UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-37995
Jagged Peak Energy Inc.
(Exact name of registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization) | 81-3943703 (IRS Employer Identification Number) | |||
1401 Lawrence Street, Suite 1800 Denver, Colorado 80202
(Address, including zip code, of registrant’s principal executive offices)
(720) 215-3700
(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 x No ¨
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 ¨ No x
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 x No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit). Yes x No ¨
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. x
Large accelerated filer x | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | Emerging growth company o | ||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.): Yes ¨ No x
The aggregate market value of common stock held by non-affiliates as of June 29, 2018, the last business day of the registrant’s most recently completed second quarter, was approximately $754 million. This amount is based on the closing price of the registrant’s common stock on the New York Stock Exchange on that date, or $13.02. Shares of common stock held by executive officers and directors of the registrant and holders of 10% or more of the outstanding common stock of the registrant have been excluded from the calculation of this amount because such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
The registrant had 213,358,572 shares of common stock outstanding at February 22, 2019.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the registrant’s definitive proxy statement for the 2019 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2018, are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
TABLE OF CONTENTS
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:
3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
Analogous reservoir. Analogous reservoirs, as used in resources 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, an analogous reservoir refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism. For a complete definition of analogous reservoir, refer to the SEC’s Regulation S-X, Rule 4-10(a)(2).
Basin. A large natural depression on the earth’s surface in which sediments have accumulated.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, NGLs or water.
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. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Boe/d. One Boe per day.
British thermal unit or Btu. The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for production of oil, natural gas or NGLs or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).
Development project. 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 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.
Dry well. A well found to be incapable of producing hydrocarbons in commercial quantities such that proceeds from the sale of such production do not 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. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).
Estimated ultimate recovery or EUR. The sum of estimated reserves remaining as of a given date and cumulative production as of that date.
Ethane rejection. Ethane rejection occurs when ethane is left in the wellhead gas stream when the gas is processed, rather than being extracted and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue gas sold is higher and marginally increases the realized price of residue gas; conversely, the volumes of NGLs sold are lower and the average realized price for NGLs sold is higher, as ethane is typically the lowest priced component of NGLs sold.
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Producers generally elect to “reject” ethane when the price received for the ethane in the gas stream is greater than the net price received for the ethane being sold as a liquid after fractionation.
Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. For a complete definition of exploration costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(12).
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another 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. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).
Formation. A layer of rock which 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.
Held by production. Acreage covered by a mineral lease that perpetuates a lessee’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.
Henry Hub price. A natural gas benchmark price quoted at settlement date average.
Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified formation interval.
Infill drilling. Drilling wells in between established producing wells to increase recovery of natural gas, oil and NGLs from a known reservoir.
MBbl. One thousand barrels of crude oil, condensate or NGLs.
MBoe. One thousand Boe.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. One Mcf per day.
MMBbl. One million barrels of crude oil, condensate or NGLs.
MMBoe. One million Boe.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
MMcf/d. One MMcf per day.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be. For example, an owner who has 50% interest in 100 acres owns 50 net acres. Likewise, an owner who has a 50% working interest in a well has a 0.50 net well.
Net production. Production less royalties and production due to others.
Net revenue interest. A working interest owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests, which are owned by other parties.
NGL(s). Natural gas liquid(s). Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
NYMEX. The New York Mercantile Exchange.
Operator. The individual or company responsible for the development and/or production of an oil or natural gas well or lease.
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Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).
Productive well. An exploratory or development well that is not a dry well and is capable of proceeds from production exceeding production expenses and taxes.
Proration unit. A unit that can be effectively and efficiently drained by one well, as allocated by a governmental agency having regulatory jurisdiction.
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 area. The part of a property to which proved reserves have been specifically attributed.
Proved developed reserves. Reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved properties. Properties with proved reserves.
Proved reserves. Those quantities of oil, natural gas and NGLs, 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).
Proved undeveloped reserves. 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. This includes infill wells, which are drilled into the same reservoir as a known producing well in order to accelerate recovery. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Realized price. The cash market price less all expected quality, transportation and demand adjustments.
Reasonable certainty. A high degree of confidence that quantities will be recovered. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).
Recompletion. The completion for production of an existing wellbore in another formation, or other zones within the same 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. 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
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or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
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 individual and separate from other reservoirs.
Resources. 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 to be unrecoverable. Resources include both discovered and undiscovered accumulations.
Royalty. An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof) but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of an interest in the leasehold in connection with a transfer to a subsequent owner.
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. For example, if wells on a 640-acre section are drilled evenly such that each well is assigned to drain 40 acres, each of the resulting 16 wells would be spaced on 40 acres per well.
Spot market price. The cash market price for oil, natural gas or NGLs without reduction for expected quality, transportation and demand adjustments.
Spud. Commenced drilling operations on an identified location.
Stacked hydrocarbon-bearing formations. Vertically layered geologic zones that exist at differing underground depths and are capable of producing oil, natural gas and NGLs. The existence of stacked-hydrocarbon bearing formations enables the development of multiple hydrocarbon bearing zones from a common surface area.
Standardized measure. Discounted future net cash flows estimated by applying the average price for the last 12 months 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.
Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known producing area or “development type” if drilled in a known producing area.
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, drilling unit or spacing 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 in coordination with the separate property interests. Also, the area covered by a unitization agreement.
Unproved properties. Lease acreage with no proved reserves.
Wellbore. The hole drilled by the bit that is equipped for oil, natural gas and NGLs production on a completed well. Also called well or borehole.
Working interest. The right granted to the lessee of a property to develop and 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 market index price for oil of certain specifications that is widely quoted by financial markets.
Zipper Fracs. Hydraulically fracturing adjacent wells in parallel, with one or more wells holding frac pressure while the adjacent well is fractured.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
The information in this Form 10-K includes “forward-looking statements.” All statements, other than statements of historical fact included in or incorporated by reference into this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Item 1A. Risk Factors” in this Annual Report on Form 10-K.
Forward-looking statements include statements about:
• | our business strategy; |
• | our reserves; |
• | our drilling prospects, inventories, projects and programs; |
• | our intention to replace the reserves we produce through drilling and property acquisitions; |
• | our financial strategy, liquidity and capital required for our drilling program and our expectation that our cash flows from operating activities, access to capital markets and availability under our credit facility will be sufficient to fund our 2019 capital program; |
• | our expected timing of the closing of the exchange offer for our 5.875% Senior Notes; |
• | our expected pricing for oil, natural gas and NGL sales; |
• | the timing and amount of our future production of oil, natural gas and NGLs; |
• | our expected ability to meet minimum volume requirements contained in a new marketing agreement when such volume requirements become effective; |
• | our future drilling plans, including the number of wells anticipated to be spud in 2019, the number of wells anticipated to begin producing in 2019 and anticipated well economics; |
• | our future drilling locations and zones and growth opportunities, including development opportunities relating to our acreage in the Brushy Canyon, Avalon Shale, 1st Bone Spring and Pennsylvanian aged formations; |
• | our expected use of longer laterals, pad drilling, shared facilities and zipper fracs to improve our well economics; |
• | government regulations and our ability to obtain permits and governmental approvals; |
• | our pending legal or environmental matters; |
• | our marketing of oil, natural gas and NGLs; |
• | our leasehold or business acquisitions; |
• | our costs of developing our properties; |
• | our hedging strategy and results; |
• | uncertainty regarding our future operating results; |
• | general economic conditions; and |
• | our plans, objectives, expectations and intentions contained in this annual report that are not historical. |
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Item 1A. Risk Factors” in this Annual Report on Form 10-K.
Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could impact our strategy and change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
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Should one or more of the risks or uncertainties described in this Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report on Form 10-K.
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PART I
ITEMS 1 AND 2. | BUSINESS AND PROPERTIES |
General
Jagged Peak Energy Inc., a Delaware corporation, is an independent oil and natural gas exploration and production company with operations in the southern Delaware Basin; the Delaware Basin is a sub-basin of the Permian Basin of West Texas. Throughout this Form 10-K, references to “Jagged Peak,” the “Company,” “we,” “us” and “our” refer to Jagged Peak Energy Inc. and its subsidiaries, after the initial public offering of Jagged Peak (the “IPO”) and, prior to the IPO, to Jagged Peak Energy LLC (“JPE LLC”).
JPE LLC, a Delaware limited liability company, was formed in April 2013 by an affiliate of Quantum Energy Partners (“Quantum”) and former members of our management team at the time. Jagged Peak was formed and incorporated in the state of Delaware in September 2016. In January 2017, pursuant to a corporate reorganization completed in connection with the IPO, JPE LLC became a wholly-owned subsidiary of Jagged Peak (the “corporate reorganization”).
Business Overview
We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves in the southern Delaware Basin. We are focused on increasing stockholder value by (i) balancing the long-term development of our assets with a focus on generating attractive corporate-level returns, (ii) growing production and reserves through the development of our multi-year inventory, (iii) expanding and improving the resource potential of our existing acreage position, (iv) growing our acreage position through acquisitions and leasing efforts and (v) increasing cash flows relative to the amount of capital expenditures incurred during a given period.
The following table summarizes information regarding our operations as of of for the year ended December 31, 2018:
Area | Estimated Proved Reserves (MBoe) | % Oil | Total Net Acres | Gross Operated Potential Drilling Locations | Avg Lateral Length (feet) | 2018 Avg Daily Production (Boe/d) | ||||||||||||
Southern Delaware Basin | 118,890 | 77 | % | 79,500 | 1,800 | 9,000 | 34,207 | |||||||||||
During 2018, our average daily production of 34,207 Boe/d consisted of 77% oil, 12% NGLs and 11% natural gas.
Our Properties and Operations
Our acreage is located on large, contiguous blocks in the adjacent West Texas counties of Winkler, Ward, Reeves and Pecos, with significant original oil-in-place within multiple stacked hydrocarbon-bearing formations. As of December 31, 2018, we operated approximately 97% of our net acreage and held an average 87% working interest in approximately 91,600 gross (79,500 net) acres. This operational control gives us flexibility in development strategy and pace. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus to increase capital efficiency by reducing drilling and completion cycle times, optimizing completions and reducing costs. We expect that further optimization in the field, which will include drilling long and extra-long laterals, pad drilling, shared facilities and zipper fracs will continue to improve our well economics.
We divide our current area of operation within the southern Delaware Basin into three distinct project areas: Cochise, Whiskey River and Big Tex. The Cochise project area lies in the northern part of our acreage position and straddles Ward and Winkler Counties. Whiskey River is in the central part of our overall leasehold position and primarily lies just west of the junction between Ward, Reeves and Pecos Counties in Texas. The Big Tex project area is our southernmost leasehold position and lies in northern Pecos County.
The following table summarizes our approximate acreage by project area as of December 31, 2018:
Acreage | ||||||
Project Area: | Gross | Net | ||||
Cochise | 13,300 | 12,900 | ||||
Whiskey River | 43,200 | 36,400 | ||||
Big Tex | 35,100 | 30,200 | ||||
Total | 91,600 | 79,500 | ||||
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During 2018, we operated an average of approximately five horizontal rigs, compared to an average of approximately six during 2017. During this same period, our average daily production grew from 9,785 Boe/d in the first quarter of 2017 to 38,413 Boe/d in the fourth quarter of 2018. During 2018, we began production on 59 gross (48.0 net) wells, of which we operated 45 gross (42.4 net) wells. As of December 31, 2018, we have 160 gross (143.0 net) producing wells. At year end, we were in the process of drilling 11 gross (10.4 net) wells and had eight gross (8.0 net) wells waiting on completion, including four gross (4.0 net) wells that were in process of being completed. At December 31, 2018, we were operating seven horizontal rigs, two of which were released in January 2019.
Through December 31, 2018, we have drilled, completed and are producing from 112 gross (106.9 net) operated horizontal wells in eight distinct targets: 2nd Bone Spring, 3rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Upper Wolfcamp B, Lower Wolfcamp B, Wolfcamp C and Woodford. While we have producing wells in these distinct targets, the formations primarily targeted have been the Lower and Upper Wolfcamp A and the 3rd Bone Spring. Of the 45 gross operated wells that we began producing from during 2018, 36 were in the Lower Wolfcamp A and five were in the 3rd Bone Spring. Other operators continue to maintain active drilling and completion operations on acreage offsetting our acreage position. We monitor this offset activity, especially with respect to downspacing pilots, and will adjust our future development plans to allow for the optimal development of our acreage position. We also believe potential development opportunities exist on portions of our acreage in the Brushy Canyon, Avalon Shale, 1st Bone Spring and Pennsylvanian aged formations.
Our contiguous acreage position enables the drilling of long laterals, resulting in significant drilling efficiencies that enhance the economic development of our acreage position. Of our approximately 1,800 gross horizontal drilling locations as of December 31, 2018, 86% are classified as long or extra-long. We consider laterals of 5,640 feet and lower as standard length, laterals between 5,640 feet and 8,000 feet to be long, and laterals greater than 8,000 feet to be extra-long. The ability to drill long-lateral wells improves our returns by (i) increasing our EUR per well, (ii) allowing us to contact more reservoir rock with fewer vertical wellbores (thus reducing drilling and completion costs on a per unit basis) and (iii) allowing us to hold by production more acreage per horizontal well drilled. Additionally, the contiguous nature of our acreage provides economies of scale by allowing us to better share our infrastructure among wells across our acreage position.
In conjunction with developing our acreage for optimized production of our oil and natural gas reserves, we have also developed our own water system, which enables us to source, store and dispose of water efficiently. As of December 31, 2018, we had approximately 5,100 net surface acres, which allows us the operational and financial control to source, dispose, store and transport water. Our water infrastructure includes approximately (i) 9.3 MMBbl of water storage capacity, (ii) 30 miles of fresh water pipelines and 130 miles of produced water pipelines, which allows us to largely eliminate water trucking in all phases of our operation, (iii) 150 MBbl/d of water sourcing capacity and (iv) 200 MBbl/d of water disposal capacity. Accordingly, we have available disposal capacity and sufficient sources of fresh water to support our current development program. Surplus fresh water and disposal capacity generated approximately $0.8 million of other operating revenues in 2018, and opportunities to leverage surplus capacities will be evaluated in 2019.
Proved Reserves
Internal Controls Over Reserve Estimating Process. Our proved reserve estimates as of December 31, 2018, 2017 and 2016, were prepared by Ryder Scott Company, LP (“Ryder Scott”), our third party, independent engineering firm. Within Ryder Scott, the technical person primarily responsible for preparing the estimates set forth in the Ryder Scott reserves report incorporated herein is Mr. Stephen E. Gardner. Mr. Gardner, a Licensed Professional Engineer in the States of Colorado and Texas, has been practicing consulting petroleum engineering at Ryder Scott since 2006 and has more than 13 years of practical experience in the estimation and evaluation of petroleum reserves. He graduated from Brigham Young University in 2001 (summa cum laude) with a Bachelor of Science Degree in Mechanical Engineering. Mr. Gardner meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and is proficient in judiciously applying industry standard practices to evaluations as well as applying Securities and Exchange Commission (“SEC”) and other industry reserves definitions and guidelines. Ryder Scott does not own an interest in any of our properties, and is not employed by us on a contingent basis. A copy of Ryder Scott’s proved reserve report as of December 31, 2018 is included as an exhibit to this Form 10-K.
The preparation of our proved reserve estimates was completed in accordance with our internal control procedures. These procedures are intended to ensure reliability of reserve estimations. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an internal review of assumptions used in the estimation as well as ultimate approval of our capital budget and review of our development plan by our senior management. The development plan underlying the Company’s proved undeveloped reserves (“PUDs”) is further subject to internal controls, including (i) a comparison of future development costs to our historical expenditures, our future development plan, and financial capabilities and (ii) an evaluation of the estimated profitability of each location at the time the report is prepared. The development plan underlying the Company’s PUDs, adopted every year by senior management, is based on the best information available at the time of adoption. As factors such as commodity price, service costs, performance data and asset mix are subject to change, the Company occasionally revises its development plan. Development plan revisions include deferrals, removals and substitutions of previously scheduled
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PUD reserve locations. These occasional changes achieve the purpose of maximizing profitability and are in the best interest of the Company’s shareholders.
Our internal professional staff worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members met 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 Ryder Scott for our properties, such as ownership interest, oil and natural gas production, realized commodity prices and operating and development costs. Our Planning and Reserves Manager is primarily responsible for overseeing the preparation of the Company’s reserve estimates. Our Planning and Reserves Manager is a reservoir engineer with more than 17 years of reservoir and operations experience and has been licensed by the Texas Board of Professional Engineers since 2005.
Estimation of Proved Reserves. The estimates of proved reserves as of December 31, 2018 are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic and analogy methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, which were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment.
Summary of Reserves. The following table sets forth the Company’s estimated net proved reserves as of December 31, 2018, 2017 and 2016, based on the proved reserve report as of such dates by Ryder Scott, prepared in accordance with the rules and regulations of the SEC. All of our proved reserves are located in the United States.
At December 31, | ||||||||
2018 | 2017 | 2016 | ||||||
Proved Developed Reserves: | ||||||||
Oil (MBbls) | 54,542 | 29,325 | 11,916 | |||||
Natural gas (MMcf) | 50,018 | 25,496 | 6,566 | |||||
NGLs (MBbls) | 8,554 | 4,166 | 1,491 | |||||
Total equivalent proved developed reserves (MBoe) | 71,432 | 37,739 | 14,501 | |||||
Proved Undeveloped Reserves: | ||||||||
Oil (MBbls) | 37,162 | 35,732 | 18,490 | |||||
Natural gas (MMcf) | 30,496 | 27,758 | 12,953 | |||||
NGLs (MBbls) | 5,213 | 4,260 | 2,545 | |||||
Total equivalent proved undeveloped reserves (MBoe) | 47,458 | 44,619 | 23,194 | |||||
Total Proved Reserves: | ||||||||
Oil (MBbls) | 91,704 | 65,057 | 30,406 | |||||
Natural gas (MMcf) | 80,514 | 53,254 | 19,519 | |||||
NGLs (MBbls) | 13,767 | 8,426 | 4,036 | |||||
Total equivalent proved reserves (MBoe) | 118,890 | 82,358 | 37,695 | |||||
Percent - proved developed reserves | 60 | % | 46 | % | 38 | % | ||
Percent - proved undeveloped reserves | 40 | % | 54 | % | 62 | % | ||
The above reserve estimates were determined using the trailing 12-month index prices in accordance with SEC guidance. These prices were adjusted for gravity, quality, local conditions, gathering and processing fees and distance from market. All prices are held constant throughout the lives of the properties. The following table summarizes the average adjusted product prices used in our reserve estimates as of December 31, 2018, 2017 and 2016:
At December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Oil price per Bbl | $ | 58.35 | $ | 48.26 | $ | 39.33 | |||||
Natural gas price per Mcf | $ | 2.23 | $ | 2.59 | $ | 2.22 | |||||
NGL price per Bbl | $ | 34.21 | $ | 26.69 | $ | 15.48 | |||||
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Total proved reserves at December 31, 2018 were 118.9 MMBoe, compared to 82.4 MMBoe at December 31, 2017, and 37.7 MMBoe at December 31, 2016. The increase in total proved reserves during 2018 was primarily related to our drilling and completion activities. During 2018, we began production on 59 gross (48.0 net) wells. This activity resulted in a combined increase of 35.7 MMBoe due to infill reserves from a proved field. Over this time period, we also had approximately 12.7 MMBoe of upward revisions to prior estimates, due primarily to 11.2 MMBoe of positive performance revisions.
Proved Undeveloped Reserves
PUDs include those 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 may be classified as proved reserves on acreage directly offsetting developed wells if the PUD locations are reasonably certain of production when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having PUDs only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2018, all 60 of our PUD drilling locations are scheduled to be developed within five years of their initial booking.
For PUD locations that are more than one development spacing area from developed producing locations, we utilized reliable geologic and engineering technology when booking PUDs. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (collected both vertically and horizontally) and petrophysical analysis of that log data, mud logs, gas sample analyses, measurements of total organic content, thermal maturity, test production, fluid properties, core data and significant statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results. In all other areas, we restricted proved undeveloped locations to development spacing areas that are immediately adjacent to developed spacing areas.
The following table summarizes the changes in our estimated PUDs during 2018:
(in MBoe) | ||
PUDs at December 31, 2017 | 44,619 | |
Converted to proved developed | (26,585 | ) |
Extensions, discoveries and other, including infill reserves in an existing proved field | 29,255 | |
Acquisitions of reserves | 187 | |
Net revisions of previous estimates | (18 | ) |
PUDs at December 31, 2018 | 47,458 | |
Conversions. The 26.6 MMBoe of PUDs converted to proved developed reserves in 2018 were converted at a total capital cost of approximately $487.0 million. Our estimated total capital costs to develop our remaining PUDs at December 31, 2018 are approximately $670.1 million.
Infill reserves in an existing proved field. We added 29.3 MMBoe in 2018 as a result of our infill PUDs.
Net revisions of previous estimates. Revisions of previous estimates reflect our ongoing evaluation of our asset portfolio. During 2018, PUDs were revised downward by 18.0 MBoe as illustrated in the table below.
(in MBoe) | ||
Revisions due to changes in prices | 271 | |
Revisions due to cost updates | 304 | |
Revisions due to performance | 1,741 | |
Removal of PUDs no longer in our five-year development plan (1) | (2,334 | ) |
Total net revisions of previous estimates | (18 | ) |
(1) | Associated with three wells that were transferred out of PUDs to unproved reserves because they are no longer expected to be developed within five years of the date of their initial recognition due to changes in the capital program in certain areas. |
The total number of PUD locations at December 31, 2018 is 60, compared with 63 at December 31, 2017. As of December 31, 2018, none of our PUDs were on acreage expected to expire or on acreage that was not expected to be held through renewal before the targeted completion date.
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For further information about our reserves, refer to “Supplemental Oil and Natural Gas Disclosures (Unaudited)” which is included as supplemental information to the financial statements in this Form 10-K.
Production, Production Prices and Production Costs
The following table sets forth information regarding production of oil, natural gas and NGLs and certain price and cost information for each of the periods indicated:
Year Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Production: | |||||||||||
Oil (MBbls) | 9,620 | 4,979 | 1,702 | ||||||||
Natural gas (MMcf) | 7,992 | 3,601 | 953 | ||||||||
NGLs (MBbls) (1) | 1,534 | 617 | 194 | ||||||||
Total (MBoe) | 12,486 | 6,196 | 2,054 | ||||||||
Average sales price: | |||||||||||
Oil (per Bbl) | $ | 56.12 | $ | 48.56 | $ | 41.18 | |||||
Natural gas (per Mcf) (1) (2) | $ | 1.14 | $ | 2.52 | $ | 2.32 | |||||
NGLs (per Bbl) (1) (2) | $ | 20.83 | $ | 25.25 | $ | 15.81 | |||||
Total (per Boe) (2) | $ | 46.52 | $ | 43.00 | $ | 36.68 | |||||
Average sales price after impact of cash-settled derivatives: | |||||||||||
Oil (per Bbl) | $ | 52.57 | $ | 48.04 | $ | 39.84 | |||||
Natural gas (per Mcf) (1) (2) | $ | 1.14 | $ | 2.52 | $ | 2.32 | |||||
NGLs (per Bbl) (1) (2) | $ | 20.83 | $ | 25.25 | $ | 15.81 | |||||
Total (per Boe) (2) | $ | 43.79 | $ | 42.58 | $ | 35.57 | |||||
Operating expenses per Boe: | |||||||||||
Lease operating expenses | $ | 3.40 | $ | 2.88 | $ | 3.65 | |||||
Gathering and processing expenses (2) | $ | — | $ | 0.71 | $ | 0.51 | |||||
Production and ad valorem taxes | $ | 2.77 | $ | 2.60 | $ | 2.12 | |||||
(1) | During 2018, our primary gas purchaser transitioned from ethane rejection to ethane recovery, which resulted in decreased realized natural gas price per Mcf and NGL price per barrel, while increasing NGL volumes. |
(2) | On January 1, 2018, we adopted ASC 606. As a result of adoption, natural gas and NGL realized prices for the year ended December 31, 2018 include gathering and processing costs which reduced our realized natural gas and NGL prices by $0.44 per Mcf and $7.33 per barrel, respectively. For additional information regarding the new revenue recognition standard, see Note 2, Significant Accounting Policies and Related Matters, included elsewhere in this report. |
Developed and Undeveloped Acreage
Developed acreage consists of acres spaced or assigned to productive wells and does not include all undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
The following table sets forth the gross and net acres of both developed and undeveloped leases held by Jagged Peak as of December 31, 2018. Acreage related to royalty, overriding royalty and other similar interests is excluded from this table.
Developed | Undeveloped | Total | ||||||||||||||||
Area | Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Southern Delaware Basin | 30,900 | 27,900 | 60,700 | 51,600 | 91,600 | 79,500 | ||||||||||||
Our mineral leases expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date or held by continuous development operations, under which circumstances the lease will remain in effect until the cessation of production. Substantially all of the leases governing our acreage have continuous development clauses that require us to initiate additional development within 120 to 180 days after the completion of the last well drilled on such lease in order to continue to hold the acreage after the expiration of the primary term. Thereafter, the lease is held with additional development every 120 to 180 days until the entire lease is held by production. None of our horizontal drilling
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locations associated with PUDs are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule or primary term. As of December 31, 2018, approximately 58% of our total net acreage was held by production or continuous development operations.
The following table sets forth the number of net undeveloped acres as of December 31, 2018 that will expire over the next three years unless production is established or development is continued within the spacing units covering the acreage prior to the expiration dates, or unless such acreage is extended or renewed.
Area | 2019 | 2020 | 2021 | ||||||
Southern Delaware Basin | 12,713 | 10,920 | 3,709 | ||||||
Of the net acres that are set to expire in the next three years, acreage in the Big Tex project area represents 90%, 87% and 82% of the expiring acreage in 2019, 2020 and 2021, respectively. During 2018, we recognized unproved oil and natural gas impairment expense of $28.2 million on certain Big Tex acreage that largely resulted from our ongoing evaluation of our undeveloped Big Tex acreage and our current plan to not drill on certain of these leases before they expire. The acreage in the table above, and throughout this Form 10-K, includes the impaired Big Tex acreage, as it has not yet expired.
Drilling Results
The following table sets forth information with respect to the number of wells that began producing hydrocarbons during the periods indicated, regardless of when drilling was initiated. Each of these wells was drilled in the southern Delaware Basin. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.
2018 | 2017 | 2016 | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Exploratory Wells | |||||||||||||||||
Productive (1) | — | — | 1.0 | 1.0 | — | — | |||||||||||
Dry | — | — | — | — | — | — | |||||||||||
Total Exploratory | — | — | 1.0 | 1.0 | — | — | |||||||||||
Development Wells | |||||||||||||||||
Productive (1) | 59.0 | 48.0 | 50.0 | 45.1 | 11.0 | 10.9 | |||||||||||
Dry | — | — | — | — | — | — | |||||||||||
Total Development | 59.0 | 48.0 | 50.0 | 45.1 | 11.0 | 10.9 | |||||||||||
Total Wells | |||||||||||||||||
Productive (1) | 59.0 | 48.0 | 51.0 | 46.1 | 11.0 | 10.9 | |||||||||||
Dry | — | — | — | — | — | — | |||||||||||
Total | 59.0 | 48.0 | 51.0 | 46.1 | 11.0 | 10.9 | |||||||||||
(1) | Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history. |
Productive Wells
As of December 31, 2018, we owned an average working interest of 89% in 160 gross (143.0 net) productive wells and a minimal royalty interest in 24 additional productive wells. Our wells are oil wells that also produce associated liquids-rich natural gas. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities.
Transportation and Marketing
We are party to a long-term oil gathering agreement entered into in 2015 pursuant to which we dedicated all of our oil production from our Whiskey River and Cochise acreage. This agreement was amended in May 2017 to include our Big Tex acreage. We sell substantially all of our oil production pursuant to a long-term marketing agreement that expires on December 31, 2020. Additionally, in November 2018, we entered into a 5-year oil marketing agreement that is expected to take effect at the commencement of commercial operations on the Cactus II pipeline and will link a portion of our oil production to Gulf Coast pricing.
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Historically, our sales and transportation agreements were based on acreage dedications and did not contain any minimum volume commitments or other similar provisions; however, our Gulf Coast pricing oil agreement entered into in November 2018, commencing in late 2019 or early 2020, specifies a minimum gross volume commitment for oil of 30,000 barrels per day on a monthly basis. We expect to be able to meet this commitment that will be sourced from our properties in the southern Delaware Basin.
We sell substantially all of our natural gas from our Cochise acreage under a long-term gathering and processing agreement entered into in September 2015, and substantially all of our natural gas from our Whiskey River acreage under a long-term gathering and processing agreement entered into in October 2016. We sell substantially all of our natural gas from our Big Tex acreage pursuant to a short-term gathering and processing agreement expiring in the fall of 2019. Substantially all of our natural gas production is transported from the wellhead by third-party gathering lines to natural gas processing facilities.
Major Customers
We sell our oil, natural gas and NGL production to purchasers at market prices. We sell our production to a relatively small number of customers, as is customary in our business. For 2018, revenues from Trafigura Trading, LLC accounted for approximately 85% of our total revenue and no other purchaser accounted for 10% or more of our revenue. The loss of this purchaser could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil, natural gas and NGLs, and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil, natural gas and NGLs are fungible products with well-established markets.
Infrastructure
Our infrastructure strategy includes owning sufficient tracts of surface acreage to (i) allow us to control water supply for drilling and completions, (ii) provide ease of pipeline installation, (iii) allow construction of storage for both fresh and treated produced water and (iv) allow us to control facilities for disposal of flowback and produced water. In addition, we have supplemental agreements that provide for fresh water sourcing and produced water storage and disposal from surface acreage owned by adjacent landowners as needed. As of December 31, 2018, we owned approximately 5,100 net surface acres. Our water infrastructure consists of approximately (i) 9.3 MMBbl of water storage capacity, (ii) 30 miles of fresh water pipelines, (iii) 130 miles of produced water pipelines, (iv) 150 MBbl/d of water sourcing capacity and (v) 200 MBbl/d of water disposal capacity. Our infrastructure allows us to largely eliminate water trucking in all phases of our operations. Accordingly, we have available disposal capacity and sufficient sources of fresh water to support our current and anticipated development program. Surplus fresh water and surplus disposal capacity generated approximately $0.8 million revenue in 2018, and opportunities to leverage surplus capacities will be evaluated in 2019.
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. Our larger or more integrated competitors 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. Because we have fewer 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. 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 developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.
Seasonality of Business
Weather conditions can affect the demand for, and prices of, oil and natural gas and refinery turnaround, and summer driving season affects demand for, and prices of, crude oil. The prices of both oil and natural gas are heavily dependent on current and future expectations of 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 quarterly periods may not be indicative of the results that may be realized on an annual basis.
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Title to Properties
As is customary in the oil and natural gas industry, we initially conduct 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 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 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 none of these liens, restrictions, easements, burdens and 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 we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report.
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 and natural gas produced from any wells drilled on the leased premises, including flared gas. The lessor royalties and other leasehold burdens on our properties generally approximate 25%, resulting in a net revenue interest to us generally approximating 75%, subject to proportionate reduction in the event we own less than 100% working interest.
Regulation of the Oil and Natural Gas Industry
General
Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. We own or operate producing oil and natural gas properties in Texas, which has statutory provisions regulating the development 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 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 crude 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. 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 noncompliance with environmental laws or regulations may be discovered. 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. In addition, policies, proposals and proceedings that affect the oil and natural gas industry may continue to change under the current political environment. We cannot predict when or whether any such proposals may become effective. We do not believe we would be affected by any such action materially differently than similarly situated competitors.
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
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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. In Texas, flaring and venting of natural gas are regulated by the Railroad Commission of Texas (the “RRC”) and the Texas Commission on Environmental Quality (the “TCEQ”). The RRC regulations strive to maximize production and minimize waste, while the TCEQ regulations focus on limiting air pollution. The RRC allows an operator to flare gas while drilling a well and for up to 10 days after a well’s completion so that operators can conduct well potential testing. However, for most short-term and any extended flaring requests the RRC requires operators to obtain a permit. The TCEQ regulates flaring by issuing air permits on behalf of the Environmental Protection Agency (the “EPA”). The TCEQ permits require air pollution controls and process designs that limit venting and flaring of gas from production facilities.
The effect of these regulations could limit the amount of oil and natural gas that we can produce from our wells and could limit the number of wells or the locations at which we can drill, although we can at times apply for exceptions to such regulations or to have reductions in well spacing. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. We do not believe we are impacted any differently by these regulations than similarly situated competitors. The failure to comply with these rules and regulations can result in substantial penalties.
Regulation of Sales and Transportation of Oil
Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil, condensate and NGLs sales, or the prices we can charge for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the Texas state legislature and what effect, if any, the proposals might have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.
Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil may also be subject to rate and access regulation. FERC regulates interstate transportation of oil, including natural gas liquids, under the Interstate Commerce Act (the “ICA”). This includes movements of oil or natural gas liquids through any pipelines, including those located solely in one state, that are providing part of the continuous movement of the products in interstate commerce for a shipper. Prices received from the sale of oil and natural gas liquids may be affected by the cost of transporting those products to market. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service for jurisdictional movements be “just and reasonable.” In general, interstate oil pipeline rates must be cost-based, although negotiated rates with at least one nonaffiliated shipper and settlement rates agreed to by all shippers who on the day of the filing of the proposed rate are using the service covered by the rate, are permitted. Additionally, market-based rates may be permitted in certain circumstances. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.
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 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.
Regulation of Sales and Transportation 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 first 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 Policy Act of 1978 (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed price 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.
Gathering service, which occurs upstream of jurisdictional transportation 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 under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transportation function, FERC’s determinations as to the classification of facilities are done on a case by case
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basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transportation facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting natural gas to point of sale locations may increase. We believe the natural gas pipelines in the gathering systems we use meet the traditional tests FERC has used to establish a pipeline’s status as gathering facilities not subject to regulation under the NGA. However, the distinction between FERC-regulated transportation services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of the gathering facilities we use are subject to change based on future determinations by FERC, the courts or Congress.
The price at which we sell natural gas is not currently subject to federal rate 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 Energy Policy Act of 2005 (the “EP Act of 2005”) and under the Commodity Exchange Act (the “CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission (the “CFTC”). The price manipulation provisions of the CEA make it unlawful for any person, directly or indirectly, to manipulate or attempt to manipulate the price of any swap, or of any commodity in interstate commerce, or for future delivery on or subject to the rules of any registered entity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading reports concerning market information or conditions that affect or tend to affect the price of any commodity in interstate commerce, knowing, or acting in reckless disregard of the fact that such report is false, misleading or inaccurate. 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.
The EP Act of 2005 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 EP Act of 2005 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. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. 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 EP Act of 2005, 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 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 natural 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” natural gas sales, purchases or transportation subject to FERC jurisdiction. 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 annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, any market participant that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are 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 FERC on Form No. 552. The definitions accompanying the form state that reportable physical natural gas transactions are only those transactions that either use an index, or that contribute to, or may contribute to the formation of a gas index during the calendar year. 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.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies in Texas. Entities transporting crude oil and natural gas liquids in the State of Texas in intrastate commerce as common carriers may be subject to state regulation under the Texas Natural Resources Code (the “TNRC”) and the rules of the RRC. Such common carriers are required to publish tariffs under rules set by the RRC and must provide transportation service without discrimination as to rates and terms of service. Violation of these rules may result in civil and administrative penalties. The RRC is responsible for establishing and promulgating rates, though in practice its regulation of rates is primarily on a complaint basis. The RRC has broad authority to establish safety standards for intrastate pipelines transporting crude oil and natural gas liquids and has adopted by reference minimum safety standards promulgated by the Pipeline and Hazardous Materials Safety Administration (the “PHMSA”).
Intrastate natural gas pipelines located in Texas that are not regulated by FERC may be subject to state regulation as common purchasers under the TNRC or as gas utilities as defined in the Texas Utilities Code and must comply with certain rules of the RRC. These statutes and rules prohibit common purchasers and gas utilities from discriminating among similarly situated shippers and require that transportation be provided under just and reasonable terms and conditions. The RRC has the authority to regulate rates on a complaint basis and may assess administrative penalties against common purchasers and gas utilities determined to be in violation of its rules. Upon request by the RRC, common purchasers and gas utilities are obligated to provide their books and records to the RRC for audit purposes; gas utilities must also disclose to the RRC certain information about their
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contracts with customers. The RRC has broad authority to establish safety standards for intrastate natural gas pipelines and has adopted by reference minimum safety standards promulgated by PHMSA. The RRC has also enacted safety measures applicable to natural gas pipelines, including additional reporting requirements and pipeline integrity testing.
Insofar as regulation within Texas will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe the regulation of similarly situated intrastate natural gas transportation in Texas, 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 we produce, as well as the revenues we receive for sales of our natural gas.
Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies 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 and marketers with which we compete.
Regulation of Environmental and Occupational Safety and Health Matters
Our oil and natural gas development 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; 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; 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.
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 of 1980 (“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 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 directly control 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 and result in CERCLA liability.
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 development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by 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 and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of the Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. 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.
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We currently own, lease or operate numerous properties that have been used for oil and natural gas development 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 Regulation
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 certain regulated waters, including navigable 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 certain wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”) potentially following review or input by the EPA. In June 2015, the EPA and the Corps issued a new rule known as the Clean Water Rule clarifying the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated. In February 2018, the EPA issued a rule that delays the applicability of the new definition of the waters of the United States until 2020. On August 16, 2018, the U.S. District Court for South Carolina found that the EPA and the Corps failed to comply with the Administrative Procedure Act and struck the 2018 rule that attempted to delay the applicability date of the 2015 Clean Water Rule. Other district courts, however, have issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself. Taken together, the 2015 Clean Water Rule is currently in effect in 23 states, and temporarily stayed in the remaining states, including Texas and New Mexico. In those remaining states, the 1986 rule and guidance remain in effect. On December 11, 2018, the EPA and the Corps issued a proposed new rule that would differently revise the definition of “waters of the Unites States” and essentially replace both the 1986 rule and the 2015 Clean Water Rule. According to the agencies, the proposed new rule is “intended to increase CWA program predictability and consistency by increasing clarity as to the scope of ‘waters of the United States’ federally regulated under the Act”. If finalized, this new definition of “waters of the United States” will likely be challenged and sought to be enjoined in federal court. To the extent any new rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in certain areas. 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 the unauthorized discharge of dredge and fill material and 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 are currently undertaking a review of our properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.
The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (the “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.
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Air Emissions
The Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as storage tanks 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, comply with stringent air permit or other requirements or utilize specific equipment or technologies to control emissions of certain pollutants. 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, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound and methane emissions from certain fractured and refractured natural gas and oil wells for which well completion operations must be conducted through the use of reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from various equipment and processes, including production-related wet seal and reciprocating compressors pneumatic controllers and storage vessels. More recently, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. See also “—Regulation of “Greenhouse Gas” Emissions.” Compliance with these and other air pollution control and permitting requirements, including at the state level, has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant.
Regulation of “Greenhouse Gas” Emissions
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under the Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources of GHGs. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements 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. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include 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. In addition, the rules impose leak detection and repair requirements intended to address methane leaks known as “fugitive emissions” from equipment, such as valves, connectors, open-ended lines, pressure-relief devices, compressors, instruments and meters. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance. On September 11, 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency for monitoring fugitive emissions at well sites and compressor stations. The federal Bureau of Land Management (the “BLM”) also finalized similar rules regarding the control of methane emissions in November 2016 that apply to oil and natural gas exploration and development activities on federal and Indian leases, including committed state and private tracts in a federally approved unit or communitized agreement. The rules seek to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements. These new rules could result in increased compliance costs on our operations. On September 28, 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detections and repairs. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant legislative activity 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.
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
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with our operations. Demand for our products may also be adversely affected by conservation plans and efforts undertaken in response to global climate change, including plans developed in connection with the recent Paris climate conference in December 2015, which the U.S. ratified in September 2016. In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the earliest any country can withdraw is November 2020. Many governments also provide, or may in the future provide, tax advantages and other subsidies to support the use and development of alternative energy technologies. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.
Finally, 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, increased volatility in seasonal temperatures, and other climatic events; if any such effects were to occur, they could have a material adverse effect on our operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our 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, proppants 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 federal agencies have asserted jurisdiction over certain aspects of the process. The EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (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. The EPA has also taken the following actions: issued final regulations under the Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and, in June 2016, published an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The BLM rescinded the rule in December 2017; however, the BLM’s rescission of the rule has been challenged by several states in the United States District Court for the Northern District of California. In addition, 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 additional federal regulation of hydraulic fracturing activities may affect our operations.
Certain governmental reviews have been conducted or proposed that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing activities related to water use and disposal at the federal level. These studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.
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 RRC 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. The well integrity rule took effect in January 2014. The RRC also published a rule in October 2014 governing the permitting of disposal wells that requires the submission of detailed information related to seismicity. 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. In July 2018, the EPA and the State of New Mexico entered into a Memorandum of Understanding to clarify the existing regulatory and permitting frameworks related to the way wastewater from oil and natural gas extraction activities can be re-used, recycled, and renewed for other purposes. A work group will be convened to develop a white paper that synthesizes the existing regulatory framework under state and federal law in New Mexico and identifies potential opportunities for the beneficial use of treated water. In November 2018, the EPA and the non-profit organization known as the State Review of Oil and Natural Gas Environmental Regulations (“STRONGER”) entered into a Memorandum of Understanding pursuant to which the EPA has affirmed its commitment to meaningful participation in STRONGER’s efforts to develop guidelines for state oil and natural gas environmental regulatory programs, conduct reviews of such programs, and publish reports on those reviews. If new or more stringent federal, state or local legal restrictions relating to
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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 development activities and perhaps even be precluded from drilling wells.
ESA
The Endangered Species Act (“ESA”) and, in some cases, comparable state laws were established to protect endangered and threatened species. Because listing a fish or wildlife species as threatened or endangered pursuant to the ESA prohibits death and harassment of, and injury and harm to, the species, a listing has the effect of restricting activities that adversely affect the species and its habitat. We may conduct operations on oil and natural gas leases in areas where threatened or endangered species may exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. Under the ESA, the U.S. Fish and Wildlife Service also may designate as critical habitat areas it determines are essential for the conservation of a threatened or endangered species. A critical habitat designation results in additional material restrictions to federal agency actions and authorizations, such as federal land management decisions and federal permits on non-federal lands such as permits under section 404 of the Clean Water Act. Therefore, a critical habitat designation may materially delay or prohibit land access for oil and natural gas development. The presence of, or potential presence of, threatened or endangered species, or critical habitat in areas where operations are conducted could cause us to incur increased costs from species protection measures or could result in limitations on activities that could adversely impact our ability to develop and produce reserves. If a portion of our leases are designated as critical habitat, it could adversely impact the value of our leases.
OSHA
We are subject to the requirements of the Occupational Safety and Health 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.
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.
We have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We did not have any material capital or other nonrecurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2017 or 2018, nor do we anticipate that such expenditures will be material in 2019.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development 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.
Principal Executive Offices and Employees
Our principal executive offices are located at 1401 Lawrence Street, Suite 1800, Denver, Colorado, 80202, and our telephone number at that address is (720) 215-3700.
As of December 31, 2018, we had 94 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.
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Availability of Public Filings and Internet Website
We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). Our Annual Reports 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) or 15(d) of the Exchange Act are available free of charge on our website at www.jaggedpeakenergy.com and on the SEC’s website at www.SEC.gov as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
ITEM 1A. | RISK FACTORS |
The following risks and uncertainties, together with other information set forth in this Form 10-K, should be carefully considered by current and future investors in our common stock. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties presently unknown to us or currently deemed immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, our financial condition, and the results of our operations, which in turn could negatively impact the value of our common stock.
Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.
Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to market uncertainty and relatively minor changes in the supply of and demand for oil, natural gas and NGLs. Historically, oil, natural gas and NGL prices have been volatile. For example, during the period from January 1, 2016 through January 31, 2019 the WTI spot price for oil ranged from a high of $77.41 per Bbl on June 27, 2018, to a low of $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas ranged from a high of $6.24 per MMBtu on January 2, 2018, to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have also experienced price fluctuations. The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access to capital, future rate of growth and carrying value of our properties. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:
• | worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGLs; |
• | the price and quantity of foreign imports and exports of oil, natural gas and NGLs; |
• | political and economic conditions in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia; |
• | actions of the Organization of the Petroleum Exporting Countries, its members and state-controlled oil companies relating to oil price and production controls; |
• | the level of global exploration, development and production; |
• | the level of global inventories; |
• | prevailing prices on local price indexes in the area in which we operate; |
• | the proximity, capacity, cost and availability of gathering and transportation facilities; |
• | 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; and |
• | U.S. federal, state and local and non-U.S. governmental regulation and taxes. |
Lower commodity prices may reduce our cash flows and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected. Furthermore, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current WTI or Henry Hub strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our PUDs and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.
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Our acquisition and development 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 production and reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue making substantial capital expenditures related to our acquisition and development projects. Our 2019 capital budget for drilling, completion and recompletion activities and facilities costs is expected to range from $600.0 million to $660.0 million, excluding potential acquisitions. In addition, our production costs may increase as we continue to use enhanced recovery techniques, including gas lifts and electric submersible pumps, and other new drilling and completion technologies, which are capital intensive and may not produce oil and natural gas in paying quantities or at all. Further, we regularly evaluate potential acquisition opportunities as an important aspect of our growth strategy, and any such acquisitions we pursue could require substantial capital expenditures. We expect to fund our capital expenditures with cash on hand, cash generated by operations and borrowings under our credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to our other stockholders. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.
Our cash flow from operations and access to capital are subject to a number of variables, including:
• | the prices at which our production is sold; |
• | our proved reserves; |
• | the level of hydrocarbons we are able to produce from existing wells; |
• | our ability to acquire, locate and produce new reserves; |
• | results of our hedging program; |
• | the levels of our operating expenses; and |
• | our ability to borrow under our credit facility and our ability to access the capital markets. |
If our revenues or the borrowing base under our credit facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.
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 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; and |
• | being able to run tools and other equipment consistently through the horizontal wellbore. |
Risks that we face while completing our wells include 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; |
• | the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage; and |
• | the effectiveness of the fracture stimulation process on reservoir rock. |
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. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
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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 development, acquisition and production 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 develop or purchase 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, the analogies we draw from available data from other wells, including type curves from such wells, and more fully explored locations may not be applicable to our drilling locations. For a discussion of the uncertainty involved in the process of making reserve estimates, see “— 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.” In addition, our cost of drilling, completing and operating wells is often uncertain.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
• | delays imposed by or resulting from compliance with regulatory requirements including limitations on wastewater disposal, additional regulation related to seismic activity, 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 materials required for our drilling activities, including drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, sand, water and other supplies; |
• | power failures or lack of power availability; |
• | equipment failures, accidents or other unexpected operational events; |
• | lack of available and economic gathering and takeaway capacity, including gathering facilities and 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; |
• | title problems; and |
• | limitations in the market for oil and natural gas. |
For example, in 2017 we experienced completion delays related to frac fleet equipment reliability from our service providers, which resulted in increased completed well costs and reduced our total number of well completions. Furthermore, the results of any drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production.
Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, depletion from offset wells, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.
As of December 31, 2018, we had identified approximately 1,800 gross horizontal drilling locations on our acreage based on approximately 880-foot spacing in an offset pattern with five to six wells across a 640-acre section. As a result of the limitations described above, we may be unable to drill many of our identified locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “—Our acquisition and development 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 production and reserves.” Any drilling activities we are able to conduct on these locations may not
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be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations.
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 reserves is complex. It requires interpretations of available technical data and many assumptions, including 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 and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, estimated ultimate recoveries, well type curves, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected and production declines may be greater than we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.
It should not be assumed that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We base the estimated discounted future net cash flows from reserves on the 12-month average of the first-day-of-the-month pricing, and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development 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 our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, 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.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that they own.
Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations by us or other operators could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells by us or other operators could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
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 any future borrowings under our credit facility, 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 future indebtedness.
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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. 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.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our debt agreements contain a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:
• | incur additional indebtedness; |
• | pay dividends on capital stock or redeem, repurchase, or retire capital stock or subordinated indebtedness; |
• | enter into agreements that restrict dividends or other payments from its restricted subsidiaries to the Company or any of its restricted subsidiaries; |
• | incur liens; |
• | make investments; |
• | make loans to others; |
• | merge or consolidate with another entity; |
• | sell assets; |
• | make certain payments; |
• | enter into transactions with affiliates; |
• | create unrestricted subsidiaries; |
• | hedge commodity prices; |
• | hedge interest rates; and |
• | engage in certain other transactions without the prior consent of the lenders. |
In addition, our credit agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. For example, as described in greater detail in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Senior Secured Revolving Credit Facility,” we are required to maintain a ratio of current assets to current liabilities of not less than 1.0 to 1.0, as defined by the senior secured revolving credit facility, which was amended and restated in February 2017 (the “Amended and Restated Credit Facility”).
Further, under our credit agreement as of December 31, 2018, we were only permitted to hedge up to 85% of forecasted future production for up to 36 months in the future, and up to the greater of 75% of production from our proved reserves and 60% of our reasonably anticipated forecasted production for 37 to 60 months in the future, provided that no hedges have a term beyond five years.
The restrictions in our debt agreements may also 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 the limitations that the restrictive covenants in our debt agreements impose on us.
A breach of any covenant in our debt agreements would result in a default under the applicable agreement after any applicable cure and grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under such debt agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under all other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
Any significant reduction in our borrowing base under our credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
Our credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually by April 1 and October 1, or during an elected quarterly redetermination. The borrowing base depends on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties
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securing our loan. The value of our proved reserves is dependent upon, among other things, the prevailing and expected market prices of the underlying commodities in our estimated reserves. See “—Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments” and “—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.” During a borrowing base redetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. As of December 31, 2018, our borrowing base was $900.0 million, of which our elected commitments were $540.0 million.
In the future, we may not be able to access adequate funding under our 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 a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Our variable rate indebtedness subjects us to interest rate risk and increases in interest rates could adversely affect our business.
Borrowings under our credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease.
In addition, 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. Recent and continuing disruptions and volatility in the global financial markets 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.
Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above.
We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the credit facility. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we and our subsidiaries now face.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.
As of December 31, 2018, approximately 58% of our total net acreage was held by production or continuous drilling operations. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions of the leases or the leases are renewed. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. This could result in impairment of remaining costs, a reduction in our reserves and our growth opportunities (or the incurrence of significant costs) and therefore could have an adverse effect on our financial results. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.
Our derivative activities may not effectively mitigate the impact of commodity price volatility from our cash flows and could result in financial losses or could reduce our earnings.
We enter into derivative instrument contracts for a portion of our oil production. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of any derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
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• | 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 derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates 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. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.
Adverse weather conditions and other natural disasters may negatively affect our operating results and our ability to conduct drilling activities.
Adverse weather conditions and other natural disasters 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, natural gas and NGLs. 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. For example, in 2017 industry infrastructure impacts from Hurricane Harvey caused a portion of our wells to be shut-in for a short period of time, which reduced production and revenue from such wells for that period.
Our operations are substantially dependent on the availability of water, and our ability to dispose of the water we produce. Restrictions on our ability to obtain and dispose water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas development during the drilling, hydraulic fracturing and production processes. If we are unable to obtain water to use in our operations or dispose of or recycle water used in operations, or if the prices of water or water disposal increases dramatically, 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 Delaware Basin, a sub-basin of the Permian Basin, in West Texas, making us vulnerable to risks associated with operating in a single geographic area.
All of our producing properties are geographically concentrated in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas. At December 31, 2018, 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, natural gas or NGLs. For example, since our production originates near Midland, Texas, our realizations on sales of our oil production may be affected 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 oil 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 reached as high as $16.21 per barrel in September 2018. 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.
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We are dependent on third-party pipeline and trucking systems to transport our production and gathering and processing systems to prepare our production. The lack of available capacity in these systems could interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect our cash flow and results of operations.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production getting to market. The marketability of our oil and natural gas and production depends in part on the availability, proximity and capacity of gathering, processing, pipeline and trucking systems. The amount of oil and natural gas that can be produced and sold is subject to limitation in certain circumstances, such as a lack of contracted capacity on such systems. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. As a result, we may be required to shut in wells due to the inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. Any significant curtailment in gathering, processing or pipeline system capacity or lack of availability of transport would interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect the expected results of our drilling program, as well as our cash flow and results of operations.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities experience disruptions, 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. 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 inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.
We may incur losses as a result of title defects in the properties in which we invest.
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 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, 2018, approximately 40% of our total estimated proved reserves were classified as proved undeveloped. Development of these PUDs 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, we may 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 prevailing commodity prices and 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. We may incur noncash impairment charges in the future. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, 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.
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We depend upon a significant purchaser for the sale of most of our oil, natural gas and NGL production.
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports and exports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon a significant purchaser for the sale of most of our oil and natural gas production. See “Items 1 and 2. Business and Properties—Major Customers.” We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.
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, release or emission of materials into the environment, health and safety aspects of our operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated 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, natural resource damages, 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. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements our business, prospects, financial condition or results of operations could be materially adversely affected.
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 development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
• | environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination; |
• | abnormally pressured formations; |
• | mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; |
• | fires, explosions and ruptures of pipelines; |
• | personal injuries and death; |
• | natural disasters; and |
• | terrorist attacks targeting oil and natural gas related facilities and infrastructure. |
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:
• | injury or loss of life; |
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• | 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.
Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. 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. The use of 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. 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. 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 |
• | increases in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services. |
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future 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 not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.
The success of any completed acquisition will depend on our ability to integrate effectively 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. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. 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 credit agreement and indenture impose certain limitations on our ability to enter into mergers or combination transactions. Our credit agreement and indenture also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses or assets.
We may be subject to risks in connection with acquisitions of properties.
The successful acquisition of producing properties requires an assessment of several factors, including:
• | recoverable reserves; |
• | future oil and natural gas prices and their applicable differentials; |
• | operating costs; and |
• | potential environmental and other liabilities. |
The accuracy of these assessments is inherently uncertain. 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
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contamination, are not necessarily observable even when an inspection is undertaken. 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.
In addition, acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges.
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. Such 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 development activities and perhaps even be precluded from the drilling of wells.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, pipe and other equipment and supplies (particularly sand and other proppants), as well as 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. Our operations are concentrated in areas in which industry activity has increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, has increased, as did the costs for those items. To the extent that commodity prices improve in the future, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to resume or increase our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, 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.
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 NGL 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; increased demand for labor, services and materials as drilling activity increases; and increased taxes. These costs may rise faster than increases in our revenue if commodity prices rise, or they may rise without a corresponding increase in commodity prices, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.
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 EP Act of 2005, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Items 1 and 2. Business and Properties—Regulation of the Oil and Natural Gas Industry.”
A change in the jurisdictional characterization of some of the natural gas assets we use by federal, state or local regulatory agencies or a change in policy by those agencies could result in increased regulation of the natural gas assets we use, which could cause our revenues to decline and operating expenses to increase.
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that the natural gas pipelines we use meet the traditional tests FERC has used to determine if a pipeline is a gathering pipeline and are, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial ongoing litigation and, over time, FERC policy concerning where to
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draw the line between activities it regulates and activities excluded from its regulation has changed. The classification and regulation of the gathering facilities we use are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels.
Climate change laws and regulations restricting emissions of GHGs 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.
See “Items 1 and 2.—Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters—Regulation of “Greenhouse Gas” Emissions.”
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.
See “Items 1 and 2.—Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters—Hydraulic Fracturing Activities.”
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies recently have focused on a possible connection between the disposal of wastewater in underground injection wells, or to a lesser extent the hydraulic fracturing of oil and gas wells, and the increased occurrence of seismic activity in certain areas, and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. For example, in 2016, the Texas state legislature provided nearly $5 million to the University of Texas to develop and manage an earthquake monitoring system in Texas. In addition, lawsuits have been filed in several states alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting or operation of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in 2014, the RRC adopted a new rule governing the permitting of disposal wells that requires, among other things, the submittal of information on seismic events occurring within a specified radius of the disposal well as well as logs, geologic cross sections and structure maps for the disposal area. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The RRC has used this authority in the past to deny permits for disposal wells. The RRC is currently reviewing their process of approving permits for disposal wells. We use disposal wells to inject water produced from our drilling and completion operations. Increased regulation in areas in which we operate will likely impact our ability to permit disposal wells which could adversely impact or delay our operations.
We dispose of large volumes of produced water gathered from our drilling, completion and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or operating prohibitions or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. In addition, the enforcement of existing laws and regulations could delay our receipt of the necessary permits and result in a material adverse effect on our business, financial condition and results of operations. The adoption and implementation of any new laws or regulations or the imposition of any orders or requirements that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by limiting volumes, injection pressures or rates, producing or disposal well locations or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
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 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, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and
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exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our 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. The cost to attract and retain qualified personnel may increase substantially in the future. In addition, because of our smaller size compared to some of our competitors, such competitors may be in a better position to secure oilfield services and equipment on a timelier basis or on more favorable terms. Furthermore, 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.
Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. The termination of employment of senior management or technical personnel could adversely affect operations.
Our future success depends to a large extent on the services of our senior management and key employees. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. 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 use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 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. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.
Restrictions on drilling activities intended to protect certain species 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 species. Seasonal restrictions to protect wildlife 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 or threatened species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered or the designation of critical habitat for threatened or endangered species in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.
Laws regulating the derivatives market could adversely affect our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. Under the Dodd-Frank Act, the CFTC and the SEC have promulgated rules, and may continue to promulgate other rules, required to implement the derivatives regulatory provisions of the Dodd-Frank Act. The CFTC has adopted certain position aggregation rules and re-proposed certain other rules that would place limits on positions in certain core futures and economically equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. These new position limit rules are not yet final, and the impact of the final position rules on us is uncertain at this time.
The Dodd-Frank Act also made the clearing of certain swaps over a derivatives clearing organization mandatory and the execution of cleared swaps over a board of trade or swap execution facility mandatory, subject to certain exemptions. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. As of the date hereof, the CFTC has not yet issued notices designating certain other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the exception from mandatory clearing available to commercial end-users of swaps, if we were to have to clear any swap we enter, we might not have the same flexibility we have with the bilateral swaps we now enter and would have to post margin with the derivatives clearing organization for such cleared swaps, which could adversely our ability to execute hedges to reduce risk and protect our cash flow, could adversely affect our liquidity and could reduce cash available to us for capital expenditures.
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Certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for exemptions from such margin requirements available to certain users of swaps who are non-financial end-users entering into uncleared swaps to hedge their commercial risks with respect to any swaps we enter for such purpose, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If we do not qualify for an exemption from the margin rules, we could have to post initial and variation margin with the counterparties to our swaps, which could impact our liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect our cash flow.
The full impact of the Dodd-Frank Act’s swap regulatory provisions and the related rules of the CFTC and SEC on our business will not be known until all of the rules required under the Dodd-Frank Act have been adopted and fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act, the existing rules and any new rules could increase compliance and documentation burdens on our business or on our counterparties, significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act’s swap regulatory provisions and the related rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act’s swap regulatory provisions were intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us and our financial condition.
In addition, the European Union and other non-U.S. jurisdictions have implemented or may implement regulations with respect to the derivatives market, some of which impose mechanisms and restrictions similar to those arising under the Dodd-Frank Act and related rules. If we enter into swaps with counterparties based in foreign jurisdictions, we may become subject to such regulations, which could have adverse effects on our operations similar to the possible effects on our operations of the Dodd-Frank Act’s swap regulatory provisions and the rules of the CFTC, SEC and U.S. banking regulators.
We operate in a litigious environment and may be involved in legal proceeding that could have an adverse effect on our results of operations and financial condition.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of our estimated reserves.
Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received.
In addition, our predecessor generally passed through its taxable income to its owners for income tax purposes and was not subject to U.S. federal, state or local income taxes other than franchise tax in the State of Texas. Accordingly, our standardized measure as of December 31, 2016 does not provide for U.S. federal, state or local income taxes other than franchise tax in the State of Texas. However, following our corporate reorganization, we are subject to U.S. federal, state and local income taxes, which is reflected in the standardized measure computation as of December 31, 2018 and 2017.
Therefore, the standardized measure of our estimated reserves included in this Form 10-K should not be construed as accurate estimates of the current fair value of our proved reserves.
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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, our business, financial condition or results of operations could be materially and adversely affected.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.
Quantum and its affiliates have the ability to direct the voting of a majority of our common stock, and its interests may conflict with those of our other stockholders.
As of December 31, 2018, Quantum beneficially owned approximately 68.6% of our outstanding common stock. As a result, Quantum is able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of Quantum with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. Given this concentrated ownership, Quantum would have to approve any potential acquisition of us. In addition, certain of our directors are currently employees of Quantum. These directors’ duties as employees of Quantum may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest. Furthermore, we are party to a stockholders’ agreement with Quantum, JPE Management Holdings LLC and certain current and former officers and employees. Among other things, the stockholders’ agreement provides that JPE Management Holdings LLC and the current and former officers and employees party thereto will vote all of their shares of common stock in accordance with the direction of
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Quantum. Further, the stockholders’ agreement provides Quantum with the right to designate a certain number of nominees to our board of directors so long as it and its affiliates collectively beneficially own at least 5% of the outstanding shares of our common stock.
We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements. Our stockholders do not have the same protections afforded to stockholders of companies that are subject to such requirements.
Quantum continues to control a majority of the combined voting power of our common stock. As a result, we are a “controlled company” within the meaning of the New York Stock Exchange (“NYSE”) listing standards. Under these rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements of the NYSE, including the requirement (1) that a majority of the board of directors consist of independent directors, (2) that we have a nominating and corporate governance committee composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities and (3) that we have a compensation committee composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. We rely on some or all of these exemptions. As a result, we do not have a majority of independent directors or a nominating or governance committee, and our compensation committee does not consist entirely of independent directors. Accordingly, our stockholders do not have the same protections afforded to stockholders of companies subject to all of the corporate governance requirements of the NYSE.
Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Certain of our directors, who are and will be responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including affiliates of Quantum) that are in the business of identifying and acquiring oil and natural gas properties. For example, four of our directors, Messrs. Davidson, VanLoh, Jr., Verma and Webster, are employees of Quantum and serve as Venture Partner, Founder and Chief Executive Officer, President and Managing Director, respectively. A fifth director, Mr. Linn, is a nonemployee Senior Advisor to Quantum. Quantum is in the business of investing in oil and natural gas companies with independent management teams that also seek to acquire oil and natural gas properties. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor.
Quantum and its affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable Quantum to benefit from corporate opportunities that might otherwise be available to us.
Our governing documents provide that Quantum and its affiliates (including portfolio investments of Quantum and its affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation, among other things:
• | permits Quantum and its affiliates and our nonemployee directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and |
• | provides that if Quantum or any of its affiliates who is also one of our nonemployee directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us. |
Quantum or its affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, Quantum and its affiliates may dispose of oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Quantum and its affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours.
Quantum and its affiliates are established participants in the oil and natural gas industry and have resources greater than ours, which may make it more difficult for us to compete with such persons with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one
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hand, and Quantum, on the other hand, will be resolved in our favor. As a result, competition from Quantum and its affiliates could adversely impact our results of operations.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
The credit risk of financial institutions could adversely affect us.
We have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges and insurance companies in the form of claims under our policies. In addition, if any lender under our revolving credit facility is unable to fund its commitment, our liquidity may be reduced by an amount up to the aggregate amount of such lender’s commitment under the credit agreement.
Our ability to obtain financing may be limited in the future by, among other things, increases in interest rates.
We require continued access to capital and 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. We expect to use our revolving credit facility to finance a portion of our future growth, and 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 in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. Although interest rates are low by historical standards, they have recently increased and a continued increase in interest rates could increase our interest expense and materially adversely affect our financial condition. A significant reduction in cash flow from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
ITEM 3. | LEGAL PROCEEDINGS |
We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition.
Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
ITEM 4. | MINE SAFETY DISCLOSURES |
Not applicable.
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PART II
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Market Information
Our common stock is traded on the NYSE under the symbol “JAG.”
Holders
On February 22, 2019, there were approximately six stockholders of record of our common stock.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
We did not purchase any shares of our common stock during the three months ended December 31, 2018.
Sales of Unregistered Equity Securities
We did not have any sales of unregistered equity securities during the three months ended December 31, 2018.
Stock Performance Graph
The graph below compares the cumulative total shareholder return on our common stock to the cumulative total return on the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Dow Jones US Select Oil Exploration & Production Total Return Index (“DJ US Select Oil E&P Index”), since January 27, 2017, the first day on which shares of our common stock issued in our IPO commenced trading on the NYSE. The graph assumes that $100 was invested in our common stock and in each index on January 27, 2017 and that any dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.
The information contained in this stock performance graph section shall not be deemed to be “soliciting material” or “filed” or incorporated by reference in future filings with the SEC, or subject to the liabilities section of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended, or the Exchange Act.
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ITEM 6. | SELECTED FINANCIAL DATA |
The following tables show selected historical consolidated and combined financial data, for the periods and as of the dates indicated. Our historical results are not necessarily indicative of future results. The following selected financial and operating data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated and combined financial statements and related notes, each of which is included in this report.
Year Ended December 31, | |||||||||||||||||||
(in thousands, except per share data) | 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||
Statements of Operations Data: | |||||||||||||||||||
Revenues | |||||||||||||||||||
Oil sales | $ | 539,802 | $ | 241,788 | $ | 70,078 | $ | 31,534 | $ | 14,605 | |||||||||
Natural gas sales | 9,136 | 9,065 | 2,213 | 948 | 646 | ||||||||||||||
NGL sales | 31,956 | 15,571 | 3,068 | 1,329 | 1,029 | ||||||||||||||
Other operating revenues | 750 | 888 | 1,163 | 40 | — | ||||||||||||||
Total revenues | 581,644 | 267,312 | 76,522 | 33,851 | 16,280 | ||||||||||||||
Operating expenses | |||||||||||||||||||
Lease operating expenses | 42,406 | 17,874 | 7,505 | 3,165 | 2,041 | ||||||||||||||
Gathering and processing expenses | — | 4,424 | 1,046 | 171 | 121 | ||||||||||||||
Production and ad valorem taxes | 34,642 | 16,120 | 4,345 | 2,244 | 920 | ||||||||||||||
Exploration | 29 | 31 | 2,484 | 11 | 64 | ||||||||||||||
Depletion, depreciation, amortization and accretion | 222,355 | 111,049 | 40,417 | 22,685 | 8,444 | ||||||||||||||
Impairment of unproved oil and natural gas properties | 28,198 | 373 | 372 | 6,489 | 1,414 | ||||||||||||||
General and administrative expenses (including equity-based compensation of $83,346 in 2018 and $442,976 in 2017) | 122,472 | 466,067 | 11,690 | 7,446 | 7,330 | ||||||||||||||
Other operating expenses | 63 | 247 | 649 | 250 | — | ||||||||||||||
Total operating expenses | 450,165 | 616,185 | 68,508 | 42,461 | 20,334 | ||||||||||||||
Income (loss) from operations | 131,479 | (348,873 | ) | 8,014 | (8,610 | ) | (4,054 | ) | |||||||||||
Other income (expense) | |||||||||||||||||||
Gain (loss) on commodity derivatives | 119,338 | (42,615 | ) | (15,145 | ) | 1,323 | 5,375 | ||||||||||||
Interest expense, net | (25,152 | ) | (2,861 | ) | (2,629 | ) | (197 | ) | — | ||||||||||
Gain on sale of oil and natural gas properties | 6,225 | — | — | — | — | ||||||||||||||
Other, net | 43 | 358 | — | — | — | ||||||||||||||
Total other income (expense) | 100,454 | (45,118 | ) | (17,774 | ) | 1,126 | 5,375 | ||||||||||||
Income (loss) before income tax | 231,933 | (393,991 | ) | (9,760 | ) | (7,484 | ) | 1,321 | |||||||||||
Income tax expense (benefit) | 66,475 | 57,943 | — | — | — | ||||||||||||||
Net income (loss) | 165,458 | (451,934 | ) | (9,760 | ) | (7,484 | ) | 1,321 | |||||||||||
Less: Net loss attributable to Jagged Peak Energy LLC (predecessor) | — | (375,476 | ) | (9,760 | ) | (7,484 | ) | 1,321 | |||||||||||
Net income (loss) attributable to Jagged Peak Energy Inc. stockholders | $ | 165,458 | $ | (76,458 | ) | $ | — | $ | — | $ | — | ||||||||
Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders per common share: | |||||||||||||||||||
Basic | $ | 0.78 | $ | (0.36 | ) | ||||||||||||||
Diluted | $ | 0.78 | $ | (0.36 | ) | ||||||||||||||
Weighted average common shares outstanding: | |||||||||||||||||||
Basic | 213,128 | 212,932 | |||||||||||||||||
Diluted | 213,203 | 212,932 | |||||||||||||||||
Cash Flow Data: | |||||||||||||||||||
Net cash provided by operating activities | $ | 427,656 | $ | 178,871 | $ | 32,083 | $ | 20,372 | $ | 7,615 | |||||||||
Net cash used in investing activities | $ | (733,219 | ) | $ | (600,034 | ) | $ | (195,425 | ) | $ | (110,232 | ) | $ | (187,067 | ) | ||||
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Net cash provided by financing activities | $ | 331,269 | $ | 418,959 | $ | 160,904 | $ | 70,397 | $ | 199,800 | |||||||||
Other Financial Data: | |||||||||||||||||||
Adjusted EBITDAX (1) | $ | 431,316 | $ | 203,296 | $ | 48,995 | $ | 26,510 | $ | 6,631 | |||||||||
December 31, | |||||||||||||||||||
(in thousands) | 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||
Balance Sheet Data: | |||||||||||||||||||
Cash and cash equivalents | $ | 35,229 | $ | 9,523 | $ | 11,727 | $ | 14,165 | $ | 33,628 | |||||||||
Total oil and gas properties, net | $ | 1,518,615 | $ | 1,029,239 | $ | 473,592 | $ | 302,726 | $ | 214,188 | |||||||||
Total assets | $ | 1,767,141 | $ | 1,103,428 | $ | 518,392 | $ | 327,732 | $ | 257,084 | |||||||||
Long-term debt | $ | 489,239 | $ | 155,000 | $ | 132,000 | $ | 20,000 | $ | — | |||||||||
Other long-term liabilities | $ | 141,970 | $ | 74,608 | $ | 3,859 | $ | 779 | $ | 850 | |||||||||
Total stockholders' / members' equity | $ | 947,950 | $ | 699,345 | $ | 326,112 | $ | 284,330 | $ | 240,814 | |||||||||
(1) | Adjusted EBITDAX is a non-GAAP financial measure. For a definition and discussion of Adjusted EBITDAX and a reconciliation of net income (loss) to Adjusted EBITDAX, see below under “Non-GAAP Financial Measure.” |
Non-GAAP Financial Measure
Adjusted EBITDAX
Adjusted EBITDAX is a non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
We define Adjusted EBITDAX as net income (loss) before interest expense, net of capitalized interest, depletion, depreciation, amortization and accretion, impairment of oil and natural gas properties, exploration expense, equity-based compensation expense, income taxes, gains or losses on sales of assets and net gains or losses on derivatives less net cash from derivative settlements. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles (“GAAP”).
Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods, book values of assets, capital structures, equity-based compensation programs, hedging programs, commodity prices and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depletable and depreciable assets, exploration expenses, equity-based compensation expense and net gains or losses on derivatives less net cash from derivative settlements, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by such items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.
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The following table presents a reconciliation of net income (loss), our most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted EBITDAX.
Year Ended December 31, | |||||||||||||||||||
(in thousands) | 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||
Reconciliation of Net income (loss) to Adjusted EBITDAX: | |||||||||||||||||||
Net Income (Loss) | $ | 165,458 | $ | (451,934 | ) | $ | (9,760 | ) | $ | (7,484 | ) | $ | 1,321 | ||||||
Adjustments to reconcile to Adjusted EBITDAX | |||||||||||||||||||
Interest expense, net of capitalized | 25,152 | 2,861 | 2,629 | 197 | — | ||||||||||||||
Income tax expense | 66,475 | 57,943 | — | — | — | ||||||||||||||
Depletion, depreciation, amortization and accretion | 222,355 | 111,049 | 40,417 | 22,685 | 8,444 | ||||||||||||||
Impairment of unproved oil and natural gas properties | 28,198 | 373 | 372 | 6,489 | 1,414 | ||||||||||||||
Exploration expenses | 29 | 31 | 2,484 | 11 | 64 | ||||||||||||||
(Gain) loss on commodity derivatives, net, less net cash from derivative settlements (1) | (153,472 | ) | 39,997 | 12,853 | 4,612 | (4,612 | ) | ||||||||||||
Equity-based compensation expense | 83,346 | 442,976 | — | — | — | ||||||||||||||
Gain on sale of oil and natural gas properties | (6,225 | ) | — | — | — | — | |||||||||||||
Adjusted EBITDAX | $ | 431,316 | $ | 203,296 | $ | 48,995 | $ | 26,510 | $ | 6,631 | |||||||||
(1) | Has the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as cash flow hedges. |
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Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis should be read in conjunction with our consolidated and combined financial statements and related notes presented in this Annual Report on Form 10-K. The following discussion and analysis contains forward-looking statements, including, without limitation, statements related to our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to update any forward-looking statements except as otherwise required by applicable law.
In this section, references to “Jagged Peak,” “the Company,” “we,” “us” and “our” refer to Jagged Peak Energy Inc. and its subsidiaries, after the initial public offering of Jagged Peak (the “IPO”) and, prior to the IPO, to Jagged Peak Energy LLC (“JPE LLC”).
Jagged Peak Energy Inc. and our Predecessor
Jagged Peak was formed in September 2016 and, prior to the consummation of the IPO, did not have historical financial operating results. For purposes of this Annual Report, our accounting predecessor reflects the results of JPE LLC, which was formed in 2013 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves. In connection with the IPO, a corporate reorganization took place whereby JPE LLC became a wholly owned subsidiary of Jagged Peak.
Overview
We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves. Our operations are entirely located in the United States, within the Permian Basin of West Texas. Our primary area of focus is the southern Delaware Basin; the Delaware Basin is a sub-basin of the Permian Basin. Our acreage is located on large, contiguous blocks in the adjacent Texas counties of Winkler, Ward, Reeves and Pecos, with significant original oil-in-place within multiple stacked hydrocarbon-bearing formations.
We have assembled a portfolio of contiguous acreage in the core oil window of the southern Delaware Basin. This acreage is characterized by a multi-year, oil-weighted inventory of horizontal drilling locations that provide attractive growth and return opportunities. At December 31, 2018, our acreage position was approximately 79,500 net acres. We divide our current areas of operation into three distinct project areas: Cochise, with approximately 12,900 net acres, Whiskey River, with approximately 36,400 net acres, and Big Tex, with approximately 30,200 net acres. During 2018, we recognized unproved oil and natural gas impairment expense of $28.2 million on certain Big Tex acreage that largely resulted from our ongoing evaluation of our undeveloped Big Tex acreage and our current plan to not drill on certain of these leases before they expire. The Big Tex acreage discussed above, and throughout this Annual Report, includes the impaired Big Tex acreage, as it has not yet expired.
As of December 31, 2018, our estimated proved reserves were approximately 118.9 MMBoe, consisting of 77% oil. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operational improvements and cost efficiencies. As the operator of approximately 97% of our acreage, we have the flexibility to manage our development program, which allows us to optimize our field-level returns and profitability.
Market Conditions
Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL production. Compared to 2017, our realized oil price for 2018 increased 16% to $56.12 per barrel, our realized natural gas price declined 55% to $1.14 per Mcf, and our realized price for NGLs declined by 18% to $20.83 per barrel between these same periods. The decrease in natural gas and NGL realized prices was partially due to the adoption of ASC 606 on January 1, 2018, and the transition from ethane rejection to ethane recovery during 2018 by our primary gas purchaser. See “Sources of Our Revenues” below for further information regarding our realized commodity prices.
As the U.S. oil and gas industry continues to confront volatile commodity prices, we may experience adverse effects on our business, financial condition, results of operations, operating cash flows, liquidity and ability to finance planned capital expenditures. Lower prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore, potentially lower our oil, natural gas and NGL reserves. Decreasing reserves may also reduce the borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves. Our ability to access capital markets may be restricted, which could have an impact on our flexibility to react to
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changing economic and business conditions. Further, oversupply and high inventory storage levels could put downward pressure on commodity prices and have an adverse impact on our business partners, customers and lenders, potentially causing them to fail to meet their obligations to us.
Factors Affecting the Comparability of Our Results of Operations
Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, primarily for the reasons described below.
Increased Oil and Natural Gas Development Activities
Since commencing our drilling program in late 2013, we operated an average of one horizontal drilling rig through June 2016. We began operating our second and third rigs in July of 2016. During 2017 we operated an average of six horizontal rigs, and in 2018 we operated an average of approximately five horizontal rigs. During 2018 we began production on 59 gross (48.0 net) wells. Our average daily production has grown from 16,974 Boe/d in 2017 to 34,207 Boe/d in 2018. During 2018 we spent $711.0 million for drilling and completing wells and on water infrastructure costs, which included $1.0 million to purchase surface acreage. This compares to $595.9 million that we spent in 2017 for drilling, completion and infrastructure.
Our board of directors approved a capital budget for 2019 which is projected to range from $605.0 million to $665.0 million, excluding acquisitions. We expect to allocate between $580.0 million and $630.0 million of our 2019 capital budget for the drilling and completion of operated and non-operated wells, and $25.0 million to $35.0 million for water infrastructure costs, excluding any potential additions to surface acreage. The ultimate amount of capital that we expend may fluctuate materially based on market conditions, availability and/or attractiveness of acquisitions and our drilling results.
Equity-based Compensation
During the year ended December 31, 2018, we recognized equity-based compensation expense of $83.3 million, which included $71.3 million related to a modification of service requirements for incentive unit awards. During the year ended December 31, 2017, we recognized equity-based compensation of $443.0 million which included $379.0 million related to incentive unit awards that vested at the time of the IPO. Please refer to Note 5, Equity-based Compensation, included elsewhere in this report for additional information on equity-based compensation.
Interest Expense
In May 2018, JPE LLC issued $500.0 million aggregate principal amount of 5.875% senior unsecured notes that mature in May 2026 (the “Senior Notes”). The Senior Notes resulted in net proceeds to the Company of $488.3 million, net of offering expenses. A portion of such proceeds was used to repay the entire outstanding balance under the Amended and Restated Credit Facility of $320.0 million as of the date the Senior Notes proceeds were received. During the year ended December 31, 2018, we incurred interest expense of $25.2 million, of which approximately $19.0 million related to the Senior Notes. During the year ended December 31, 2017 and 2016, we incurred $2.9 million and $2.6 million, respectively. Please refer to Note 4, Debt, included elsewhere in this report for more information on the Senior Notes.
Income Taxes
As a result of our corporate reorganization, we became subject to federal and state income tax. The change in tax status required the recognition of deferred tax assets and liabilities for the temporary differences at the time of the change in status. The resulting net deferred tax liability of approximately $80.7 million was recognized as tax expense from continuing operations during the year ended December 31, 2017. For periods following completion of the corporate reorganization, we began recording income taxes associated with our status as a corporation. Please refer to Note 7, Income Taxes, included elsewhere in this report for more information on income taxes.
Adoption of ASC 606
As of January 1, 2018, we adopted ASC 606 using the modified retrospective method. This adoption did not have an impact on the opening balance of retained earnings. As a result of the adoption, we changed the presentation of the costs to gather and process natural gas and NGLs. For the twelve months ended December 31, 2018, the adoption of ASC 606 resulted in a decrease of $14.7 million to our natural gas and NGL sales revenues, with a corresponding decrease to gathering and processing expense, but did not affect operating income, net income or operating cash flows. Comparative information for the prior period continues to be reported under the accounting standards in effect for that period. Adoption of the new standard did not impact natural gas or NGL production volumes. For additional information regarding the new revenue recognition standard, see Note 2, Significant Accounting Policies and Related Matters, in “Part I. Financial Information - Item 1. Financial Statements.”
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Public Company Expenses
Subsequent to our IPO, we incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, corporate tax return preparation, increased independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations for the year ended December 31, 2016.
Summary of Operating and Financial Results
• | Successfully began production on 59 gross (48.0 net) wells, of which we operate 45 gross (42.4 net), all within the southern Delaware Basin; |
• | Increased total proved reserves by 44% to 118.9 MMBoe at December 31, 2018, and replaced 393% of 2018 production; |
• | Added 35.7 MMBoe of proved reserves from infill reserves in an existing proved field; |
• | Increased average daily production by 102% to 34,207 Boe/d, comprised of 77% oil; |
• | Grew oil production 93% to 26,355 barrels per day, natural gas production by 122% to 21.9 MMcf/d and NGL production rose 149% to 4,203 barrels per day; |
• | Production revenues increased 118% to $580.9 million; |
• | Improved cash flow from operating activities to $427.7 million from $178.9 million in the previous year; |
• | Incurred equity-based compensation expense of $83.3 million, which included $71.3 million related to a modification of service requirements for incentive unit awards; |
• | Experienced a noncash derivative gain of $153.5 million; |
• | Realized net income of $165.5 million; |
• | Increased our elected commitment under our credit facility from $425.0 million to $540.0 million; |
• | Successfully completed the offering of $500.0 million aggregate principal amount of the 5.875% Senior Notes; and |
• | Repaid our outstanding borrowings on our Amended and Restated Credit Facility with a portion of the proceeds from the issuance of the 5.875% Senior Notes. |
Sources of Our Revenues
Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. In 2018, our production revenues were derived 93% from oil sales, 1% from natural gas sales and 6% from NGL sales. Our oil, natural gas and NGL revenues do not include the effects of derivatives.
Increases or decreases in our revenue, profitability and future production are highly dependent on the commodity prices we receive. Oil, natural gas and NGL prices are market driven and have been historically volatile. We expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors.
The following table presents our average realized commodity prices, the effects of derivative settlements on our realized prices and certain major U.S. index prices.
Year Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
Crude Oil (per Bbl): | |||||||||||
Average NYMEX price | $ | 65.23 | $ | 50.80 | $ | 43.29 | |||||
Average realized price | $ | 56.12 | $ | 48.56 | $ | 41.18 | |||||
Average realized price, including derivative settlements | $ | 52.57 | $ | 48.04 | $ | 39.84 | |||||
Natural Gas (per Mcf): | |||||||||||
Average NYMEX price | $ | 3.15 | $ | 2.99 | $ | 2.52 | |||||
Average realized price (1) (2) | $ | 1.14 | $ | 2.52 | $ | 2.32 | |||||
NGLs (per Bbl): | |||||||||||
Average realized price (1) (2) | $ | 20.83 | $ | 25.25 | $ | 15.81 | |||||
(1) | On January 1, 2018, we adopted ASC 606. As a result of adoption, natural gas and NGL realized prices for the year ended December 31, 2018 include gathering and processing costs which reduced our realized natural gas and NGL prices by $0.44 per Mcf and $7.33 per barrel, respectively. For additional information regarding the new revenue recognition standard, see Note 2, Significant Accounting Policies and Related Matters, included elsewhere in this report. |
(2) | During 2018, our primary gas purchaser transitioned from ethane rejection to ethane recovery, which resulted in decreased realized natural gas price per Mcf and NGL price per barrel, while increasing NGL volumes. |
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While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location, gathering and processing and transportation differentials for these products.
See “Results of Operations” below for an analysis of the impact changes in realized prices had on our revenues.
In addition to sales of oil, natural gas, and NGLs, we derive a minimal portion of our revenues from sales of fresh water and produced water disposal services to third parties. These revenues are reflected as other operating revenues on the consolidated and combined statements of operations.
Production Volumes Directly Impact Our Results of Operations
As reservoir pressures decline, production from a given well or formation decreases. Growth in our cash flow, future production and reserves will depend on our ability to continue to add production and proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through drilling, as well as acquisitions. Our ability to add reserves through successful drilling results and acquisitions is dependent on many factors, including our ability to increase our levels of cash flow from operations, borrow or raise capital, obtain regulatory approvals, procure materials, services and personnel and successfully identify and consummate acquisitions.
Operating Costs and Expenses
Costs associated with producing oil, natural gas and NGLs are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production and others are a function of the number of wells we own.
Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation and maintenance of producing properties. Expenses for utilities, direct labor, water transportation, injection and disposal, repairs, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and materials and supplies, generally remain consistent across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. Certain operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. Workover costs are variable and can fluctuate based on the timing of workover activities.
We monitor our operations to ensure that we are incurring LOE at an acceptable level to determine if any wells or properties should be shut in, repaired, recompleted or sold. We also monitor our LOE on a per BOE basis to determine the efficiency of our production operations. This unit rate also allows us to identify trends and to benchmark against other producers. Although we strive to minimize our LOE, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of properties.
Gathering and Processing Expenses. Gathering and processing expenses largely consist of contractual costs to gather and process our natural gas and NGLs. These costs may fluctuate with changes in production volumes, contractual arrangements or fuel and compression costs. As a result of adopting ASC 606, natural gas and NGL gathering and processing costs that would have previously been presented as expenses were deducted from revenues. Based on the sales contracts we currently have, all gathering and processing costs are now deducted from revenue; however, future contracts could have different terms which may require us to record gathering and processing expense.
Production and Ad Valorem Taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold. These taxes are calculated using fixed rates established by state taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which generally trends with the value of our proved developed reserves and is influenced by current and anticipated future oil and natural gas prices.
Exploration Expenses. Exploration expenses consist of the costs of unsuccessful exploratory wells and delay rentals for leases on certain unproved properties.
Depletion, Depreciation, Amortization and Accretion. Depletion, depreciation, amortization and accretion (“DD&A”) is primarily the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs incurred related to the acquisition, development, and successful exploration and development of oil and natural gas properties, and deplete these costs based on the related reserves. DD&A also includes straight-line depreciation of capitalized corporate assets and operations support equipment, as well as the accretion of asset retirement obligation liabilities.
Impairment of Unproved Oil and Natural Gas Properties. Impairment of unproved oil and natural gas properties represents the book value of unproved properties that will no longer be held by production or extensions of leases.
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Other Operating Expenses. Other operating expenses represent water sourcing and disposal costs related to third-party sales and other costs associated with our oil and natural gas properties.
General and Administrative. General and administrative (“G&A”) expenses consist of costs incurred for overhead, including payroll and benefits for our corporate staff, equity-based compensation, costs of maintaining our headquarters, costs of managing our production and development operations, and costs of audit, tax, legal, consulting and other professional services.
Interest Expense. We incur interest on our Senior Notes that were issued in May 2018. Interest is payable on the Senior Notes semi-annually in arrears on each May 1 and November 1. We may also finance a portion of our working capital requirements and capital expenditures with borrowings under our credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest expense is reflected net of capitalized interest.
Derivative Activity
Historically, pricing for oil, natural gas and NGLs has been volatile and unpredictable, and we expect this volatility to continue in the future. As of December 31, 2018, we had entered into derivative oil swap contracts covering periods from January 1, 2019 through December 31, 2020 for approximately 10.6 MMBbls of our projected oil production at a weighted average WTI oil price of $60.19 per barrel. We also have basis differential derivative contracts between Midland, TX and Cushing, OK for the periods from January 1, 2019 through December 31, 2020 covering 18.3 MMBbls at a weighted average basis differential of $(3.52) per barrel. These derivative instruments allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. Our derivative instruments provide increased certainty of cash flows for funding our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil prices and may partially limit our potential gains from future increases in prices. During the year ended December 31, 2018, we incurred net payments of $34.1 million related to derivative agreements that settled during this time. In the future, we may seek to hedge price risk associated with our natural gas and NGL production. See “Item 7A.—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.
We expect to continue to use commodity derivative instruments to hedge our price risk in the future. Subject to restrictions in our credit agreement, 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. Under our Amended and Restated Credit Facility as of December 31, 2018, we can hedge up to 85% of forecasted future production for up to 36 months in the future, and up to the greater of 75% of our proved reserves and 60% of our reasonably anticipated forecasted production for 37 to 60 months in the future, provided that no hedges have a term beyond five years.
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Results of Operations
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Revenues
Oil and Natural Gas Revenues. The following table provides the components of our production revenues for the years ended December 31, 2018 and 2017, as well as each period’s respective average realized prices and production volumes:
Year Ended December 31, | ||||||||||||||
(in thousands or as indicated) | 2018 | 2017 | Change | % Change | ||||||||||
Production revenues: | ||||||||||||||
Oil sales | $ | 539,802 | $ | 241,788 | $ | 298,014 | 123 | % | ||||||
Natural gas sales | 9,136 | 9,065 | 71 | 1 | % | |||||||||
NGL sales | 31,956 | 15,571 | 16,385 | 105 | % | |||||||||
Total production revenues | $ | 580,894 | $ | 266,424 | $ | 314,470 | 118 | % | ||||||
Average realized price: (1) (2) (3) | ||||||||||||||
Oil (per Bbl) | $ | 56.12 | $ | 48.56 | $ | 7.56 | 16 | % | ||||||
Natural gas (per Mcf) | $ | 1.14 | $ | 2.52 | $ | (1.38 | ) | (55 | )% | |||||
NGLs (per Bbl) | $ | 20.83 | $ | 25.25 | $ | (4.42 | ) | (18 | )% | |||||
Total (per Boe) | $ | 46.52 | $ | 43.00 | $ | 3.52 | 8 | % | ||||||
Production volumes: | ||||||||||||||
Oil (MBbls) | 9,620 | 4,979 | 4,641 | 93 | % | |||||||||
Natural gas (MMcf) | 7,992 | 3,601 | 4,391 | 122 | % | |||||||||
NGLs (MBbls) (2) | 1,534 | 617 | 917 | 149 | % | |||||||||
Total (MBoe) | 12,486 | 6,196 | 6,290 | 102 | % | |||||||||
Average daily production volume: | ||||||||||||||
Oil (Bbls/d) | 26,355 | 13,640 | 12,715 | 93 | % | |||||||||
Natural gas (Mcf/d) | 21,897 | 9,865 | 12,032 | 122 | % | |||||||||
NGLs (Bbls/d) | 4,203 | 1,690 | 2,513 | 149 | % | |||||||||
Total (Boe/d) | 34,207 | 16,974 | 17,233 | 102 | % | |||||||||
(1) | Average prices shown in the table do include settlements of commodity derivative transactions. |
(2) | During 2018, our primary gas purchaser transitioned from ethane rejection to ethane recovery, which resulted in decreased realized natural gas price per Mcf and NGL price per barrel, while increasing NGL volumes. |
(3) | On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of our natural gas and NGL sales revenues, with a corresponding change to our gathering and processing expense. For additional information regarding the new revenue recognition standard, see Note 2, Significant Accounting Policies and Related Matters, included elsewhere in this report. See the table below for a breakout of the impact on our revenues and expense of adopting ASC 606: |
Year Ended December 31, 2018 | |||||||||||
(in thousands) | Amounts presented on statements of operations | ASC 606 Adjustments | Previous Revenue Recognition Method | ||||||||
Production revenues: | |||||||||||
Oil sales | $ | 539,802 | $ | — | $ | 539,802 | |||||
Natural gas sales | 9,136 | 3,488 | 12,624 | ||||||||
NGL sales | 31,956 | 11,243 | 43,199 | ||||||||
Total production revenues | $ | 580,894 | $ | 14,731 | $ | 595,625 | |||||
Operating expenses: | |||||||||||
Gathering and processing expenses | $ | — | $ | 14,731 | $ | 14,731 | |||||
As reflected in the table above, our total production revenue for the year ended December 31, 2018 was 118%, or $314.5 million, higher than that of the same period from 2017. The increase is primarily due to higher sales volumes, along with higher average realized oil prices during 2018. Our aggregate production volumes in 2018 were 12,486 MBoe, comprised of 77% oil,
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11% natural gas and 12% NGLs. This represents an increase of 102% over aggregate production volumes of 6,196 MBoe during 2017.
The following table shows the effects of volume and price related changes on oil, natural gas and NGL sales from the year ended December 31, 2017 to the year ended December 31, 2018:
(in thousands) | Oil sales | Natural gas sales | NGL sales | Total | |||||||||||
Year Ended December 31, 2017 | $ | 241,788 | $ | 9,065 | $ | 15,571 | $ | 266,424 | |||||||
Changes due to: | |||||||||||||||
Increase (decrease) in production volumes (1) | 225,290 | 11,100 | 23,166 | 259,556 | |||||||||||
Increase (decrease) in average realized prices (2) | 72,724 | (11,029 | ) | (6,781 | ) | 54,914 | |||||||||
Year Ended December 31, 2018 | $ | 539,802 | $ | 9,136 | $ | 31,956 | $ | 580,894 | |||||||
(1) | Production increases are largely related to our drilling program, which added 48.0 net wells that began production during 2018. Additionally, the increase in NGL volumes from 2017 to 2018 partially resulted from our primary gas purchaser transitioning from ethane rejection to ethane recovery during 2018, as described above. |
(2) | The changes due to natural gas and NGL average realized prices were impacted by the adoption of ASC 606 and the transition from ethane rejection to ethane recovery, as described above. |
Operating Expenses
The following table summarizes our operating expenses for the periods indicated:
Year Ended December 31, | Per Boe | |||||||||||||||||||||
(in thousands, except per Boe) | 2018 | 2017 | Change | % Change | 2018 | 2017 | ||||||||||||||||
Lease operating expenses | $ | 42,406 | $ | 17,874 | $ | 24,532 | 137 | % | $ | 3.40 | $ | 2.88 | ||||||||||
Gathering and processing expenses (1) | — | 4,424 | (4,424 | ) | (100 | )% | $ | — | $ | 0.71 | ||||||||||||
Production and ad valorem taxes | 34,642 | 16,120 | 18,522 | 115 | % | $ | 2.77 | $ | 2.60 | |||||||||||||
Exploration | 29 | 31 | (2 | ) | (6 | )% | $ | — | $ | 0.01 | ||||||||||||
Depletion, depreciation, amortization and accretion | 222,355 | 111,049 | 111,306 | 100 | % | $ | 17.81 | $ | 17.92 | |||||||||||||
Impairment of unproved oil and natural gas properties | 28,198 | 373 | 27,825 | NM | NM | NM | ||||||||||||||||
Other operating expenses | 63 | 247 | (184 | ) | (74 | )% | $ | 0.01 | $ | 0.04 | ||||||||||||
General and administrative (before equity-based compensation) | 39,126 | 23,091 | 16,035 | 69 | % | $ | 3.13 | $ | 3.73 | |||||||||||||
Total operating expenses (before equity-based compensation) | 366,819 | 173,209 | 193,610 | 112 | % | $ | 29.38 | $ | 27.95 | |||||||||||||
Equity-based compensation | 83,346 | 442,976 | (359,630 | ) | ||||||||||||||||||
Total operating expenses | $ | 450,165 | $ | 616,185 | $ | (166,020 | ) | |||||||||||||||
(1) | On January 1, 2018, we adopted ASC 606 which changed the presentation of our natural gas and NGL sales revenues, with a corresponding change to our gathering and processing expense. See Note 2, Significant Accounting Policies and Related Matters, included elsewhere in this report for more information, and the table in footnote 3 to the oil and natural gas revenues table, above, for a breakout of the impact from ASC 606. |
NM Not meaningful.
Lease Operating Expenses. Our LOE varies in conjunction with our level of production, the timing of our workover expenses and variations in industry activity that cause fluctuations in service provider costs. LOE increased to $42.4 million during 2018, compared to $17.9 million for the same period of 2017. The increase largely corresponds to our increased production and well counts between periods, resulting in higher overall costs for equipment rental, electricity, contract labor, and general maintenance and repair. Additionally, during 2018 we incurred approximately $11.0 million of additional workover expense, as compared to the same period of 2017. LOE per Boe increased 18% to $3.40 for the year ended December 31, 2018, primarily due to the additional workover costs, which increased more than production levels.
Gathering and Processing Expenses. Gathering and processing expenses were $4.4 million in 2017 and were reduced to $0 in 2018 as a result of adopting ASC 606. During 2018, $14.7 million of gathering and processing costs that would have previously been presented as expenses were deducted from revenues. Based on the sales contracts we currently have, all gathering and processing costs are deducted from revenue; however, future contracts could have different terms which may require us to record gathering and processing expense. For additional information regarding the adoption of ASC 606, see Note 2, Significant Accounting Policies and Related Matters, included elsewhere in this report.
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Production and Ad Valorem Taxes. Production and ad valorem taxes increased 115% between 2018 and 2017, from $16.1 million in 2017 to $34.6 million in 2018. The increase in production taxes is due to an increase in revenues, and the increase in ad valorem taxes relates to the addition of multiple new high-volume wells.
Depletion, Depreciation, Amortization and Accretion. DD&A expense increased $111.3 million, or 100%, during 2018 compared to 2017. The increase in DD&A expense was largely due to an increase in production, partially offset by a decrease in our DD&A rate. Our DD&A rate can vary due to changes in proved reserve volumes, acquisition and disposition activity, development costs and impairments. The DD&A rate per Boe decreased 1% to $17.81 per Boe, compared to $17.92 per Boe in 2017. The decrease in our DD&A rate was largely due to an increase in reserve volumes due to continued successful drilling activities, whereas the rate of increase in capitalized costs related to those drilling activities was lower than the rate of reserve increase.
Impairment of Unproved Oil and Natural Gas Properties. We incurred $28.2 million of impairment costs in 2018, compared to $0.4 million in 2017. The impairments in 2018 were largely related to certain acreage within our Big Tex area, and our current plan to not drill on certain of these leases before they expire. The impairments in 2017 were due to the expiration of certain leases on unproved properties. No impairments were recorded on proved properties during 2018 and 2017.
General and Administrative and Equity-based Compensation. G&A, excluding equity-based compensation, increased 69% to $39.1 million during 2018, from $23.1 million in 2017. The increase is primarily due to a $10.9 million increase in costs related to salaries, employee benefits, contract personnel and other general business expenses required to support the growth of our capital program and production levels, and a $4.2 million increase related to severance and other nonrecurring expenses, primarily in the first quarter of 2018. The number of our full-time employees increased from 36 at January 1, 2017 to 94 at December 31, 2018.
Equity-based compensation expense for the year ended December 31, 2018 and 2017 is summarized as follows:
Year Ended December 31, | |||||||||||
(in thousands) | 2018 | 2017 | Change | ||||||||
Incentive unit awards | $ | 76,442 | $ | 439,411 | $ | (362,969 | ) | ||||
Restricted stock unit awards | 4,374 | 2,068 | 2,306 | ||||||||
Performance stock unit awards | 2,530 | 1,497 | 1,033 | ||||||||
Total equity-based compensation expense | $ | 83,346 | $ | 442,976 | $ | (359,630 | ) | ||||
Equity-based compensation expense for the year ended December 31, 2018 includes $71.3 million related to a modification of the service requirements in February 2018 for the incentive unit awards allocated at the IPO. For the year ended December 31, 2017, equity-based compensation expense included (i) $379.0 million related to common stock issued to MIU holders that vested at the IPO date, all of which was noncash except for $14.7 million related to a management incentive advance payment made in April 2016, and (ii) $22.2 million related to a modification in conjunction with a March 2017 separation agreement of a former executive officer. As of December 31, 2018, we expect to recognize additional noncash compensation expense of approximately $5.7 million over approximately 2.3 years for the incentive unit awards, $7.9 million over approximately 2.1 years for restricted stock unit awards and $7.2 million over approximately 1.9 years for the performance stock unit awards. For additional information regarding our equity-based compensation, see Note 5, Equity-based Compensation, included elsewhere in this report.
Other Income and Expense
The following table summarizes our other income and expenses for the periods indicated:
Year Ended December 31, | |||||||||||
(in thousands) | 2018 | 2017 | Change | ||||||||
Gain (loss) on commodity derivatives | $ | 119,338 | $ | (42,615 | ) | $ | 161,953 | ||||
Interest expense, net | (25,152 | ) | (2,861 | ) | (22,291 | ) | |||||
Gain on sale of oil and natural gas properties | 6,225 | — | 6,225 | ||||||||
Other, net | 43 | 358 | (315 | ) | |||||||
Total other income (expense) | $ | 100,454 | $ | (45,118 | ) | $ | 145,572 | ||||
Gain (loss) on Commodity Derivatives. Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity prices against our derivative instruments and monthly settlements, if any, of the instruments. To the extent the future commodity price outlook declines between measurement periods, we will generally have noncash mark-to-
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market gains, while to the extent future commodity price outlook increases between measurement periods, we will generally have noncash mark-to-market losses.
The following table sets forth the components of gain (loss) on commodity derivatives for the periods indicated:
Year Ended December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Net cash receipts (payments) on settled derivatives | $ | (34,134 | ) | $ | (2,618 | ) | |
Gain (loss) from the change in fair value of open derivative contracts, net | 153,472 | (39,997 | ) | ||||
Gain (loss) on commodity derivatives | $ | 119,338 | $ | (42,615 | ) | ||
Interest Expense, net. The following table summarizes our interest expense for the periods indicated:
Year Ended December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Amended and Restated Credit Facility (1) | $ | 5,046 | $ | 2,595 | |||
Senior Notes | 19,012 | — | |||||
Amortization of debt issuance costs (2) | 2,340 | 606 | |||||
Capitalized interest | (1,246 | ) | (340 | ) | |||
Interest expense, net | $ | 25,152 | $ | 2,861 | |||
(1) | Includes interest on outstanding balances and commitment fees on undrawn balances. |
(2) | Includes amortization of debt issuance costs on the Amended and Restated Credit Facility and the Senior Notes. |
The increase in interest expense on our Amended and Restated Credit Facility is primarily due to an increase in the weighted average outstanding balance on our credit facility of $86.7 million during 2018, compared to $44.8 million during 2017. The increase is also attributable to increased commitment fees that resulted from our increased elected borrowing base. Interest expense on the Senior Notes during 2018 is a result of the issuance of the Senior Notes in May 2018.
Gain on Sale of Assets. The $6.2 million gain on sale of assets in 2018 related to the sale of non-core unproved acreage.
Income tax expense
Income tax expense increased to $66.5 million during 2018, from $57.9 million for 2017. The increased income tax expense during 2018 was primarily due to higher net income earned in 2018 compared to the same period of 2017. Income tax expense in 2017 was primarily due to the change in tax status resulting from our corporate reorganization. Income tax expense was higher in both 2018 and 2017 as a result of the equity-based compensation expense related to the incentive unit awards that were allocated at the time of the IPO, which is not deductible for federal or state income tax purposes.
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Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Revenues
Oil and Natural Gas Revenues. The following table provides the components of our revenues for the years indicated, as well as each year’s respective average realized prices and production volumes:
Year Ended December 31, | ||||||||||||||
(in thousands or as indicated) | 2017 | 2016 | Change | % Change | ||||||||||
Production revenues: | ||||||||||||||
Oil sales | $ | 241,788 | $ | 70,078 | $ | 171,710 | 245 | % | ||||||
Natural gas sales | 9,065 | 2,213 | 6,852 | 310 | % | |||||||||
NGL sales | 15,571 | 3,068 | 12,503 | 408 | % | |||||||||
Total production revenues | $ | 266,424 | $ | 75,359 | $ | 191,065 | 254 | % | ||||||
Average realized price: (1) | ||||||||||||||
Oil (per Bbl) | $ | 48.56 | $ | 41.18 | $ | 7.38 | 18 | % | ||||||
Natural gas (per Mcf) | $ | 2.52 | $ | 2.32 | $ | 0.20 | 9 | % | ||||||
NGLs (per Bbl) | $ | 25.25 | $ | 15.81 | $ | 9.44 | 60 | % | ||||||
Total (per Boe) | $ | 43.00 | $ | 36.68 | $ | 6.32 | 17 | % | ||||||
Production volumes: | ||||||||||||||
Oil (MBbls) | 4,979 | 1,702 | 3,277 | 193 | % | |||||||||
Natural gas (MMcf) | 3,601 | 953 | 2,648 | 278 | % | |||||||||
NGLs (MBbls) | 617 | 194 | 423 | 218 | % | |||||||||
Total (MBoe) | 6,196 | 2,054 | 4,142 | 202 | % | |||||||||
Average daily production volume: | ||||||||||||||
Oil (Bbls/d) | 13,640 | 4,649 | 8,991 | 193 | % | |||||||||
Natural gas (Mcf/d) | 9,865 | 2,603 | 7,262 | 279 | % | |||||||||
NGLs (Bbls/d) | 1,690 | 530 | 1,160 | 219 | % | |||||||||
Total (Boe/d) | 16,974 | 5,613 | 11,361 | 202 | % | |||||||||
(1) | Average prices shown in the table do not include settlements of commodity derivative transactions. |
As reflected in the table above, our total production revenue for 2017 was 254%, or $191.1 million, higher than that of 2016. The increase in 2017 compared to 2016 is due to higher sales volumes, along with higher realized commodity prices. Our aggregate production volumes in 2017 were 6,196 MBoe, comprised of 80% oil, 10% natural gas and 10% NGLs. This represents an increase of 202% from 2016 aggregate production volumes of 2,054 MBoe.
Increased production volumes accounted for an approximate $147.8 million increase in year-over-year production revenues, while increases in our total equivalent prices accounted for an approximate $43.3 million increase in year-over-year production revenues. Production increases are largely related to our active drilling program, which added 46.1 net wells that began production during 2017.
Oil sales increased 245%, or $171.7 million, due to a 193% increase in production volumes and an 18% increase in the average realized price for 2017 compared to the prior year. Natural gas sales increased 310%, or $6.9 million, due to a 278% increase in volumes in 2017 and a 9% increase in the average sales price. NGL sales increased 408%, or $12.5 million, due to a 218% increase in sales volumes, as well as a 60% increase in the average realized price for 2017. The increase in average realized price is due to increased market prices for NGLs, particularly for propane, which constitutes the largest component, by value, of our NGLs. In addition, beginning in June 2017 and through the remainder of 2017, we experienced ethane rejection, which leaves ethane in the residue gas stream and increases the average realized price of NGLs per barrel.
Other Operating Revenues. Other operating revenues relate to third-party sales of fresh water and water disposal services. During 2017 and 2016, we recognized other operating revenue of $0.9 million and $1.2 million, respectively. The change year-over-year is due to fluctuating sales of our excess fresh water and water disposal capacity between periods.
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Operating Expenses
The following table summarizes our operating expenses for the periods indicated:
Year Ended December 31, | Per Boe | |||||||||||||||||||||
(in thousands, except per Boe) | 2017 | 2016 | Change | % Change | 2017 | 2016 | ||||||||||||||||
Lease operating expenses | $ | 17,874 | $ | 7,505 | $ | 10,369 | 138 | % | $ | 2.88 | $ | 3.65 | ||||||||||
Gathering and processing expenses | 4,424 | 1,046 | 3,378 | 323 | % | $ | 0.71 | $ | 0.51 | |||||||||||||
Production and ad valorem taxes | 16,120 | 4,345 | 11,775 | 271 | % | $ | 2.60 | $ | 2.12 | |||||||||||||
Exploration | 31 | 2,484 | (2,453 | ) | (99 | )% | $ | 0.01 | $ | 1.21 | ||||||||||||
Depletion, depreciation, amortization and accretion | 111,049 | 40,417 | 70,632 | 175 | % | $ | 17.92 | $ | 19.67 | |||||||||||||
Impairment of unproved oil and natural gas properties | 373 | 372 | 1 | — | % | NM | NM | |||||||||||||||
Other operating expenses | 247 | 649 | (402 | ) | (62 | )% | $ | 0.04 | $ | 0.32 | ||||||||||||
General and administrative (before equity-based compensation) | 23,091 | 11,690 | 11,401 | 98 | % | $ | 3.73 | $ | 5.69 | |||||||||||||
Total operating expenses (before equity-based compensation) | 173,209 | 68,508 | 104,701 | 153 | % | $ | 27.95 | $ | 33.35 | |||||||||||||
Equity-based compensation | 442,976 | — | 442,976 | |||||||||||||||||||
Total operating expenses | $ | 616,185 | $ | 68,508 | $ | 547,677 | ||||||||||||||||
Lease Operating Expenses. Our LOE varies in conjunction with our level of production, the timing of our workover expenses and variations in industry activity that cause fluctuations in service provider costs. LOE increased 138% to $17.9 million in 2017, compared to $7.5 million for 2016. The increase largely relates to our increased production and well counts between periods that resulted in higher costs for equipment repair and maintenance, contract labor, chemicals, electricity, water disposal and equipment rental. LOE per Boe decreased 21% to $2.88 during 2017 compared to 2016, primarily due to fixed costs and the impact of the 202% increase in production between the two periods, largely coming from the addition of early-life high-producing, low-operating cost wells.
Gathering and Processing Expenses. Gathering and processing expenses increased $3.4 million during 2017 compared to 2016 primarily due to increased production. In addition, we experienced an increase in our per unit gathering and processing expense. The period over period increase in our per unit gathering and processing expense is due to an increase in natural gas production under our fixed fee contracts, as opposed to our percent-of-proceeds contracts. Under percent-of-proceeds contracts, we receive a percentage of the total proceeds received by the marketer, which is net of gathering and processing costs. Conversely, under our fixed fee natural gas marketing contracts, our gas sales revenue is determined after transporting gas to a downstream sales point and we are separately charged for the associated gathering and processing costs.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased 271% between 2016 and 2017, from $4.3 million in 2016 to $16.1 million in 2017. The increase in production taxes is due to an increase in revenues, and the increase in ad valorem taxes relates to the addition of multiple new high-volume wells.
Exploration. The $2.5 million decrease in exploration expense between 2016 and 2017, is due to decreases in delay rentals on certain unproved properties of $1.3 million, as well as exploratory dry hole costs of $1.2 million incurred in 2016. The exploratory dry hole costs related to an unproductive vertical test well drilled to a shallow horizon.
Depletion, Depreciation, Amortization and Accretion. DD&A expense increased $70.6 million, or 175%, during 2017 compared to 2016. The increase in DD&A expense was largely due to an increase in production, partially offset by a decrease in our DD&A rate. Our DD&A rate can vary due to changes in proved reserve volumes, acquisition and disposition activity, development costs and impairments. The DD&A rate per Boe decreased 9% to $17.92 per Boe, compared to $19.67 per Boe in 2016. The decrease in our DD&A rate was largely due to an increase in reserve volumes due to continued successful drilling activities, whereas the rate of increase in capitalized costs related to those drilling activities was lower than the rate of reserve increase.
Impairment of Unproved Oil and Natural Gas Properties. We incurred $0.4 million of impairment costs in 2017 and 2016, which were primarily due to the expiration of certain leases on unproved properties. No impairments were recorded on proved properties during 2017 and 2016.
Other Operating Expenses. Other operating expenses decreased $0.4 million to $0.2 million in 2017 from $0.6 million in 2016. The $0.2 million of other operating expenses in 2017 was primarily due to sales of fresh water and water disposal to third
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parties. During 2016, other operating expenses of $0.6 million related to rig termination fees of $0.2 million and $0.4 million of costs related to selling fresh water and water disposal.
General and Administrative and Equity-based Compensation. G&A, excluding equity-based compensation, increased 98% to $23.1 million for the year ended December 31, 2017, from $11.7 million for the same period of 2016. The increase is primarily due to a $9.2 million increase in costs related to salaries, employee benefits, contract personnel and other general business expenses required to support the growth of our capital program and production levels. The number of our full-time employees increased from 23 at January 1, 2016 to 59 at December 31, 2017. Additionally, we incurred $1.0 million in higher audit, tax and legal fees, which increases are largely a result of becoming a publicly traded company.
Equity-based compensation expense for the year ended December 31, 2017 was $443.0 million, as summarized in the table below:
(in thousands) | |||
Incentive unit awards | $ | 439,411 | |
Restricted stock unit awards | 2,068 | ||
Performance stock unit awards | 1,497 | ||
Total equity-based compensation expense | $ | 442,976 | |
The equity-based compensation expense for the incentive unit awards relates to the common stock transferred to Management Holdco, which is subject to the terms of the amended and restated JPE Management Holdings LLC limited liability company agreement (the “Management Holdco LLC Agreement”) and includes approximately $379.0 million of equity-based compensation expense relative to the common stock issued to MIU holders that vested upon the IPO. Also included in the $439.4 million is $22.2 million of equity-based compensation recognized during the first quarter of 2017 related to incentive unit awards, which were modified in conjunction with a March 2017 separation agreement of a former executive officer. The restricted stock unit and performance stock unit awards were granted throughout 2017.
Other Income and Expenses
The following table summarizes our other income and expenses for the periods indicated:
Year Ended December 31, | ||||||||||||
(in thousands) | 2017 | 2016 | Change | |||||||||
Gain (loss) on commodity derivatives | $ | (42,615 | ) | $ | (15,145 | ) | $ | (27,470 | ) | |||
Interest expense, net | (2,861 | ) | (2,629 | ) | (232 | ) | ||||||
Other, net | 358 | — | 358 | |||||||||
Total other income (expense) | $ | (45,118 | ) | $ | (17,774 | ) | $ | (27,344 | ) | |||
Gain (loss) on Commodity Derivatives. Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity prices against our derivative instruments and monthly settlements, if any, of the instruments. To the extent the future commodity price outlook declines between measurement periods, we will generally have noncash mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will generally have noncash mark-to-market losses.
The following table sets forth the components of gain (loss) on commodity derivatives for the periods indicated:
(in thousands) | 2017 | 2016 | |||||
Net cash receipts (payments) on settled derivatives | $ | (2,618 | ) | $ | (2,292 | ) | |
Gain (loss) from the change in fair value of open derivative contracts, net | $ | (39,997 | ) | $ | (12,853 | ) | |
Gain (loss) on commodity derivatives | $ | (42,615 | ) | $ | (15,145 | ) | |
Interest Expense, net. Interest expense relates to interest on our credit facility and amortization of financing costs on this facility, net of capitalized interest. During 2017 and 2016, we recorded $2.9 million and $2.6 million, respectively, of interest expense, net of capitalized interest, related to borrowings on our credit facility. Interest expense includes interest paid on the outstanding balance of the credit facility, commitment fees paid on the unused borrowing base, and amortization of debt issuance costs. The terms of our credit facility require us to pay higher interest rate margins as we utilize a larger percentage of our available commitments. The increased interest expense year over year primarily relates to higher commitment fees paid during 2017, which resulted from a higher borrowing base throughout the year. Our average borrowing base during 2017 was $276.3 million compared to $85.4 million in 2016. Interest expense also increased as a result of higher amortization of debt issuance costs, which related to additional financing costs incurred throughout 2017 related to borrowing base increases. These
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increases were partially offset by a decrease in interest paid, as our average outstanding debt balance during 2017 was $44.8 million, compared to an average outstanding balance of $71.4 million during 2016.
Income tax expense (benefit)
Income tax expense of $57.9 million in 2017 is a result of our change in tax status to a C-corporation, subject to U.S. federal and state income tax, as part of the corporate reorganization in January 2017. Our predecessor was a pass-through entity subject only to the Texas margin tax at a statutory rate of up to 1.0% and was not subject to U.S. federal income tax. Further, our predecessor did not have taxable net income for purposes of calculating 2016 Texas franchise tax.
Upon the change in tax status, we established an $80.7 million provision for deferred income taxes, which was recognized as income tax expense. Subsequent to the change in tax status, we recognized $14.5 million of income tax expense. Our total deferred income taxes were reduced in the fourth quarter by $37.3 million as a result of the favorable impact of the Tax Act.
Liquidity and Capital Resources
Historically, our and our predecessor’s primary sources of liquidity were capital contributions from equity owners, including the IPO, borrowings under our credit facility and cash flows from operations. During the year ended 2018, our primary sources of liquidity were the proceeds from the Senior Notes offering of $488.3 million, cash flows from operations of $427.7 million and borrowings on our credit facility of $165.0 million. Our primary uses of cash have been the development and acquisition of oil, natural gas and NGL properties, the development of water sourcing and disposal infrastructure and a repayment on our credit facility of $320.0 million. As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.
Capital Expenditures
Capital expenditures for oil and gas acquisitions, exploration, development and infrastructure activities are summarized below:
Year Ended December 31, | |||||||||||
(in thousands) | 2018 | 2017 | 2016 | ||||||||
Acquisitions | |||||||||||
Proved properties | $ | 2,401 | $ | — | $ | 7,482 | |||||
Unproved properties (1) | 27,354 | 70,693 | 50,570 | ||||||||
Development costs | 690,848 | 567,555 | 144,786 | ||||||||
Infrastructure costs | 20,162 | 28,299 | 10,611 | ||||||||
Exploration costs | 29 | 31 | 1,673 | ||||||||
Total oil and gas capital expenditures | $ | 740,794 | $ | 666,578 | $ | 215,122 | |||||
(1) | Relates to the acquisition of undeveloped leaseholds and oil and natural gas mineral interest leasing activity, and includes surface acreage purchased during 2018, 2017 and 2016 of $1.0 million, $1.6 million and $3.1 million, respectively. |
For the years ended December 31, 2018, 2017 and 2016, our capital expenditures have been focused on the development of our properties in the southern Delaware Basin. As of December 31, 2018, we had approximately 91,600 gross (79,500 net) acres, including acreage in the Big Tex area that was impaired during 2018, which has not yet expired.
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The following table reflects wells that began producing in the periods indicated:
Year Ended December 31, | ||||||||
2018 | 2017 | 2016 | ||||||
Gross wells | ||||||||
Operated | 45 | 46 | 11 | |||||
Non-operated | 14 | 5 | — | |||||
59 | 51 | 11 | ||||||
Net wells | ||||||||
Operated | 42.4 | 44.3 | 10.9 | |||||
Non-operated | 5.6 | 1.8 | — | |||||
48.0 | 46.1 | 10.9 | ||||||
At December 31, 2018, we were in the process of drilling eleven gross (10.4 net) wells and had eight gross (8.0 net) wells waiting on completion, including four gross (4.0 net) wells that were in process of being completed.
2019 Capital Budget
Our 2019 capital budget for development of oil and gas properties and infrastructure is as follows:
(in millions) | |||||||
Drilling and completion | $ | 580.0 | — | $ | 630.0 | ||
Water infrastructure | 25.0 | — | 35.0 | ||||
Total | $ | 605.0 | — | $ | 665.0 | ||
Our 2019 capital budget excludes potential leasehold and/or surface acreage additions. Based on our 2019 capital budget, we expect to begin production on approximately 52 to 56 gross operated wells and 2.0 net non-operated wells. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.
Because we operate a high percentage of our acreage, capital expenditure amounts and timing are largely discretionary and within our control. We determine our capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if we curtail or reallocate priorities in our drilling program, we may lose a portion of our acreage through lease expirations. Furthermore, we may be required to remove some portion of our reserves currently booked as PUDs if such changes in planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and additional borrowing capacity under our credit facility to execute our planned 2019 capital program. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. If we require additional capital funding for capital expenditures, acquisitions or other reasons, we may seek such capital through borrowings under our credit facility, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our planned drilling program. 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, fluctuates primarily as a result of our realized commodity prices, increases or decreases in our production volumes, changes in receivables and payables related to our operating and development of oil and natural gas activities, changes in our hedging activities and changes in our cash and cash equivalents. At December 31, 2018, we had working capital of $13.2 million, an increase of $126.6 million compared to a working capital deficit of $113.4 million at December 31, 2017. The increase is primarily the result of a net increase in current derivative assets of $121.7 million primarily related to the increase in fair value of our derivative contracts expected to settle over the next 12 months. Additionally, we experienced a $25.7 million increase in our cash balance, which increased primarily due to
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the net proceeds from the Senior Notes offering in May 2018, net of repayment of our then outstanding balance on our credit facility and underwriter and other offering fees, as well as a $12.9 million increase related to increased JIB and other accounts receivable. Partially offsetting our increased current assets, our revenue receivables, net of the related payable, decreased $16.3 million, current liabilities associated with ongoing development activities increased $10.4 million and accrued interest increased $4.6 million primarily due to interest accrued on our Senior Notes.
We may incur working capital deficits in the future due to future increases in current liabilities related to our drilling program or decreases in current assets, including the value of our current commodity derivatives expected to settle in the next 12 months. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents balance totaled approximately $35.2 million and $9.5 million at December 31, 2018 and 2017, respectively. We expect that our cash flows from operating activities, access to capital markets and availability under our Amended and Restated Credit Facility will be sufficient to fund our working capital needs. We expect that our timing of receivables and payables, pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production, our derivative contracts and the implementation of ASU 2016-02 which will add short-term lease liabilities, will be the largest variables affecting our working capital going forward.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
Year Ended December 31, | |||||||||||
(in thousands) | 2018 | 2017 | 2016 | ||||||||
Net cash provided by operating activities | $ | 427,656 | $ | 178,871 | $ | 32,083 | |||||
Net cash used in investing activities | $ | (733,219 | ) | $ | (600,034 | ) | $ | (195,425 | ) | ||
Net cash provided by financing activities | $ | 331,269 | $ | 418,959 | $ | 160,904 | |||||
Operating Activities. Net cash provided by operating activities is primarily affected by production volumes, the price of oil, natural gas and NGLs, and changes in working capital.
The $248.8 million increase in 2018 compared to 2017 primarily resulted from a $314.3 million increase in revenues, which resulted from a 102% increase in volumes and an 8% increase in the average price received per Boe. Increases in operating cash flows were partially offset by $38.4 million of higher cash operating costs primarily due to increased production and workover costs, payments on derivative settlements of $34.1 million and $16.0 million of increased cash G&A costs largely due to additional personnel costs, as well as severance and other nonrecurring expenses.
The $146.8 million increase in 2017 compared to 2016 primarily resulted from a $190.8 million increase in revenues, which resulted from a 202% increase in volumes and a 17% increase in the average price received per Boe. This was partially offset by $22.7 million of higher cash operating costs primarily due to increased production and $11.4 million of increased cash G&A costs largely due to additional personnel.
Investing Activities. Cash flows from investing activities primarily consist of the acquisition, exploration and development of oil and natural gas properties, net of dispositions of oil and natural gas properties.
During 2018, net cash flow used in investing activities included investments in developing our acreage of $706.7 million and leasehold and acquisition costs of $29.7 million. In 2017, net cash used for investing activities included investments in developing our acreage of $523.6 million and leasehold and acquisition costs of $73.5 million. In 2016, net cash used for investing activities included $139.6 million and $54.7 million for the development and acquisition of oil and natural gas properties, respectively.
Financing Activities. Net cash provided by financing activities includes the issuance of equity and debt transactions.
Net cash provided by financing activities during 2018 was primarily due to $488.3 million of net proceeds from the Senior Notes offering, which was partially offset by a net repayment on our credit facility of $155.0 million. Net cash provided by financing activities in 2017 was primarily due to $398.4 million of net proceeds from the sale of our common stock in the IPO and net borrowings of $23.0 million our credit facility. Net cash provided by financing activities in 2016 included $51.5 million of cash provided by contributions from JPE LLC members and $112.0 million of borrowings under our credit facility.
Senior Secured Revolving Credit Facility
At December 31, 2017, the Amended and Restated Credit Facility had a borrowing base of $425.0 million, with $155.0 million outstanding under the credit facility, and $270.0 million in unused borrowing capacity.
In March 2018, we entered into Amendment No. 2 to the Amended and Restated Credit Facility, which extended the maturity date of the Amended and Restated Credit Facility to March 21, 2023 and increased the borrowing base to $540.0
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million. Borrowings under the Amended and Restated Credit Facility under Amendment No. 2 bear interest at a rate elected by the Company that is equal to an adjusted base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the adjusted base rate, and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the elected commitments. We also incur a commitment fee that is between 0.375% to 0.50% per year on the unused portion of the elected commitments, depending on the relative amount of the loan outstanding in relation to the elected commitments.
In April 2018, and in connection with the issuance of the Senior Notes, we voluntarily elected to reduce our elected commitments to $475.0 million, effective as of the closing of the Senior Notes offering.
In June 2018, we entered into Amendment No. 3 to the Amended and Restated Credit Facility which increased the amount we are permitted to hedge up to 85% of forecasted future production for up to 36 months in the future, and up to the greater of 75% of our proved reserves and 60% of our reasonably anticipated forecasted production for 37 to 60 months in the future, provided that no hedges have a term beyond five years.
In August 2018, we entered into Amendment No. 4 to the Amended and Restated Credit Facility which increased the borrowing base to $825.0 million and we increased our elected commitments to $540.0 million.
In November 2018, we entered into Amendment No. 5 to the Amended and Restated Credit Facility which increased the borrowing base to $900.0 million while the elected commitments remained at $540.0 million.
The amount available to be borrowed under our Amended and Restated Credit Facility is subject to a borrowing base that is subject to semiannual borrowing base redeterminations on or around each April 1 and October 1, of each year by the lenders at their sole discretion. Additionally, at our option, we may request up to two additional redeterminations per year, to be effective on or about January 1 and July 1, respectively. The borrowing base depends on, among other things, the volumes of our proved reserves and estimated cash flows from these reserves and our commodity hedge positions as well as any other outstanding debt. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity are outstanding, we could be required to immediately repay a portion of the debt outstanding under our credit agreement.
At December 31, 2018, we were obligated to pay a commitment fee on unused amounts of our Amended and Restated Credit Facility of 0.375% to 0.50% per year on the unused portion of the elected commitments, depending on the relative amount of the loan outstanding in relation to the elected commitments. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
Our Amended and Restated Credit Facility contains restrictive covenants that limit our ability to, among other things:
• | incur additional indebtedness; |
• | incur liens; |
• | make investments; |
• | make loans to others; |
• | merge or consolidate with another entity; |
• | sell assets; |
• | make certain payments; |
• | enter into transactions with affiliates; |
• | hedge interest rates; and |
• | engage in certain other transactions without the prior consent of the lenders. |
The Amended and Restated Credit Facility contains financial covenants, which are measured on a quarterly basis. The covenants, as defined in the Amended and Restated Credit Facility, include requirements to comply with the following financial ratios:
• | a current ratio, which is the ratio of our consolidated current assets (including unused commitments under our credit facility and excluding noncash assets related to ARO and derivatives) to our consolidated current liabilities (excluding the current portion of long-term debt under our credit agreement and noncash liabilities related to ARO obligations and derivatives), as of the last day of each fiscal quarter, of not less than 1.0 to 1.0; and |
• | a leverage ratio, which is the ratio of our consolidated Debt (as defined in our credit agreement) as of the last day of each fiscal quarter, subject to certain exclusions (as described in our credit agreement) to EBITDAX (as defined in our credit agreement) for the last 12 months ending on the last day of that fiscal quarter, of not greater than 4.0 to 1.0. |
As of December 31, 2018, we were in compliance with all financial covenants.
As of the date of this filing, we have $35.0 million outstanding, and $505.0 million available under our elected commitments.
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Contractual Obligations
A summary of our contractual obligations as of December 31, 2018 is provided in the following table:
Payments Due by Period for the Year Ending December 31, | |||||||||||||||||||||||||||
(in thousands) | 2019 | 2020 | 2021 | 2022 | 2023 | Thereafter | Total | ||||||||||||||||||||
Senior notes—principal | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 500,000 | $ | 500,000 | |||||||||||||
Senior notes—interest (1) | 29,375 | 29,375 | 29,375 | 29,375 | 29,375 | 73,438 | 220,313 | ||||||||||||||||||||
Operating leases (2) | 1,547 | 1,539 | 1,553 | 1,559 | 1,589 | 7,378 | 15,165 | ||||||||||||||||||||
Service and purchase contracts (3) | 7,598 | 1,285 | 750 | — | — | — | 9,633 | ||||||||||||||||||||
Rig contracts (4) | 36,805 | 31,897 | — | — | — | — | 68,702 | ||||||||||||||||||||
Frac fleet contracts (5) | 63,135 | — | — | — | — | — | 63,135 | ||||||||||||||||||||
Total | $ | 138,460 | $ | 64,096 | $ | 31,678 | $ | 30,934 | $ | 30,964 | $ | 580,816 | $ | 876,948 | |||||||||||||
(1) | Interest represents the scheduled cash payments on the Senior Notes. |
(2) | Primarily relates to the lease of our corporate office. |
(3) | Primarily relates to a coiled tubing service agreement and a retail power purchase agreement. |
(4) | Relates to seven drilling rigs under contract as of December 31, 2018. If we were to terminate these contracts at December 31, 2018, we would be required to pay early termination penalties of approximately $37.7 million. |
In January 2019, two of the seven rigs were released, which resulted in early termination penalties of $0.3 million. Of these two rigs that were released, one was on a well-to-well contract, while the other was contractually obligated through August 2019. Included in the contractual obligations table above is $0.3 million that represents the obligations for these two rigs to finish the wells they were drilling as of December 31, 2018.
(5) | Relates to two frac fleets under contract at December 31, 2018. In the first quarter of 2019, the Company terminated one of the frac fleet contracts. As a result, the Company paid a termination fee of $3.2 million in 2019. Excluding the canceled contract, our contractual obligation for the remaining frac fleet contract is $32.4 million. The remaining frac fleet under contract at does not contain any early termination fees. |
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated and combined financial statements, which have been prepared in accordance with GAAP. The preparation of our 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 consolidated and combined financial statements. Our more significant accounting policies and estimates include: impairment of oil and natural gas properties, oil, natural gas and NGL reserve quantities and standardized measure of discounted future net cash flows, derivative instruments and income taxes. We provide an expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated and combined financial statements.
A complete list of our significant accounting policies is described in Note 2, Significant Accounting Policies and Related Matters, to our consolidated and combined financial statements for the year ended December 31, 2018.
Impairment of Oil and Natural Gas Properties
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of oil and natural gas properties and compare these undiscounted 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 will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate.
Unproved properties are periodically assessed for impairment on a property-by-property basis. We evaluate significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage and record impairment expense for any decline in value or expectation that the unproved property will expire unused.
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Oil, Natural Gas and NGL Reserve Quantities and Standardized Measure of Discounted Future Net Cash Flows
We engage Ryder Scott, our independent petroleum engineer, to prepare our total estimated proved reserves. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves internally each quarter and Ryder Scott estimates our proved reserves annually. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The estimates of proved reserves are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, which are considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, are also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment.
It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenue, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
It should not be assumed that the standardized measure included in this report as of December 31, 2018 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the 2018 standardized measure on the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See “Item 1A. Risk Factors” and “Item 1 and 2. Business and Properties” for additional information regarding estimates of proved reserves.
Derivative Instruments
We utilize commodity derivative instruments to manage our exposure to commodity price volatility. All our commodity derivative instruments are utilized to manage price risk attributable to our expected production, and we do not enter into such instruments for speculative trading purposes. We do not designate any derivative instruments as cash flow hedges for financial reporting purposes. We record all derivative instruments on the balance sheet as either assets or liabilities measured at estimated fair value. We compute the fair value of our derivatives by computing the discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves as of the date of the estimate. We compare these prices to the price parameters contained in our hedge contracts to determine estimated future cash inflows or outflows. The fair value estimates are adjusted relative to non-performance risk as appropriate. We record gains and losses from the change in fair value of derivative instruments in current earnings as they occur. We do not currently utilize any derivative instruments to manage exposure to variable interest rates, but may do so in the future.
Income Taxes
We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our consolidated and combined financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance if we believe it is more likely than not such deferred tax assets will not be realized. Additionally, our federal and state income tax returns are generally not filed before the consolidated and combined financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period, as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations.
The calculation of deferred tax assets and liabilities involves uncertainties in the application of complex tax laws and regulations. We recognize the financial statement effects of a tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination.
Recently Issued Accounting Pronouncements
Please refer to Note 2, Significant Accounting Policies and Related Matters – Recent Accounting Pronouncements, to the consolidated and combined financial statements included elsewhere in this report for a discussion of recent accounting pronouncements and their anticipated effect on our business.
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Off-Balance Sheet Arrangements
We had no material off-balance sheet arrangements as of December 31, 2018. Please read Note 10, Commitments and Contingencies, included in notes to the consolidated and combined financial statements included elsewhere in this report, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.
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ITEM 7A. | QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK |
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, natural gas and NGL 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 major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on numerous factors beyond our control, some of which are discussed in “Item 1A. Risk Factors—Risks Related to Our Business—Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.”
The following table shows how hypothetical changes in the realized prices we receive for our commodity sales would have impacted revenue for the year ended December 31, 2018:
Sensitivity Analysis | ||||||||||||
(in thousands) | Revenue | % of Total | Change in Realized Prices | Impact on Revenue | ||||||||
Oil | $ | 539,802 | 93% | + / - 10% per barrel | + / - | $ | 53,980 | |||||
Natural gas | 9,136 | 1% | + / - 10% per Mcf | + / - | $ | 914 | ||||||
NGL | 31,956 | 6% | + / - 10% per barrel | + / - | $ | 3,196 | ||||||
Total (1) | $ | 580,894 | 100% | |||||||||
(1) | Our oil, natural gas and NGL revenues do not include the effects of derivatives instruments. |
To reduce our exposure to changes in the prices of commodities, we have entered into, and may in the future enter into, commodity derivative instruments for a portion of our oil production for the years 2019 and 2020. The agreements entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil production over a fixed period of time. Our commodity derivative instruments are recorded at fair value and thus changes to the future commodity prices will have an impact on net income. During the year ended December 31, 2018, we recorded a gain on derivatives of $119.3 million, compared to a loss of $42.6 million for the same period from 2017.
The fair value of our derivative instruments is determined based on valuation models. We did not change our valuation method for our derivative instruments during the year ended December 31, 2018.The following table reconciles the changes that occurred in the fair values of our derivative instruments from December 31, 2017 to December 31, 2018:
Commodity Derivative Instruments | |||
(in thousands) | Net Assets (Liabilities) | ||
Fair value of open contracts at December 31, 2017 | $ | (52,851 | ) |
Gain (loss) on commodity derivatives | 119,338 | ||
Net cash payments on settled derivatives | 34,134 | ||
Fair value of open contracts at December 31, 2018 | $ | 100,621 | |
The following table sets forth the hypothetical impact on the fair value of our net oil derivative asset of $100.6 million as of December 31, 2018, using an average increase or decrease of 10% to the commodity prices:
Change to Prices | ||||||||
(in thousands) | 10% Increase | 10% Decrease | ||||||
Increase (decrease) to net oil derivative asset as of December 31, 2018 | $ | (46,323 | ) | $ | 46,323 | |||
Our commodity derivative instruments allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. These instruments provide only partial price protection against declines in oil prices and may partially limit our potential gains from future increases in prices. In the future, we may use commodity derivatives to hedge a portion of our natural gas or NGL production.
See Note 3, Derivative Instruments, and Note 9, Fair Value Measurements, to our consolidated and combined financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.
62
Credit Risk
Our 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 have investment grade ratings, and are all lenders under our Amended and Restated Credit Facility.
In addition to credit risk from out derivative counterparties, our remaining principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas receivables with a significant customer. The inability or failure of our significant customer to meet its obligation to us or its insolvency or liquidation may adversely affect our financial results. 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 drill. We have little ability to control whether these entities will participate in our wells, but have not had historical issues collecting receivables.
Interest Rate Risk
We are exposed to market risk related to changes in interest rates, which affects the amount of interest we pay on certain of our borrowings and the amount of interest we earn on our short-term investments.
As of December 31, 2018, we had no significant investments other than cash and cash equivalents; therefore, we were not exposed to material interest rate risk on investments.
Prior to paying down the outstanding balance on our Amended and Restated Credit Facility to $0 in May 2018, we were exposed to changes in interest rates as a result of our Amended and Restated Credit Facility. As of December 31, 2018, we had $500.0 million aggregate principal of fixed-rate long-term debt outstanding with a fixed interest rate of 5.875%. Although near term changes in interest rates may impact the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss. Therefore, we have no exposure to fluctuating interest rates as of December 31, 2018.
We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness. For additional information regarding our debt instruments, refer to Note 4, Debt, to our consolidated and combined financial statements included elsewhere in this report.
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
The information required by this Item is included in this Annual Report as set forth in the “Index to Financial Statements” on page F-1 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
In accordance with Rules 13a-15(b) of the Exchange Act, our management, including our principal executive officer and principal financial officer, evaluated 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, 2018. 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, 2018 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There were no changes in our 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 fourth quarter of 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
63
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. 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. 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 policies or procedures may deteriorate.
As of December 31, 2018, our management assessed the effectiveness of our 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 this assessment and those criteria, management determined that we maintained effective internal control over financial reporting as of December 31, 2018.
Attestation Report of the Registered Public Accounting Firm
The effectiveness of our internal control over financial reporting as of December 31, 2018 has been audited by KPMG LLP, an independent registered public accounting firm which also audited our consolidated and combined financial statements as of and for the year ended December 31, 2018, as stated in their report which appears on page F-3 in this report.
ITEM 9B. | OTHER INFORMATION |
None.
64
PART III
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Information as to Item 10 is incorporated by reference from the information in our definitive proxy statement for the 2019 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.
Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors and employees, which is available on our website (www.jaggedpeakenergy.com) under “Corporate Governance” within the “Investor Relations” section. We intend to satisfy the disclosure requirement under Item 406(d) of Regulation S‑K regarding an amendment to, or waiver from, a provision of our Code of Business Conduct and Ethics by posting such information on our website at the address and the location specified above.
ITEM 11. | EXECUTIVE COMPENSATION |
Information as to Item 11 is incorporated by reference from the information in our definitive proxy statement for the 2019 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Information as to Item 12 is incorporated by reference from the information in our definitive proxy statement for the 2019 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Information as to Item 13 is incorporated by reference from the information in our definitive proxy statement for the 2019 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
Information as to Item 14 is incorporated by reference from the information in our definitive proxy statement for the 2019 Annual Meeting of Stockholders, which we will file pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2018.
65
PART IV
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
The consolidated and combined financial statements are listed on the Index to Financial Statements to this report beginning on page F-1.
(a)(3) Exhibits.
_______________________________________________________________________________
Exhibit Number | Description of Exhibit | ||
2.1†† | |||
3.1 | |||
3.2 | |||
4.1 | |||
4.2 | |||
4.3 | |||
4.4 | |||
4.5 | |||
4.6 | |||
10.1 | |||
10.2.1 | |||
10.2.2 | |||
10.2.3 | |||
10.2.4 | |||
66
10.2.5 | |||
10.2.6 | |||
10.2.7 | |||
10.3† | |||
10.4† | |||
10.5† | |||
10.6† | |||
10.7† | |||
10.8† | |||
10.9† | |||
10.10† | |||
10.11† | |||
10.12† | |||
10.13† | |||
10.14† | |||
10.15† | |||
10.16† | |||
10.17† | |||
*21.1 | |||
*23.1 | |||
*23.2 | |||
*31.1 | |||
*31.2 | |||
**32.1 | |||
**32.2 | |||
67
*99.1 | |||
*101.INS | XBRL Instance Document | ||
*101.SCH | XBRL Schema Document | ||
*101.CAL | XBRL Calculation Linkbase Document | ||
*101.LAB | XBRL Label Linkbase Document | ||
*101.PRE | XBRL Presentation Linkbase Document | ||
*101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | ||
† | Compensatory plan or arrangement. | ||
†† | Schedules and similar attachments to the Master Reorganization Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant will furnish a supplemental copy of any omitted schedule or similar attachment to the SEC upon request. | ||
* | Filed herewith. | ||
** | Furnished herewith. | ||
ITEM 16. | FORM 10-K SUMMARY |
None.
68
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
JAGGED PEAK ENERGY INC. | ||||
Date: | February 28, 2019 | By: | /s/ JAMES J. KLECKNER | |
Name: | James J. Kleckner | |||
Title: | Chief Executive Officer and President | |||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated.
Signature | Title | Date | |||
/s/ JAMES J. KLECKNER | Chief Executive Officer and President | February 28, 2019 | |||
James J. Kleckner | (Principal Executive Officer) | ||||
/s/ ROBERT W. HOWARD | Executive Vice President, Chief Financial Officer | February 28, 2019 | |||
Robert W. Howard | (Principal Financial Officer) | ||||
/s/ SHONN D. STAHLECKER | Controller | February 28, 2019 | |||
Shonn D. Stahlecker | |||||
/s/ CHARLES D. DAVIDSON | Chairman | February 28, 2019 | |||
Charles D. Davidson | |||||
/s/ ROGER L. JARVIS | Director | February 28, 2019 | |||
Roger L. Jarvis | |||||
/s/ MICHAEL C. LINN | Director | February 28, 2019 | |||
Michael C. Linn | |||||
/s/ JOHN R. SULT | Director | February 28, 2019 | |||
John R. Sult | |||||
/s/ S. WIL VANLOH, JR. | Director | February 28, 2019 | |||
S. Wil VanLoh, Jr. | |||||
/s/ DHEERAJ VERMA | Director | February 28, 2019 | |||
Dheeraj Verma | |||||
/s/ BLAKE A. WEBSTER | Director | February 28, 2019 | |||
Blake A. Webster | |||||
69
INDEX TO FINANCIAL STATEMENTS
Page | |
Notes to Consolidated Financial Statements | |
Supplemental information to consolidated financial statements | |
F-1
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Jagged Peak Energy Inc.:
Opinion on the Consolidated and Combined Financial Statements
We have audited the accompanying consolidated and combined balance sheets of Jagged Peak Energy Inc. and subsidiaries (the Company) as of December 31, 2018 and 2017, the related consolidated and combined statements of operations, changes in equity, and cash flows for each of the years in the three‑year period ended December 31, 2018, and the related notes (collectively, the consolidated and combined financial statements). In our opinion, the consolidated and combined financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.
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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated and combined 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 consolidated and combined 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 consolidated and combined 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 regarding the amounts and disclosures in the consolidated and combined 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 consolidated and combined financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP | |
We have served as the Company’s auditor since 2014. | |
Denver, Colorado | |
February 28, 2019 | |
F-2
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Jagged Peak Energy Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Jagged Peak Energy Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated and combined balance sheets of the Company as of December 31, 2018 and 2017, the related consolidated and combined statements of operations, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes (collectively, the consolidated and combined financial statements), and our report dated February 28, 2019 expressed an unqualified opinion on those consolidated and combined 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 of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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/ KPMG LLP | |
Denver, Colorado | |
February 28, 2019 | |
F-3
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED BALANCE SHEETS
(in thousands, except share data)
December 31, | |||||||
2018 | 2017 | ||||||
ASSETS | |||||||
CURRENT ASSETS | |||||||
Cash and cash equivalents | $ | 35,229 | $ | 9,523 | |||
Accounts receivable | 61,186 | 50,734 | |||||
Derivative instruments | 103,092 | — | |||||
Other current assets | 1,627 | 806 | |||||
Total current assets | 201,134 | 61,063 | |||||
PROPERTY AND EQUIPMENT | |||||||
Oil and natural gas properties, successful efforts method | 1,905,498 | 1,195,831 | |||||
Accumulated depletion | (386,883 | ) | (166,592 | ) | |||
Total oil and gas properties, net | 1,518,615 | 1,029,239 | |||||
Other property and equipment, net | 11,670 | 9,708 | |||||
Total property and equipment, net | 1,530,285 | 1,038,947 | |||||
OTHER NONCURRENT ASSETS | |||||||
Unamortized debt issuance costs | 3,704 | 3,273 | |||||
Derivative instruments | 31,899 | 26 | |||||
Other assets | 119 | 119 | |||||
Total noncurrent assets | 35,722 | 3,418 | |||||
TOTAL ASSETS | $ | 1,767,141 | $ | 1,103,428 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
CURRENT LIABILITIES | |||||||
Accounts payable | $ | 34,762 | $ | 382 | |||
Accrued liabilities | 130,012 | 132,311 | |||||
Derivative instruments | 23,208 | 41,782 | |||||
Total current liabilities | 187,982 | 174,475 | |||||
LONG-TERM LIABILITIES | |||||||
Long-term debt | 489,239 | 155,000 | |||||
Derivative instruments | 11,162 | 11,095 | |||||
Asset retirement obligations | 1,946 | 811 | |||||
Deferred income taxes | 124,418 | 57,943 | |||||
Other long-term liabilities | 4,444 | 4,759 | |||||
Total long-term liabilities | 631,209 | 229,608 | |||||
Commitments and contingencies | |||||||
STOCKHOLDERS’ EQUITY | |||||||
Preferred stock, $0.01 par value; 50,000,000 shares authorized, none issued | — | — | |||||
Common stock, $0.01 par value; 1,000,000,000 shares authorized, 213,187,780 shares issued at December 31, 2018; 212,930,655 shares issued at December 31, 2017 | 2,132 | 2,129 | |||||
Additional paid-in capital | 856,818 | 773,674 | |||||
Retained Earnings (Accumulated deficit) | 89,000 | (76,458 | ) | ||||
Total stockholders' equity | 947,950 | 699,345 | |||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 1,767,141 | $ | 1,103,428 | |||
The accompanying Notes are an integral part of these consolidated and combined financial statements.
F-4
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
Year Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
REVENUES | |||||||||||
Oil sales | $ | 539,802 | $ | 241,788 | $ | 70,078 | |||||
Natural gas sales | 9,136 | 9,065 | 2,213 | ||||||||
NGL sales | 31,956 | 15,571 | 3,068 | ||||||||
Other operating revenues | 750 | 888 | 1,163 | ||||||||
Total revenues | 581,644 | 267,312 | 76,522 | ||||||||
OPERATING EXPENSES | |||||||||||
Lease operating expenses | 42,406 | 17,874 | 7,505 | ||||||||
Gathering and processing expenses | — | 4,424 | 1,046 | ||||||||
Production and ad valorem taxes | 34,642 | 16,120 | 4,345 | ||||||||
Exploration | 29 | 31 | 2,484 | ||||||||
Depletion, depreciation, amortization and accretion | 222,355 | 111,049 | 40,417 | ||||||||
Impairment of unproved oil and natural gas properties | 28,198 | 373 | 372 | ||||||||
General and administrative expenses (including equity-based compensation of $83,346, $442,976 and $0 in 2018, 2017 and 2016, respectively) | 122,472 | 466,067 | 11,690 | ||||||||
Other operating expenses | 63 | 247 | 649 | ||||||||
Total operating expenses | 450,165 | 616,185 | 68,508 | ||||||||
INCOME (LOSS) FROM OPERATIONS | 131,479 | (348,873 | ) | 8,014 | |||||||
OTHER INCOME (EXPENSE) | |||||||||||
Gain (loss) on commodity derivatives | 119,338 | (42,615 | ) | (15,145 | ) | ||||||
Interest expense, net | (25,152 | ) | (2,861 | ) | (2,629 | ) | |||||
Gain on sale of oil and natural gas properties | 6,225 | — | — | ||||||||
Other, net | 43 | 358 | — | ||||||||
Total other income (expense) | 100,454 | (45,118 | ) | (17,774 | ) | ||||||
INCOME (LOSS) BEFORE INCOME TAX | 231,933 | (393,991 | ) | (9,760 | ) | ||||||
Income tax expense (benefit) | 66,475 | 57,943 | — | ||||||||
NET INCOME (LOSS) | 165,458 | (451,934 | ) | (9,760 | ) | ||||||
Less: Net loss attributable to Jagged Peak Energy LLC (predecessor) | — | (375,476 | ) | (9,760 | ) | ||||||
NET INCOME (LOSS) ATTRIBUTABLE TO JAGGED PEAK ENERGY INC. STOCKHOLDERS | $ | 165,458 | $ | (76,458 | ) | $ | — | ||||
Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders per common share: | |||||||||||
Basic | $ | 0.78 | $ | (0.36 | ) | ||||||
Diluted | $ | 0.78 | $ | (0.36 | ) | ||||||
Weighted average common shares outstanding: | |||||||||||
Basic | 213,128 | 212,932 | |||||||||
Diluted | 213,203 | 212,932 | |||||||||
The accompanying Notes are an integral part of these consolidated and combined financial statements.
F-5
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN EQUITY
(in thousands)
Members' Equity | Common Stock | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | Total Stockholders' Equity / Members' Equity | ||||||||||||||||||
Shares | Amount | |||||||||||||||||||||
BALANCE AT DECEMBER 31, 2015 | $ | 294,556 | — | $ | — | $ | — | $ | (10,226 | ) | $ | 284,330 | ||||||||||
Capital contributions | 51,542 | — | — | — | — | 51,542 | ||||||||||||||||
Net income (loss) | — | — | — | — | (9,760 | ) | (9,760 | ) | ||||||||||||||
BALANCE AT DECEMBER 31, 2016 | 346,098 | — | — | — | (19,986 | ) | 326,112 | |||||||||||||||
Deemed contribution - incentive unit compensation | 364,314 | — | — | — | — | 364,314 | ||||||||||||||||
Net income (loss) for the period prior to the corporate reorganization | — | — | — | — | (375,476 | ) | (375,476 | ) | ||||||||||||||
Balance prior to corporate reorganization and initial public offering | 710,412 | — | — | — | (395,462 | ) | 314,950 | |||||||||||||||
Issuance of common stock in corporate reorganization | (710,412 | ) | 184,605 | 1,846 | 313,104 | 395,462 | — | |||||||||||||||
Issuance of common stock in initial public offering, net of offering costs | — | 28,333 | 283 | 396,708 | — | 396,991 | ||||||||||||||||
Equity-based compensation | — | — | — | 63,950 | — | 63,950 | ||||||||||||||||
Vested stock exchanged for tax withholding | — | (7 | ) | — | (88 | ) | — | (88 | ) | |||||||||||||
Net income (loss) | — | — | — | — | (76,458 | ) | (76,458 | ) | ||||||||||||||
BALANCE AT DECEMBER 31, 2017 | — | 212,931 | 2,129 | 773,674 | (76,458 | ) | 699,345 | |||||||||||||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes | — | 257 | 3 | (202 | ) | — | (199 | ) | ||||||||||||||
Equity-based compensation | — | — | — | 83,346 | — | 83,346 | ||||||||||||||||
Net income (loss) | — | — | — | — | 165,458 | 165,458 | ||||||||||||||||
BALANCE AT DECEMBER 31, 2018 | $ | — | 213,188 | $ | 2,132 | $ | 856,818 | $ | 89,000 | $ | 947,950 | |||||||||||
The accompanying Notes are an integral part of these consolidated and combined financial statements.
F-6
JAGGED PEAK ENERGY INC.
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||
Net income (loss) | $ | 165,458 | $ | (451,934 | ) | $ | (9,760 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
Depletion, depreciation, amortization and accretion expense | 222,355 | 111,049 | 40,417 | ||||||||
Management incentive unit advance | — | — | (14,712 | ) | |||||||
Impairment of unproved oil and natural gas properties | 28,198 | 373 | 372 | ||||||||
Exploratory dry hole costs | — | — | 1,192 | ||||||||
Amortization of debt issuance costs | 2,340 | 606 | 260 | ||||||||
Deferred income taxes | 66,475 | 57,943 | — | ||||||||
Equity-based compensation | 83,346 | 442,976 | — | ||||||||
(Gain) loss on commodity derivatives | (119,338 | ) | 42,615 | 15,145 | |||||||
Net cash receipts (payments) on settled derivatives | (34,134 | ) | (2,618 | ) | (2,292 | ) | |||||
(Gain) on sale of oil and natural gas properties | (6,225 | ) | — | — | |||||||
Other | (314 | ) | 882 | (160 | ) | ||||||
Change in operating assets and liabilities: | |||||||||||
Accounts receivable and other current assets | (11,273 | ) | (40,442 | ) | (2,588 | ) | |||||
Other assets | — | (3 | ) | 11 | |||||||
Accounts payable and accrued liabilities | 30,768 | 17,424 | 4,198 | ||||||||
Net cash provided by operating activities | 427,656 | 178,871 | 32,083 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||
Leasehold and acquisition costs | (29,671 | ) | (73,492 | ) | (54,681 | ) | |||||
Development of oil and natural gas properties | (706,689 | ) | (523,559 | ) | (139,571 | ) | |||||
Other capital expenditures | (5,236 | ) | (2,983 | ) | (1,969 | ) | |||||
Proceeds from sale of oil and natural gas properties | 8,377 | — | 796 | ||||||||
Net cash used in investing activities | (733,219 | ) | (600,034 | ) | (195,425 | ) | |||||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||
Proceeds from senior notes | 500,000 | — | — | ||||||||
Proceeds from credit facility | 165,000 | 165,000 | 112,000 | ||||||||
Repayment of credit facility | (320,000 | ) | (142,000 | ) | — | ||||||
Debt issuance costs | (13,531 | ) | (2,362 | ) | (1,220 | ) | |||||
Proceeds from issuance of common stock in initial public offering, net of underwriting fees | — | 401,625 | — | ||||||||
Proceeds from JPE LLC members | — | — | 51,542 | ||||||||
Costs relating to initial public offering | — | (3,216 | ) | (1,418 | ) | ||||||
Employee tax withholding for settlement of equity compensation awards | (200 | ) | (88 | ) | — | ||||||
Net cash provided by financing activities | 331,269 | 418,959 | 160,904 | ||||||||
NET CHANGE IN CASH AND CASH EQUIVALENTS | 25,706 | (2,204 | ) | (2,438 | ) | ||||||
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 9,523 | 11,727 | 14,165 | ||||||||
CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 35,229 | $ | 9,523 | $ | 11,727 | |||||
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION | |||||||||||
Interest paid, net of capitalized interest | $ | 23,157 | $ | 2,021 | $ | 2,190 | |||||
Cash paid for income taxes | — | — | — | ||||||||
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES | |||||||||||
Accrued capital expenditures | $ | 106,674 | $ | 105,401 | $ | 36,581 | |||||
Asset retirement obligations | 1,035 | 600 | (100 | ) | |||||||
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES | |||||||||||
Accrued offering costs | $ | — | $ | — | $ | 1,224 | |||||
The accompanying Notes are an integral part of these consolidated and combined financial statements.
F-7
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Note 1—Organization, Operations and Basis of Presentation
Organization and Operations
Jagged Peak Energy Inc. (either individually or together with its subsidiaries, as the context requires, “Jagged Peak” or the “Company”) is an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves in the southern Delaware Basin; the Delaware Basin is a sub-basin of the Permian Basin of West Texas. The Company’s acreage is located on large, contiguous blocks in the adjacent counties of Winkler, Ward, Reeves and Pecos, with significant oil-in-place within multiple stacked hydrocarbon-bearing formations.
Corporate Reorganization and Initial Public Offering
Jagged Peak is a Delaware corporation formed in September 2016, as a wholly owned subsidiary of Jagged Peak Energy LLC (“JPE LLC”), a Delaware limited liability company formed in April 2013. JPE LLC was formed by an affiliate of Quantum Energy Partners (“Quantum”) and former members of Jagged Peak’s management team. Jagged Peak was formed to become the holding company of JPE LLC in connection with Jagged Peak’s initial public offering (the “IPO”).
Immediately prior to the IPO, all capital interests and management incentive units (“MIUs”) in JPE LLC were converted into a single class of units which were then converted into common stock. Certain members of management and employees contributed a portion of common stock received upon the conversion of unvested or unallocated MIUs to JPE Management Holdings LLC, a limited liability company formed in connection with the IPO for the purpose of holding the unvested or unallocated common stock. Also immediately prior to the IPO, a corporate reorganization (the “corporate reorganization”) took place whereby Jagged Peak, initially formed as a subsidiary of JPE LLC, formed JPE Merger Sub LLC as a subsidiary. JPE LLC merged into JPE Merger Sub LLC, with JPE LLC as the surviving entity. As a result, JPE LLC became a wholly owned subsidiary of Jagged Peak. Prior to the corporate reorganization, Quantum owned 98.6% of the membership interests of JPE LLC. Immediately following the corporate reorganization and IPO, Quantum owned 68.7% of the outstanding common stock of Jagged Peak. As all power and authority to control the core functions of Jagged Peak and JPE LLC were, and continue to be, controlled by Quantum, the corporate reorganization was treated as a reorganization of entities under common control and the results of JPE LLC have been consolidated and combined for all periods.
On January 27, 2017, the Company initiated its IPO of common stock to the public, and its common stock began trading on the New York Stock Exchange. During the IPO, the Company and selling stockholders sold 31,599,334 shares at $15.00 per share, raising $474.0 million of gross proceeds. Of the 31,599,334 shares issued to the public, 28,333,334 shares were sold by the Company, and 3,266,000 shares were sold by the selling stockholders. The gross proceeds of the IPO to the Company, based on the public offering price of $15.00 per share, were approximately $425.0 million, which resulted in net proceeds to the Company of $397.0 million after deducting offering expenses and underwriting discounts and commissions of approximately $28.0 million. The Company did not receive any proceeds from the sale of the shares by the selling stockholders. A portion of the proceeds from the IPO were used to repay the entire outstanding balance on JPE LLC’s credit facility of $142.0 million as of the date the IPO proceeds were received. The remainder of the net proceeds from the IPO were used to fund a portion of the Company’s 2017 capital expenditures program, and for other general corporate purposes.
Basis of Presentation
The accompanying consolidated and combined financial statements include the accounts of Jagged Peak and JPE LLC, and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These consolidated and combined financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany and intra-company balances and transactions have been eliminated. The consolidated and combined financial statements for periods prior to January 27, 2017 reflect the historical results of JPE LLC, other than the equity-based compensation expense and deferred tax expense, as further described in Notes 5 and 7, respectively.
Certain reclassifications have been made to prior period amounts to conform to the current presentation.
Industry Segment and Geographic Information
The Company evaluated how it is organized and managed, and has identified one operating segment—the production and development of oil and natural gas. All of the Company’s assets are located in the United States, and all of its revenues are attributable to customers located in the United States.
F-8
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Note 2—Significant Accounting Policies and Related Matters
Use of Estimates
In the course of preparing the consolidated and combined financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Estimates made in preparing these consolidated and combined financial statements include, among other things, (1) estimates of oil and natural gas reserve quantities, which impact depreciation, depletion and amortization and impairment of proved oil and natural gas properties, (2) accrued operating and capital costs, (3) estimates of timing and costs used in calculating asset retirement obligations, (4) estimates of the fair value of equity-based compensation, (5) assumptions and estimates used in the calculation of fair value, (6) estimates of deferred income taxes and (7) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in these estimates and assumptions could have a significant impact on results in future periods.
Fair Value Measurements
The Company’s financial instruments consist of derivative instruments, cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, the senior secured revolving credit facility and the Company’s5.875% senior unsecured notes. The Company’s derivative instruments are measured at fair value on a recurring basis, while the senior secured revolving credit facility and the senior unsecured notes are not recorded at fair value on the consolidated and combined balance sheets. The carrying amounts of the Company’s other financial instruments are considered to be representative of their fair values due to the nature of and short-term maturities of those instruments.
The Company also applies fair value accounting guidance to measure nonfinancial assets and liabilities, such as the acquisition or impairment of oil and gas properties and the inception value of asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. See Note 9, Fair Value Measurements, for further discussion.
Cash and Cash Equivalents
The Company considers all liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company’s cash balances held at commercial banks may at times exceed the Federal Deposit Insurance Corporation limit. The Company has not experienced any credit losses to date.
Revenue Recognition
On January 1, 2018, the Company adopted Accounting Standards Codification Topic 606, Revenue from Contracts with Customers, (“ASC 606”) using the modified retrospective approach, which only applied to contracts that were in effect as of the date of adoption. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and did not impact the Company’s previously reported results of operations, nor its ongoing consolidated and combined balance sheets, statements of cash flow or statements of changes in equity.
Under ASC 606, oil, natural gas and NGL sales revenues are recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. All of the Company’s oil, natural gas and NGL sales are made under contracts with customers. The performance obligations for the Company’s contracts with customers are satisfied at a point in time through the delivery of oil and natural gas to its customers. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. The Company typically receives payment for oil, natural gas and NGL sales within 30 days of the month of delivery. The Company’s contracts for oil, natural gas and NGL sales are standard industry contracts that include variable consideration based on the monthly index price and adjustments that may include counterparty-specific provisions related to volumes, price differentials, discounts and other adjustments and deductions.
Under the Company’s current gas processing contracts, it delivers natural gas to a purchaser at or near the wellhead. For these contracts, the Company has concluded the purchaser is the customer, and as such, the Company recognizes natural gas and NGL revenues based on the net amount of proceeds it receives from the purchaser.
F-9
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
The Company’s product types are as follows:
Oil Sales. Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser at or near the wellhead, and collects a contractually agreed upon index price, net of pricing and gathering and transportation differentials. The Company transfers control of the product to the purchaser at or near the wellhead and recognizes revenue based on the net price received.
Natural Gas and NGL Sales. Under the Company’s natural gas sales contracts, the Company delivers and transfers control of natural gas to the purchaser at delivery points at or near the wellhead. The purchaser gathers and processes the natural gas and sells the resulting residue gas and NGLs. The Company receives its contractual portion of the proceeds for the sale of the residue gas and NGLs at an agreed upon index price, net of pricing differentials and applicable selling expenses including gathering, processing and fractionation costs. The Company recognizes revenue at the net price when control transfers to the purchaser.
The Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which the variable consideration is allocated entirely to a wholly unsatisfied performance obligation, as allowed under ASC 606. Under the Company’s oil, natural gas and NGL sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Disaggregation of Revenue
The Company’s oil, natural gas and NGL sales revenues represent substantially all of its revenues, and are derived from the sale of oil, natural gas and NGL production within the Permian Basin. The Company believes the disaggregation of revenues into the three product types of oil sales, natural gas sales and NGL sales, as seen on the consolidated and combined statements of operations, is an appropriate level of detail for its primary activity.
Accounts Receivable
The Company’s accounts receivable are generated primarily from the sale of oil, natural gas and NGLs to various customers, from the billing of working interest partners for work on wells the Company operates, and from derivative settlements receivable shortly after the balance sheet date. The Company monitors the financial strength of its customers, partners, and counterparties. At December 31, 2018 and 2017, the Company did not have any reserves for doubtful accounts and did not incur any bad debt expense in any period presented.
At December 31, 2018 and 2017, accounts receivable was comprised of the following:
December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Oil and gas sales | $ | 40,465 | $ | 42,869 | |||
Joint interest | 14,058 | 7,860 | |||||
Other | 6,663 | 5 | |||||
Total accounts receivable | $ | 61,186 | $ | 50,734 | |||
Significant Customers
The Company’s share of oil, natural gas and NGL production relates to its operations in the southern Delaware Basin and is sold to a relatively small number of customers. The loss of any single purchaser could materially and adversely affect the Company’s revenues in the short-term; however, the Company believes that the loss of any of its purchasers would not have a long-term material adverse effect on its financial condition and results of operations, as oil and natural gas are fungible products with well-established markets and numerous purchasers.
The following purchasers individually accounted for 10% or more of the Company’s total production revenue during the years ended December 31, 2018, 2017 and 2016:
Year Ended December 31, | ||||||||
2018 | 2017 | 2016 | ||||||
Trafigura Trading, LLC | 85 | % | 78 | % | 57 | % | ||
Sunoco Partners Marketing | 2 | % | 11 | % | 31 | % | ||
F-10
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Other Current Assets
The components of other current assets are shown below:
December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Prepaid expenses | $ | 1,626 | $ | 607 | |||
Other current assets | 1 | 199 | |||||
Total other current assets | $ | 1,627 | $ | 806 | |||
Derivative Instruments
The Company uses commodity derivative instruments to manage its exposure to oil and natural gas price volatility. All of the commodity derivative instruments are utilized to manage price risk attributable to the Company’s expected oil production, and the Company does not enter into such instruments for speculative trading purposes. The Company does not designate any derivative instruments as hedges for accounting purposes. The Company records all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. The Company records gains and losses from the change in fair value of derivative instruments in current earnings as they occur. The Company currently does not utilize any derivative instruments to manage exposure to variable interest rates, but may do so in the future.
The cash flow impact of the Company’s derivative activities is reflected as cash flows from operating activities. See Note 3, Derivative Instruments, for a more detailed discussion of the Company’s derivative activities.
Oil and Natural Gas Properties
A summary of the Company’s oil and natural gas properties, net is as follows:
December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Proved oil and natural gas properties | $ | 1,746,766 | $ | 1,012,321 | |||
Unproved oil and natural gas properties | 158,732 | 183,510 | |||||
Total oil and natural gas properties | 1,905,498 | 1,195,831 | |||||
Less: Accumulated depletion | (386,883 | ) | (166,592 | ) | |||
Total oil and natural gas properties, net | $ | 1,518,615 | $ | 1,029,239 | |||
Proved Oil and Natural Gas Properties
The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Under this method, all costs incurred related to the acquisition of oil and natural gas properties and the costs of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when the well is determined not to have recoverable reserves in commercial quantities. Other items charged to expense generally include lease and well operating costs and delay rentals. Geological and geophysical costs directly related to developing proved properties are capitalized. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units of production amortization rate.
Capitalized leasehold costs attributable to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. Capitalized well costs, including asset retirement costs, are depleted based on proved developed reserves on a field basis. For the years ended December 31, 2018, 2017 and 2016, the Company recorded depletion for oil and natural gas properties of $220.3 million, $109.2 million and $39.4 million, respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated and combined statements of operations.
Proved oil and natural gas properties are reviewed for impairment when facts and circumstances indicate their carrying value may not be recoverable. The Company estimates the expected future cash flows of oil and natural gas properties and compares these undiscounted 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, the Company will write down the carrying amount of the oil and natural gas properties to estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future
F-11
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs, as further discussed in Note 9, Fair Value Measurements. The Company did not record any impairment expense associated with its proved properties during the years ended December 31, 2018, 2017 and 2016.
Unproved Oil and Natural Gas Properties
Unproved oil and natural gas properties consist of costs to acquire undeveloped leases and unproved reserves, and are capitalized when incurred. When a successful well is drilled on an undeveloped leasehold or reserves are otherwise attributed to a property, unproved property costs are transferred to proved properties. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered.
Unproved properties are periodically assessed for impairment on a property-by-property basis. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage, and records impairment expense for any decline in value. Impairment of unproved properties for leases which have expired, or are expected to expire, was $28.2 million, $0.4 million and $0.4 million for the years ended December 31, 2018, 2017 and 2016, respectively. Impairment of unproved oil and natural gas properties in 2018 primarily resulted from the Company’s ongoing evaluation of its undeveloped Big Tex acreage and the current plan to not drill on certain of these leases before they expire. There were no exploratory dry hole costs incurred in 2018 or 2017. However, during 2016 the Company incurred dry hole costs of $1.2 million related to a vertical test well drilled to an unproductive shallow horizon. Impairments are presented within impairment of unproved oil and natural gas properties, while exploratory dry hole costs are presented within exploration expenses on the consolidated and combined statements of operations.
Oil and Natural Gas Reserves
The estimates of proved oil and natural gas reserves utilized in the preparation of the financial statements are estimated in accordance with the rules established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”). The Company’s annual reserve estimates were prepared by third-party petroleum engineers. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash flows, future gross revenue, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. See “Supplemental Oil and Natural Gas Disclosures (Unaudited)” following these Notes for a more detailed discussion of the Company’s oil and natural gas reserves.
Other Property and Equipment
The following table presents the components of other property and equipment, net:
December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Other property and equipment | $ | 16,021 | $ | 12,167 | |||
Less: Accumulated depreciation | (4,351 | ) | (2,459 | ) | |||
Total other property and equipment, net | $ | 11,670 | $ | 9,708 | |||
Other property and equipment includes equipment used in drilling and completion activities, the Company’s field office, leasehold improvements, vehicles, IT hardware and software and office furniture, and is recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives, which range from 3 to 30 years. Depreciation expense for the years ended December 31, 2018, 2017 and 2016 was $1.9 million, $1.7 million and $0.9 million, respectively. When property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounting records.
F-12
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Accrued Liabilities
The components of accrued liabilities are shown below:
December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Accrued capital expenditures | $ | 74,688 | $ | 102,956 | |||
Accrued accounts payable | 5,941 | 8,488 | |||||
Royalties payable | 19,964 | 6,105 | |||||
Other current liabilities | 29,419 | 14,762 | |||||
Total accrued liabilities | $ | 130,012 | $ | 132,311 | |||
Asset Retirement Obligations
The Company records a liability for the fair value of an asset retirement obligation (“ARO”) related to future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and restoration in accordance with local, state and federal laws. The discounted fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized in proved oil and natural gas property costs as part of the carrying cost of the oil and natural gas asset, and depleted over the life of the asset. The recognition of the ARO requires management to make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements, credit-adjusted risk-free discount rates and inflation rates. Revisions to estimated ARO can result from changes in working interest, retirement cost estimates and estimated timing of abandonment. The ARO liability is accreted at the end of each period through charges to accretion expense, which is included in the statements of operations within depletion, depreciation, amortization and accretion expense.
Equity-based Compensation
The Company recognizes compensation cost related to equity-based awards granted to employees, members of the Company’s board of directors and nonemployee contractors in the financial statements based on their estimated grant-date fair value. The Company may grant various types of equity-based awards including stock options, stock appreciation rights, restricted stock, restricted stock units (including awards with service-based vesting and market condition-based vesting provisions), stock awards, dividend equivalents and other types of awards. Service-based restricted stock and units are valued using the market price of Jagged Peak’s common stock on the grant date. The fair value of the market condition-based restricted stock units is based on the grant-date fair value of the award utilizing a Monte Carlo valuation model. Compensation cost is recognized ratably over the applicable vesting period and is recognized in general and administrative expense on the consolidated and combined statements of operations. The Company has elected to account for forfeitures in compensation expense as they occur.
Income Taxes
Income taxes are accounted for under the asset and liability method. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses, interest expense and tax credit carryforwards, using enacted tax rates in effect for the taxing jurisdiction in which the Company operates for the year in which those temporary differences are expected to be recovered or settled. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company classifies all deferred tax assets and liabilities as noncurrent. The Company recognizes the financial statement effects of a tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination. The Company periodically assesses the realizability of its deferred tax assets by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available positive and negative evidence when determining whether a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences available and tax planning strategies. Deferred tax assets are then reduced by a valuation allowance if the Company believes it is more likely than not such deferred tax assets will not be realized.
The Company’s accounting predecessor, JPE LLC, was treated as a partnership for federal and state income tax purposes. Accordingly, the accompanying consolidated and combined financial statements do not include a provision or liability for income taxes prior to the corporate reorganization.
F-13
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Earnings per Share
The Company uses the treasury stock method to determine the potential dilutive effect of restricted stock units and performance stock units.
Defined Contribution Plan
The Company sponsors a 401(k) defined contribution plan for the benefit of all employees at their date of hire. The plan allows eligible employees to contribute a portion of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions for participating employees up to a certain percentage of the employee contributions. Matching contributions totaled approximately $0.7 million, $0.5 million and $0.2 million for each of the years ended December 31, 2018, 2017 and 2016, respectively. Benefits under this plan are available to all employees, and employees are fully vested in the employer contribution upon receipt.
Recent Accounting Pronouncements
Recently Adopted Accounting Standards
Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which outlined a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most prior revenue recognition guidance, including industry-specific guidance. The Company adopted the new standard on January 1, 2018, as described above. The Company implemented the necessary changes to its business processes, systems and controls to support recognition and disclosure of this new standard.
The Company’s financial statement presentation related to revenue received from certain gas sales contracts changed as a result of the new standard. Under previous guidance, proceeds from certain gas sales contracts were reported gross, with related costs for gathering and processing being presented separately as gathering and processing expense. Upon adoption of the new standard, the Company presents revenue from these contracts net of gathering and processing costs, as these costs are incurred after control of the product is transferred to the customer. The impact of the new revenue recognition standard on the Company’s current period results is as follows:
Year Ended December 31, 2018 | |||||||||||
(in thousands) | Amounts presented on statements of operations | ASC 606 Adjustments | Previous Revenue Recognition Method | ||||||||
Revenues | |||||||||||
Oil sales | $ | 539,802 | $ | — | $ | 539,802 | |||||
Natural gas sales | 9,136 | 3,488 | 12,624 | ||||||||
NGL sales | 31,956 | 11,243 | 43,199 | ||||||||
Other operating revenues | 750 | — | 750 | ||||||||
Total revenues | $ | 581,644 | $ | 14,731 | $ | 596,375 | |||||
Operating expenses | |||||||||||
Gathering and processing expenses | $ | — | $ | 14,731 | $ | 14,731 | |||||
Net income (loss) | $ | 165,458 | $ | — | $ | 165,458 | |||||
Adoption of the new standard did not impact the Company’s previously reported results of operations or consolidated and combined cash flows statements.
Stock Compensation - Scope of Modification Accounting. In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting. The ASU clarified which changes to the terms or conditions of an equity-based payment award require an entity to apply modification accounting in Topic 718. The standard became effective for the Company on January 1, 2018. The adoption of this new standard did not impact the Company’s consolidated and combined balance sheets, statements of operations or statements of cash flows.
F-14
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Accounting Standards Not Yet Adopted
Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires entities to determine at the inception of a contract if the contract is, or contains, a lease. Entities are then required to recognize leases as right-of-use assets and lease payment liabilities on the balance sheet as well as disclose key information about leasing arrangements. The new standard is effective for the Company on January 1, 2019. Entities are permitted to make a policy election under ASU 2016-02 to not recognize lease assets or liabilities when the term of the lease is less than twelve months. For agreements that contain both lease and non-lease components, entities are also permitted to make a policy election to combine both the lease and non-lease components together and account for these arrangements as a single lease. The update does not apply to leases of mineral rights to explore for or use oil and natural gas. ASU 2016-02 retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and cash flows. Under ASU 2016-02, entities are required to adopt the new standard using a modified retrospective approach and apply the provisions of ASU 2016-02 to leasing arrangements existing at, or entered into, after the earliest comparative period presented in the financial statements. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Company's adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued ASU 2018-11, Targeted Improvements, which provides entities an optional transitional relief method whereby prior periods would not require restatement while a cumulative adjustment to retained earnings during the period of adoption would be recorded.
The Company will adopt ASU 2016-02, as amended, using a modified retrospective approach as permitted under ASU 2018-11, which allows the Company to apply the legacy lease guidance and disclosure requirements in the comparative periods presented for the year of adoption. No cumulative-effect adjustment to retained earnings is expected to be recognized upon adoption of ASU 2016-02. As part of the adoption, the Company elected the short-term lease recognition policy election for all leases that qualify, and as such, no right-of-use assets or lease payment liabilities will be recorded on the balance sheet when the term of the lease is less than twelve months. The Company also elected the practical expedient under ASC 2018-01 pertaining to land easements, that allows the new guidance to be applied prospectively to all new or modified land easements and rights-of-way. The implementation of this standard will impact the Company’s current processes and controls, including contract identification and assessment. Additionally, the Company is currently finalizing the implementation of a lease administration software that will support the accounting and disclosure for leases.
Adopting ASU 2016-02 will result in increases to long-term assets, current liabilities and long-term liabilities on its consolidated and combined balance sheets, related to the recognition of new right-of-use assets and lease liabilities, and will require additional disclosures of key information related to its leases in the footnotes to the financial statements. The Company is finalizing its implementation of ASU 2016-02, as amended, and has identified long-term leases for certain asset classes, including drilling rigs, corporate office space and certain office equipment. As of December 31, 2018, the Company’s undiscounted obligations for operating leases and drilling rigs in the Company’s contractual obligations table totaled approximately $83.9 million (see Note 10, Commitments and Contingencies, for additional information).
Financial Instruments: Credit Losses. In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which replaces the currently required incurred loss methodology with an expected loss methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. The update is intended to provide financial statement users with more useful information about expected credit losses on financial instruments. The amended standard is effective for the Company on January 1, 2020, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. Historically, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have been de minimis, and the Company does not believe the adoption of 2016-13 will have a material impact on its consolidated and combined financial statements.
Note 3—Derivative Instruments
The Company hedges a portion of its crude oil sales through derivative instruments to mitigate volatility in commodity prices. The use of these instruments exposes the Company to market basis differential risk if the WTI price does not move in parity with the Company’s underlying sales of crude oil produced in the southern Delaware Basin. The Company also hedges a portion of its market basis differential risk through basis swap contracts.
The Company’s derivative instruments are carried at fair value on the consolidated and combined balance sheets using Level 2 inputs. The Company estimates the fair value using risk adjusted discounted cash flow calculations. Cash flows are based on published future commodity price curves for the underlying commodity as of the date of the estimate. Due to the volatility of commodity prices, the estimated fair values of the Company’s derivative instruments are subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. For more information, refer to Note 9, Fair Value Measurements.
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JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Commodity Price Risk
The Company’s principal market risks are its exposure to changes in oil, natural gas and NGL commodity prices. The prices of these commodities are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond the Company’s control. The Company monitors these risks and enters into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on its business.
In an effort to reduce the variability of the Company’s cash flows, the Company hedged the commodity prices associated with a portion of its expected future oil volumes by entering into swap and basis swap derivative financial instruments. With swaps, the Company typically receives an agreed upon fixed price for a specified notional quantity of oil or natural gas, and the Company pays the hedge counterparty a floating price for that same quantity based upon published index prices. Basis swap contracts establish the differential between Cushing WTI prices and Midland WTI prices for the notional volumes contracted. The Company’s commodity derivatives may expose it to the risk of financial loss in certain circumstances. The Company’s derivative arrangements provide protection on the hedged volumes if market prices decline below the prices at which these derivatives are set. If market prices rise above the prices at which the Company has hedged, the Company will be required to make settlement payments to its derivative counterparties.
The following table summarizes the Company’s derivative contracts as of December 31, 2018:
Contract Period | Volumes (Bbls) | Wtd Avg Price ($/Bbl) | |||||
Oil Swaps: (1) | |||||||
First quarter 2019 | 1,890,000 | $ | 59.95 | ||||
Second quarter 2019 | 1,911,000 | $ | 59.95 | ||||
Third quarter 2019 | 1,932,000 | $ | 59.95 | ||||
Fourth quarter 2019 | 1,932,000 | $ | 59.95 | ||||
Total 2019 | 7,665,000 | $ | 59.95 | ||||
Year ending December 31, 2020 | 2,928,000 | $ | 60.82 | ||||
Oil Basis Swaps: (2) | |||||||
First quarter 2019 | 2,070,000 | $ | (7.17 | ) | |||
Second quarter 2019 | 2,093,000 | $ | (7.17 | ) | |||
Third quarter 2019 | 2,300,000 | $ | (4.79 | ) | |||
Fourth quarter 2019 | 2,300,000 | $ | (4.79 | ) | |||
Total 2019 | 8,763,000 | $ | (5.92 | ) | |||
Year ending December 31, 2020 | 9,516,000 | $ | (1.31 | ) | |||
(1) | The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price. |
(2) | The oil basis swap differential price is between Cushing–WTI and Midland–WTI. |
The Company has elected to not apply hedge accounting, and as a result, its earnings are affected by the use of the mark-to-market method of accounting for derivative financial instruments. Accordingly, the changes in fair value of these instruments are recognized through current earnings as other income or expense as they occur. The use of mark-to-market accounting for financial instruments can cause noncash earnings volatility due to changes in the underlying commodity price indices. The ultimate gain or loss upon settlement of these transactions is recognized in earnings as other income or expense. Cash settlements of the Company’s derivative contracts are included in cash flows from operating activities in the Company’s statements of cash flows.
The following table sets forth the components of gain (loss) on commodity derivatives for the years ended December 31, 2018, 2017 and 2016:
(in thousands) | 2018 | 2017 | 2016 | ||||||||
Net cash receipts (payments) on settled derivatives | $ | (34,134 | ) | $ | (2,618 | ) | $ | (2,292 | ) | ||
Gain (loss) from the change in fair value of open derivative contracts, net | 153,472 | (39,997 | ) | (12,853 | ) | ||||||
Gain (loss) on commodity derivatives | $ | 119,338 | $ | (42,615 | ) | $ | (15,145 | ) | |||
The Company’s derivative contracts are carried at their fair value on the Company’s consolidated and combined balance sheets, and are subject to industry standard master netting arrangements, which allow the Company to offset recognized asset
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JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
and liability fair value amounts on contracts with the same counterparty. The Company’s policy is to not offset these positions in its consolidated and combined balance sheets.
The following tables present the amounts and classifications of the Company’s commodity contract derivative assets and liabilities as of December 31, 2018 and 2017 (in thousands):
As of December 31, 2018: | Balance Sheet Location | Gross amounts presented on the balance sheet | Netting adjustments not offset on the balance sheet | Net amounts | ||||||||||
Assets | ||||||||||||||
Commodity contracts | Current assets - derivative instruments | $ | 103,092 | $ | (18,815 | ) | $ | 84,277 | ||||||
Commodity contracts | Noncurrent assets - derivative instruments | 31,899 | (9,668 | ) | 22,231 | |||||||||
Total assets | $ | 134,991 | $ | (28,483 | ) | $ | 106,508 | |||||||
Liabilities | ||||||||||||||
Commodity contracts | Current liabilities - derivative instruments | $ | 23,208 | $ | (18,815 | ) | $ | 4,393 | ||||||
Commodity contracts | Noncurrent liabilities - derivative instruments | 11,162 | (9,668 | ) | 1,494 | |||||||||
Total liabilities | $ | 34,370 | $ | (28,483 | ) | $ | 5,887 | |||||||
As of December 31, 2017: | Balance Sheet Location | Gross amounts presented on the balance sheet | Netting adjustments not offset on the balance sheet | Net amounts | ||||||||||
Assets | ||||||||||||||
Commodity contracts | Current assets - derivative instruments | $ | — | $ | — | $ | — | |||||||
Commodity contracts | Noncurrent assets - derivative instruments | 26 | (26 | ) | — | |||||||||
Total assets | $ | 26 | $ | (26 | ) | $ | — | |||||||
Liabilities | ||||||||||||||
Commodity contracts | Current liabilities - derivative instruments | $ | 41,782 | $ | — | $ | 41,782 | |||||||
Commodity contracts | Noncurrent liabilities - derivative instruments | 11,095 | (26 | ) | 11,069 | |||||||||
Total liabilities | $ | 52,877 | $ | (26 | ) | $ | 52,851 | |||||||
Derivative Counterparty Risk
Where the Company is exposed to credit risk in its financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement and monitors the appropriateness of these counterparties on an ongoing basis. Generally, the Company does not require collateral and does not anticipate nonperformance by its counterparties.
The Company’s counterparty credit exposure related to commodity derivative instruments comprises contracts with a net positive fair value at the reporting date. These outstanding instruments, if any, expose the Company to credit risk in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of the Company’s counterparties decline, its ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third-party. In the event of a counterparty default, the Company may sustain a loss and its cash receipts could be negatively impacted.
At December 31, 2018, the Company had commodity derivative contracts with six counterparties, all of which were lenders under the Company’s Amended and Restated Credit Facility (as defined in Note 4, Debt) and all of which had investment grade credit ratings. These counterparties accounted for all the Company’s counterparty credit exposure related to commodity derivative assets.
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JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Note 4—Debt
The Company’s debt consisted of the following at December 31, 2018 and December 31, 2017:
(in thousands) | December 31, 2018 | December 31, 2017 | |||||
Senior secured revolving credit facility | $ | — | $ | 155,000 | |||
5.875% senior unsecured notes due 2026 | 500,000 | — | |||||
Debt issuance costs on senior unsecured notes | (10,761 | ) | — | ||||
Total long-term debt | $ | 489,239 | $ | 155,000 | |||
Senior Secured Revolving Credit Facility
In June 2015, the Company entered into a five-year senior secured revolving credit facility. At December 31, 2017, the credit facility, as amended (the “Amended and Restated Credit Facility”), had a borrowing base of $425.0 million, with $155.0 million outstanding under the credit facility, and $270.0 million in unused borrowing capacity. The weighted average interest rate as of December 31, 2017 was 3.68%. During the year ended December 31, 2017, JPE LLC capitalized $0.3 million of interest.
In March 2018, the Company entered into Amendment No. 2 to the Amended and Restated Credit Facility, which extended the maturity date of the Amended and Restated Credit Facility to March 21, 2023 and increased the borrowing base to $540.0 million. Borrowings under the Amended and Restated Credit Facility under Amendment No. 2 bear interest at a rate elected by the Company that is equal to an adjusted base rate (which is equal to the greatest of the prime rate, the federal funds effective rate plus 0.50% and the thirty-day adjusted LIBOR plus 1.0%) or LIBOR, in each case, plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the adjusted base rate, and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the elected commitments. The Company also incurs a commitment fee that is between 0.375% to 0.50% per year on the unused portion of the elected commitments, depending on the relative amount of the loan outstanding in relation to the elected commitments.
In April 2018, and in connection with the issuance of the Senior Notes (as described and defined below), the lenders of the Amended and Restated Credit Facility agreed to waive a provision that would require a borrowing base reduction as a result of the Senior Notes. As a result, the borrowing base of the Amended and Restated Credit Facility continued to be $540.0 million. The Company also voluntarily elected to reduce the elected commitments to $475.0 million, effective as of the closing of the Senior Notes offering. Additionally, a portion of the proceeds from the Senior Notes were used to repay the entire outstanding balance under the Amended and Restated Credit Facility of $320.0 million as of the date the Senior Notes proceeds were received.
In June 2018, the Company entered into Amendment No. 3 to the Amended and Restated Credit Facility which increased the amount of production volumes the Company is permitted to hedge up to 85% of forecasted future production for up to 36 months in the future, and up to the greater of 75% of production from its proved reserves and 60% of its reasonably anticipated forecasted production for 37 to 60 months in the future, provided that no hedges have a term beyond five years.
In August 2018, the Company entered into Amendment No. 4 to the Amended and Restated Credit Facility, which increased the borrowing base to $825.0 million, and the Company increased its elected commitments to $540.0 million.
In November 2018, the Company entered into Amendment No. 5 to the Amended and Restated Credit Facility, which increased the borrowing base to $900.0 million while the elected commitments remained at $540.0 million.
The Amended and Restated Credit Facility is secured by oil and natural gas properties representing at least 90% of the value of the Company’s proved reserves. The Amended and Restated Credit Facility contains certain nonfinancial covenants, including among others, restrictions on indebtedness, liens, investments, mergers, sales of assets, hedging activity, and dividends and payments to the Company’s capital interest holders.
The Amended and Restated Credit Facility also contains financial covenants, which are measured on a quarterly basis. The covenants, as defined in the Amended and Restated Credit Facility, include requirements to comply with the following financial ratios:
• | a current ratio, which is the ratio of consolidated current assets (including unused commitments under the credit facility and excluding noncash assets related to ARO and derivatives) to consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and noncash liabilities related to ARO and derivatives), as of the last day of each fiscal quarter, of not less than 1.0 to 1.0; and |
• | a leverage ratio, which is the ratio of consolidated Debt (as defined in the credit agreement) as of the last day of each fiscal quarter, subject to certain exclusions (as described in the credit agreement) to EBITDAX (as defined in |
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JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
the credit agreement) for the last 12 months ending on the last day of that fiscal quarter, of not greater than 4.0 to 1.0.
As of December 31, 2018, the Company was in compliance with its financial covenants.
As of December 31, 2018, there were no outstanding amounts under the Amended and Restated Credit Facility, and $540.0 million of elected commitments available. During the year ended December 31, 2018, the Company capitalized $1.2 million of interest.
5.875% Senior Unsecured Notes due 2026
On May 8, 2018, JPE LLC issued $500.0 million aggregate principal amount of 5.875% senior unsecured notes that mature on May 1, 2026 (the “Senior Notes”) in a 144A private placement that was exempt from registration under the Securities Act. Interest is payable on the Senior Notes semi-annually in arrears on each May 1 and November 1, which commenced on November 1, 2018. The Senior Notes resulted in net proceeds to the Company of $488.3 million, net of offering expenses. A portion of such proceeds was used to repay the entire outstanding balance under the Amended and Restated Credit Facility of $320.0 million as of the date the Senior Notes proceeds were received. The remainder of the net proceeds were used to fund a portion of the Company’s 2018 capital program and for other general corporate purposes.
The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by Jagged Peak and may be guaranteed by future subsidiaries. Jagged Peak has no independent assets or operations and has no other subsidiaries other than JPE LLC. There are no significant restrictions on the Company’s ability to obtain funds from its subsidiary in the form of cash dividends or other distributions of funds.
In connection with the issuance of the Senior Notes, the Company entered into a registration rights agreement with the initial purchasers, dated May 8, 2018, to allow holders of the unregistered Senior Notes to exchange the unregistered Senior Notes for registered notes that have substantially identical terms. On December 13, 2018, the Company filed a registration statement on Form S-4 (the “S-4 Registration Statement”) with the SEC with respect to an offer to exchange the Senior Notes for registered, publicly tradable notes that have terms identical in all material respects to the Senior Notes (except that the exchange notes do not contain any transfer restrictions) (the “Exchange Offer”). On January 31, 2019, the Company filed Amendment No. 1 to the S-4 Registration Statement with respect to the Exchange Offer. On February 5, 2019, the S-4 Registration was declared effective by the SEC and the Company commenced the Exchange Offer. The Exchange Offer is expected to close in the first quarter of 2019.
If the Company experiences certain defined changes of control, each holder of the Senior Notes may require the Company to repurchase all or a portion of its Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes plus accrued and unpaid interest as of the date of repurchase, if any.
The indenture governing the Senior Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Company’s ability and the ability of the Company’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
Note 5—Equity-based Compensation
In connection with the IPO, the Company adopted the Jagged Peak Energy Inc. 2017 Long Term Incentive Plan (the “Plan”), which allows the Company to grant up to 21,200,000 equity-based compensation shares to employees, consultants and directors of the Company and its affiliates who perform services for the Company. The Plan provides for grants of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, performance awards and other types of awards. The terms and conditions of the awards granted are established by the Company’s Board of Directors. Shares issued as a result of awards granted under the Plan are generally new common shares.
F-19
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Equity-based compensation expense, which is recorded in general and administrative expense in the accompanying consolidated and combined statements of operations, was as follows for the periods indicated:
Year Ended December 31, | |||||||||||
(in thousands) | 2018 | 2017 | 2016 | ||||||||
Incentive unit awards | $ | 76,442 | $ | 439,411 | $ | — | |||||
Restricted stock unit awards | 3,873 | 1,616 | — | ||||||||
Performance stock unit awards | 2,530 | 1,497 | — | ||||||||
Restricted stock unit awards issued to nonemployee directors | 501 | 452 | — | ||||||||
Total equity-based compensation expense | $ | 83,346 | $ | 442,976 | $ | — | |||||
Incentive Unit Awards
In connection with its formation in April 2013, JPE LLC established an incentive pool plan, whereby JPE LLC granted MIUs to employees and selected other participants. The MIUs were considered “profits interests” that participated in certain events whereupon distributions would be made to MIU holders (only after certain return thresholds were achieved by the capital interests) following a qualifying initial public offering, sale, merger or other qualifying transaction involving the units or assets of JPE LLC (“Vesting Event”).
The MIUs were accounted for under FASB ASC Topic 710, Compensation–General, which requires compensation expense for the MIUs to be recognized when all performance, market and service conditions are probable of being satisfied, which is generally upon a Vesting Event. As of and through December 31, 2016, the vesting of the MIUs was not deemed probable, therefore no expense was recognized through December 31, 2016.
The corporate reorganization provided a mechanism by which all capital interests and MIUs in JPE LLC were converted into a single class of units, which were then converted into the Company’s common stock. A portion of these shares vested and a portion were transferred to JPE Management Holdings LLC (“Management Holdco”) and became subject to the terms and conditions of the amended and restated JPE Management Holdings LLC limited liability company agreement (the “Management Holdco LLC Agreement”). As a result of the IPO, the satisfaction of all conditions relating to MIUs in JPE LLC held by the current and former officers and employees who owned equity interests in JPE LLC, was deemed probable.
The shares of common stock transferred to Management Holdco are accounted for under ASC 718, Compensation–Stock Compensation, and generally vest over three years, beginning at the date of allocation. During the year ended December 31, 2018, the Company recognized $76.4 million of equity-based compensation expense related to the shares held by Management Holdco, which included $71.3 million of equity-based compensation related to a modification of the service requirements in February 2018 for the incentive unit awards allocated at the IPO (as described further below). For the year ended December 31, 2017, equity-based compensation expense of $443.0 million included (1) $379.0 million related to the vested shares of common stock at the IPO date, all of which was noncash except for $14.7 million related to a management incentive advance payment made in April 2016, and (2) $22.2 million related to a modification in conjunction with a March 2017 separation agreement of a former executive officer. The remaining compensation expense of these awards will be recognized ratably according to the terms of the Management Holdco LLC Agreement. The equity-based compensation relative to these shares of common stock transferred to Management Holdco is not deductible for federal or state income tax purposes.
In February 2018, certain employees notified the Company of their desire to terminate their employment. Under the terms of the Management Holdco LLC Agreement, upon voluntary termination of employment by an incentive unit award holder, the Board of Directors has the discretion to allow outstanding unvested incentive unit awards to immediately vest, to continue to vest post-termination, and/or to be automatically forfeited, or any combination thereof. Any forfeited incentive units would be reallocated to the remaining incentive unit holders employed by the Company. In February 2018, the Board of Directors modified these employees’ unvested incentive units to either immediately accelerate vesting, in the case of retiring employees, or continue to vest post-termination under the original vesting period. The Company determined that these should be accounted for as modifications under ASC 718 in the first quarter of 2018. As a result of these modifications to the service requirements, the Company determined that, for accounting purposes under ASC 718, the incentive unit awards allocated at the IPO no longer met the substantive service condition, and that any previously unrecognized equity-based compensation expense should be recognized immediately. The acceleration of all previously unrecognized equity-based compensation expense for incentive unit awards allocated at the time of the IPO resulted in the recognition of approximately $71.3 million of noncash equity-based compensation expense in the first quarter of 2018. This accounting does not alter the legal service obligations under the Management Holdco LLC Agreement for remaining employees whose awards were not modified. Equity-based compensation expense recognition related to incentive unit awards that were unallocated at the time of the IPO is unaffected.
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JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
A summary of incentive unit award activity for the year ended December 31, 2018 is as follows:
Weighted Average | |||||||
Grant-date | |||||||
Incentive Units | Fair Value | ||||||
Unvested at December 31, 2017 | 7,755,745 | $ | 14.93 | ||||
Granted | 504,628 | $ | 13.21 | ||||
Vested | (2,789,511 | ) | $ | 14.95 | |||
Forfeited | (73,307 | ) | $ | 12.21 | |||
Unvested at December 31, 2018 | 5,397,555 | $ | 14.79 | ||||
Compensation costs remaining at December 31, 2018 (in millions) | $ | 5.7 | |||||
Weighted average remaining period at December 31, 2018 (in years) | 2.3 | ||||||
The weighted average grant-date fair value of incentive units was $13.21 in 2018 and $12.45 in 2017. No incentive units were granted prior to the corporate reorganization. The total fair value of incentive units that vested according to the legal service obligations during the year ended December 31, 2018 was $35.4 million, and the fair value that vested from the IPO date to December 31, 2017 was $25.2 million.
At December 31, 2018, there were no remaining unallocated shares of Company common stock held at Management Holdco.
Restricted Stock Unit Awards
Restricted stock unit awards (“RSUs”) vest subject to the satisfaction of service requirements. Expense related to each RSU award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur through reversal of expense on awards that were forfeited during the period. The grant-date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant.
A summary of RSU award activity for the year ended December 31, 2018 is as follows:
Weighted Average | |||||||
Grant-date | |||||||
RSUs | Fair Value | ||||||
Unvested at December 31, 2017 | 582,973 | $ | 12.44 | ||||
Granted | 716,734 | $ | 12.57 | ||||
Vested | (272,678 | ) | $ | 12.40 | |||
Forfeited | (155,910 | ) | $ | 12.51 | |||
Unvested at December 31, 2018 | 871,119 | $ | 12.55 | ||||
Compensation costs remaining at December 31, 2018 (in millions) | $ | 7.9 | |||||
Weighted average remaining period at December 31, 2018 (in years) | 2.1 | ||||||
The weighted average grant-date fair value of RSUs was $12.57 in 2018 and $12.45 in 2017. No RSUs were granted prior to 2017. The total fair value of RSUs that vested during the year ended December 31, 2018 was $3.4 million, while no RSUs vested prior to 2018.
Of the 716,734 RSUs granted during 2018, nonemployee directors received 30,753 at a weighted average grant-date fair value of $13.17. The remaining compensation costs at December 31, 2018 for these nonemployee director RSUs was $0.1 million, with a weighted average remaining period of 0.3 years.
F-21
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Performance Stock Unit Awards
The Company grants performance stock unit awards (“PSUs”) to certain of its officers, which vest based on continuous employment and satisfaction of a performance metric based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR of a peer group of companies over an approximate three-year performance period. The number of shares which may ultimately be earned ranges from zero to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over approximately three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
A summary of PSU award activity for the year ended December 31, 2018 is as follows:
Weighted Average | |||||||
Grant-date | |||||||
PSUs | Fair Value | ||||||
Unvested at December 31, 2017 | 398,566 | $ | 16.32 | ||||
Granted | 546,319 | $ | 16.23 | ||||
Vested | — | $ | — | ||||
Forfeited | (253,522 | ) | $ | 16.32 | |||
Unvested at December 31, 2018 | 691,363 | $ | 16.25 | ||||
Compensation costs remaining at December 31, 2018 (in millions) | $ | 7.2 | |||||
Weighted average remaining period at December 31, 2018 (in years) | 1.9 | ||||||
The weighted average grant-date fair value of PSUs was $16.23 in 2018 and $16.32 in 2017. No PSUs were granted prior to 2017 and no PSUs vested in 2018 or 2017.
The grant-date fair value of the PSUs was determined using a Monte Carlo simulation, which uses a probabilistic approach for estimating the fair value of the awards. The expected volatility was derived from a weighted combination of implied volatility and historical volatility. The risk-free interest rate was determined using the yield available for zero-coupon U.S. government issues with remaining terms corresponding to the service periods of the PSUs.
The three-year performance period for the PSUs granted during the years ended December 31, 2018 and 2017 ends December 31, 2020 and December 31, 2019, respectively. The following table presents information regarding the weighted average fair value for the PSUs granted in 2018 and 2017, including the assumptions used to determine the fair values:
Years Ended December 31, | |||||
2018 | 2017 | ||||
Dividend yield | — | % | — | % | |
Volatility | 37.3 | % | 55.7 | % | |
Risk-free interest rate | 2.34 | % | 1.34 | % | |
Note 6—Earnings Per Share
Basic earnings per share (“EPS”) is computed by dividing net earnings by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested RSUs and PSUs if including such potential shares of common stock units is dilutive. The PSUs included in the calculation of diluted weighted average shares outstanding are based on the number of shares of common stock that would be issuable if the end of the reporting period was the end of the performance period required for the vesting of such PSU awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all awards is anti-dilutive.
For the year ended December 31, 2017, the Company’s EPS calculation includes only the net loss for the period subsequent to the corporate reorganization and IPO and omits income or loss prior to these events. In addition, the basic weighted average shares outstanding calculation is based on the actual days in which the shares were outstanding for the period from January 27, 2017 to December 31, 2017.
F-22
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
Year Ended | From January 27, 2017, to | ||||||
(in thousands, except per share amounts) | December 31, 2018 | December 31, 2017 | |||||
Net income (loss) attributable to Jagged Peak Energy Inc. stockholders | $ | 165,458 | $ | (76,458 | ) | ||
Basic weighted average shares outstanding | 213,128 | 212,932 | |||||
Dilutive restricted stock units | 75 | — | |||||
Dilutive performance stock units | — | — | |||||
Diluted weighted average shares outstanding | 213,203 | 212,932 | |||||
Net income (loss) per common share: | |||||||
Basic | $ | 0.78 | $ | (0.36 | ) | ||
Diluted | $ | 0.78 | $ | (0.36 | ) | ||
The following table presents the weighted average number of outstanding equity awards that have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive:
Year Ended | From January 27, 2017, to | ||||
(in thousands) | December 31, 2018 | December 31, 2017 | |||
Number of antidilutive units: (1) | |||||
Antidilutive restricted stock units | 217 | 411 | |||
Antidilutive performance stock units | 585 | 523 | |||
(1) | When the Company incurs a net loss, all outstanding equity awards are excluded from the calculation of diluted loss per common share because the inclusion of these awards would be antidilutive. |
Note 7—Income Taxes
JPE LLC was organized as a limited liability company and treated as a pass-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and included in their tax returns. Accordingly, provision for federal and state corporate income taxes were made for the operations of the Company following January 27, 2017 in the accompanying consolidated and combined financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the change in tax status as a result of the corporate reorganization, the Company established an $80.7 million provision for deferred income taxes, which was recognized as tax expense from continuing operations.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act, among other things, (i) permanently reduced the U.S. corporate income tax rate to 21%, (ii) repealed the corporate alternative minimum tax, (iii) imposed new limitations on the utilization of net operating losses and eliminated their carryforward restrictions and (iv) provided for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense. In addition, the Tax Act preserved deductibility of intangible drilling costs and provided for 100% bonus depreciation on tangible personal property expenditures through 2022. The bonus depreciation percentage is phased down from 100% beginning in 2023 to 0% for years after 2026.
The SEC issued rules that allowed for a measurement period of up to one year after the enactment date of the Tax Act to finalize the impact of the Tax Act on a company's financial statements. The Company's accounting for the effects of the tax rate change on its deferred tax balances as well as other relevant aspects of the Tax Act was completed as of December 31, 2017 and no provisional amounts were recorded at year-end 2017 that were later adjusted in 2018. Future interpretations relating to the passage of the Tax Act which vary from the Company’s current interpretation, and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on the Company’s future taxable position. The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.
F-23
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
The components of the Company’s provision for income taxes are as follows:
Year Ended December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Current income tax expense: | |||||||
Federal | $ | — | $ | — | |||
State | — | — | |||||
— | — | ||||||
Deferred income tax expense: | |||||||
Federal | 64,364 | 56,350 | |||||
State | 2,111 | 1,593 | |||||
66,475 | 57,943 | ||||||
Provision for income taxes | $ | 66,475 | $ | 57,943 | |||
A reconciliation of the income tax expense calculated at the federal statutory rate to the total income tax expense is as follows:
Year Ended December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Income (loss) before income taxes | $ | 231,933 | $ | (393,991 | ) | ||
Less: loss before income taxes prior to corporate reorganization | — | (375,476 | ) | ||||
Income (loss) before income taxes subsequent to corporate reorganization | $ | 231,933 | $ | (18,515 | ) | ||
Income tax expense (benefit) at the federal statutory rate | $ | 48,706 | $ | (6,480 | ) | ||
Nondeductible equity-based compensation (1) | 15,614 | 20,781 | |||||
State income taxes, net of federal benefit | 2,111 | 199 | |||||
Other permanent differences | 44 | 21 | |||||
Income tax expense relating to change in tax status | — | 80,704 | |||||
Federal tax reform changes - the Tax Act (2) | — | (37,282 | ) | ||||
Income tax expense (benefit) | $ | 66,475 | $ | 57,943 | |||
Effective tax rate | 28.7 | % | (14.7 | )% | |||
(1) | The equity-based compensation related to shares of common stock transferred to Management Holdco is not deductible for federal or state income tax purposes. See Note 5, Equity-based Compensation, for more information on the shares of common stock transferred to Management Holdco. |
(2) | The Tax Act reduced the U.S. federal statutory rate from 35% to 21% beginning in 2018. |
Prior to the Company’s change in tax status in January 2017, income taxes did not significantly impact the results of operations.
F-24
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
The components of the Company’s deferred income tax assets and liabilities are as follows:
(in thousands) | December 31, 2018 | December 31, 2017 | |||||
Deferred income tax assets: | |||||||
Commodity derivatives | $ | — | $ | 11,412 | |||
Equity-based compensation | 1,963 | 928 | |||||
Net operating loss carryforwards | 19,788 | 16,093 | |||||
Other | 3,026 | 1,726 | |||||
24,777 | 30,159 | ||||||
Deferred income tax liabilities: | |||||||
Oil and natural gas properties | 127,468 | 88,102 | |||||
Commodity derivatives | 21,727 | — | |||||
149,195 | 88,102 | ||||||
Net deferred income tax assets (liabilities) | $ | (124,418 | ) | $ | (57,943 | ) | |
The Company had U.S. net operating losses of approximately $94.2 million, of which approximately $75.5 million expire in 2037 and $18.8 million are limited to 80% of taxable income per year and will not expire. Deferred tax assets are reduced by a valuation allowance if the Company believes it is more likely than not such deferred tax assets will not be realized. The Company periodically assesses its deferred tax assets for realizability and, as a result of such assessment, determined as of December 31, 2018 sufficient evidence existed to indicate it is more likely than not that its deferred tax assets will be realized.
The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. That Company gives financial statement recognition to those tax provisions that it believes are more likely than not to be sustained upon examination by the Internal Revenue Service or other government agency. As of December 31, 2018, the Company did not have any accrued liability for unrecognized tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. At December 31, 2018, the Company has made no provisions for interest or penalties related to uncertain tax positions.
The Company files income tax returns in the U.S. federal jurisdiction, Texas and Colorado. There are currently no federal or state income tax examinations underway. The Company’s U.S. federal income tax returns remain open to examination by the taxing authorities for tax years 2015 through 2017, and its Texas and Colorado tax returns remain open to examination for the years 2014 through 2017.
Note 8—Asset Retirement Obligations
The following table summarizes the changes in the carrying amount of the ARO liabilities for the years ended December 31, 2018 and 2017. Any ARO classified as current is included in accrued liabilities on the consolidated and combined balance sheets.
(in thousands) | 2018 | 2017 | |||||
Asset retirement obligations at January 1, | $ | 929 | $ | 448 | |||
Liabilities incurred and assumed | 718 | 590 | |||||
Liability settlements and disposals | (33 | ) | (190 | ) | |||
Revisions of estimated liabilities | 335 | 9 | |||||
Accretion | 123 | 72 | |||||
Asset retirement obligations at December 31, | 2,072 | 929 | |||||
Less current portion of asset retirement obligations | (126 | ) | (118 | ) | |||
Long-term asset retirement obligations | $ | 1,946 | $ | 811 | |||
In 2018 and 2017, the Company recognized revisions of estimated liabilities totaling $0.3 million and $9 thousand, respectively, which were due to changes in estimated abandonment timing and costs.
F-25
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Note 9—Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Certain financial assets and liabilities, such as derivative instruments, are measured at fair value on a recurring basis. Nonfinancial assets and liabilities, such as the initial measurement of ARO liabilities and oil and natural gas properties upon acquisition or impairment, are recognized at fair value on a nonrecurring basis.
The Company categorizes the inputs to the fair value of its financial assets and liabilities using a three-tier fair value hierarchy, established by the FASB, that prioritizes the significant inputs used in measuring fair value:
Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.
Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry standard models that consider various assumptions, including quoted prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in the category include nonexchange-traded derivatives such as over-the-counter forwards, swaps and options.
Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value, and the company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. 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 year ended December 31, 2018.
Assets and liabilities measured on a recurring basis
Certain assets and liabilities are reported at fair value on a recurring basis. The following table sets forth the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:
Level 2 | |||||||
(in thousands) | December 31, 2018 | December 31, 2017 | |||||
Assets from commodity derivative contracts | $ | 134,991 | $ | 26 | |||
Liabilities due to commodity derivative contracts | $ | 34,370 | $ | 52,877 | |||
The fair value of the Company’s oil swaps and basis swaps is computed using discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves as of the date of the estimate. The Company compares these prices to the price parameters contained in its hedge contracts to determine estimated future cash inflows or outflows, which are then discounted. The fair values of the Company’s commodity derivative assets and liabilities include a measure of credit risk. These valuations are Level 2 inputs.
Fair Value of Other Financial Instruments
The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated and combined balance sheets:
December 31, 2018 | December 31, 2017 | ||||||||||||||
(in thousands) | Principal Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||
Long-term debt: | |||||||||||||||
Senior secured revolving credit facility | $ | — | $ | — | $ | 155,000 | $ | 155,000 | |||||||
5.875% senior unsecured notes due 2026 | $ | 500,000 | $ | 466,250 | $ | — | $ | — | |||||||
F-26
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
The fair value of the Amended and Restated Credit Facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes at December 31, 2018 was based on the quoted market price and is classified as Level 1 in the fair value hierarchy.
The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are considered to be representative of their respective fair values due to the nature of and short-term maturities of those instruments.
Assets and liabilities measured on a nonrecurring basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. These assets and liabilities include the acquisition or impairment of proved and unproved oil and gas properties and the inception value of asset retirement obligation liabilities.
Proved oil and natural gas properties. The Company reviews its proved oil and natural gas properties for impairment whenever facts and circumstances indicate their carrying value may not be recoverable. In such circumstances, the income approach is used to determine the fair value of proved oil and natural gas reserves. Under this approach, the Company estimates the expected future cash flows of oil and natural gas properties and compares these undiscounted 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, the Company will write down the carrying amount of the oil and natural gas properties to estimated fair value. The factors used to determine fair value may include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures and a commensurate discount rate. These assumptions and estimates represent Level 3 inputs.
Unproved oil and natural gas properties. Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of the unproved properties, the Company uses a market approach and takes into account future development plans, remaining lease term, drilling results and reservoir performance. These assumptions and estimates represent Level 3 inputs.
The following table sets forth the noncash impairments of both proved and unproved properties for the periods indicated:
Year Ended December 31, | |||||||||||
(in thousands) | 2018 | 2017 | 2016 | ||||||||
Proved oil and natural gas property impairments | $ | — | $ | — | $ | — | |||||
Unproved oil and natural gas property impairments (1) | 28,198 | 373 | 372 | ||||||||
$ | 28,198 | $ | 373 | $ | 372 | ||||||
(1) | Impairment of unproved oil and natural gas properties in 2018 primarily resulted from the Company’s ongoing evaluation of its undeveloped Big Tex acreage and the current plan to not drill on certain of these leases before they expire. Impairment of unproved oil and natural gas properties in 2017 and 2016 resulted from expirations of certain undeveloped leases. |
Asset retirement obligations. The inception value and new layers resulting from upward revisions of the Company’s ARO liabilities are also measured at fair value on a nonrecurring basis. The inputs used to determine such fair value are based primarily on the present value of estimated future cash outflows. Given the unobservable nature of these inputs, they represent Level 3 inputs.
F-27
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Note 10—Commitments and Contingencies
Commitments
The table below shows the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2018:
(in thousands) | 2019 | 2020 | 2021 | 2022 | 2023 | Thereafter | Total | ||||||||||||||||||||
Operating leases | $ | 1,547 | $ | 1,539 | $ | 1,553 | $ | 1,559 | $ | 1,589 | $ | 7,378 | $ | 15,165 | |||||||||||||
Service and purchase contracts (1) | 7,598 | 1,285 | 750 | — | — | — | 9,633 | ||||||||||||||||||||
Rig contracts | 36,805 | 31,897 | — | — | — | — | 68,702 | ||||||||||||||||||||
Frac fleet contracts | 63,135 | — | — | — | — | — | 63,135 | ||||||||||||||||||||
Total | $ | 109,085 | $ | 34,721 | $ | 2,303 | $ | 1,559 | $ | 1,589 | $ | 7,378 | $ | 156,635 | |||||||||||||
(1) | Primarily relates to a retail power purchase agreement. |
Operating lease commitments
The Company leases office space in Denver, Colorado. The Company’s corporate office lease in Denver expires in 2028. In connection with this lease, the Company received $4.7 million of lease incentives primarily related to tenant improvements, which is recorded within other long-term liabilities on the consolidated and combined balance sheets. The lease incentive liability is amortized on a straight-line basis as a reduction to rent expense over the lease term. The tenant improvements are depreciated over the shorter of the useful life of the asset or the life of the lease. The Company also leases certain office equipment under operating leases, which expire over the next five years.
Rent expense with respect to these lease commitments was approximately $2.3 million, $0.9 million, and $0.6 million for the years ended December 31, 2018, 2017, and 2016, respectively.
Drilling rig commitments
At December 31, 2018, the Company had seven operated drilling rigs running. If the Company were to terminate all of its drilling rig contracts at December 31, 2018, it would be required to pay early termination penalties of $37.7 million. In January 2019, two of the seven rigs were released, which resulted in early termination penalties of $0.3 million. Of these two rigs that were released, one was on a well-to-well contract, while the other was contractually obligated through August 2019. Included in the commitments table above is $0.3 million that represents the obligations for these two rigs to finish the wells they were drilling as of December 31, 2018.
Frac fleet commitments
At December 31, 2018, the Company had two frac fleets under contract through December 31, 2019. In the first quarter of 2019 the Company terminated one of the frac fleet contracts. As a result, the Company paid a termination fee of $3.2 million in 2019. The remaining frac fleet under contract at December 31, 2018 does not contain early termination fees.
Minimum volume commitments
In November 2018, the Company entered into a 5-year oil marketing agreement that is expected to take effect at the commencement of commercial operations on the Cactus II pipeline and will link a portion of the Company’s oil production to Gulf Coast pricing. This agreement specifies a minimum gross volume commitment of 30,000 barrels of oil per day. If the Company is not able to provide the contractual quantity to the buyer, it would be subject to a deficiency payment relative to a price difference on the deficient volume. Based on its current and projected production levels, the Company does not believe a deficiency payment will be required under this agreement.
Contingencies
Legal Matters
In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
F-28
JAGGED PEAK ENERGY INC.
Notes to Consolidated and Combined Financial Statements
Environmental Matters
The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both December 31, 2018 and 2017, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Note 11—Related Party Transactions
Quantum employs certain members of the Company’s board of directors and had significant capital interests in JPE LLC. As of December 31, 2018, Quantum owns 68.6% of the Company’s common stock.
Quantum owns a 41.5% interest in Oryx Midstream Services, LLC (together with Oryx Southern Delaware Holdings, LLC, “Oryx”). The Company has a 12-year crude oil gathering agreement with Oryx whereby Oryx provides midstream gathering services to the Company. Under that agreement, the Company has the right to designate, and has designated, a third-party shipper to market the Company’s crude oil. In addition, the Company paid fees to Oryx for the purchase and maintenance of connecting equipment.
Quantum also owns a 62.0% interest in Phoenix Lease Services, LLC (“Phoenix”), and an indirect interest in Trident Water Services, LLC (“Trident”), a wholly owned subsidiary of Phoenix. The Company regularly leases frac tanks and other oil field equipment from Phoenix, and regularly uses water transfer services provided by Trident. The Company is under no obligation to use either provider, and both provide services only when selected as a vendor through the Company’s normal bidding process.
The following table summarizes fees paid to Oryx, Phoenix and Trident for the periods indicated:
Year Ended December 31, | |||||||||||
(in thousands) | 2018 | 2017 | 2016 | ||||||||
Oryx via 3rd party shipper (1) | $ | 23,239 | $ | 10,058 | $ | 2,125 | |||||
Oryx (2) | $ | 894 | $ | 798 | $ | 1,765 | |||||
Phoenix (3) | $ | 364 | $ | 366 | $ | 338 | |||||
Trident (3) | $ | 464 | $ | 236 | $ | 590 | |||||
(1) | Fees paid by the Company’s third-party shipper to Oryx pursuant to the crude oil transportation and gathering agreement are netted against revenue as they are included in the net price paid by to the third-party shipper. |
(2) | Fees paid to Oryx for the purchase and installation of metering equipment are capitalized to proved properties on the consolidated and combined balance sheets. |
(3) | Fees paid to Phoenix and Trident are capitalized to proved properties on the consolidated and combined balance sheets. |
At December 31, 2018 and 2017, the Company had outstanding payables to these related parties of $2.6 million and $1.8 million, respectively.
F-29
Supplemental Oil and Natural Gas Disclosures (Unaudited)
Oil and Gas Exploration and Production Activities
The Company has only one reportable operating segment, which is oil and gas development, exploration and production in the United States. See the Company’s accompanying consolidated and combined statements of operations for information about results of operations for oil and gas producing activities. The amounts shown include the Company’s net working interests in all of its oil and gas properties.
Capitalized Costs Relating to Oil and Gas Producing Activities
Aggregate capitalized costs related to the Company’s oil and natural gas producing activities at December 31, 2018 and 2017 were as follows:
December 31, | |||||||
(in thousands) | 2018 | 2017 | |||||
Proved property | $ | 1,746,766 | $ | 1,012,321 | |||
Unproved property | 158,732 | 183,510 | |||||
1,905,498 | 1,195,831 | ||||||
Accumulated depletion, depreciation and amortization | (386,883 | ) | (166,592 | ) | |||
Net capitalized costs | $ | 1,518,615 | $ | 1,029,239 | |||
Costs Incurred for Oil and Gas Activities
Costs incurred for the Company’s oil and natural gas activities for the years ended December 31, 2018, 2017 and 2016 were as follows:
Year Ended December 31, | |||||||||||
(in thousands) | 2018 | 2017 | 2016 | ||||||||
Acquisition costs: | |||||||||||
Proved property | $ | 2,401 | $ | — | $ | 7,482 | |||||
Unproved property | 27,354 | 70,693 | 50,570 | ||||||||
Development costs (1) | 711,010 | 595,854 | 155,397 | ||||||||
Exploration costs | 29 | 31 | 1,673 | ||||||||
Total costs incurred | $ | 740,794 | $ | 666,578 | $ | 215,122 | |||||
(1) | Includes amounts related to estimated asset retirement costs of $1.1 million, $0.6 million and $22 thousand for the years ended December 31, 2018, 2017 and 2016, respectively. The increase to the Company’s asset retirement estimate for the year ended December 31, 2018, as compared to 2017, is primarily due to the estimated abandonment costs on the 48.0 net wells that began producing during 2018, as well as changes in estimated abandonment timing. |
Oil and Natural Gas Reserve Quantities
The Company’s proved oil and natural gas reserves are all located in the United States, within the Delaware Basin, a sub-basin of the Permian Basin of West Texas. All of the estimates of proved reserves at December 31, 2018, 2017 and 2016 are based on reports prepared by Ryder Scott Company, LP, the Company’s independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e. costs as of the date the estimate is made). A variety of methodologies are used to determine the Company’s proved reserve estimates. The primary methodologies used are decline curve analysis, advanced production type curve matching, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates across substantially all the Company’s properties. Reserve estimates are inherently imprecise and estimates of undeveloped locations are more imprecise than estimates of established proved producing locations. Accordingly, the Company’s reserve estimates are expected to change as future information becomes available.
Proved oil and natural gas reserves were calculated based on the prices for oil and natural gas during the 12-month period before the reporting date, determined as the unweighted average of the first-day-of-the-month pricing. For oil and NGL volumes, the benchmark WTI posted price is adjusted for quality and regional price differentials. For natural gas volumes, the Henry Hub spot price is adjusted for energy content and regional price basis differentials. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.
F-30
Supplemental Oil and Natural Gas Disclosures (Unaudited)
The following table summarizes the average adjusted product prices for 2018, 2017 and 2016:
2018 | 2017 | 2016 | |||||||||
Oil price per Bbl | $ | 58.35 | $ | 48.26 | $ | 39.33 | |||||
Natural gas price per Mcf | $ | 2.23 | $ | 2.59 | $ | 2.22 | |||||
NGL price per Bbl | $ | 34.21 | $ | 26.69 | $ | 15.48 | |||||
In addition, the SEC requires that reserves classified as proved undeveloped (“PUDs”) be capable of conversion into proved developed within five years of classification unless specific circumstances justify a longer time. The Company’s development plans at December 31, 2018 related to scheduled drilling over the next five years are subject to many uncertainties and variables, including availability of capital, future oil and natural gas prices, cash flows from operations, future drilling costs, demand for oil and natural gas and other economic factors.
The following table presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended December 31, 2018:
Oil (MBbls) | Gas (MMcf) | NGLs (MBbls) | Total (MBoe) | ||||||||
Proved reserves: | |||||||||||
Balance December 31, 2015 | 10,493 | 6,157 | 1,491 | 13,011 | |||||||
Acquisitions of reserves | 340 | 430 | 54 | 466 | |||||||
Extensions, discoveries and other additions, including infill reserves in an existing proved field | 20,314 | 13,663 | 2,653 | 25,244 | |||||||
Revisions of previous estimates | 1,035 | 353 | 56 | 1,149 | |||||||
Sales of reserves | (75 | ) | (132 | ) | (24 | ) | (121 | ) | |||
Production | (1,701 | ) | (952 | ) | (194 | ) | (2,054 | ) | |||
Balance December 31, 2016 | 30,406 | 19,519 | 4,036 | 37,695 | |||||||
Extensions, discoveries and other additions, including infill reserves in an existing proved field | 41,172 | 33,790 | 5,015 | 51,819 | |||||||
Revisions of previous estimates | (1,542 | ) | 3,546 | (8 | ) | (960 | ) | ||||
Production | (4,979 | ) | (3,601 | ) | (617 | ) | (6,196 | ) | |||
Balance December 31, 2017 | 65,057 | 53,254 | 8,426 | 82,358 | |||||||
Acquisitions of reserves | 488 | 417 | 71 | 629 | |||||||
Extensions, discoveries and other additions, including infill reserves in an existing proved field | 27,977 | 22,798 | 3,919 | 35,696 | |||||||
Revisions of previous estimates | 7,801 | 12,037 | 2,885 | 12,693 | |||||||
Production | (9,619 | ) | (7,992 | ) | (1,534 | ) | (12,486 | ) | |||
Balance December 31, 2018 | 91,704 | 80,514 | 13,767 | 118,890 | |||||||
Proved developed reserves: | |||||||||||
December 31, 2016 | 11,916 | 6,566 | 1,491 | 14,501 | |||||||
December 31, 2017 | 29,325 | 25,496 | 4,166 | 37,739 | |||||||
December 31, 2018 | 54,542 | 50,018 | 8,554 | 71,432 | |||||||
Proved undeveloped reserves: | |||||||||||
December 31, 2016 | 18,490 | 12,953 | 2,545 | 23,194 | |||||||
December 31, 2017 | 35,732 | 27,758 | 4,260 | 44,619 | |||||||
December 31, 2018 | 37,162 | 30,496 | 5,213 | 47,458 | |||||||
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Undrilled locations may be classified as having PUDs only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2018, all of the Company’s PUD drilling locations are scheduled to be developed within five years of their initial booking. PUDs include drilling locations that are more than one offset location away from productive wells.
F-31
Supplemental Oil and Natural Gas Disclosures (Unaudited)
2018 Activity. Total proved reserves increased by 36.5 MMBoe in 2018 primarily due to the following:
Extensions, discoveries and other, including infill reserves in an existing proved field. Proved reserves increased by 35.7 MMBoe due to the Company’s 2018 drilling program and the addition of 39.0 net PUD locations, both of which are associated with the Company’s infill drilling activities.
Revisions of previous estimates. Prior estimates of proved reserves were revised upward by 12.7 MMBoe as follows:
(in MBoe) | ||
Revisions due to changes in prices | 1,867 | |
Revisions due to cost updates | 1,933 | |
Revisions due to performance | 11,227 | |
Removal of PUDs no longer in the five-year development plan (1) | (2,334 | ) |
Total net revisions of previous estimates | 12,693 | |
(1) | Associated with three wells that were transferred out of PUDs to unproved reserves because they are no longer expected to be developed within five years of the date of their initial recognition due to changes in the capital program in certain areas. |
2017 Activity. Total proved reserves increased by 44.7 MMBoe in 2017 primarily due to the following:
Extensions, discoveries and other, including infill reserves in an existing proved field. Proved reserves increased by 51.8 MMBoe of proved reserves that resulted entirely from extensions and discoveries on the Company’s properties due to the Company’s 2017 drilling program and the addition of 45.0 net PUD locations.
Revisions of previous estimates. Prior estimates of proved reserves were revised downward by 1.0 MMBoe as follows:
(in MBoe) | ||
Revisions due to changes in prices | 650 | |
Revisions due to cost updates | (2,221 | ) |
Revisions due to performance | 610 | |
Total net revisions of previous estimates | (961 | ) |
2016 Activity. Total proved reserves increased by 24.7 MMBoe in 2016 primarily due to the following:
Extensions, discoveries and other, including infill reserves in an existing proved field. Proved reserves increased by 25.2 MMBoe that resulted wholly from extensions and discoveries on the Company’s properties due to the Company’s drilling program and the addition of 23.9 net PUD locations.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure is calculated in accordance with guidance provided by the FASB, and is computed by applying the adjusted 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.
The assumptions used to calculate estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. If reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. Future development and production costs are calculated by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions.
The 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves and is prescribed by GAAP.
F-32
Supplemental Oil and Natural Gas Disclosures (Unaudited)
With regard to the future income taxes, the Company’s predecessor was a limited liability company, therefore a pass-through entity for tax purposes. The effect of future net income taxes has been excluded from the standardized measure of discounted future net cash flows for 2016 as the Company’s predecessor was not subject to federal income taxes. The Company’s predecessor was, however, subject to the Texas franchise tax, which is an entity-level tax at a statutory rate of up to 1.0% of a portion of gross revenue apportioned to Texas.
The following table presents the standardized measure of discounted net cash flows related to proved oil and natural gas reserves as of December 31, 2018, 2017 and 2016:
(in thousands) | 2018 | 2017 | 2016 | ||||||||
Future cash inflows | $ | 6,001,670 | $ | 3,502,239 | $ | 1,301,702 | |||||
Future production costs | (1,646,023 | ) | (1,136,692 | ) | (382,999 | ) | |||||
Future development costs | (670,091 | ) | (579,060 | ) | (278,229 | ) | |||||
Future income tax expenses | (634,671 | ) | (291,218 | ) | (8,671 | ) | |||||
Future net cash flows | 3,050,885 | 1,495,269 | 631,803 | ||||||||
10% annual discount | (1,507,617 | ) | (723,397 | ) | (360,857 | ) | |||||
Standardized measure of discounted future net cash flows | $ | 1,543,268 | $ | 771,872 | $ | 270,946 | |||||
A summary of principal sources of changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2018, 2017 and 2016 is as follows:
(in thousands) | 2018 | 2017 | 2016 | ||||||||
Standardized measure of discounted future net cash flows, beginning of period | $ | 771,872 | $ | 270,946 | $ | 131,721 | |||||
Sales of oil and natural gas, net of production costs and taxes | (503,847 | ) | (228,006 | ) | (62,453 | ) | |||||
Extensions, discoveries and other, including infill reserves in an existing proved field, less related costs | 400,998 | 607,043 | 160,238 | ||||||||
Revisions of previous quantity estimates | 245,779 | (9,177 | ) | 14,315 | |||||||
Net changes in prices and production costs | 332,726 | 125,082 | (36,752 | ) | |||||||
Previously estimated development costs incurred during the period | 320,407 | 121,135 | 36,996 | ||||||||
Changes in estimated future development costs | (29,902 | ) | 12,330 | 1,019 | |||||||
Accretion of discount | 91,620 | 27,539 | 13,347 | ||||||||
Acquisitions of reserves | 11,427 | — | 3,373 | ||||||||
Sales of reserves in place | — | — | (1,506 | ) | |||||||
Net change in taxes | (144,541 | ) | (141,653 | ) | (2,674 | ) | |||||
Changes in timing and other | 46,729 | (13,367 | ) | 13,322 | |||||||
Standardized measure of discounted future net cash flows, end of period | $ | 1,543,268 | $ | 771,872 | $ | 270,946 | |||||
F-33
The following tables provide selected quarterly financial data derived from the Company’s consolidated and combined financial statements for the years ended December 31, 2018 and 2017 (in thousands, except per share data):
Quarter | ||||||||||||||||
2018 | First | Second | Third | Fourth | ||||||||||||
Revenues | $ | 129,053 | $ | 158,676 | $ | 155,378 | $ | 138,537 | ||||||||
Operating expenses | 151,763 | 85,505 | 90,724 | 122,173 | ||||||||||||
Operating income (loss) | (22,710 | ) | 73,171 | 64,654 | 16,364 | |||||||||||
Net income (loss) | (39,403 | ) | 45,081 | (26,566 | ) | 186,346 | ||||||||||
Earnings per common share | ||||||||||||||||
Basic | $ | (0.18 | ) | $ | 0.21 | $ | (0.12 | ) | $ | 0.87 | ||||||
Diluted | $ | (0.18 | ) | $ | 0.21 | $ | (0.12 | ) | $ | 0.87 | ||||||
Net income (loss) for each respective quarter includes the following items:
First-quarter 2018:
• | Includes a $71.3 million charge to equity-based compensation related to a modification of the service requirements for the incentive unit awards allocated at the IPO, as discussed in Note 5, Equity-based Compensation. |
Third-quarter 2018:
• | Includes a $96.5 million net loss on derivative instruments. Additional information regarding the Company’s derivative instruments can be found in Note 3, Derivative Instruments. |
Fourth-quarter 2018:
• | Includes a $229.8 million net gain on derivative instruments. Additional information regarding the Company’s derivative instruments can be found in Note 3, Derivative Instruments. |
• | Includes $28.1 million of impairment expense primarily related to certain acreage in the Big Tex area, as discussed in Note 9, Fair Value Measurements. |
Quarter | ||||||||||||||||
2017 | First | Second | Third | Fourth | ||||||||||||
Revenues | $ | 39,388 | $ | 53,051 | $ | 70,451 | $ | 104,422 | ||||||||
Operating expenses | 432,403 | 48,763 | 60,168 | 74,851 | ||||||||||||
Operating income (loss) | (393,015 | ) | 4,288 | 10,283 | 29,571 | |||||||||||
Net income (loss) | (465,881 | ) | 16,403 | (15,219 | ) | 12,763 | ||||||||||
Less: Net loss attributable to Jagged Peak Energy LLC (predecessor) | (375,476 | ) | — | — | — | |||||||||||
Net income (loss) attributable to Jagged Peak Energy Inc. Stockholders | (90,405 | ) | 16,403 | (15,219 | ) | 12,763 | ||||||||||
Earnings per common share (1) | ||||||||||||||||
Basic | $ | (0.42 | ) | $ | 0.08 | $ | (0.07 | ) | $ | 0.06 | ||||||
Diluted | $ | (0.42 | ) | $ | 0.08 | $ | (0.07 | ) | $ | 0.06 | ||||||
(1) | The Company’s EPS calculation for the first quarter of 2017 includes only the net loss for the period subsequent to the corporate reorganization and IPO, and omits income or loss prior to these events. In addition, the basic weighted average shares outstanding that were used in the calculation of the first quarter 2017 EPS calculation is based on the actual days in which the shares were outstanding for the period from January 27, 2017, to March 31, 2017. See Note 6, Earnings Per Share, for more details. |
Net income (loss) for each respective quarter includes the following items:
First-quarter 2017:
• | Includes a $379.0 million charge to equity-based compensation related to MIUs in JPE LLC that vested at the time of the IPO, as discussed in Note 1, Organization, Operations and Basis of Presentation, and Note 5, Equity-based Compensation. |
• | Includes $79.1 million of income tax expense related to a change in tax status resulting from the corporate reorganization, which occurred in connection with the IPO. See Note 1, Organization, Operations and Basis of Presentation, and Note 7, Income Taxes, for additional information about the corporate reorganization and the change in tax status. |
F-34
Fourth-quarter 2017:
• | Includes a $58.5 million net loss related to derivative instruments. Additional information regarding the Company’s derivative instruments can be found in Note 3, Derivative Instruments. |
• | Includes a $37.3 million income tax benefit related to the impact of the Tax Act, as discussed in Note 7, Income Taxes. |
F-35
