | 67,395 | (6,621 | ) | |||||||||||
Income (loss) before taxes | 114,508 | (43,557 | ) | (29,937 | ) | 160,304 | 65,000 | |||||||||||||
Income tax (expense) benefit (4) | 117,628 | 18,706 | 11,683 | (157,806 | ) | (2,262 | ) | |||||||||||||
Net Income (loss) | $ | 232,136 | $ | (24,851 | ) | $ | (18,254 | ) | $ | 2,498 | $ | 62,738 | ||||||||
Earnings (loss) per common share: | ||||||||||||||||||||
Basic | $ | 1.50 | $ | (0.23 | ) | $ | (0.21 | ) | $ | 0.03 | $ | 1.26 | ||||||||
Diluted | $ | 1.49 | $ | (0.23 | ) | $ | (0.21 | ) | $ | 0.03 | $ | 1.26 | ||||||||
Cash Flow Data: | ||||||||||||||||||||
Net cash provided by operating activities | $ | 498,367 | $ | 166,213 | $ | 218,805 | $ | 223,157 | $ | 73,345 | ||||||||||
Net cash used in investing activities | (1,517,254 | ) | (1,029,423 | ) | (874,939 | ) | (816,925 | ) | (119,591 | ) | ||||||||||
Net cash provided by financing activities | 366,213 | 1,411,245 | 742,583 | 636,826 | 8,248 | |||||||||||||||
(1) We have completed numerous acquisitions and dispositions which impact the comparability of the selected financial data between periods.
(2) Represents our predecessor’s historical financial data for 2013 and our predecessor’s historical financial data the first 22 days of 2014 plus RSP Permian, Inc.’s historical financial data for the remainder of the year.
(3) Impairments in 2014, 2016 and 2017 primarily relate to unproved properties where lease terms expired. Impairments in 2015 relate primarily to write downs of the value of proved properties in Dawson County, where these properties were deemed impaired based upon impairment testing under successful efforts accounting, along with impairments on unproved properties where lease terms expired.
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(4) Income tax benefit in 2017 was primarily related to a decrease in the federal corporate tax rate from 35% to 21% as a result of the Tax Act enacted in December 2017, resulting in a one-time, non-cash adjustment to the income tax provision of $144.4 million for the quarter ended December 31, 2017.
Year Ended December 31, | ||||||||||||||||||||
(in thousands) | 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||
Cash and cash equivalents | $ | 38,102 | $ | 690,776 | $ | 142,741 | $ | 56,292 | $ | 13,234 | ||||||||||
Other current assets | 111,221 | 85,486 | 44,799 | 117,450 | 33,901 | |||||||||||||||
Total current assets | 149,323 | 776,262 | 187,540 | 173,742 | 47,135 | |||||||||||||||
Property, plant and equipment, net | 6,080,719 | 4,129,635 | 2,758,630 | 2,094,618 | 516,288 | |||||||||||||||
Other long-term assets | 40,144 | 90,530 | 21,263 | 10,551 | 24,232 | |||||||||||||||
Total assets | $ | 6,270,186 | $ | 4,996,427 | $ | 2,967,433 | $ | 2,278,911 | $ | 587,655 | ||||||||||
Current liabilities | $ | 206,561 | $ | 108,269 | $ | 77,402 | $ | 104,252 | $ | 30,866 | ||||||||||
Long-term debt | 1,509,128 | 1,132,275 | 686,512 | 488,964 | 128,155 | |||||||||||||||
NPI payable | — | — | — | — | 36,931 | |||||||||||||||
Other long-term liabilities | 232,139 | 338,571 | 344,935 | 359,924 | 4,822 | |||||||||||||||
Total stockholders’/members’ equity | 4,322,358 | 3,417,312 | 1,858,584 | 1,325,771 | 386,881 | |||||||||||||||
Total liabilities and stockholders’/members’ equity | $ | 6,270,186 | $ | 4,996,427 | $ | 2,967,433 | $ | 2,278,911 | $ | 587,655 | ||||||||||
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Item 7. 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 II, Item 8. Financial Statements and Supplementary Data.” 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” and “Part I, Item 1A. Risk Factors” in this Report.
Overview and Outlook
Overview of 2017
We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of the Company’s acreage is located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin, both sub-basins of the Permian Basin.
Our financial and operating performance and significant events during 2017 included the following highlights:
• | In March 2017, closed the SHEP II acquisition for an aggregate purchase price of approximately $646.0 million of cash and 16.0 million shares of RSP Inc. common stock in aggregate, before purchase price adjustments. The cash portion of the purchase price was funded with cash on hand. See Note 3 in the notes to our consolidated financial statements for additional information. |
• | Increased our total proved reserves by 59% from 236.9 MMBoe as of December 31, 2016 to 375.9 MMBoe as of December 31, 2017. |
• | Increased our average daily production rate by 89% for the year ended December 31, 2017 as compared to the same period in 2016. |
• | Increased our borrowing base under the Revolving Credit Facility to $1.5 billion in October 2017. |
• | Acquired $279.0 million of additional undeveloped acreage and mineral interests. |
• | Acquired water infrastructure assets which service Delaware Basin properties for an aggregate purchase price of $19.2 million. |
Our average daily production rate during 2017 was 55,255 Boe/d, an 89% increase from 2016 average daily production of 29,161 Boe/d. Oil production was 72% of total production on a volumetric basis and oil sales were 88% of our total revenues in 2017.
During 2017, we participated in the drilling of 136 gross horizontal wells (95 operated) and participated in the completion of 113 gross horizontal wells (70 operated). At the end of 2017, we operated three horizontal rigs in the Midland Basin and four horizontal rigs in the Delaware Basin. During 2016, we participated in the drilling of 81 gross horizontal wells (46 operated) and participated in the completion of 90 gross horizontal wells (53 operated). In our 2016 vertical drilling program, we drilled 4 gross vertical operated wells and completed 6 gross operated vertical wells.
Outlook and Capital Budget for 2018
Our board of directors has approved an initial capital budget for drilling, completion, and infrastructure and other for 2018 of approximately $815 million to $895 million which anticipates adding an eight rig and a third dedicated frac crew by the middle of the year. We continuously monitor commodity prices, our cash flow and returns to determine adjustments to our capital budget. We intend to allocate our 2018 capital budget approximately as follows:
•$725 million to $785 million for drilling and completion activities; approximately 10% of which is non-operated drilling and completion activities; and
•$90 million to $110 million for infrastructure and other.
Our 2018 capital budget excludes acquisitions and additions to leasehold and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and natural gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.
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We expect increased activity under our drilling program in 2018 over 2017. We expect this drilling program will result in higher production volumes in 2018.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our operations, including:
• | production volumes; |
• | revenues on the sale of oil, NGLs and natural gas, including the effect of our commodity derivative contracts on our production; |
• | operating expenses; and |
• | capital efficiency |
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. Our commodity derivative instruments are not held 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 projected production volumes.
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. For information regarding the summary of open positions, see Note 4 in the notes to our consolidated financial statements.
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Results of Operations
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Oil, NGLs and Natural Gas 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:
Year Ended December 31, | Change | ||||||||||||||
2017 | 2016 | $ | % | ||||||||||||
Revenues (in thousands, except percentages): | |||||||||||||||
Oil sales | $ | 704,838 | $ | 321,588 | $ | 383,250 | 119 | % | |||||||
Natural gas sales | 36,206 | 13,945 | 22,261 | 160 | |||||||||||
NGLs sales | 62,664 | 18,324 | 44,340 | 242 | |||||||||||
Total revenues | $ | 803,708 | $ | 353,857 | $ | 449,851 | 127 | % | |||||||
Average sales prices: | |||||||||||||||
Oil (per Bbl) (excluding impact of cash settled derivatives) | $ | 48.79 | $ | 41.28 | $ | 7.51 | 18 | % | |||||||
Oil (per Bbl) (after impact of cash settled derivatives) | 47.75 | 41.06 | 6.69 | 16 | |||||||||||
Natural gas (per Mcf) | 2.39 | 1.94 | 0.45 | 23 | |||||||||||
Natural gas (per Mcf) (after impact of cash settled derivatives) | 2.43 | 1.94 | 0.49 | 25 | |||||||||||
NGLs (per Bbl) | 19.57 | 10.87 | 8.70 | 80 | |||||||||||
Total (per Boe) (excluding impact of cash settled derivatives) | $ | 39.85 | $ | 33.15 | $ | 6.70 | 20 | % | |||||||
Total (per Boe) (after impact of cash settled derivatives) | $ | 39.12 | $ | 32.99 | $ | 6.13 | 19 | % | |||||||
Production: | |||||||||||||||
Oil (MBbls) | 14,445 | 7,790 | 6,655 | 85 | % | ||||||||||
Natural gas (MMcf) | 15,126 | 7,188 | 7,938 | 110 | |||||||||||
NGLs (MBbls) | 3,202 | 1,685 | 1,517 | 90 | |||||||||||
Total (MBoe) | 20,168 | 10,673 | 9,495 | 89 | % | ||||||||||
Average daily production volume: | |||||||||||||||
Total (Boe/d) | 55,255 | 29,161 | 26,094 | 89 | % | ||||||||||
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. The NYMEX WTI futures price is a widely-used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the ability to transport oil to the transportation hubs or refineries. The NYMEX Henry Hub price of natural gas is a widely-used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, depending on pricing, liquids‑rich natural gas with a high Btu content may sell at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered.
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Year Ended December 31, | ||||||||
2017 | 2016 | |||||||
Average realized oil price ($/Bbl) | $ | 48.79 | $ | 41.28 | ||||
Average NYMEX ($/Bbl) | 50.95 | 43.32 | ||||||
Differential to NYMEX | (2.16 | ) | (2.04 | ) | ||||
Average realized oil price to NYMEX percentage | 96 | % | 95 | % | ||||
Average realized natural gas price ($/Mcf) | $ | 2.39 | $ | 1.94 | ||||
Average NYMEX ($/Mcf) | 3.11 | 2.46 | ||||||
Differential to NYMEX | (0.72 | ) | (0.52 | ) | ||||
Average realized natural gas price to NYMEX percentage | 77 | % | 79 | % | ||||
Average realized NGLs price ($/Bbl) | $ | 19.57 | $ | 10.87 | ||||
Average NYMEX oil price ($/Bbl) | 50.95 | 43.32 | ||||||
Average realized NGLs price to NYMEX oil price percentage | 38 | % | 25 | % | ||||
Our average realized oil price as a percentage of the average NYMEX price was 96% and 95% for the years ended December 31, 2017 and 2016, respectively. All of our oil contracts are impacted by the Midland-Cushing differential, which was a negative $0.30 per Bbl for the year ended December 31, 2017 and a negative $0.15 per Bbl for the year ended December 31, 2016.
Oil revenues increased 119% to $704.8 million for the year ended December 31, 2017 from $321.6 million for the year ended December 31, 2016 as a result of an increase in oil production volumes of 6,655 MBbls, or 85%, and a $7.51 per Bbl increase, or 18%, in our average realized price for oil.
Natural gas revenues increased 160% to $36.2 million for the year ended December 31, 2017 from $13.9 million for the year ended December 31, 2016 as a result of an increase in natural gas production of 7,938 MMcf, or 110%, and a $0.45 per Mcf increase, or 23%, in our average realized natural gas price.
NGLs revenues increased 242% to $62.7 million for the year ended December 31, 2017 from $18.3 million for the year ended December 31, 2016 as a result of an increase in NGLs production of 1,517 MBbls, or 90%, and a $8.70 per Bbl increase, or 80%, in our average realized price for NGLs.
Our higher production volumes for all products were primarily a result of increased production from our drilling program, along with the full period impact of our acquisitions during 2016 and 2017. We expect our increased drilling program in 2018 will result in higher production volumes in 2018.
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Operating Expenses. The following table summarizes our expenses for the years indicated:
Year Ended December 31, | Change | ||||||||||||||
2017 | 2016 | $ | % | ||||||||||||
Operating expenses (in thousands, except percentages): | |||||||||||||||
Lease operating expenses | $ | 122,893 | $ | 57,778 | $ | 65,115 | 113 | % | |||||||
Production and ad valorem taxes | 48,908 | 21,615 | 27,293 | 126 | |||||||||||
Depreciation, depletion and amortization | 279,711 | 194,360 | 85,351 | 44 | |||||||||||
Asset retirement obligation accretion | 605 | 472 | 133 | 28 | |||||||||||
Impairments of oil and natural gas properties | 59,077 | 4,901 | 54,176 | 1,105 | |||||||||||
Exploration expenses | 7,771 | 1,093 | 6,678 | 611 | |||||||||||
General and administrative expenses | 47,408 | 36,170 | 11,238 | 31 | |||||||||||
Acquisition costs | 4,525 | 6,374 | (1,849 | ) | (29 | ) | |||||||||
Total operating expenses | $ | 570,898 | $ | 322,763 | $ | 248,135 | 77 | % | |||||||
Expenses per Boe: | |||||||||||||||
Lease operating expenses (excluding gathering and transportation) | $ | 5.13 | $ | 4.93 | $ | 0.20 | 4 | % | |||||||
Gathering and transportation | 0.96 | 0.48 | 0.48 | 100 | |||||||||||
Production and ad valorem taxes | 2.43 | 2.03 | 0.40 | 20 | |||||||||||
Depreciation, depletion and amortization | 13.87 | 18.21 | (4.34 | ) | (24 | ) | |||||||||
Asset retirement obligation accretion | 0.03 | 0.04 | (0.01 | ) | (25 | ) | |||||||||
Impairments of oil and natural gas properties | 2.93 | 0.46 | 2.47 | 537 | |||||||||||
Exploration expenses | 0.39 | 0.10 | 0.29 | 290 | |||||||||||
General and administrative - cash component | 1.50 | 2.10 | (0.60 | ) | (29 | ) | |||||||||
General and administrative - recurring stock comp (1) | 0.85 | 1.23 | (0.38 | ) | (31 | ) | |||||||||
General and administrative - non-recurring stock comp (2) | — | 0.06 | (0.06 | ) | (100 | ) | |||||||||
Acquisition costs | 0.22 | 0.60 | (0.38 | ) | (63 | ) | |||||||||
Total operating expenses per Boe | $ | 28.31 | $ | 30.24 | $ | (1.93 | ) | (6 | )% | ||||||
(1) Represents non-cash compensation expense related to restricted stock awards and performance-based restricted stock awards granted as part of the Company’s ongoing compensation and retention program.
(2) The non-recurring 2016 amount is a compensation charge associated with the retirement of an officer of the Company.
Lease Operating Expenses. Lease operating expenses increased to $122.9 million for the year ended December 31, 2017 from $57.8 million for the year ended December 31, 2016 primarily due to an 89% increase in production. On a per-Boe basis, lease operating expense, excluding gathering and transportation costs, increased from $4.93 per Boe in 2016 to $5.13 per Boe in 2017. The increase was primarily due to higher water transportation expenses for our recently acquired Delaware Basin properties. Additionally, we incurred higher lease operating expenses associated with ramping up initial operations on our Delaware Basin properties. Gathering and transportation costs, which are included in lease operating expenses, were $19.4 million and $5.1 million for the year ended December 31, 2017 and 2016, respectively. On a per-Boe basis, our gathering and transportation costs were $0.96 and $0.48 for the years ended December 31, 2017 and 2016, respectively. The increase in our gathering and transportation costs was primarily related to higher fee arrangements on midstream services used for our Delaware Basin properties.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased 126% to $48.9 million for the year ended December 31, 2017 from $21.6 million for the year ended December 31, 2016. The increase was primarily due to higher production volumes and revenues, as well as increases in property taxes related to our Delaware Basin properties. On a per-Boe basis, production and ad valorem taxes increased to $2.43 per Boe in 2017 from $2.03 per Boe in 2016 due to higher commodity prices.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased 44% to $279.7 million for the year ended December 31, 2017 from $194.4 million for the year ended December 31, 2016 due to increased production partially offset by lower depletion rate per Boe. The DD&A rate decreased 24% to $13.87 per Boe for the year ended December 31, 2017 from $18.21 per Boe for the year ended December 31, 2016. The decrease in depletion per Boe during 2017 was due to an increase in our reserve volumes from acquisitions and successful drilling activities, partially offset by an increase in capitalized costs in proved property over the last year.
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Impairments. We incurred $59.1 million and $4.9 million of impairment expense for the years ended December 31, 2017 and 2016, respectively. The impairments recorded during 2017 and 2016 related to unproved properties with acreage lease expirations that we do not intend to extend or develop. We may incur additional unproved property impairments in the future due to acreage expirations and changes in development plans. We may incur proved property impairments in the future if commodity prices experience sustained declines. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future oil and gas prices, estimates of proved reserves and future capital expenditures and production costs.
Exploration Expenses. Exploration expense increased from $1.1 million for the year ended December 31, 2016 to $7.8 million for the year ended December 31, 2017 due to higher expenditures on geological and geophysical activity primarily related to seismic projects on acreage acquired in the Delaware Basin.
General and Administrative Expenses. General and administrative expenses increased to $47.4 million for the year ended December 31, 2017 from $36.2 million for the year ended December 31, 2016 primarily due to an increase in employee headcount and related expenses, including additional equity-based compensation. Equity-based compensation expense, which is recorded in general and administrative expenses, was $17.2 million and $13.8 million for the year ended December 31, 2017 and 2016, respectively.
Acquisition costs. Acquisition costs in 2017 and 2016 were related to costs associated with the Silver Hill acquisitions.
Other Income and Expense. The following table summarizes our other income and expense:
Year Ended December 31, | Change | ||||||||||||||
2017 | 2016 | $ | % | ||||||||||||
Other income (expense) (in thousands, except percentages): | |||||||||||||||
Other income, net | $ | 3,436 | $ | 1,833 | $ | 1,603 | 87 | % | |||||||
Net gain (loss) on derivative instruments | (39,279 | ) | (23,760 | ) | (15,519 | ) | 65 | ||||||||
Interest expense | (82,459 | ) | (52,724 | ) | (29,735 | ) | 56 | ||||||||
Total other income (expense) | $ | (118,302 | ) | $ | (74,651 | ) | $ | (43,651 | ) | 58 | % | ||||
Net Gain (Loss) on Derivative Instruments. During the year ended December 31, 2017, we recorded a $39.3 million net loss on derivative instruments as compared to $23.8 million in the 2016 period. The change was a result of new derivative positions entered into over the last year and the future commodity price outlook as of December 31, 2017 as compared to December 31, 2016.
Interest Expense. During the year ended December 31, 2017, we recorded $82.5 million of interest expense as compared to $52.7 million during the year ended December 31, 2016. The increase in interest expense was primarily due to the issuance of 2025 Senior Notes in December 2016 and increased borrowings under our Revolving Credit Facility.
Income Tax Benefit. During the year ended December 31, 2017, we recorded an income tax benefit of $117.6 million as compared to $18.7 million during the year ended December 31, 2016. The income tax benefit recorded during 2017 was primarily due to a decrease in the federal corporate tax rate from 35% to 21% as a result of the Tax Act enacted in December 2017, resulting in a one-time, non-cash adjustment to the income tax provision of $144.4 million for the quarter ended December 31, 2017. See Note 2 and Note 10 in the notes to our consolidated financial statements for additional discussion of income taxes and the Tax Act. In 2016, the Company recorded a return to provision adjustment which incorporated both a tax provision benefit and a reserve for an uncertain tax position which resulted in a net tax benefit of $2.3 million. The Company also recorded estimated research and development credits, less a reserve for uncertain tax positions, which resulted in a net tax benefit of $1.5 million. These adjustments resulted in an effective rate change during 2017 as compared with 2016.
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Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Oil, NGLs and Natural Gas 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:
Year Ended December 31, | Change | ||||||||||||||
2016 | 2015 | $ | % | ||||||||||||
Revenues (in thousands, except percentages): | |||||||||||||||
Oil sales | $ | 321,588 | $ | 263,286 | $ | 58,302 | 22 | % | |||||||
Natural gas sales | 13,945 | 10,517 | 3,428 | 33 | |||||||||||
NGLs sales | 18,324 | 10,189 | 8,135 | 80 | |||||||||||
Total revenues | $ | 353,857 | $ | 283,992 | $ | 69,865 | 25 | % | |||||||
Average sales prices: | |||||||||||||||
Oil (per Bbl) (excluding impact of cash settled derivatives) | $ | 41.28 | $ | 45.36 | $ | (4.08 | ) | (9 | )% | ||||||
Oil (per Bbl) (after impact of cash settled derivatives) | 41.06 | 61.22 | (20.16 | ) | (33 | ) | |||||||||
Natural gas (per Mcf) | 1.94 | 2.11 | (0.17 | ) | (8 | ) | |||||||||
Natural gas (per Mcf) (after impact of cash settled derivatives) | 1.94 | 2.11 | (0.17 | ) | (8 | ) | |||||||||
NGLs (per Bbl) | 10.87 | 9.75 | 1.12 | 11 | |||||||||||
Total (per Boe) (excluding impact of cash settled derivatives) | $ | 33.15 | $ | 36.97 | $ | (3.82 | ) | (10 | )% | ||||||
Total (per Boe) (after impact of cash settled derivatives) | $ | 32.99 | $ | 48.96 | $ | (15.97 | ) | (33 | )% | ||||||
Production: | |||||||||||||||
Oil (MBbls) | 7,790 | 5,805 | 1,985 | 34 | % | ||||||||||
Natural gas (MMcf) | 7,188 | 4,991 | 2,197 | 44 | |||||||||||
NGLs (MBbls) | 1,685 | 1,045 | 640 | 61 | |||||||||||
Total (MBoe) | 10,673 | 7,682 | 2,991 | 39 | % | ||||||||||
Average daily production volume: | |||||||||||||||
Total (Boe/d) | 29,161 | 21,047 | 8,114 | 39 | % | ||||||||||
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. The NYMEX WTI futures price is a widely-used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the ability to transport oil to the transportation hubs or refineries. The NYMEX Henry Hub price of natural gas is a widely-used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, depending on pricing, liquids‑rich natural gas with a high Btu content may sell at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered.
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Year Ended December 31, | ||||||||
2016 | 2015 | |||||||
Average realized oil price ($/Bbl) | $ | 41.28 | $ | 45.36 | ||||
Average NYMEX ($/Bbl) | 43.32 | 48.80 | ||||||
Differential to NYMEX | (2.04 | ) | (3.44 | ) | ||||
Average realized oil price to NYMEX percentage | 95 | % | 93 | % | ||||
Average realized natural gas price ($/Mcf) | $ | 1.94 | $ | 2.11 | ||||
Average NYMEX ($/Mcf) | 2.46 | 2.67 | ||||||
Differential to NYMEX | (0.52 | ) | (0.56 | ) | ||||
Average realized natural gas price to NYMEX percentage | 79 | % | 79 | % | ||||
Average realized NGLs price ($/Bbl) | $ | 10.87 | $ | 9.75 | ||||
Average NYMEX oil price ($/Bbl) | 43.32 | 48.80 | ||||||
Average realized NGLs price to NYMEX oil price percentage | 25 | % | 20 | % | ||||
Our average realized oil price as a percentage of the average NYMEX price was 95% and 93% for the years ended December 31, 2016 and 2015, respectively. All of our oil contracts are impacted by the Midland-Cushing differential, which was a negative $0.15 per Bbl for the year ended December 31, 2016 and a negative $0.41 per Bbl for the year ended December 31, 2015. As the differential decreased, our realized price per barrel of oil increased. Lower differential in 2016 was primarily due to new pipeline infrastructure that has been put into service and lower than anticipated production growth, alleviating pipeline capacity constraints that occurred in prior periods.
Oil revenues increased 22% to $321.6 million for the year ended December 31, 2016 from $263.3 million for the year ended December 31, 2015 as a result of an increase in oil production volumes of 1,985 MBbls, or 34%, partially offset by an $4.08 per Bbl decrease, or 9%, in our average realized price for oil.
Natural gas revenues increased 33% and were $13.9 million and $10.5 million for the years ended December 31, 2016 and 2015, respectively. Natural gas production volumes increased by 2,197 MMcf, or 44%, partially offset by an 8% decrease in our average realized price per Mcf.
NGL revenues increased 80% to $18.3 million for the year ended December 31, 2016 from $10.2 million for the year ended December 31, 2015 period as a result of a $1.12 per Bbl increase, or 11%, in our average realized NGL price and an increase in NGL production volumes of 640 MBbls, or 61%.
Our higher production volumes for all products were primarily a result of increased production from our drilling program, along with the full period impact of our acquisitions that closed in 2015.
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Operating Expenses. The following table summarizes our expenses for the years indicated:
Year Ended December 31, | Change | ||||||||||||||
2016 | 2015 | $ | % | ||||||||||||
Operating expenses (in thousands, except percentages): | |||||||||||||||
Lease operating expenses | $ | 57,778 | $ | 53,124 | $ | 4,654 | 9 | % | |||||||
Production and ad valorem taxes | 21,615 | 19,995 | 1,620 | 8 | |||||||||||
Depreciation, depletion and amortization | 194,360 | 154,039 | 40,321 | 26 | |||||||||||
Asset retirement obligation accretion | 472 | 336 | 136 | 40 | |||||||||||
Impairments of oil and natural gas properties | 4,901 | 34,269 | (29,368 | ) | (86 | ) | |||||||||
Exploration expenses | 1,093 | 2,380 | (1,287 | ) | (54 | ) | |||||||||
General and administrative expenses | 36,170 | 27,317 | 8,853 | 32 | |||||||||||
Acquisition costs | 6,374 | — | 6,374 | 100 | |||||||||||
Total operating expenses before loss on sale of assets | $ | 322,763 | $ | 291,460 | $ | 31,303 | 11 | % | |||||||
Expenses per Boe: | |||||||||||||||
Lease operating expenses (excluding gathering and transportation) | $ | 4.93 | $ | 6.46 | $ | (1.53 | ) | (24 | )% | ||||||
Gathering and transportation | 0.48 | 0.46 | 0.02 | 4 | |||||||||||
Production and ad valorem taxes | 2.03 | 2.60 | (0.57 | ) | (22 | ) | |||||||||
Depreciation, depletion and amortization | 18.21 | 20.05 | (1.84 | ) | (9 | ) | |||||||||
Asset retirement obligation accretion | 0.04 | 0.04 | — | — | |||||||||||
Impairments of oil and natural gas properties | 0.46 | 4.46 | (4.00 | ) | (90 | ) | |||||||||
Exploration expenses | 0.10 | 0.31 | (0.21 | ) | (68 | ) | |||||||||
General and administrative - cash component | 2.10 | 2.33 | (0.23 | ) | (10 | ) | |||||||||
General and administrative - recurring stock comp (1) | 1.23 | 1.03 | 0.20 | 19 | |||||||||||
General and administrative - IPO stock comp (2) | — | 0.19 | (0.19 | ) | (100 | ) | |||||||||
General and administrative - non-recurring stock comp (3) | 0.06 | — | 0.06 | 100 | |||||||||||
Acquisition costs | 0.60 | — | 0.60 | 100 | |||||||||||
Total operating expenses per Boe | $ | 30.24 | $ | 37.93 | $ | (7.69 | ) | (20 | )% | ||||||
(1) Represents non-cash compensation expense related to restricted stock awards and performance share awards granted as part of the Company’s ongoing compensation and retention program.
(2) IPO stock compensation in 2015 includes compensation expense related to the successful completion of the Company’s IPO. These one-time awards vested over time for retention purposes.
(3) The non-recurring 2016 amount is a compensation charge associated with the retirement of an officer of the Company.
Lease Operating Expenses. Lease operating expenses increased 9% to $57.8 million for the year ended December 31, 2016 from $53.1 million for the 2015 period due to a 39% increase in production. On a per-Boe basis, lease operating expense, excluding gathering and transportation costs, decreased from $6.46 per Boe in 2015 to $4.93 per Boe in 2016. The decrease was primarily attributable to production growth over a fixed component of costs, increased operating efficiencies and cost reduction efforts in 2016. Gathering and transportation costs, which are included in lease operating expenses, were $5.1 million for the year ended December 31, 2016 and $3.5 million for the 2015 period. On a per-Boe basis, our gathering and transportation costs were $0.48 and $0.46 for the years ended December 31, 2016 and 2015 respectively.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased 8% to $21.6 million for the year ended December 31, 2016 from $20.0 million for the 2015 period primarily due to higher production volumes and revenues in the 2016 period, and decreased 22% on a per-Boe basis to $2.03 per Boe for the year ended December 31, 2016.
Depreciation, Depletion and Amortization. DD&A expense increased 26% to $194.4 million for the year ended December 31, 2016 from $154.0 million for the 2015 period mainly due to increased production. The DD&A rate decreased 9% to $18.21 per Boe for the year ended December 31, 2016 from $20.05 per Boe for the 2015 period. The decrease in depletion per Boe in 2016 was due to an increase in our reserve volumes over the last year from acquisitions as well as successful drilling activities, somewhat offset by an increase in capitalized costs in proved property over the last year from these same activities.
Impairments. We incurred $4.9 million and $34.3 million of impairment expense for the years ended December 31, 2016 and 2015, respectively. The impairments recognized in 2016 related to unproved properties with upcoming acreage lease
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expirations that the Company does not intend to extend or develop. Impairments in 2015 included $19.6 million for proved properties and $14.7 million for unproved properties. The impairments to proved property in 2015 related to properties whose future net revenues were less than the property’s carrying value, while the impairment to unproved properties related to acreage pending lease expirations that the Company did not intend to extend or develop.
Exploration Expense. Exploration expense decreased from $2.4 million for the year ended December 31, 2015 to $1.1 million for the 2016 period due to a decrease in expenditures on geological and geophysical activity in 2016.
General and Administrative Expenses. General and administrative expenses increased to $36.2 million for the year ended December 31, 2016, from $27.3 million for the 2015 period primarily due to increases in the number of employees and related expense including equity-based compensation. Equity-based compensation expense, which is recorded in general and administrative expenses, was $13.8 million for the year ended December 31, 2016 and $9.4 million for the 2015 period. On a per-Boe basis, recurring general and administrative expenses decreased from $3.36 per Boe to $3.33 per Boe.
Acquisition costs. Acquisition costs in 2016 related to costs associated with the Silver Hill acquisitions.
Other Income and Expenses. The following table summarizes our other income and expenses:
Year Ended December 31, | Change | ||||||||||||||
2016 | 2015 | $ | % | ||||||||||||
Other income (expense) (in thousands, except percentages): | |||||||||||||||
Other income, net | $ | 1,833 | $ | 469 | $ | 1,364 | 291 | % | |||||||
Net gain (loss) on derivative instruments | (23,760 | ) | 20,906 | (44,666 | ) | (214 | ) | ||||||||
Interest expense | (52,724 | ) | (43,538 | ) | (9,186 | ) | 21 | ||||||||
Total other income (expense) | $ | (74,651 | ) | $ | (22,163 | ) | $ | (52,488 | ) | 237 | % | ||||
Net Gain (Loss) on Derivative Instruments. During the year ended December 31, 2016, we recorded a $23.8 million net loss on derivative instruments as compared to a $20.9 million net gain in the 2015 period. The change was a result of expiring contracts on derivative positions over the prior year and the future commodity price outlook as of December 31, 2016, as compared to December 31, 2015.
Interest Expense. During the year ended December 31, 2016, we recorded $52.7 million of interest expense as compared to $43.5 million in the 2015 period. Interest expense was higher than the prior-year period as a result of a full year of interest expense related to the issuance of 2022 Senior Notes in August 2015, and to a lesser extent, due to 2025 Senior Notes issued in December 2016.
Income Tax Benefit. During the year ended December 31, 2016, we recorded $18.7 million of income tax benefit, compared to $11.7 million of income tax benefit in the 2015 period. In 2016, the Company recorded a return to provision adjustment which incorporated both a tax provision benefit and a reserve for an uncertain tax position which resulted in a net tax benefit of $2.3 million. The Company also recorded estimated research and development credits, less a reserve for uncertain tax positions, which resulted in a net tax benefit of $1.5 million. These adjustments resulted in an effective rate change year over year.
Capital Requirements and Sources of Liquidity
We define liquidity as available borrowing capacity under our Revolving Credit Facility plus cash and cash equivalents. Our primary sources of liquidity have been proceeds from equity offerings, borrowings under our Revolving Credit Facility, proceeds from the issuance of senior notes, and cash flows from operations. To date, our primary use of capital has been for the acquisition, development, exploration and exploitation of oil and natural gas properties. In October 2017, we increased the borrowing base under our Revolving Credit Facility to $1.5 billion from $1.1 billion. We maintained our elected commitment amount of $900.0 million. At December 31, 2017, we had $523.1 million of borrowing capacity under our Revolving Credit Facility and $38.1 million of cash on hand.
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The following table summarizes our liquidity position as of December 31, 2017:
(in thousands) | December 31, 2017 | |||
Revolving Credit Facility elected commitment amount | $ | 900,000 | ||
Revolving Credit Facility borrowings | (375,000 | ) | ||
Letters of credit | (1,933 | ) | ||
Available borrowing capacity | 523,067 | |||
Cash and cash equivalents | 38,102 | |||
Liquidity | $ | 561,169 | ||
During 2017, our capital expenditures totaled approximately $673.3 million, which included approximately $610.6 million spent on drilling and completion activities and approximately $62.7 million spent on infrastructure and other expenditures. The SHEP II acquisition closed on March 1, 2017 for a purchase price of $1.3 billion, before purchase price adjustments, that included cash consideration of $646.0 million, and approximately 16.0 million shares of RSP Inc. common stock, valued at $663.9 million based on our closing common share price of $41.44 per share on March 1, 2017. In addition, we spent $279.0 million on acquisitions of undeveloped acreage and additional mineral interests. In 2016, our capital expenditures totaled approximately $294.2 million, which included approximately $275.5 million spent on drilling and completion activities and $18.7 million spent on infrastructure and other expenditures. In addition, we spent approximately $673.9 million cash on oil and natural gas property acquisitions primarily related to the Delaware Basin properties purchased in the SHEP I acquisition and acquisitions and additions to leasehold in the Midland Basin.
We operate a high percentage of our acreage; therefore, the amount and timing of these capital expenditures are largely discretionary. We may elect to defer a portion of planned capital expenditures depending on a variety of factors, including: returns generated by our drilling program, the level of our expenditures in relation to our cash flow from operations, the success of our drilling activities; prevailing and anticipated prices for oil, NGLs and natural gas; 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.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and available borrowings under our Revolving Credit Facility to execute our capital program for 2018, as described above under “Overview and Outlook - Outlook and Capital Budget for 2018.” However, future cash flows are subject to a number of variables, including the level of oil, NGLs and natural gas production and prices, our ability to integrate acquisitions, the level of capital expenditures required to develop our properties and other factors described under “Risk Factors.” 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 borrowings under our Revolving Credit Facility, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot provide assurance 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, was a deficit of $57.2 million at December 31, 2017, and $668.0 million at December 31, 2016. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $38.1 million and $690.8 million at December 31, 2017 and 2016, respectively. Due to the amounts that accrue related to our drilling program, we may incur incremental 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 consummate. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil, NGLs and natural gas production will be the largest variables affecting our working capital.
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Contractual Obligations
A summary of our contractual obligations as of December 31, 2017 is provided in the following table:
Payments Due by Period For the Year Ended December 31, | ||||||||||||||||||||||||||||
(in thousands) | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total | |||||||||||||||||||||
Revolving Credit Facility (1) | $ | — | $ | — | $ | — | $ | 375,000 | $ | — | $ | — | $ | 375,000 | ||||||||||||||
5.25% Senior Notes due 2025 (1) | — | — | — | — | — | 450,000 | 450,000 | |||||||||||||||||||||
6.625% Senior Notes due 2022 (1) | — | — | — | — | 700,000 | — | 700,000 | |||||||||||||||||||||
Interest cost (2) | 70,000 | 70,000 | 70,000 | 70,000 | 58,406 | 48,221 | 386,627 | |||||||||||||||||||||
Drilling rig commitments (3) | 14,375 | — | — | — | — | — | 14,375 | |||||||||||||||||||||
Purchase obligations (4) | 45,013 | 16,346 | 9,180 | 9,180 | 1,752 | 8,654 | 90,125 | |||||||||||||||||||||
Operating lease obligations (5) | 2,163 | 2,032 | 1,257 | 1,077 | 1,119 | — | 7,648 | |||||||||||||||||||||
Asset retirement obligations (6) | — | — | — | — | — | 15,849 | 15,849 | |||||||||||||||||||||
Total | $ | 131,551 | $ | 88,378 | $ | 80,437 | $ | 455,257 | $ | 761,277 | $ | 522,724 | $ | 2,039,624 | ||||||||||||||
(1) The amounts presented in the table above are outstanding principal balances only. Our Revolving Credit Facility amount is based on the outstanding borrowing as of December 31, 2017. Principal amount borrowed under our Revolving Credit Facility must be repaid prior to the maturity date of December 19, 2021. Any future advances or repayments could change the total amount outstanding under the Revolving Credit Facility.
(2) The amounts include interest costs related to our fixed rate senior notes. The annual interest obligation on the 2025 Senior Notes is $23.6 million, based on the interest rate of 5.25%. The annual interest obligation on the 2022 Senior Notes is $46.4 million, based on the interest rate of 6.625%. The table above does not include interest costs, future commitment fees or other fees on our Revolving Credit Facility, as these obligations are based on floating rates as more fully described in Note 6 in the notes to our consolidated financial statements.
(3) Drilling rig commitments represent the contractual rate for our operated drilling rigs through the term of the contracts as of December 31, 2017. The amounts presented in the table represent our gross commitments under these contracts.
(4) Purchase obligations include sand commitments, water commitments and throughput volume delivery commitments. Subsequent to December 31, 2017, we entered into a fixed-price power purchase contract to manage the volatility of the price of power needed for ongoing operations. This contract will increase our purchase obligations by approximately $72 million over twelve years.
(5) Operating lease obligations include office and vehicle leases.
(6) Costs related to asset retirement obligations typically extend many years into the future. Our calculation of asset retirement obligations uses numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, changes in technology and changes in the legal, regulatory, environmental and political environments.
Off-Balance Sheet Arrangements
As of December 31, 2017, we did not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources and would be considered material to investors.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
Year Ended December 31, | ||||||||||||
(in thousands) | 2017 | 2016 | 2015 | |||||||||
Net cash provided by operating activities | $ | 498,367 | $ | 166,213 | $ | 218,805 | ||||||
Net cash used in investing activities | (1,517,254 | ) | (1,029,423 | ) | (874,939 | ) | ||||||
Net cash provided by financing activities | 366,213 | 1,411,245 | 742,583 | |||||||||
Net change in cash | $ | (652,674 | ) | $ | 548,035 | $ | 86,449 | |||||
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For the year ended December 31, 2017, our net cash provided by operating activities was $498.4 million as compared to $166.2 million for the year ended December 31, 2016. The increase was primarily attributable to increased production from our drilling program, along with the impact of our SHEP I and SHEP II acquisitions that closed in 2016 and 2017, respectively, and increased realized pricing for all our products. For the year ended December 31, 2016, our net cash provided by operating activities was $166.2 million as compared to $218.8 million for the year ended December 31, 2015. The decrease was primarily attributable to a reduction in amounts received from our settled derivative contracts in the 2016 period.
For the year ended December 31, 2017, our net cash used in investing activities was $1.5 billion due to oil and natural gas property acquisitions of $866.9 million primarily related to the Delaware Basin properties purchased in the SHEP II acquisition and $629.0 million of cash used for the drilling and completion activity of our oil and natural gas properties in the Midland and Delaware basins. For the year ended December 31, 2016, our net cash used in investing activities was $1.0 billion primarily related to the SHEP I acquisition and drilling and completion activity of our oil and natural gas properties. For the year ended December 31, 2015, our net cash used in investing activities was $874.9 million primarily related to the acquisitions of undeveloped acreage and oil and gas producing properties in the Midland Basin and drilling and completion activity of our oil and natural gas properties.
For the year ended December 31, 2017, our net cash provided by financing activities was $366.2 million primarily due to $375.0 million of borrowings under our Revolving Credit Facility. For the year ended December 31, 2016, our net cash provided by financing activities was $1.4 billion primarily due to $976.0 million of net proceeds received from the issuance of our common stock and $450.0 million of proceeds received from the issuance of 2025 Senior Notes. For the year ended December 31, 2015, our net cash provided by financing activities was $742.6 million primarily due to $543.5 million of net proceed received from the issuance of our common stock and $198.5 million of net proceeds received from the issuance of additional 2022 Senior Notes.
Our Revolving Credit Facility
As of December 31, 2017, our credit agreement had a borrowing base of $1.5 billion, an elected commitment amount of $900 million, lenders’ maximum facility commitments of $2.5 billion, and a maturity date of December 19, 2021. The credit agreement permits RSP Permian L.L.C, a wholly-owned subsidiary of the Company (“RSP LLC”), to make payments to the Company to enable it to pay principal, premium (if any) and interest on our existing senior notes, provided no default has occurred, and to allow RSP LLC to guarantee the existing senior notes.
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, NGLs and natural gas reserves, estimated cash flows from these reserves and our commodity hedge positions. As of December 31, 2017, we had $375.0 million of borrowings and $1.9 million of letters of credit outstanding under our Revolving Credit Facility and $523.1 million of borrowing capacity. In the event of any future offerings of senior unsecured notes issued or guaranteed by RSP LLC, the borrowing base under our Revolving Credit Facility will be automatically reduced by an amount equal to 0.25 multiplied by the aggregate principal amount of notes issued or guaranteed on the date of such issuance.
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 designate as an unrestricted subsidiary.
Our Revolving Credit Facility contains restrictive covenants that may limit our 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 our expected production;
•enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness;
•incur liens;
•sell assets; and
•engage in certain other transactions without the prior consent of the lenders.
Our Revolving Credit Facility also requires us to maintain the following two financial ratios:
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• | a working capital ratio, which is the ratio of consolidated current assets (includes unused commitments under our Revolving Credit Facility and excludes restricted cash and derivative assets) to consolidated current liabilities (excluding the current portion of long term debt under our Revolving 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 our Revolving Credit Facility) for the four fiscal quarters then ended, of not greater than 4.25 to 1.0. |
We were in compliance with such covenants and ratios as of December 31, 2017.
Principal amounts borrowed under our Revolving Credit Facility 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. We have a choice of borrowing at a Eurodollar rate or at the adjusted base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR plus an applicable margin depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s referenced rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate plus 100 basis points, plus an applicable margin depending on the percentage of our borrowing base utilized, plus a commitment fee charged on the undrawn commitment amount. On December 31, 2017, our weighted average interest rate was approximately 3.6%.
See Note 6 in the notes to our consolidated financial statements for a further discussion of our Revolving Credit Facility.
Critical Accounting Policies and Estimates
The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements.
Successful Efforts Method of Accounting for Oil and Natural Gas Activities
Our oil, NGLs and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, we capitalize lease acquisition costs, all development costs and successful exploration well costs.
Unproved properties. Costs associated with the acquisition of undeveloped leaseholds are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.
Exploration costs. Exploration costs are charged to expense as incurred. These costs include seismic expenditures, geological and geophysical costs and lease rentals.
Proved oil and natural gas properties. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil, gas and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells and service wells, including unsuccessful development wells, are capitalized. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted using the unit-of-production method based on proved reserves. Capitalized exploration well costs and development costs, including asset retirement obligations, are depleted using the unit-of-production method based on proved developed reserves.
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Estimates of Proved Reserves
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations. To estimate economically recoverable proved reserves and related future net cash flows, many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates were considered. Proved reserve quantities directly and materially impact depletion expense, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. See Item 2. Properties and Note 12 in the note to our consolidated financial statements for additional information regarding our estimates of proved reserves.
Impairment
The capitalized costs of proved oil and natural gas properties are reviewed for impairment annually or whenever events or changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and natural gas properties and compare these future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to fair value. We estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate. The calculation of expected future net cash flows in impairment evaluations are mainly based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserves quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted reserves. The Company’s estimates for future oil, NGLs and natural gas prices used in the impairment evaluations are based on observable prices for the next three years, and then held constant for the remaining lives of the properties. For purposes of our impairment analysis as of December 31, 2017, for 2018, 2019, 2020 and thereafter we used (i) average oil prices of $59.14, $55.82, $53.55 and $52.10 per Bbl, respectively, (ii) average NGLs prices of $21.07, $20.15, $19.50 and $19.37 per Bbl, respectively, and (iii) average natural gas prices of $2.90, $2.80, $2.82 and $2.85 per MMBtu, respectively. Oil, NGLs and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. For example, during the period from January 1, 2014 through December 31, 2017, oil prices fluctuated from a high of $107.62 per Bbl on July 23, 2014 to $26.21 per Bbl on February 11, 2016, and natural gas prices fluctuated from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. We are unable to predict the direction of future commodity prices. If the prices used to assess our oil and natural gas properties for impairment were 15% lower than the prices we used for such analysis, holding all other variables constant, we would not have expected to record any material impairment to our proved oil and natural properties. However, oil and natural gas prices used in future impairment evaluations may decline, which could result in the need to impair the carrying value of our proved properties.
Unproved property costs and related leasehold expirations are assessed quarterly for potential impairment and when industry conditions dictate an impairment may be possible. If unproved leasehold costs are found to be impaired, a loss is recognized in the consolidated statements of operations. To the extent that the Company has substantial amounts of expiring acreage in future periods, and may not be able to successfully develop this acreage due to, among other things, market or liquidity concerns, then impairment expense may be material in those future periods. The possibility and amount of any future impairment expense is difficult to predict and requires substantial judgment. Please see the table of expiring acreage in “Part I, Item 2. Properties” in this report.
Valuation of Business Combinations
In connection with a business combination, the acquiring company must record assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax basis of assets and liabilities. Any excess of purchase price over amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the value attributed to assets acquired and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties and integrated assets. To estimate the fair values of these properties, we utilize estimates of oil, NGLs and natural gas reserves. We make future price assumptions to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows were discounted using a market-
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based weighted average cost of capital rates determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rates are subject to additional project-specific risking factors. To estimate the fair value of unproved property, we apply risk-weighting factors of the future net cash flows of unproved reserves, or we may evaluate acreage values through recent market transactions in the area.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in a higher depletion expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value.
Income Taxes
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. On December 22, 2017, the Tax Act was enacted, which reduced the federal corporate tax rate from 35% to 21% beginning January 1, 2018. We recognized the effect of this rate change on our deferred tax assets and liabilities in 2017, which resulted in a non-cash decrease to the income tax provision of $144.4 million for the quarter ended December 31, 2017. 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.
Derivative Financial Instruments
We use derivative instruments to manage our exposure to cash-flow variability from commodity-price risk inherent in oil and natural gas production. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings. The fair value of derivative financial instruments is determined utilizing industry standard models incorporating assumptions and inputs, most of 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.
Recently Issued Accounting Pronouncements
The effects of recently issued accounting pronouncements are discussed in Note 2 of the notes to our consolidated financial statements included in “Part II, Item 8. Financial Statements and Supplementary Data.”
ITEM 7A. QUALITATIVE AND QUANTITATIVE 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, NGLs 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 we receive for our oil, NGLs and natural gas production. Pricing for oil, NGLs and natural gas 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 NGLs and natural gas. 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 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.
The fair value of our derivative contracts as of December 31, 2017 was a net liability of $42.2 million. For information regarding the summary of open positions and terms of these hedges, see Note 4 in the notes to our consolidated financial statements.
60
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 we deem appropriate. The counterparties to our derivative contracts currently in place are lenders under our Revolving Credit Facility and 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, NGLs and natural gas production due to the concentration of our oil, NGLs 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
Our exposure to interest rate changes related primarily to borrowings under our Revolving Credit Facility. Interest is payable on borrowings under the Revolving Credit Facility based on a floating rate as more fully described in Note 6 in the notes to our consolidated financial statements. At December 31, 2017, we had $375.0 million in borrowings outstanding under the Revolving Credit Facility that are subject to interest rate risk. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the assumed weighted average interest rate would result in an increase or decrease in our interest expense of approximately $3.8 million per year. We currently do not engage in any interest rate hedging activity.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this Item appears beginning on page 67 of this Report and is incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. 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 December 31, 2017. 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 December 31, 2017 at the reasonable assurance level.
Attestation Report of the Registered Public Accounting Firm
Grant Thornton LLP, our independent registered public accounting firm, attested to, and report on, our internal control over financial reporting. Grant Thornton’s attestation report is referenced on page 68 under the caption “Report of Independent Registered Public Accounting Firm” and is incorporated herein by reference.
Changes in Internal Control over Financial Reporting
61
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 December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed by or under the supervision of the Company’s principal executive officer and principal financial officer and effected by the Company’s board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
The Company’s management, with the participation of its principal executive officer and principal financial officer assessed the effectiveness, as of December 31, 2017, of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework (2013),” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting at a reasonable assurance level as of December 31, 2017, based on those criteria.
ITEM 9B. OTHER INFORMATION
None.
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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required under Item 10 will be set forth in our definitive proxy statement to be filed in connection with our annual stockholders’ meeting to be held in May 2018 and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required under Item 11 will be set forth in our definitive proxy statement to be filed in connection with our annual stockholders’ meeting to be held in May 2018 and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required under Item 12 will be set forth in our definitive proxy statement to be filed in connection with our annual stockholders’ meeting to be held in May 2018 and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required under Item 13 will be set forth in our definitive proxy statement to be filed in connection with our annual stockholders’ meeting to be held in May 2018 and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required under Item 14 will be set forth in our definitive proxy statement to be filed in connection with our annual stockholders’ meeting to be held in May 2018 and is incorporated herein by reference.
63
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
a. The following documents are filed as a part of this Report or incorporated herein by reference:
(1) Financial Statements:
See “Part II, Item 8. Financial Statements and Supplementary Data.”
(2) Financial Statement Schedules:
None.
(3) Exhibits:
The following documents are included as exhibits to this Report:
EXHIBIT INDEX | ||
Exhibit No. | Description | |
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). | ||
Amended and Restated Bylaws 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 December 21, 2016). | ||
Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-1/A (File No. 333-192268) filed with the Commission on January 13, 2014). | ||
Registration Rights Agreement, dated as of January 23, 2014, among the Company, 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. 001-36264) filed with the Commission on January 29, 2014). | ||
Stockholders’ Agreement, dated as of January 23, 2014, among the Company, 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. 001-36264) filed with the Commission on January 29, 2014). | ||
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). | ||
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). | ||
Registration Rights Agreement, dated as of November 28, 2016, by and between the Company and Silver Hill Energy Partners Holdings, LLC (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the SEC on October 13, 2016). | ||
Stockholder’s Agreement, dated as of November 28, 2016, by and between the Company and Kayne Anderson Capital Advisors, LP (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the SEC on October 13, 2016). | ||
Indenture, dated as of December 27, 2016, by and among the Company, RSP Permian, L.L.C., Silver Hill Energy Partners, LLC 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 December 27, 2016). | ||
Form of Senior Note due 2025 (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 December 27, 2016). | ||
Registration Rights Agreement, dated as of March 1, 2017, by and between the Company and Silver Hill Energy Partners II, LLC (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the SEC on October 13, 2016). | ||
10.1(c) | 2014 Long Term Incentive Plan (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 January 22, 2014). | |
10.2(c) | Form of Restricted Stock Grant and Award Agreement (Performance Vesting) (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 April 16, 2014). | |
10.3(c) | Form of Restricted Stock Grant and Award Agreement (incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q (File No. 001-36264) filed with the Commission on May 15, 2014). | |
10.4(c) | Form of Indemnification Agreement (incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1/A (File No. 333-192268) filed with the Commission on January 2, 2014). | |
10.5(c) | Executive Change in Control and Severance Benefit Plan of RSP Permian, Inc. (incorporated by reference to Exhibit 10.6 to the Company’s Registration Statement on Form S-1/A (File No. 333-196388) filed with the Commission on July 25, 2014). | |
10.6(c) | Form of Amendment No. 1 to Restricted Stock Grant and Award Agreement (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 February 20, 2018). | |
64
10.7(c) | Form of Amendment No. 1 to Restricted Stock Grant and Award Agreement (Performance Vesting) (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the Commission on February 20, 2018). | |
10.8(c) | Form of Restricted Stock Grant and Award Agreement (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the Commission on February 20, 2018). | |
10.9(c) | Form of Restricted Stock Grant and Award Agreement (Performance Vesting) (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the Commission on February 20, 2018). | |
Surface Use and Settlement Agreement, dated November 17, 2015, by and between Collins & Wallace Holdings, LLC and RSP Permian, L.L.C. (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 November 23, 2015). | ||
Membership Interest Purchase and Sale Agreement, dated as of October 13, 2016, by and among Silver Hill Energy Partners Holdings, LLC, Silver Hill Energy Partners, LLC, RSP Permian, L.L.C. and the Company (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 October 13, 2016). | ||
Membership Interest Purchase and Sale Agreement, dated as of October 13, 2016, by and among Silver Hill Energy Partners II, LLC, Silver Hill E&P II, LLC, RSP Permian, L.L.C. and the Company (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the Commission on October 13, 2016). | ||
Purchase Agreement dated as of December 12, 2016, by and among the Company, the Guarantors and Barclays Capital Inc. and RBC Capital Markets, LLC, as representatives of the several initial purchasers (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 December 13, 2016). | ||
Credit Agreement, dated as of December 19, 2016, among the Company, RSP Permian, L.L.C., JPMorgan Chase Bank, N.A., 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 December 21, 2016). | ||
First Amendment to Credit Agreement dated as of October 19, 2017, by and among RSP Permian, Inc., RSP Permian, L.L.C., the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36264) filed with the SEC on October 23, 2017). | ||
12.1(a) | Computation of Ratio of Earnings to Fixed Charges. | |
21.1(a) | Subsidiaries of RSP Permian, Inc. | |
23.1(a) | Consent of Grant Thornton LLP. | |
23.2(a) | Consent of Netherland, Sewell & Associates, Inc. | |
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. | |
Netherland, Sewell & Associates, Inc. Summary of Reserves at December 31, 2017 (RSP Permian, Inc.). | ||
101.INS(a) | XBRL Instance Document. | |
101.SCH(a) | XBRL Taxonomy Extension Schema Document. | |
101.CAL(a) | XBRL Taxonomy Extension Calculation Linkbase Document. | |
101.DEF(a) | XBRL Taxonomy Extension Definition Linkbase Document. | |
101.LAB(a) | XBRL Taxonomy Extension Label Linkbase Document. | |
101.PRE(a) | 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) Management contract or compensatory plan or arrangement.
65
ITEM 16. FORM 10-K SUMMARY
None
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/ Steven Gray | |||
Steven Gray | ||||
Chief Executive Officer and Director | ||||
Date: | February 27, 2018 | |||
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. | ||||
Signature | Title | Date | ||
/s/ Steven Gray | Chief Executive Officer and Director | February 27, 2018 | ||
Steven Gray | (Principal Executive Officer) | |||
/s/ Scott McNeill | Chief Financial Officer and Director | February 27, 2018 | ||
Scott McNeill | (Principal Financial Officer) | |||
/s/ Uma L. Datla | Chief Accounting Officer | February 27, 2018 | ||
Uma L. Datla | (Principal Accounting Officer) | |||
/s/ Michael Grimm | Chairman of the Board | February 27, 2018 | ||
Michael Grimm | ||||
/s/ Joseph B. Armes | Director | February 27, 2018 | ||
Joseph B. Armes | ||||
/s/ Kenneth Huseman | Director | February 27, 2018 | ||
Kenneth Huseman | ||||
/s/ Matthew S. Ramsey | Director | February 27, 2018 | ||
Matthew S. Ramsey | ||||
/s/ Michael W. Wallace | Director | February 27, 2018 | ||
Michael W. Wallace | ||||
66
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
67
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
RSP Permian, Inc.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of RSP Permian, Inc. (a Delaware corporation) and subsidiary (the “Company”) as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2017, and our report dated February 27, 2018 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Dallas, Texas
February 27, 2018
68
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
RSP Permian, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of RSP Permian, Inc. (a Delaware corporation) and subsidiary (the “Company”) as of December 31, 2017 and 2016, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 27, 2018 expressed an unqualified opinion thereon.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2013.
Dallas, Texas
February 27, 2018
69
PART IV
RSP PERMIAN, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data) | December 31, 2017 | December 31, 2016 | ||||||
ASSETS | ||||||||
CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 38,102 | $ | 690,776 | ||||
Accounts receivable | 111,157 | 73,671 | ||||||
Derivative instruments | 64 | 11,815 | ||||||
Total current assets | 149,323 | 776,262 | ||||||
PROPERTY, PLANT AND EQUIPMENT | ||||||||
Oil and natural gas properties, successful efforts method | 6,802,517 | 4,645,781 | ||||||
Accumulated depletion | (778,596 | ) | (554,419 | ) | ||||
Total oil and natural gas properties, net | 6,023,921 | 4,091,362 | ||||||
Other property and equipment, net | 56,798 | 38,273 | ||||||
Total property, plant and equipment | 6,080,719 | 4,129,635 | ||||||
OTHER LONG-TERM ASSETS | ||||||||
Derivative instruments | 37 | — | ||||||
Restricted cash | — | 152 | ||||||
Other long-term assets | 40,107 | 90,378 | ||||||
Total other long-term assets | 40,144 | 90,530 | ||||||
TOTAL ASSETS | $ | 6,270,186 | $ | 4,996,427 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
CURRENT LIABILITIES | ||||||||
Accounts payable | $ | 26,758 | $ | 14,074 | ||||
Accrued expenses | 119,439 | 53,192 | ||||||
Interest payable | 23,798 | 12,142 | ||||||
Derivative instruments | 36,566 | 28,861 | ||||||
Total current liabilities | 206,561 | 108,269 | ||||||
LONG-TERM LIABILITIES | ||||||||
Other long term liabilities | 15,849 | 15,916 | ||||||
Derivative instruments | 5,722 | — | ||||||
Long-term debt | 1,509,128 | 1,132,275 | ||||||
Deferred taxes | 210,568 | 322,655 | ||||||
Total long-term liabilities | 1,741,267 | 1,470,846 | ||||||
Total liabilities | 1,947,828 | 1,579,115 | ||||||
STOCKHOLDERS’ EQUITY | ||||||||
Common stock, $.01 par value; 300,000,000 shares authorized, 158,596,324 shares issued and outstanding at December 31, 2017; 141,923,591 shares issued and outstanding at December 31, 2016 | 1,586 | 1,419 | ||||||
Additional paid-in capital | 4,128,659 | 3,455,916 | ||||||
Accumulated earnings (deficit) | 192,113 | (40,023 | ) | |||||
Total stockholders’ equity | 4,322,358 | 3,417,312 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 6,270,186 | $ | 4,996,427 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
70
RSP PERMIAN, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, | ||||||||||||
(in thousands, except per share data) | 2017 | 2016 | 2015 | |||||||||
REVENUES | ||||||||||||
Oil sales | $ | 704,838 | $ | 321,588 | $ | 263,286 | ||||||
Natural gas sales | 36,206 | 13,945 | 10,517 | |||||||||
NGL sales | 62,664 | 18,324 | 10,189 | |||||||||
Total revenues | 803,708 | 353,857 | 283,992 | |||||||||
OPERATING EXPENSES | ||||||||||||
Lease operating expenses | 122,893 | 57,778 | 53,124 | |||||||||
Production and ad valorem taxes | 48,908 | 21,615 | 19,995 | |||||||||
Depreciation, depletion and amortization | 279,711 | 194,360 | 154,039 | |||||||||
Asset retirement obligation accretion | 605 | 472 | 336 | |||||||||
Impairments of oil and natural gas properties | 59,077 | 4,901 | 34,269 | |||||||||
Exploration expenses | 7,771 | 1,093 | 2,380 | |||||||||
General and administrative expenses | 47,408 | 36,170 | 27,317 | |||||||||
Acquisition costs | 4,525 | 6,374 | — | |||||||||
Total operating expenses | 570,898 | 322,763 | 291,460 | |||||||||
Loss on sale of assets | — | — | 306 | |||||||||
OPERATING INCOME (EXPENSE) | 232,810 | 31,094 | (7,774 | ) | ||||||||
OTHER INCOME (EXPENSE) | ||||||||||||
Other income, net | 3,436 | 1,833 | 469 | |||||||||
Net gain (loss) on derivative instruments | (39,279 | ) | (23,760 | ) | 20,906 | |||||||
Interest expense | (82,459 | ) | (52,724 | ) | (43,538 | ) | ||||||
Total other expense | (118,302 | ) | (74,651 | ) | (22,163 | ) | ||||||
INCOME (LOSS) BEFORE TAXES | 114,508 | (43,557 | ) | (29,937 | ) | |||||||
INCOME TAX BENEFIT | 117,628 | 18,706 | 11,683 | |||||||||
NET INCOME (LOSS) | $ | 232,136 | $ | (24,851 | ) | $ | (18,254 | ) | ||||
Earnings (loss) per common share: | ||||||||||||
Basic | $ | 1.50 | $ | (0.23 | ) | $ | (0.21 | ) | ||||
Diluted | $ | 1.49 | $ | (0.23 | ) | $ | (0.21 | ) | ||||
Weighted average shares outstanding: | ||||||||||||
Basic | 154,162 | 107,324 | 86,770 | |||||||||
Diluted | 155,526 | 107,324 | 86,770 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
71
RSP PERMIAN, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
Common Stock | |||||||||||||||||||
(in thousands) | Shares | Amount | Additional Paid-in Capital | Accumulated Earnings (Deficit) | Total Stockholders’ Equity | ||||||||||||||
BALANCE AT DECEMBER 31, 2014 | 77,904 | $ | 779 | $ | 1,322,494 | $ | 2,498 | $ | 1,325,771 | ||||||||||
Shares of common stock issued in public offerings, net of offering costs | 22,540 | 226 | 543,298 | — | 543,524 | ||||||||||||||
Repurchase and retirement of common stock | (69 | ) | (1 | ) | (1,840 | ) | — | (1,841 | ) | ||||||||||
Equity-based compensation | 432 | 4 | 9,380 | — | 9,384 | ||||||||||||||
Net loss | — | — | — | (18,254 | ) | (18,254 | ) | ||||||||||||
BALANCE AT DECEMBER 31, 2015 | 100,807 | $ | 1,008 | $ | 1,873,332 | $ | (15,756 | ) | $ | 1,858,584 | |||||||||
Shares of common stock issued in public offerings, net of offering costs | 25,300 | 253 | 975,722 | — | 975,975 | ||||||||||||||
Shares of common stock issued for acquisition | 14,980 | 150 | 595,769 | — | 595,919 | ||||||||||||||
Repurchase and retirement of common stock | (98 | ) | (1 | ) | (2,661 | ) | — | (2,662 | ) | ||||||||||
Equity-based compensation | 935 | 9 | 13,754 | — | 13,763 | ||||||||||||||
Net loss | — | — | — | (24,851 | ) | (24,851 | ) | ||||||||||||
BALANCE AT DECEMBER 31, 2016 | 141,924 | $ | 1,419 | $ | 3,455,916 | $ | (40,607 | ) | $ | 3,416,728 | |||||||||
Adoption of ASU 2016-09 (Note 2) | — | — | — | 584 | 584 | ||||||||||||||
BALANCE AT JANUARY 1, 2017 | 141,924 | $ | 1,419 | $ | 3,455,916 | $ | (40,023 | ) | $ | 3,417,312 | |||||||||
Shares of common stock issued for acquisition | 16,020 | 160 | 663,694 | — | 663,854 | ||||||||||||||
Equity issuance costs | (349 | ) | — | (349 | ) | ||||||||||||||
Repurchase and retirement of common stock | (179 | ) | (1 | ) | (7,744 | ) | — | (7,745 | ) | ||||||||||
Equity-based compensation | 831 | 8 | 17,142 | — | 17,150 | ||||||||||||||
Net income | — | — | — | 232,136 | 232,136 | ||||||||||||||
BALANCE AT DECEMBER 31, 2017 | 158,596 | $ | 1,586 | $ | 4,128,659 | $ | 192,113 | $ | 4,322,358 | ||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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RSP PERMIAN, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, | ||||||||||||
(in thousands) | 2017 | 2016 | 2015 | |||||||||
OPERATING ACTIVITIES: | ||||||||||||
Net income (loss) | $ | 232,136 | $ | (24,851 | ) | $ | (18,254 | ) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||
Depreciation, depletion and amortization | 279,711 | 194,360 | 154,039 | |||||||||
Asset retirement obligation accretion | 605 | 472 | 336 | |||||||||
Impairment of oil and natural gas properties | 59,077 | 4,901 | 34,269 | |||||||||
Equity-based compensation | 17,150 | 13,763 | 9,384 | |||||||||
Amortization of loan fees and discount on debt issuance | 4,181 | 2,675 | 2,219 | |||||||||
Deferred income taxes | (112,087 | ) | (14,633 | ) | (17,179 | ) | ||||||
Other | (593 | ) | (570 | ) | (8 | ) | ||||||
Loss on sale of assets | — | — | 306 | |||||||||
Net (gain) loss on derivative instruments | 39,279 | 23,760 | (20,906 | ) | ||||||||
Net cash (payments) receipts from settled derivatives | (11,907 | ) | 7,704 | 89,533 | ||||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable | (37,486 | ) | (45,909 | ) | 6,698 | |||||||
Other assets | (8,396 | ) | 3,180 | (13,570 | ) | |||||||
Accounts payable and accounts payable to related parties | 10,454 | (4,096 | ) | (13,700 | ) | |||||||
Accrued expenses | 14,587 | 5,464 | 2,717 | |||||||||
Interest payable | 11,656 | (7 | ) | 2,921 | ||||||||
Net cash provided by operating activities | $ | 498,367 | $ | 166,213 | $ | 218,805 | ||||||
INVESTING ACTIVITIES: | ||||||||||||
Development of oil and natural gas properties | (628,998 | ) | (286,901 | ) | (401,191 | ) | ||||||
Acquisitions of oil and natural gas properties | (866,855 | ) | (673,946 | ) | (454,552 | ) | ||||||
Acquisition deposit held in escrow | (1,812 | ) | (64,109 | ) | — | |||||||
Acquisitions of infrastructure assets | (19,156 | ) | — | — | ||||||||
Additions to other property and equipment | (1,772 | ) | (2,123 | ) | (17,126 | ) | ||||||
Investment in unconsolidated subsidiary | (188 | ) | (2,344 | ) | (2,704 | ) | ||||||
Proceeds from sale of assets | 1,527 | — | 634 | |||||||||
Net cash used in investing activities | $ | (1,517,254 | ) | $ | (1,029,423 | ) | $ | (874,939 | ) | |||
FINANCING ACTIVITIES: | ||||||||||||
Issuance of common stock | — | 975,975 | 543,524 | |||||||||
Payment of deferred loan costs | (693 | ) | (12,068 | ) | 2,400 | |||||||
Borrowings under long-term debt | 375,000 | 253,826 | 65,000 | |||||||||
Payments on long-term debt | — | (253,826 | ) | (65,000 | ) | |||||||
Issuance of senior unsecured notes | — | 450,000 | 198,500 | |||||||||
Payments of equity issuance costs | (349 | ) | — | — | ||||||||
Repurchase and retirement of common stock | (7,745 | ) | (2,662 | ) | (1,841 | ) | ||||||
Net cash provided by financing activities | 366,213 | 1,411,245 | 742,583 | |||||||||
NET CHANGE IN CASH | (652,674 | ) | 548,035 | 86,449 | ||||||||
CASH AT BEGINNING OF PERIOD | 690,776 | 142,741 | 56,292 | |||||||||
CASH AT END OF PERIOD | $ | 38,102 | $ | 690,776 | $ | 142,741 | ||||||
SUPPLEMENTAL CASH FLOW INFORMATION | ||||||||||||
Cash paid for interest | $ | 66,622 | $ | 50,010 | $ | 42,960 | ||||||
Cash paid for taxes | — | 2,000 | 3,450 | |||||||||
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES | ||||||||||||
Change in accrued capital expenditures | 46,405 | 8,496 | (21,463 | ) | ||||||||
Common stock issued for oil and gas properties | 663,854 | 595,919 | — | |||||||||
Release of deposit held in escrow for oil and gas properties | 64,122 | — | — | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION
RSP Permian, Inc., a Delaware corporation (“RSP Inc.,” the “Company,” “we,” “our,” or “us”), is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of the Company’s acreage is located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin, both sub-basins of the Permian Basin. The Midland Basin properties are primarily in the adjacent counties of Midland, Martin, Andrews, Ector and Glasscock. The Delaware Basin properties are in Loving and Winkler counties. The Company’s common stock is listed and traded on the NYSE under the ticker symbol “RSPP.”
Basis of Presentation
These consolidated financial statements have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and are presented in accordance with generally accepted accounting principles in the United States (“GAAP”). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation. The consolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.
Subsequent Events
During the first quarter of 2018, we entered into additional derivative contracts covering 698,000 barrels of oil for 2018 and 2.6 million barrels of oil for 2019. See Note 4 for a summary of derivative positions entered into subsequent to December 31, 2017.
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. The more significant estimates pertain to proved oil, NGLs and natural gas reserves, asset retirement obligations (“AROs”), equity-based compensation, estimates relating to oil, natural gas liquids (“NGLs”) and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and income taxes. 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, NGLs and natural gas reserves that may affect the amount at which oil and natural gas properties are recorded. Depletion of oil and natural gas properties are determined using estimates of proved oil, NGLs 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. It is possible that these estimates could be revised at future dates and these revisions could be material.
Reclassifications
Certain reclassifications have been made to prior periods to conform to current period presentation. None of these reclassifications impacted previously reported stockholders’ equity, cash flows, or operating income.
Cash and Cash Equivalents
The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation; however, the Company believes that the counterparties risks are minimal based on the reputation and history of the financial institutions where the deposits are held.
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Accounts Receivable
As of December 31, | ||||||||
(in thousands) | 2017 | 2016 | ||||||
Sale of oil, natural gas and NGLs | $ | 95,942 | $ | 54,422 | ||||
Joint interest owners | 14,880 | 16,681 | ||||||
Federal income tax receivable | 335 | 2,568 | ||||||
Accounts receivable | $ | 111,157 | $ | 73,671 | ||||
Accounts receivable, which are primarily from the sale of oil, NGLs and natural gas, are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. In addition, settled but uncollected derivative contracts, receivables related to joint interest billings and income tax receivables are included in accounts receivable. The Company routinely reviews outstanding balances, assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. The need for an allowance is determined based upon reviews of individual accounts, historical losses, existing economic conditions and other pertinent factors. Bad debt expense was zero for each of the years ended December 31, 2017, 2016 and 2015.
Transactions with Related Parties
There were no material related party transactions that occurred during the years ended December 31, 2017 or 2016.
In the fourth quarter of 2015, the Company acquired undeveloped acreage and oil and gas producing properties from Wolfberry Partners Resources LLC (“WPR”). These properties are located in the core of the Midland Basin and had an aggregate purchase price of approximately $137 million. At the time of the transaction, the majority of WPR was owned both directly and indirectly by certain members of our board of directors and two of our largest shareholders. Due to the related party nature of the WPR acquisition, only the disinterested members of our board of directors, consistent with our related party transaction policy, reviewed and ultimately approved the transaction. The disinterested directors also chose to hire an investment banking firm to advise them and render an opinion as to the fairness of the acquisition to the Company. Additional details of this acquisition are included in Note 3. There were no other material related party transactions that occurred during the year ended December 31, 2015.
Derivative Financial Instruments
We use derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. These derivative transactions are generally in the form of collars, swaps and puts.
We report the fair value of derivatives on the consolidated balance sheets in derivative instrument assets and derivative instrument liabilities as either current or noncurrent and determines the current and noncurrent classification based on the timing of expected future cash flows of individual contracts. We report these amounts on a gross basis by contract. We do not designate our derivative financial instruments as hedging instruments for financial reporting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings.
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 may capitalize interest on expenditures for significant exploration and development projects that last more than six months, while activities are in progress to bring the assets to their intended use. The Company has not capitalized any interest as projects generally lasted less 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.
Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted using the unit-of-production method based on proved reserves. Capitalized exploration well costs and development costs, including AROs, are depleted using the unit-of-production method based on proved developed reserves. For the years ended December
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31, 2017, 2016, and 2015, depletion expense for oil and natural gas producing property was $277.0 million, $192.8 million, and $152.8 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 December 31, 2017 and December 31, 2016 consisted of the following:
(in thousands) | December 31, 2017 | December 31, 2016 | ||||||
Proved oil and natural gas properties | $ | 3,936,565 | $ | 2,811,853 | ||||
Unproved oil and natural gas properties | 2,865,952 | 1,833,928 | ||||||
Total oil and natural gas properties | 6,802,517 | 4,645,781 | ||||||
Less: Accumulated depletion | (778,596 | ) | (554,419 | ) | ||||
Total oil and natural gas properties, net | $ | 6,023,921 | $ | 4,091,362 | ||||
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 December 31, 2017 and December 31, 2016, there were no costs capitalized in connection with exploratory wells in progress.
Proved oil and natural gas properties are evaluated for impairment annually or whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows available which is the level at which depletion is calculated. To determine if an asset is impaired, the Company compares the carrying value of the asset to the undiscounted future net cash flows by applying estimates of future oil, NGLs and natural gas prices to the estimated future production of oil, NGLs and natural gas reserves over the economic life of the asset and deducting future costs. Future net cash flows are based upon our reservoir engineers’ estimates of proved reserves and risk-adjusted probable reserves.
For a property determined to be impaired, an impairment loss equal to the difference between the asset’s carrying value and its estimated fair value is recognized. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. 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 years ended December 31, 2017 or 2016. For the year ended December 31, 2015, we impaired approximately $19.6 million of proved oil and natural gas properties, which related to properties whose discounted future net revenues were less than the property’s carrying value. The calculation of expected future net cash flows in impairment evaluations are primarily based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserve quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted probable reserves. The Company’s estimates for future oil and natural gas prices used in the impairment evaluations are based on observable prices for the next three years, and then held constant for the remaining lives of the properties.
Unproved property costs and related leasehold expirations are assessed quarterly for potential impairment and when industry conditions dictate an impairment may be possible. For the years ended December 31, 2017, 2016, and 2015 we impaired approximately $59.1 million, $4.9 million, and $14.7 million, respectively, of unproved oil and natural gas properties, which primarily related to management’s expectation that certain leasehold interests would expire and not be renewed, along with certain leasehold interests that may expire or be sold in the future.
Proceeds from the sales of individual oil and natural gas properties that are part of a depletion base are credited to accumulated depletion with no immediate impact on income until the entire depletion base is sold. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base.
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Accrued Expenses
Accrued expenses consist of the following:
As of December 31, | ||||||||
(in thousands) | 2017 | 2016 | ||||||
Accrued capital expenditures | $ | 82,748 | $ | 36,343 | ||||
Other accrued expenses | 36,691 | 16,849 | ||||||
Accrued expenses | $ | 119,439 | $ | 53,192 | ||||
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 the surface acreage 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 liability 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.
After recording these amounts, the ARO liability 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 liability consisted of the following for the period indicated:
Year Ended December 31, 2017 | ||||||||
(in thousands) | 2017 | 2016 | ||||||
Asset retirement obligation at beginning of period | $ | 10,659 | $ | 7,063 | ||||
Liabilities incurred or assumed | 4,780 | 3,154 | ||||||
Liabilities settled | (195 | ) | (30 | ) | ||||
Accretion expense | 605 | 472 | ||||||
Asset retirement obligation at end of period | $ | 15,849 | $ | 10,659 | ||||
Equity-based Compensation
Equity-based compensation expense is recognized in our consolidated statements of operations over the awards’ vesting period based on their estimated fair values on the dates of grant. The Company utilizes the grant date’s closing stock price for the fair value of restricted stock awards and the Monte Carlo simulation method for the fair value of performance-based restricted stock awards. See Note 8 for additional discussion of our equity-based compensation.
Income Taxes
On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was enacted, which made significant changes to U.S. federal income tax law affecting RSP Inc. Beginning January 1, 2018, our income will be taxed at a 21% federal corporate tax rate, a reduction from the 35% federal corporate tax rate in place prior to the Tax Act. We recognized the effect of this rate change on our deferred tax assets and liabilities in 2017, which resulted in a non-cash decrease to the income tax provision of $144.4 million for the quarter ended December 31, 2017. This one-time adjustment was recorded as an income tax benefit in
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the “Income tax benefit” line item in our consolidated statements of operations, and reduced our deferred tax liability on our consolidated balance sheet by the same amount. The Tax Act also repealed the corporate alternative minimum tax (“AMT”) for tax years beginning January 1, 2018. AMT credit carryovers as of December 31, 2017 are refundable beginning in 2018. At December 31, 2017, we had no AMT credit carryovers that are expected to be refunded as a result of the Tax Act. In addition, the Tax Act reduces the maximum deduction for net operating loss (“NOL”) carryforward arising in tax years beginning after 2017 to 80% of our taxable income, and allows any NOLs generated in tax years beginning after December 31, 2017 to be carried forward indefinitely and generally repeals carrybacks. NOLs available for utilization as of December 31, 2017 were approximately $482.0 million.
The Tax Act is a comprehensive bill containing several other provisions, such as limitations on the deductibility of interest expense, bonus depreciation and certain executive compensation changes, that are not expected to materially impact our financial statements.
Staff Accounting Bulletin No. 118 (“SAB 118”) provides a one-year measurement period from a registrant’s reporting period that includes the Tax Act’s enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under Accounting Standards Codification (“ASC”) Topic 740, Income Taxes (“ASC 740”). The ultimate impact of the Tax Act on our reported results in fiscal 2018 and beyond may differ from the estimates provided herein, possibly materially, due to, among other things, changes in interpretations and assumptions we have made, guidance that may be issued, and other actions we may take as a result of the Tax Act. See Note 10 for additional information.
The following is an analysis of the Company’s consolidated income tax (benefit) expense for the periods indicated:
Year Ended December 31, | ||||||||||||
(in thousands) | 2017 | 2016 | 2015 | |||||||||
Current | $ | (5,541 | ) | $ | (4,074 | ) | $ | 5,184 | ||||
Deferred | (112,087 | ) | (14,632 | ) | (16,867 | ) | ||||||
Income Tax Benefit | $ | (117,628 | ) | $ | (18,706 | ) | $ | (11,683 | ) | |||
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 December 31, 2016, the Company had a long-term tax payable related to uncertain tax positions totaling $5.3 million. This amount was recorded in other long term liabilities on the consolidated balance sheet. In the fourth quarter of 2017, the Company decreased the liability associated with uncertain tax positions to $0.4 million due to return to provision adjustments and current year positions, which resulted in a current tax benefit offset by deferred tax expense with no impact to total tax expense. We expect all taxes recorded related to uncertain tax positions to ultimately be refundable due to the Tax Act.
The Company’s U.S. federal income tax returns for 2014 and beyond, and its Texas franchise tax returns for 2013 and beyond, remain subject to examination by the taxing authorities. No other jurisdiction’s returns are significant to the Company’s financial position.
Revenue Recognition
The Company records oil, NGLs and natural gas sales when title passes to the purchaser, which for the Company is primarily at the wellhead. Oil and natural gas production imbalances, which there were none, are accounted for using the sales method. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). See below for additional discussion on the implementation of ASU 2014-09 and the anticipated impact on our financial statements.
Segment Reporting
The Company operates in only one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
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New Accounting Pronouncements
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. Under ASU 2017-01, an entity must first determine whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar assets. If this threshold is met, the set is not a business. If it’s not met, the entity then evaluates whether the set meets the requirement that a business include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. We will apply the guidance in ASU 2017-07 for asset acquisitions occurring subsequent to January 1, 2018. The adoption of ASU 2017-01 will impact the process that the Company uses to evaluate whether the Company has acquired a business or an asset. This update will be applied prospectively and will not have an effect on prior acquisitions.
In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies several aspects of the accounting for share-based payment award transactions. These simplifications include the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The Company adopted this guidance in the first quarter of 2017 using the modified retrospective approach. Accordingly, the deferred tax liability at December 31, 2016 was reduced by $0.6 million with a corresponding adjustment to accumulated deficit in the consolidated balance sheet. Additional tax deductions during 2017 from stock compensation under the guidance of ASU 2016-09 resulted in a reduction to income tax expense of $4.4 million.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). ASU 2016-02 generally requires all lease transactions (with terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.
Revenue from Contracts with Customers (Topic 606) - ASU 2014-09
In May 2014, the FASB issued ASU 2014-09. ASU 2014-09 provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific guidance. The new standard is now effective for annual reporting periods beginning after December 15, 2017. 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 the financial statements. We have selected the modified retrospective method.
We are in the final stages of assessing the impact of adoption of the standard on our consolidated financial statements. We do not believe the adoption of ASU 2014-09 will have a material impact, if any, on our operating income, cash flows or stockholders’ equity. However, the adoption of this guidance is expected to result in certain reclassifications of gathering costs attributable to NGLs and natural gas revenues due to the conclusion that the Company meets the definition of an agent under the control model defined in ASU 2014-09 for certain of its gas processing and purchase contracts. Our conclusions are subject to change, and we continue to review our implementation documentation and finalize our impact assessment. Our evaluation of the new disclosure requirements is ongoing, and we expect that our disclosures surrounding revenue recognition will be more robust upon adoption of ASU 2014-09.
NOTE 3—ACQUISITIONS OF OIL AND NATURAL GAS PROPERTY INTERESTS
Silver Hill Acquisitions
On October 13, 2016, the Company entered into definitive agreements to acquire 100% of Silver Hill Energy Partners, LLC (“SHEP I”) and Silver Hill E&P II, LLC (“SHEP II”, and together with SHEP I, “Silver Hill”) for an aggregate of $1.25 billion in cash and 31.0 million shares of RSP Inc. common stock. Silver Hill was comprised of two privately-held entities that collectively own oil and gas producing properties and undeveloped acreage in Loving and Winkler counties in Texas and owned approximately 40,100 net acres. Silver Hill’s highly contiguous acreage position in the core of the Delaware Basin was complementary to the Company’s asset base and the acquisition creates substantial scale from a production and acreage standpoint. Substantially all of the value of the transaction was related to the value of the oil and gas assets acquired with minimal value ascribed to other assets.
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The SHEP I acquisition closed on November 28, 2016, with cash consideration of $604.0 million, including assumed debt obligations which were repaid, before purchase price adjustments, and approximately 15.0 million shares of RSP Inc. common stock.
The SHEP II acquisition closed on March 1, 2017, with cash consideration of $646.0 million, before purchase price adjustments, and approximately 16.0 million shares of RSP Inc. common stock.
During 2017, we recorded post-closing adjustments of $5.7 million for the Silver Hill acquisitions.
A summary of the consideration transferred and the fair value of assets and liabilities acquired in the Silver Hill acquisitions is as follows:
Purchase Price Allocation (in thousands) | SHEP I | SHEP II | Total | |||||||||
Value of the Company’s common stock issued (1) | $ | 595,919 | $ | 663,854 | $ | 1,259,773 | ||||||
Cash paid to sellers (including deposits) | 531,196 | 641,577 | 1,172,773 | |||||||||
Total consideration for the assets contributed | $ | 1,127,115 | $ | 1,305,431 | $ | 2,432,546 | ||||||
Fair value of oil and natural gas properties | $ | 1,200,632 | $ | 1,308,177 | $ | 2,508,809 | ||||||
Asset retirement obligation | (666 | ) | (822 | ) | (1,488 | ) | ||||||
Assumption of debt | (63,826 | ) | — | (63,826 | ) | |||||||
Assumption of other liabilities | (9,025 | ) | (1,924 | ) | (10,949 | ) | ||||||
Total net assets acquired (2) | $ | 1,127,115 | $ | 1,305,431 | $ | 2,432,546 | ||||||
(1) The Company issued 14,980,362 shares of common stock at $39.78 per share (closing price) on November 28, 2016 in the SHEP I acquisition. The Company issued 16,019,638 shares of common stock at $41.44 per share (closing price) on March 1, 2017 in the SHEP II acquisition.
(2) Approximately 85% and 77% of the acquisition date fair value of oil and natural gas properties was recorded as unproved property in the SHEP I and SHEP II acquisitions, respectively.
The Silver Hill acquisitions were accounted for using the acquisition method of accounting with the Company as the acquirer. Under the acquisition method of accounting, the Company recorded all assets acquired and liabilities assumed at their respective acquisition date fair values at the closing date of the acquisition. The fair values of the assets acquired and liabilities assumed are based on a detailed analysis, using industry accepted methods of estimating the current fair value as described below.
Oil and natural gas properties - Substantially all of the acquired value in the Silver Hill acquisitions was related to the value of the oil and gas assets acquired with minimal value ascribed to the other assets. The Company used two valuation methods in its determination of fair value for the oil and natural gas properties; the discounted cash flow analysis and comparable transaction analysis. The significant assumptions included in the discounted cash flow analysis include commodity price assumptions, costs and capital outlay to develop the acquired properties, pricing differentials, reserve risking, and discount rates. NYMEX strip pricing at the SHEP I and SHEP II acquisition dates of November 28, 2016 and March 1, 2017, respectively, less applicable pricing differentials, were utilized in the discounted cash flow analysis. Risking levels in the discounted cash flow analysis were determined based on a variety of factors, such as existing well performance, offset production and analogue wells. Discount rates used in the discounted cash flow analysis were determined by using the estimated weighted average cost of capital for the Company, discount rates published in third party publications, as well as industry knowledge and experience. The comparable transaction analysis was performed to establish a range of fair values for similarly-situated oil and gas properties that were recently bought or sold in arms-length, observable market transactions. The range of value observed from the Company’s analysis of recent market transactions and the fair value calculation via the discounted cash flow method was used as a basis to determine fair value of the assets. The Company’s fair value conclusion indicated that the discounted cash flow method valuation is substantially in the same range as the comparable transactions reviewed, when considering the comparable transactions on a median or average basis.
Other current liabilities - Other current liabilities assumed in the Silver Hill acquisitions, which related to revenues held in suspense, were carried over at historical carrying values because the assets and liabilities are short term in nature and their carrying values are estimated to represent the best estimate of fair value.
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Asset retirement obligation - The fair value of asset retirement obligations was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate, and timing associated with the incurrence of these costs.
Revenues and earnings of SHEP II acquisition recognized in 2017 subsequent to the acquisition were $66.4 million and $29.5 million, respectively. The Company recognized $4.5 million and $6.4 million of expenses during 2017 and 2016, respectively, primarily related to the Silver Hill acquisitions, and recorded these costs in “Acquisition costs” on the consolidated statement of operations.
Other 2017 Acquisitions
During the third quarter of 2017, the Company closed on two acquisitions of undeveloped acreage and additional mineral interests in the Delaware Basin for an aggregate purchase price of approximately $227.9 million, before purchase price adjustments. These acquisitions were funded with borrowings under our revolving credit facility (“Revolving Credit Facility”). We recorded purchase price adjustments of $3.3 million related to these acquisitions during 2017.
In addition to the acquisitions discussed above, in 2017, the Company closed on bolt-on acquisitions of mostly undeveloped acreage for an aggregate total purchase price of approximately $47.8 million. The acquisitions included additional working interests in properties where the Company owned existing interests as well as other properties in the Company’s core areas. These acquisitions were funded with cash on hand and borrowings under our Revolving Credit Facility.
On January 2, 2017, the Company closed on the acquisition of water infrastructure assets from Lone Wolf Resources and related entities for an aggregate total purchase price of $19.2 million. The acquisition was funded with cash on hand.
Other 2016 Acquisitions
During 2016, the Company also completed bolt-on acquisitions of mostly undeveloped acreage in the Midland Basin for an aggregate total purchase price of approximately $69.4 million. The acquisitions included additional working interests in properties where the Company owned existing interests as well as other properties in the Company’s core areas. These acquisitions were funded with cash on hand.
WPR Acquisition
In the fourth quarter of 2015, the Company acquired undeveloped acreage and oil and gas producing properties for an aggregate purchase price of approximately $137.0 million from WPR. Approximately $41.0 million was recorded as proved oil and gas properties. The acquisition included 4,100 largely contiguous net acres, in the core of the Midland Basin with production of approximately 1,900 Boe/d and 86 net horizontal drilling locations as of the effective date.
Glass Ranch Acquisition
In the third quarter of 2015, the Company acquired undeveloped acreage and oil and gas producing properties located in Martin and Glasscock counties for an aggregate purchase price of approximately $313.0 million. The aggregate acquisitions included 6,548 net acres in our core focus area.
Pro Forma Results (unaudited)
The Company’s summary pro forma results for the twelve months ended December 31, 2017 and 2016 were derived from the actual results of the Company adjusted to reflect the SHEP II acquisition, as if such transaction had occurred on January 1, 2016. The below information reflects pro forma adjustments for the issuance of RSP Inc. common stock to the sellers of SHEP II along with common stock issued in the October 2016 public offering that funded the cash portion of the SHEP II acquisition. Additional pro forma adjustments, based on available information and certain assumptions, include (i) the depletion of SHEP II fair-valued proved oil and gas properties, and (ii) the estimated tax impacts of the pro forma adjustments. Pro forma earnings for the year ended December 31, 2017 were adjusted to exclude $4.5 million of acquisition costs incurred by the Company.
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 SHEP II acquisition, except for the acquisition costs described above.
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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.
Year Ended December 31, 2017 | Year Ended December 31, 2016 | |||||||||||||||
(in thousands) | Actual | Pro Forma | Actual | Pro Forma | ||||||||||||
Revenues | $ | 803,708 | $ | 822,427 | $ | 353,857 | $ | 415,945 | ||||||||
Net income (loss) | 232,136 | 240,596 | (24,851 | ) | (16,757 | ) | ||||||||||
Earnings (loss) per common share: | ||||||||||||||||
Basic | $ | 1.50 | $ | 1.55 | $ | (0.23 | ) | $ | (0.11 | ) | ||||||
Diluted | $ | 1.49 | $ | 1.55 | $ | (0.23 | ) | $ | (0.11 | ) | ||||||
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 oil and natural gas production. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings.
Our commodity derivatives have historically been comprised of the following instruments:
Collars: Each collar transaction has an established price floor and ceiling, and certain collar transactions also include a short put. 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. When the settlement price is below the short put price, the Company receives from its counterparty an amount equal to the difference of the price floor and the short put price multiplied by the hedged contract volume.
Swaps: 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.
Deferred Premium Put: Each deferred premium put option has an established floor price. When the settlement price is below the floor price, the Company receives the difference between the floor price and the settlement price multiplied by the hedged contract volume less the cost of the premium for the option. When the settlement price is at or above the floor price, the Company receives no proceeds and pays the cost of the premium for the option. In either case, whether the settlement price is below or above the floor price, the Company pays the premium for the option at the expiration of the option. We had no open deferred premium put positions as of December 31, 2017.
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The following table summarizes all open positions as of December 31, 2017:
Contracts expiring in the period ending: | ||||||||||||||||||||
March 31, 2018 | June 30, 2018 | September 30, 2018 | December 31, 2018 | 2019 | ||||||||||||||||
Oil Three-Way Collars: | ||||||||||||||||||||
Notional volume (Bbl) | 2,219,000 | 1,941,000 | 1,319,000 | 1,227,000 | — | |||||||||||||||
Weighted average ceiling price ($/Bbl)(1) | $ | 58.81 | $ | 59.07 | $ | 60.56 | $ | 60.96 | $ | — | ||||||||||
Weighted average floor price ($/Bbl)(1) | $ | 46.96 | $ | 47.11 | $ | 47.79 | $ | 48.00 | $ | — | ||||||||||
Weighted average short put price ($/Bbl)(1) | $ | 36.96 | $ | 37.11 | $ | 37.79 | $ | 38.00 | $ | — | ||||||||||
Oil Costless Collars: | ||||||||||||||||||||
Notional volume (Bbl) | 571,000 | 516,000 | 1,212,000 | 1,058,000 | 1,277,500 | |||||||||||||||
Weighted average ceiling price ($/Bbl)(1) | $ | 60.19 | $ | 60.20 | $ | 60.10 | $ | 60.11 | $ | 55.99 | ||||||||||
Weighted average floor price ($/Bbl)(1) | $ | 45.00 | $ | 45.00 | $ | 46.33 | $ | 46.52 | $ | 50.00 | ||||||||||
Oil Swaps: | ||||||||||||||||||||
Notional volume (Bbl) | — | — | 322,000 | 322,000 | 1,277,500 | |||||||||||||||
Weighted average swap price ($/Bbl)(1) | $ | — | $ | — | $ | 55.77 | $ | 55.77 | $ | 53.42 | ||||||||||
Mid-Cush Differential (Basis) Swaps: | ||||||||||||||||||||
Notional volume (Bbl) | 1,859,000 | 1,911,000 | 1,932,000 | 1,932,000 | 730,000 | |||||||||||||||
Weighted average swap price ($/Bbl)(2) | $ | (0.60 | ) | $ | (0.59 | ) | $ | (0.59 | ) | $ | (0.59 | ) | $ | (0.25 | ) | |||||
(1) The oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.
(2) The Mid-Cush swap contracts are settled based on the difference in the arithmetic average during the calculation period of WTI MIDLAND ARGUS and WTI ARGUS prices in the Argus Americas Crude publication for the relevant period.
The following table summarizes all commodity derivative positions entered subsequent to December 31, 2017:
Contracts expiring in the period ending: | ||||||||||||||||||||
March 31, 2018 | June 30, 2018 | September 30, 2018 | December 31, 2018 | 2019 | ||||||||||||||||
Oil Costless Collars: | ||||||||||||||||||||
Notional volume (Bbl) | — | — | — | — | 1,277,500 | |||||||||||||||
Weighted average ceiling price ($/Bbl) | $ | — | $ | — | $ | — | $ | — | $ | 60.10 | ||||||||||
Weighted average floor price ($/Bbl) | $ | — | $ | — | $ | — | $ | — | $ | 55.00 | ||||||||||
Oil Swaps: | ||||||||||||||||||||
Notional volume (Bbl) | — | 698,000 | — | — | 1,277,500 | |||||||||||||||
Weighted average swap price ($/Bbl) | $ | — | $ | 62.97 | $ | — | $ | — | $ | 58.06 | ||||||||||
Mid-Cush Differential (Basis) Swaps: | ||||||||||||||||||||
Notional volume (Bbl) | 531,000 | 819,000 | 828,000 | 828,000 | 1,825,000 | |||||||||||||||
Weighted average swap price ($/Bbl) | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.01 | ) | $ | (0.30 | ) | |||||
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Derivative Fair Values and Gains (Losses)
The following table presents the fair value of our derivative instruments. Our derivatives are presented as separate line items in our consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities based on the expected settlement dates of the instruments. 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 | |||||||||||||||
(in thousands) | December 31, 2017 | December 31, 2016 | December 31, 2017 | December 31, 2016 | ||||||||||||
Derivative Instruments: | ||||||||||||||||
Current amounts | ||||||||||||||||
Commodity contracts | $ | 64 | $ | 11,815 | $ | 36,566 | $ | 28,861 | ||||||||
Noncurrent amounts | ||||||||||||||||
Commodity contracts | 37 | — | 5,722 | — | ||||||||||||
Total derivative instruments | $ | 101 | $ | 11,815 | $ | 42,288 | $ | 28,861 | ||||||||
Gains and losses on derivative instruments are reported in the consolidated statements of operations.
The following table represents the Company’s reported gains (losses) on derivative instruments for the periods presented:
Year Ended December 31, | ||||||||||||
(in thousands) | 2017 | 2016 | 2015 | |||||||||
Net gain (loss) on derivative instruments | $ | (39,279 | ) | $ | (23,760 | ) | $ | 20,906 | ||||
Offsetting of Derivative Assets and Liabilities
The following table presents the Company’s gross and net derivative assets and liabilities.
(in thousands) | Gross Amount Presented on Balance Sheet | Netting Adjustments (a) | Net Amount | |||||||||
December 31, 2017 | ||||||||||||
Derivative instrument assets with right of offset or master netting agreements | $ | 101 | $ | (101 | ) | $ | — | |||||
Derivative instrument liabilities with right of offset or master netting agreements | $ | (42,288 | ) | $ | 101 | $ | (42,187 | ) | ||||
December 31, 2016 | ||||||||||||
Derivative instrument assets with right of offset or master netting agreements | $ | 11,815 | $ | (11,815 | ) | $ | — | |||||
Derivative instrument liabilities with right of offset or master netting agreements | $ | (28,861 | ) | $ | 11,815 | $ | (17,046 | ) | ||||
(a) To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our commodity derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty.
Credit-Risk Related Contingent Features in Derivatives
None of the Company’s derivative instruments contain credit-risk related contingent features. No amounts of collateral were posted by the Company related to net positions as of December 31, 2017 and December 31, 2016.
NOTE 5—FAIR VALUE MEASUREMENTS
We value our derivatives and other financial instruments according to FASB ASC 820, Fair Value Measurements and Disclosures, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (“exit price”) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.
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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 and may 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.
Fair Value Measurement on a Recurring Basis
Fair value of commodity derivative instruments
The fair value of derivative financial instruments is determined utilizing industry standard models incorporating assumptions and inputs, most of which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.
The following table presents a summary of the estimated fair value of our commodity derivative instruments as of December 31, 2017 and 2016.
(in thousands) | Level 1 | Level 2 | Level 3 | Total fair value | ||||||||||||
As of December 31, 2017: | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | (42,187 | ) | $ | — | $ | (42,187 | ) | ||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total fair value | ||||||||||||
As of December 31, 2016: | ||||||||||||||||
Commodity derivative instruments | $ | — | $ | (17,046 | ) | $ | — | $ | (17,046 | ) | ||||||
Fair value of other financial instruments
Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature. The carrying value of our borrowings under our Revolving Credit Facility approximate fair value as these are subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair values of our senior notes are presented below. The estimated fair value of our senior unsecured notes due January 15, 2025 (“2025 Senior Notes”) and senior unsecured notes due October 1, 2022 (“2022 Senior Notes”) have been calculated based on quoted prices in active markets and are classified as Level 1 on December 31, 2017. As described in Note 6, the 2025 Senior Notes were initially issued through a private placement, and were exchanged for registered notes with the same terms in November 2017. As such, prior to November 2017, the estimated fair value of the 2025 Senior Notes were classified as Level 2 as these notes did not trade in active markets.
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Reclassifications of fair value among 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 among Level 1, Level 2 or Level 3 during the years ended December 31, 2017 and 2016, except that the 2025 Senior Notes were reclassified to Level 1.
The following table presents a summary of the estimated fair value of our senior notes as of December 31, 2017 and 2016.
December 31, 2017 | ||||||||||||||||
(in thousands) | Level 1 | Level 2 | Level 3 | Total fair value | ||||||||||||
2025 Senior Notes | $ | 464,022 | $ | — | $ | — | $ | 464,022 | ||||||||
2022 Senior Notes | 734,706 | — | — | 734,706 | ||||||||||||
December 31, 2016 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total fair value | |||||||||||||
2025 Senior Notes | $ | 452,300 | $ | — | $ | — | $ | 452,300 | ||||||||
2022 Senior Notes | — | 735,000 | — | 735,000 | ||||||||||||
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 assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs. Our estimated abandonment costs are obtained primarily from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition or costs incurred historically for similar work. 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:
(in thousands) | December 31, 2017 | December 31, 2016 | ||||||
Revolving Credit Facility | $ | 375,000 | $ | — | ||||
5.25% Senior Notes due 2025 | 450,000 | 450,000 | ||||||
6.625% Senior Notes due 2022 | 700,000 | 700,000 | ||||||
Less: Discount | (950 | ) | (1,150 | ) | ||||
Less: Debt issuance costs | (14,922 | ) | (16,575 | ) | ||||
Total long-term debt | $ | 1,509,128 | $ | 1,132,275 | ||||
Revolving Credit Facility
On October 19, 2017, we entered into a first amendment to our credit agreement to, among other things, (a) increase the borrowing base to $1.5 billion from $1.1 billion and maintain our elected commitment at $900.0 million and (b) decrease the applicable margins for interest rates applicable to amounts outstanding under the Revolving Credit Facility from a range of 200 basis points to 300 basis points above the applicable reference rate for Eurodollar loans and 100 basis points to 200 basis points above the applicable reference rate for alternate base rate (“ABR”) loans to ranges of 150 basis points to 250 basis points for Eurodollar loans and 50 basis points to 150 basis points for ABR loans.
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As of December 31, 2017, we had $375.0 million in borrowings, $1.9 million of letters of credit outstanding and $523.1 million of borrowing capacity under our Revolving Credit Facility. The maturity date of the Revolving Credit Facility is December 19, 2021. The borrowing base under the Revolving Credit Facility remains subject to semi-annual review and redetermination by the lenders pursuant to the term of the credit agreement. The redetermination of the borrowing base occurs in May and November of each year and, among other things, depends on the volumes of proved oil, NGLs and natural gas reserves and an estimate of associated cash flows, and commodity hedge positions. As of December 31, 2017, the borrowing base under the Company’s amended and restated credit agreement was $1.5 billion, with an elected commitment of $900.0 million, and lender commitments of $2.5 billion.
The Company’s credit agreement requires that we maintain the following two 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 4.25 to 1.0.
Our credit agreement also contains restrictive covenants that may limit our 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 our expected production, enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness, incur liens, sell assets, enter into transactions with affiliates or engage in certain other transactions without the prior consent of the lenders.
The Company was in compliance with such covenants and ratios as of December 31, 2017.
Principal amounts borrowed under our Revolving Credit Facility 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. We have a choice of borrowing at a Eurodollar rate or at the adjusted base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted London Interbank Offered Rate (“LIBOR”) (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 150 basis points to 250 basis points, as amended, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s referenced rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate plus 100 basis points, plus an applicable margin ranging from 50 basis points to 150 basis points, as amended, depending on the percentage of our borrowing base utilized, plus a commitment fee ranging from 37.5 basis points to 50 basis points charged on the undrawn commitment amount. On December 31, 2017, our weighted average interest rate was approximately 3.6%.
2025 Senior Notes
On December 27, 2016, the Company issued $450.0 million of 5.25% senior unsecured notes at par through a private placement. The 2025 Senior Notes will mature on January 15, 2025. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are effectively subordinated in rights to our assets constituting collateral held by all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including indebtedness under our Credit Facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on the 2025 Senior Notes is payable semi-annually on January 15 and July 15, commencing on July 15, 2017. On or after January 15, 2020, the Company may redeem some or all of the 2025 Senior Notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 103.938% of principal, declining in twelve-month intervals to 100% in 2023 and thereafter. In addition, prior to January 15, 2020, on any one or more occasions, the Company may redeem all or part of the notes at a redemption price of 100% of the principal amount of the notes redeemed, plus an applicable make-whole premium along with accrued and unpaid interest.
We incurred approximately $6.4 million of debt issuance costs related to the issuance of the 2025 Senior Notes during 2016, which are reductions to “Long-term debt” on our consolidated balance sheets and will be amortized to “Interest expense” on our consolidated statements of operation 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 2025 Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. The subsidiary guarantees are full and unconditional and joint and several, and any of our subsidiaries other than the subsidiary
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guarantors are minor. 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. In November 2017, the Company exchanged $450.0 million of the 2025 Senior Notes for registered notes with the same terms. The Company was in compliance with the provisions of the indenture governing the 2025 Senior Notes as of December 31, 2017.
2022 Senior Notes
On September 26, 2014, the Company issued $500.0 million of 6.625% senior unsecured notes at par through a private placement. On August 10, 2015, the Company issued an additional $200.0 million of the 2022 Senior Notes at 99.25% of the principal amount 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 borrowings under our Credit Facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on the 2022 Senior Notes is payable semi-annually on April 1 and October 1. The Company 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.
We incurred approximately $11.3 million of debt issuance costs related to the issuance of the 2022 Senior Notes during 2014 and $2.4 million during 2015, which are reductions to “Long-term debt” on our consolidated balance sheets and will be amortized to “Interest expense” on our consolidated statements of operations 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 notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. 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. In June 2015, the Company exchanged $500.0 million of the 2022 Senior Notes for registered notes with the same terms. In March 2016, the Company exchanged an additional $200.0 million of the 2022 Senior Note for registered notes with the same terms. The Company was in compliance with the provisions of the indenture governing the 2022 Senior Notes as of December 31, 2017.
NOTE 7—COMMITMENTS AND CONTINGENCIES
Legal and Environmental 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.
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. We have established procedures for the ongoing evaluation of our operations to identify potential environmental exposures and to comply with regulatory policies and procedures.
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 we determine the potential exposure related to, but not limited to, legal matters, environmental assessments and/or clean-ups, is probable and estimable. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both December 31, 2017 and 2016, we had no legal or environmental matters that we deemed to be probable and estimable or any legal or environmental matters requiring specific disclosure.
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Leases
The Company leases office space in Midland and Dallas Texas. These leases run through 2022. Rent expense for the years ended December 31, 2017, 2016, and 2015 was $1.1 million and $0.9 million, and $0.9 million respectively.
Contractual Obligations
A summary of our contractual obligations as of December 31, 2017 is provided in the following table.
Payments Due by Period For the Year Ended December 31, | ||||||||||||||||||||||||||||
(in thousands) | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | Total | |||||||||||||||||||||
Revolving Credit Facility (1) | $ | — | $ | — | $ | — | $ | 375,000 | $ | — | $ | — | $ | 375,000 | ||||||||||||||
5.25% Senior Notes due 2025 (1) | — | — | — | — | — | 450,000 | 450,000 | |||||||||||||||||||||
6.625% Senior Notes due 2022 (1) | — | — | — | — | 700,000 | — | 700,000 | |||||||||||||||||||||
Interest cost (2) | 70,000 | 70,000 | 70,000 | 70,000 | 58,406 | 48,221 | 386,627 | |||||||||||||||||||||
Drilling rig commitments (3) | 14,375 | — | — | — | — | — | 14,375 | |||||||||||||||||||||
Purchase obligations (4) | 45,013 | 16,346 | 9,180 | 9,180 | 1,752 | 8,654 | 90,125 | |||||||||||||||||||||
Operating lease obligations (5) | 2,163 | 2,032 | 1,257 | 1,077 | 1,119 | — | 7,648 | |||||||||||||||||||||
Asset retirement obligations (6) | — | — | — | — | — | 15,849 | 15,849 | |||||||||||||||||||||
Total | $ | 131,551 | $ | 88,378 | $ | 80,437 | $ | 455,257 | $ | 761,277 | $ | 522,724 | $ | 2,039,624 | ||||||||||||||
(1) The amounts presented in the table above are outstanding principal balances only. The Revolving Credit Facility amount is based on the outstanding borrowing as of December 31, 2017. Principal amount borrowed under the Revolving Credit Facility must be repaid prior to the maturity date of December 19, 2021. Any future advances or repayments could change the total amount outstanding under the Revolving Credit Facility.
(2) The amounts include interest costs related to our fixed rate senior notes. The annual interest obligation on the 2025 Senior Notes is $23.6 million, based on the interest rate of 5.25%. The annual interest obligation on the 2022 Senior Notes is $46.4 million, based on the interest rate of 6.625%. The table above does not include interest costs, future commitment fees or other fees on our revolving credit facility, as these obligations are based on floating rates as more fully described in Note 6.
(3) Drilling rig commitments represent the contractual rate for our operated drilling rigs through the term of the contracts as of December 31, 2017. The amounts presented in the table represent our gross commitments under these contracts.
(4) Purchase obligations include our sand commitments, water commitments and throughput volume delivery commitments. Subsequent to December 31, 2017, we entered into a fixed-price power purchase contract to manage the volatility of the price of power needed for ongoing operations. This contract will increase our purchase obligations by approximately $72 million over twelve years.
(5) Operating lease obligations include office and vehicle leases.
(6) Costs related to asset retirement obligations typically extend many years into the future. Our calculation of asset retirement obligations uses numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, changes in technology and changes in the legal, regulatory, environmental and political environments.
NOTE 8—EQUITY-BASED COMPENSATION
The Company adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (“LTIP”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company. A total of 10.0 million shares of common stock have been authorized for issuance under the LTIP. At December 31, 2017, there were 7.2 million shares of common stock available for future grant.
Equity-based payments, including grants of restricted stock awards and performance-based restricted stock awards are recognized in our consolidated statements of operations based on their estimated fair values. We recognize expense on a straight-line basis over the vesting period of the awards. Equity-based compensation expense, which was recorded in general and administrative expenses, was $17.2 million, $13.8 million, and $9.4 million for the years ended December 31, 2017, 2016 and 2015, respectively.
Restricted Stock Awards
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The compensation expense for these awards was determined based on the market price of the Company’s common stock at the date of grant. Equity-based compensation expense for restricted stock awards was $10.2 million, $7.9 million and $6.4 million for the years ended December 31, 2017, 2016 and 2015, respectively.
As of December 31, 2017, the Company had unrecognized compensation expense of $13.6 million related to restricted stock awards which is expected to be recognized over a weighted average period of 1.5 years.
The following table represents restricted stock award activity for the years ended December 31, 2017, 2016 and 2015:
2017 | 2016 | 2015 | |||||||||||||||||||
Shares | Weighted Average Fair Value | Shares | Weighted Average Fair Value | Shares | Weighted Average Fair Value | ||||||||||||||||
Restricted shares outstanding, beginning of period | 656,895 | $ | 22.21 | 499,529 | $ | 25.99 | 477,767 | $ | 23.71 | ||||||||||||
Restricted shares granted | 379,579 | 41.39 | 442,835 | 19.78 | 279,181 | 27.18 | |||||||||||||||
Restricted shares canceled | (27,400 | ) | 31.74 | (13,551 | ) | 21.61 | (6,640 | ) | 26.43 | ||||||||||||
Restricted shares vested | (321,797 | ) | 23.01 | (271,918 | ) | 25.22 | (250,779 | ) | 22.97 | ||||||||||||
Restricted shares outstanding, end of period | 687,277 | $ | 32.04 | 656,895 | $ | 22.21 | 499,529 | $ | 25.99 | ||||||||||||
Performance-Based Restricted Stock Awards
We granted performance-based restricted stock awards to certain officers of the Company. The payout of these awards varies depending on the Company’s total shareholder return in comparison to an identified peer group. We granted 380,174 and 484,650 performance-based restricted stock awards in 2017 and 2016, respectively, that allow for a payout between 0% and 100%. We granted 159,932 performance-based restricted stock awards in 2015 that allow for a payout between 0% and 200%.
Our performance-based restricted stock awards are valued on the date of grant with a cliff vesting period of approximately three years, subject to the achievement of certain criteria. Total compensation expense is recognized over the vesting period using the straight-line method. Equity-based compensation for these awards was $7.0 million, $5.9 million, and $3.0 million for the years ended December 31, 2017, 2016 and 2015, respectively.
The grant date fair values of the performance-based restricted stock awards were determined using a Monte Carlo model which uses company-specific inputs to generate different stock price paths. The range of assumptions used in the Monte Carlo model for the awards granted in 2017, 2016 and 2015 are as follows:
Assumptions | 2017 | 2016 | 2015 | ||||||
Risk-free rate of return | 1.52 | % | 0.95 | % | 0.98 | % | |||
Volatility | 28.5 | % | 54.6 | % | 49.2 | % | |||
The unrecognized compensation expense related to these shares is approximately $9.4 million as of December 31, 2017 and is expected to be recognized over the next 1.3 years.
The following table represents performance-based restricted stock award activity for the years ended December 31, 2017, 2016 and 2015:
2017 | 2016 | 2015 | |||||||||||||||||||
Shares | Weighted Average Fair Value | Shares | Weighted Average Fair Value | Shares | Weighted Average Fair Value | ||||||||||||||||
Restricted shares outstanding, beginning of period | 747,874 | $ | 19.82 | 294,332 | $ | 31.41 | 134,400 | $ | 28.14 | ||||||||||||
Restricted shares granted (1) | 380,174 | 26.96 | 484,650 | 13.53 | 159,932 | 31.74 | |||||||||||||||
Restricted shares canceled | (7,569 | ) | 26.96 | — | — | — | — | ||||||||||||||
Restricted shares vested (1) | (119,400 | ) | 31.01 | (31,108 | ) | 31.39 | — | — | |||||||||||||
Restricted shares outstanding, end of period | 1,001,079 | $ | 21.14 | 747,874 | $ | 19.82 | 294,332 | $ | 31.41 | ||||||||||||
(1) Performance-based restricted shares granted or vested during each period reflect the number of shares granted or vested at a 100% of the target payout. The actual payout of the shares granted may be between 0% and 200% depending on the
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Company’s total shareholder return in comparison to an identified peer group. Awards granted in 2015 allow for a payout of between 0% and 200%, while awards granted in 2016 and 2017 allow for a payout of between 0% and 100%.
NOTE 9—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 years ended December 31, 2016 and 2015, all unvested restricted stock awards and performance-based restricted stock awards were excluded from the diluted 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:
Year Ended December 31, | ||||||||||||
(in thousands, except per share data) | 2017 | 2016 | 2015 | |||||||||
Numerator: | ||||||||||||
Net income (loss) available to stockholders | $ | 232,136 | $ | (24,851 | ) | $ | (18,254 | ) | ||||
Basic net income allocable to participating securities (1) | 1,161 | — | — | |||||||||
Income available to stockholders | $ | 230,975 | $ | (24,851 | ) | $ | (18,254 | ) | ||||
Denominator: | ||||||||||||
Weighted average number of common shares outstanding - basic | 154,162 | 107,324 | 86,770 | |||||||||
Effect of dilutive securities: | ||||||||||||
Restricted stock | 1,364 | — | — | |||||||||
Weighted average number of common shares outstanding - diluted | 155,526 | 107,324 | 86,770 | |||||||||
Net earnings (loss) per share: | ||||||||||||
Basic | $ | 1.50 | $ | (0.23 | ) | $ | (0.21 | ) | ||||
Diluted | $ | 1.49 | $ | (0.23 | ) | $ | (0.21 | ) | ||||
(1) Restricted stock 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.
NOTE 10—INCOME TAXES
On December 22, 2017, the Tax Act was enacted, which made significant changes to U.S. federal income tax law affecting RSP Inc. See Note 2 for a summary of changes and discussion of certain provisions of the Tax Act and the impact of such provisions on our results of operations and consolidated financial statements.
At December 31, 2017, we have made a reasonable estimate of the effects of the Tax Act on our existing deferred tax balances based on our understanding of the guidance available as of the date of this filing. We will continue to monitor for any new administrative guidance or interpretations of the Tax Act.
The components of the provision for income taxes for the year ended December 31, 2017, 2016, and 2015 is as follows:
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For the year ended December 31, | ||||||||||||
(in thousands) | 2017 | 2016 | 2015 | |||||||||
Current Income Tax Expense (Benefit): | ||||||||||||
Federal | $ | (5,541 | ) | $ | (4,074 | ) | $ | 5,504 | ||||
State | — | — | (320 | ) | ||||||||
Total income tax expense (benefit) | (5,541 | ) | (4,074 | ) | 5,184 | |||||||
Deferred Income Tax Expense (Benefit): | ||||||||||||
Federal (1) | $ | (119,925 | ) | $ | (19,195 | ) | $ | (9,649 | ) | |||
State | 2,297 | 489 | (1,714 | ) | ||||||||
Federal alternative minimum tax | 5,541 | 4,074 | (5,504 | ) | ||||||||
Total deferred income tax benefit | (112,087 | ) | (14,632 | ) | (16,867 | ) | ||||||
Total Income Tax Benefit | $ | (117,628 | ) | $ | (18,706 | ) | $ | (11,683 | ) | |||
(1) Beginning January 1, 2018, our income will be taxed at a 21% federal corporate rate, a reduction from the 35% federal corporate rate in place prior to the Tax Act. We recognized the effect of this rate change as a result of the Tax Act on our deferred tax assets and liabilities in 2017, which resulted in a federal deferred income tax benefit of $144.4 million for the quarter ended December 31, 2017.
A reconciliation of tax expense (benefit) based upon the statutory federal income tax rate to the actual income tax expense (benefit)is as follows:
For the year ended December 31, | ||||||||||||
(in thousands) | 2017 | 2016 | 2015 | |||||||||
Income tax expense (benefit) at the federal statutory rate (35%) | $ | 40,078 | $ | (15,245 | ) | $ | (10,478 | ) | ||||
State income tax expense (benefit), net of federal tax benefit | 1,493 | 318 | (1,322 | ) | ||||||||
Impact of enacted legislation | (144,361 | ) | — | — | ||||||||
Equity-based compensation | (4,386 | ) | — | — | ||||||||
Research and development credit | (10,478 | ) | (3,804 | ) | — | |||||||
Other | 26 | 25 | 117 | |||||||||
Provision for (benefit from) income taxes | $ | (117,628 | ) | $ | (18,706 | ) | $ | (11,683 | ) | |||
The components of the Company’s deferred tax assets and liabilities are as follows:
For the year ended December 31, | ||||||||
(in thousands) | 2017 | 2016 (2) | ||||||
Non-current deferred tax assets: | ||||||||
Net operating loss carryforwards (subject to 20 year expiration) (1) | $ | 101,220 | $ | 88,632 | ||||
Tax credit carryforwards | 16,856 | 9,320 | ||||||
Other | 14,615 | 13,185 | ||||||
Total noncurrent deferred tax assets | 132,691 | 111,137 | ||||||
Non-current deferred tax liabilities: | ||||||||
Oil and natural gas properties and equipment | (343,259 | ) | (433,792 | ) | ||||
Total noncurrent deferred tax liabilities | (343,259 | ) | (433,792 | ) | ||||
Net noncurrent deferred tax liabilities | $ | (210,568 | ) | $ | (322,655 | ) | ||
(1) Federal NOL carryforwards totaled $482.0 million and $251.6 million at December 31, 2017 and 2016, respectively, and will begin to expire in 2034. As a result of the Tax Act, maximum deduction allowed for NOL carryforwards arising in tax years beginning after December 31, 2017 will be reduced to 80% of our taxable income, and any NOLs generated in tax years beginning after December 31, 2017 will be carried forward indefinitely.
(2) The deferred tax liability at December 31, 2016 was reduced by $0.6 million from the previously reported amount as a result of the adoption of ASU 2016-09. See Note 2 for additional discussion of ASU 2016-09.
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We have not recognized any interest and penalties relating to unrecognized tax benefits in our consolidated financial statements. Changes in the balance of unrecognized tax benefits on uncertain positions were as follows:
For the year ended December 31, | ||||||||||||
(in thousands) | 2017 | 2016 | 2015 | |||||||||
Unrecognized tax benefits at beginning of period | $ | 9,035 | $ | — | $ | — | ||||||
Increase resulting from prior period tax positions | 6,653 | 8,483 | — | |||||||||
Increase resulting from current period tax positions | 7,370 | 552 | — | |||||||||
Unrecognized tax benefits at the end of period | 23,058 | 9,035 | — | |||||||||
Less: Effects of temporary items | (3,729 | ) | (5,256 | ) | — | |||||||
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year | $ | 19,329 | $ | 3,779 | $ | — | ||||||
NOTE 11—MAJOR CUSTOMERS AND SUPPLIERS
The Company believes, due to the competitive nature of goods and services supporting the oil and natural gas industry, plus access to several marketing alternatives, that it is not significantly dependent on any single purchaser. The following purchasers accounted for 10% or greater of total revenues for the periods indicated:
Percentage of Total Revenues for the Year Ended December 31, | |||||||||
2017 | 2016 | 2015 | |||||||
Western Refining | 21 | % | * | * | |||||
Enterprise Crude Oil LLC | 21 | % | 27 | % | 12 | % | |||
Shell Trading (US) Company | 14 | % | 23 | % | 37 | % | |||
Phillips 66 Company | * | * | 22 | % | |||||
Diamondback E&P, LLC | * | * | 13 | % | |||||
* These purchasers did not account for 10% or more of total revenues for the periods indicated.
Although the Company is exposed to a concentration of credit risk, management believes that all of the Company’s purchasers are credit worthy and that the loss of any single purchaser would not significantly impact the Company due to the presence of a large number of additional potential purchasers.
NOTE 12 - SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED)
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the years ended December 31:
(in thousands) | 2017 (1) | 2016 (1) | 2015 | |||||||||
Property acquisition costs: | ||||||||||||
Proved | $ | 339,895 | $ | 210,977 | $ | 104,532 | ||||||
Unproved | 1,253,326 | 1,063,109 | 351,806 | |||||||||
Exploration costs | — | 1,811 | — | |||||||||
Development costs | 675,988 | 293,833 | 378,910 | |||||||||
Total costs incurred | $ | 2,269,209 | $ | 1,569,730 | $ | 835,248 | ||||||
(1) Includes acquisition costs related to the issuance of stock directly to the sellers in the SHEP I acquisition in 2016 and SHEP II acquisition in 2017. See Note 3 for further discussion of the SHEP I and SHEP II acquisitions.
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Capitalized Oil and Natural Gas Costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below for the years ended December 31:
(in thousands) | 2017 | 2016 | ||||||
Capitalized costs: | ||||||||
Proved | $ | 3,936,565 | $ | 2,811,853 | ||||
Unproved | 2,865,952 | 1,833,928 | ||||||
Total capitalized costs | $ | 6,802,517 | $ | 4,645,781 | ||||
Less accumulated depreciation, depletion, amortization and impairment | (778,596 | ) | (554,419 | ) | ||||
Net capitalized costs | $ | 6,023,921 | $ | 4,091,362 | ||||
Net Proved Oil and Natural Gas Reserves
The Company’s proved oil, NGLs and natural gas reserves as of December 31, 2017 and December 31, 2015 were audited by independent third party engineers. The Company’s proved oil, NGLs and natural gas reserves as of December 31, 2016 were prepared by independent third party reserve engineers. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.
In accordance with SEC regulations, reserves at December 31, 2017, 2016, and 2015 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Prices were adjusted for quality, transportation fees and regional differentials. The following table summarizes the average first-day-of-the-month prices utilized in the reserve estimates for 2017, 2016 and 2015.
Year Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
Oil per Bbl | $ | 51.34 | $ | 42.75 | $ | 50.28 | ||||||
Natural gas per MMBtu | $ | 2.98 | $ | 2.48 | $ | 2.59 | ||||||
NGLs per Bbl | $ | 17.74 | $ | 11.19 | $ | 10.56 | ||||||
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An analysis of the change in estimated quantities of oil, NGLs and natural gas reserves, all of which are located within the United States, for the years ended December 31, 2017, 2016, and 2015 is as follows:
Oil (MBbls) | Natural Gas (MMcf) | NGLs (MBbls) | MBoe | |||||||||
Proved developed and undeveloped reserves: | ||||||||||||
As of January 1, 2015 | 69,273 | 92,422 | 21,739 | 106,416 | ||||||||
Revisions of previous estimates | (12,886 | ) | (20,205 | ) | (4,251 | ) | (20,505 | ) | ||||
Extensions and discoveries | 50,375 | 55,313 | 6,971 | 66,565 | ||||||||
Purchases of minerals in place | 10,178 | 10,968 | 2,373 | 14,379 | ||||||||
Production | (5,805 | ) | (4,991 | ) | (1,045 | ) | (7,682 | ) | ||||
As of December 31, 2015 | 111,135 | 133,507 | 25,787 | 159,173 | ||||||||
Revisions of previous estimates | (14,115 | ) | (30,284 | ) | 1,412 | (17,750 | ) | |||||
Extensions and discoveries | 46,017 | 45,541 | 11,631 | 65,238 | ||||||||
Purchases of minerals in place | 29,481 | 35,210 | 5,551 | 40,900 | ||||||||
Production | (7,790 | ) | (7,188 | ) | (1,685 | ) | (10,673 | ) | ||||
As of December 31, 2016 | 164,728 | 176,786 | 42,696 | 236,888 | ||||||||
Revisions of previous estimates | 11,130 | 25,889 | 3,075 | 18,520 | ||||||||
Extensions and discoveries | 64,925 | 73,698 | 16,009 | 93,217 | ||||||||
Purchases of minerals in place | 34,997 | 33,772 | 6,859 | 47,485 | ||||||||
Production | (14,445 | ) | (15,126 | ) | (3,202 | ) | (20,168 | ) | ||||
As of December 31, 2017 | 261,335 | 295,019 | 65,437 | 375,942 | ||||||||
Proved developed reserves: | ||||||||||||
December 31, 2015 | 44,128 | 56,640 | 11,020 | 64,588 | ||||||||
December 31, 2016 | 65,025 | 76,255 | 18,759 | 96,493 | ||||||||
December 31, 2017 | 106,668 | 133,116 | 30,162 | 159,016 | ||||||||
Proved undeveloped reserves: | ||||||||||||
December 31, 2015 | 67,007 | 76,867 | 14,767 | 94,585 | ||||||||
December 31, 2016 | 99,703 | 100,531 | 23,937 | 140,395 | ||||||||
December 31, 2017 | 154,667 | 161,903 | 35,275 | 216,926 | ||||||||
The tables above include changes in estimated quantities of oil, NGLs and natural gas reserves shown in MBbl equivalents (“MBoe”) at a rate of six MMcf per one MBbl.
For the year ended December 31, 2017, our extensions and discoveries of 93,217 Mboe were primarily the result of our continued horizontal drilling program in both the Midland Basin and Delaware Basin. This includes 65,657 Mboe of new proved undeveloped locations added during the year. The purchases of minerals in place of 47,485 Mboe were primarily related to the SHEP II acquisition that closed in March 2017, as further described in Note 3. Positive revisions of previous estimates of 18,520 Mboe were primarily related to modified spacing in certain sections, improved performance on certain wells based on additional historical results incorporated to our reserve estimates and higher prices.
For the year ended December 31, 2016, our negative revisions of previously estimated quantities of 17,750 MBoe were primarily due to the removal of certain vertical PUDs as these locations will be replaced with horizontal wells when drilled in the future. The negative revisions of previously estimated quantities due to pricing were 2,131 MBoe. Extensions and discoveries of 65,238 MBoe during 2016 resulted primarily from the drilling of new wells during the year to delineate our acreage position. The purchase of minerals in place of 40,900 MBoe during 2016 included our acquisition of SHEP I that closed in November 2016, as further described in Note 3.
For the year ended December 31, 2015, our negative revisions of previously estimated quantities of 20,505 MBoe were primarily due to negative revisions of 19,641 MBoe due to pricing. Extensions and discoveries of 66,565 MBoe during 2015 resulted primarily from the drilling of new wells during the year and from new proved undeveloped locations added during the
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year. The purchase of minerals in place of 14,379 MBoe during 2015 were related to several acquisitions during the year, as described in Note 3.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGLs and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2017, 2016, and 2015 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.
The standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves is as follows at December 31:
(in thousands) | 2017 | 2016 | 2015 | |||||||||
Future cash inflows | $ | 14,634,925 | $ | 7,433,650 | $ | 5,964,332 | ||||||
Future production costs | (3,867,816 | ) | (2,352,287 | ) | (1,855,044 | ) | ||||||
Future development costs | (1,893,108 | ) | (1,315,835 | ) | (1,187,244 | ) | ||||||
Future income tax expense | (1,553,250 | ) | (659,105 | ) | (699,070 | ) | ||||||
Future net cash flows | 7,320,751 | 3,106,423 | 2,222,974 | |||||||||
10% discount for estimated timing of cash flows | (4,289,975 | ) | (1,913,027 | ) | (1,426,958 | ) | ||||||
Standardized measure of discounted future net cash flows | $ | 3,030,776 | $ | 1,193,396 | $ | 796,016 | ||||||
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
Changes in the standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves are as follows:
(in thousands) | 2017 | 2016 | 2015 | |||||||||
Standardized measure of discounted future net cash flows, beginning of year | $ | 1,193,396 | $ | 796,016 | $ | 876,131 | ||||||
Changes in the year resulting from: | ||||||||||||
Sales, less production costs | (631,907 | ) | (279,603 | ) | (210,874 | ) | ||||||
Revisions of previous quantity estimates | 200,298 | (142,956 | ) | (192,081 | ) | |||||||
Extensions and discoveries | 967,933 | 390,752 | 440,744 | |||||||||
Net change in prices and production costs | 803,662 | (251,166 | ) | (537,613 | ) | |||||||
Changes in estimated future development costs | 43,130 | 156,162 | 14,480 | |||||||||
Previously estimated development costs incurred during the period | 162,759 | 68,238 | 107,829 | |||||||||
Purchases of minerals in place | 377,822 | 244,977 | 95,207 | |||||||||
Accretion of discount | 141,887 | 86,109 | 131,764 | |||||||||
Net change in income taxes | (381,109 | ) | 15,059 | 164,377 | ||||||||
Timing differences and other | 152,905 | 109,808 | (93,948 | ) | ||||||||
Standardized measure of discounted future net cash flows, end of year | $ | 3,030,776 | $ | 1,193,396 | $ | 796,016 | ||||||
Estimates of economically recoverable oil, NGLs and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The
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reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.
NOTE 13 - QUARTERLY FINANCIAL DATA (Unaudited)
The following are summarized quarterly financial data for the years ended December 31, 2017 and 2016:
First | Second | Third | Fourth | |||||||||||||
(in thousands, except per share amounts) | Quarter | Quarter | Quarter | Quarter | ||||||||||||
2017 | ||||||||||||||||
Revenues | $ | 169,931 | $ | 183,100 | $ | 201,654 | $ | 249,023 | ||||||||
Operating income (1) | 55,389 | 54,887 | 67,077 | 55,457 | ||||||||||||
Net gain (loss) on derivative instruments | 17,121 | 12,194 | (21,626 | ) | (46,968 | ) | ||||||||||
Income tax (expense) benefit | (15,072 | ) | (17,072 | ) | (3,678 | ) | 153,450 | |||||||||
Net income | $ | 38,934 | $ | 31,090 | $ | 21,326 | $ | 140,786 | ||||||||
Earnings per share: | ||||||||||||||||
Basic | $ | 0.27 | $ | 0.20 | $ | 0.14 | $ | 0.89 | ||||||||
Diluted | $ | 0.26 | $ | 0.20 | $ | 0.14 | $ | 0.89 | ||||||||
2016 | ||||||||||||||||
Revenues | $ | 55,815 | $ | 81,485 | $ | 93,621 | $ | 122,934 | ||||||||
Operating income (loss) (2) | (14,342 | ) | 2,295 | 13,248 | 29,892 | |||||||||||
Net gain (loss) on derivative instruments | 396 | (3,684 | ) | (2,934 | ) | (17,538 | ) | |||||||||
Income tax benefit | 9,298 | 4,438 | 3,507 | 1,464 | ||||||||||||
Net income (loss) | $ | (17,416 | ) | $ | (9,801 | ) | $ | 985 | $ | 1,381 | ||||||
Earnings (loss) per share: | ||||||||||||||||
Basic | $ | (0.17 | ) | $ | (0.10 | ) | $ | 0.01 | $ | 0.01 | ||||||
Diluted | $ | (0.17 | ) | $ | (0.10 | ) | $ | 0.01 | $ | 0.01 | ||||||
(1) Operating income for the second and fourth quarters of 2017 includes $5.3 million and $52.9 million, respectively, of impairments of unproved properties. Operating income for the first quarter of 2017 also includes $4.1 million of acquisition costs primarily related to the SHEP II acquisition.
(2) Operating income (loss) includes $6.4 million of acquisition costs recorded during the fourth quarter of 2016 primarily related to the Silver Hill acquisitions.
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