Jagged Peak Energy Inc. - FORM 10-K

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EX-23.2 - EXHIBIT 23.2 - Jagged Peak Energy Inc.	exhibit232kpmgllcconsentq4.htm
EX-99.1 - EXHIBIT 99.1 - Jagged Peak Energy Inc.	exhibit991q42016.htm
EX-32.2 - EXHIBIT 32.2 - Jagged Peak Energy Inc.	exhibit322q42016.htm
EX-32.1 - EXHIBIT 32.1 - Jagged Peak Energy Inc.	exhibit321q42016.htm
EX-31.2 - EXHIBIT 31.2 - Jagged Peak Energy Inc.	exhibit312q42016.htm
EX-31.1 - EXHIBIT 31.1 - Jagged Peak Energy Inc.	exhibit311q42016.htm
EX-23.3 - EXHIBIT 23.3 - Jagged Peak Energy Inc.	exhibit233ryderconsentq420.htm
EX-23.1 - EXHIBIT 23.1 - Jagged Peak Energy Inc.	exhibit231kpmgincconsentq4.htm

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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, 2016

¨ 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)

1125 17th Street, Suite 2400 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 ¨ No x

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 ¨ No x

Indicate by check mark whether the registrant has submitted electronically and posted to its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer o	Accelerated filer o	Non-accelerated filer x (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.): Yes ¨ No x

As of June 30, 2016, the last business day of the registrant’s most recently completed second quarter, there was no public market for the registrant’s common stock. The registrant’s common stock began trading on the New York Stock Exchange on January 27, 2017.

The registrant had 212,937,746 shares of common stock outstanding at March 17, 2017.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for the 2017 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2016, are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.

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TABLE OF CONTENTS



Glossary of Oil and Natural Gas Terms		1
Cautionary Statement Regarding Forward-Looking Statements		6
Emerging Growth Company Status		8

Part I

Items 1 and 2.	Business and Properties	9
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	42
Item 3.	Legal Proceedings	42
Item 4.	Mine Safety Disclosures	42

Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	43
Item 6.	Selected Financial Data	44
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	63
Item 8.	Financial Statements and Supplementary Data	64
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	64
Item 9A.	Controls and Procedures	64
Item 9B.	Other Information	65

Part III

Item 10.	Directors, Executive Officers and Corporate Governance	66
Item 11.	Executive Compensation	66
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	66
Item 13.	Certain Relationships and Related Transactions, and Director Independence	66
Item 14.	Principal Accounting Fees and Services	66

Part IV

Item 15.	Exhibits, Financial Statement Schedules	67
Item 16.	Form 10-K Summary	68

Signatures		69

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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 generally brought by water accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

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).

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Estimated ultimate recovery or EUR. The sum of reserves remaining as of a given date and cumulative production as of that date.

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 interval.

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.

Net acres. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. For example, an owner who has 50% interest in 100 acres owns 50 net acres.

Net production. Production that is owned by us less royalties and production due 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.

Net well. The percentage ownership interest in a well that an owner has based on such owner’s working interest in that well. An owner who has a 50% working interest has a 0.50 net well.

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.

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Offset operator. Any operator that has an active lease on an adjoining property for oil, natural gas or NGL purposes.

Operator. The individual or company responsible for the development and/or production of an oil or natural gas well or lease.

Play. A geographic area with hydrocarbon potential.

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.

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 or PUDs. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. 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

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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 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 area or “development type” if drilled in a known area.

Success rate. The percentage of wells drilled which produce hydrocarbons in commercial quantities.

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.

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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 that is widely quoted by financial markets.

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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 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” and the other information included in this Annual Report on Form 10-K.

Forward-looking statements may include statements about:


•	our business strategy;


•	our reserves;


•	our drilling prospects, inventories, projects and programs;


•	our ability to replace the reserves we produce through drilling and property acquisitions;


•	our ability to convert PUDs to proved producing properties within five years of their initial proved booking date:


•	our financial strategy, liquidity and capital required for our drilling program;


•	our realized oil, natural gas and NGL prices;


•	the timing and amount of our future production of oil, natural gas and NGLs;


•	our future drilling plans and anticipated well economics;


•	our competition and government regulations;


•	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;


•	general economic conditions;


•	credit markets;


•	uncertainty regarding our future operating results; 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” and elsewhere in this 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 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 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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Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act, or the “JOBS Act.” For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, we are not required to:


•	provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;


•	comply with any new requirements adopted by the Public Company Accounting Oversight Board, or the “PCAOB,” requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;


•	provide certain disclosure regarding executive compensation required of larger public companies or hold shareholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”); or


•	obtain shareholder approval of any golden parachute payments not previously approved.

We will cease to be an “emerging growth company” upon the earliest of:


•	the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;


•	the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more measured as of June 30);


•	the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or


•	the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, or the “Securities Act,” for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

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PART I


ITEMS 1 AND 2.	BUSINESS AND PROPERTIES

General

Jagged Peak Energy Inc., a Delaware corporation (“JPE Inc.” or the “Company”), is an independent oil and natural gas exploration and production company with operations in the Southern Delaware Basin, a sub-basin of the Permian Basin of West Texas. Throughout this Form 10-K the terms “we,” “our,” “us” or like terms and the “Company” and “Jagged Peak” refer to, prior to the initial public offering of JPE Inc. (the “IPO”), Jagged Peak Energy LLC (“JPE LLC”) and, after the IPO, to JPE Inc. and its subsidiary, JPE LLC.

JPE LLC, a Delaware limited liability company, was formed in April 2013 by an affiliate of Quantum Energy Partners (“Quantum”) and key members of our management team. JPE Inc. 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 Company’s IPO, JPE LLC became a wholly-owned subsidiary of the Company.

Information presented in this Form 10-K on a pro forma basis gives effect to the completion of the corporate reorganization and the IPO, and information in this Form 10-K with respect to our predecessor reflects the activities of JPE LLC.

Business Overview

We are a growth-oriented, 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) growing production and reserves through the development of our multi-year inventory, (ii) expanding and improving the resource potential of our existing acreage position and (iii) growing our acreage position through acquisitions and leasing efforts.

The following table summarizes information regarding our operations as of December 31, 2016:



Area	Estimated Proved Reserves (MBoe)	% Oil		Total Net Acres	Gross Potential Drilling Locations	Avg Lateral Length (feet)	2016 Avg Daily Production (Boe/d)
Southern Delaware Basin	37,695	81	%	66,393	1,303	7,375	5,613

During 2016, our average daily production of 5,613 Boe/d averaged 83% oil, 9% NGLs and 8% natural gas.

Our Properties and Operations

The Permian Basin consists of mature, legacy, onshore oil and liquids-rich natural gas reservoirs that span approximately 86,000 square miles in West Texas and New Mexico. The basin is composed of five sub regions: the Delaware Basin, the Central Basin Platform, the Midland Basin, the Northwest Shelf and the Eastern Shelf. Since our inception, we have specifically targeted the Southern Delaware Basin, which we consider to be the eastern and southern portion of the Permian Basin, due to the abundant amount of oil-in-place, stacked pay potential, low breakeven prices, attractive well economics, favorable operating environment and in-place midstream infrastructure. The Southern Delaware Basin is further characterized by high quality oil and liquids-rich natural gas reservoirs, a well-developed network of oilfield service providers, and long-lived reserves from well-understood geologic features of predictable reservoir quality with historically high development success rates. We have assembled our current acreage position by executing privately sourced acquisitions of largely underdeveloped acreage and through grassroots leasing.

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, 2016, we operated approximately 98% of our net acreage and held an average 92% working interest in approximately 72,306 gross (66,393 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 on reducing drilling times, optimizing completions and reducing costs. We expect that further optimization in the field, which may include increased drilling of longer laterals, pad

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drilling, use of shared facilities and zipper fracs (i.e. fracturing adjacent wells in sequence, with one well holding frac pressure while the adjacent well is fractured) will continue to improve our well economics going forward.

We divide our current area of operation within the Southern Delaware Basin into three distinct 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 is just west of the junction between Ward, Reeves and Pecos Counties in Texas. The Whiskey River project area also includes a leasehold block informally named County Line, which is in northern Pecos County, just south of the majority of the Whiskey River leasehold. The Big Tex project area is our southernmost leasehold position and lies in northern Pecos County. The following table summarizes our acreage by project area as of December 31, 2016.



	Acreage
Project Area:	Gross	Net
Cochise	13,935	13,319
Whiskey River	35,938	31,386
Big Tex	22,433	21,688
Total	72,306	66,393

Through December 31, 2016, we have drilled, completed and are producing from 20 operated horizontal wells in three distinct zones: Lower Wolfcamp A, Upper Wolfcamp A and Wolfcamp B. Based on the wells we have drilled to date and wells drilled by other operators, we believe these formations, along with the 3rd Bone Spring Sand formation, are significantly delineated across our acreage. As a result, we have broadly appraised our acreage across all three project areas and several stratigraphic zones. Other operators have been active in drilling and completion operations on acreage offsetting our acreage position. We continue to monitor this offset activity, especially with respect to downspacing pilots, and adjust our future development plans accordingly to allow for the optimal development of our acreage position. We also believe significant additional development opportunities exist on our acreage in the Brushy Canyon, Avalon Shale, 1st Bone Spring Sand, 2nd Bone Spring Sand and Wolfcamp C 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 1,303 gross horizontal drilling locations, 70% are classified as long or extra-long laterals, with an average length of 8,792 feet. We consider laterals of 5,600 feet and lower as standard length, laterals between 5,600 feet and 8,250 feet to be long, and laterals greater than 8,250 feet to be extra-long. The ability to drill long-lateral wells improves our returns by (i) increasing our estimated ultimate recovery (“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 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.

Since commencing our drilling program in late 2013, we have consistently increased EURs and improved our well and field-level returns by refining our landing zones, drilling longer length laterals and enhancing our completion techniques. We operated an average of one horizontal drilling rig from late 2013 through June 2016.We began operating our second and third rigs in July of 2016. At December 31, 2016, we were operating three horizontal rigs which contributed two completed wells, both of which began producing in November 2016. During 2017 we expect to operate a five to six-rig drilling program, and expect to operate two to four fracturing fleets, as needed, to complete wells in a timely manner. Our average daily production has grown from 345 Boe/d in the first quarter of 2014 (normalized for five days of production) to 6,438 Boe/d in the fourth quarter of 2016.

While increasing our average daily production, we have also substantially reduced drilling days for our horizontal wells. The average time from spud to rig release for wells drilled during 2016 was approximately 36 days, compared to an average of 50 days for wells drilled in 2015. We also continue to modify our completion design to optimize the performance of our wells and expect to realize further drilling efficiencies going forward.

During 2016, we completed and began production on 11 gross (10.9 net) wells, all of which we operated. As of December 31, 2016, we have drilled, completed and are producing from 20 gross (19.3 net) wells. At year-end, we were in the process of drilling four gross (4.0 net) wells, and were awaiting the completion of six gross (5.9 net) additional wells.

As part of our development plan, we have also made a strategic decision to construct and operate water handling infrastructure to source fresh water and dispose of flowback and produced water within our project areas, which allows us to realize significant operating and cost efficiencies. We have installed, and will continue to install, water handling infrastructure

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to accommodate our projected future production growth. We currently have disposal capacity of more than three times our current produced water volumes and sufficient sources of fresh water to support our current drilling program, and we believe our water infrastructure is scalable to support additional rigs. This infrastructure position provides important cost advantages compared to utilizing third-party services.

Proved Reserves

Evaluation and Audit of Proved Reserves. Our proved reserve estimates as of December 31, 2016, 2015 and 2014, were prepared by Ryder Scott Company, LP (“Ryder Scott”), our independent petroleum engineers. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott does not own an interest in any of our properties, nor is it employed by us on a contingent basis. A copy of Ryder Scott’s proved reserve report as of December 31, 2016 is included as an exhibit to this Form 10-K.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to Ryder Scott for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. James T. Jaggers, our Reservoir Engineering Manager, is primarily responsible for overseeing the preparation of all of our reserve estimates. James T. Jaggers is a reservoir engineer with over 11 years of reservoir and operations experience, and has been licensed by the Texas Board of Professional Engineers since 2009. Our geoscience staff has an average of approximately 11 years of energy industry experience.

The preparation of our proved reserve estimates was completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:


•	review and verification of historical production data, which data is based on actual production as reported by us;


•	review of reserve estimates by our Reservoir Engineering Manager or under his direct supervision;


•	review by our Vice President, Development Planning & Geoscience of all of our reported proved reserves, including the review of all significant reserve changes and all new PUDs additions;


•	direct reporting responsibilities by our Vice President, Development Planning & Geoscience to our Chief Executive Officer and President; and


•	verification of property ownership by our land department.

Estimation of Proved Reserves. Under rules set forth by the United States Securities and Exchange Commission (the “SEC”), proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2016, 2015 and 2014 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the SEC’s regulations. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (i) performance-based methods; (ii) volumetric-based methods; and (iii) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Proved reserves for our properties were estimated by performance methods for the majority of properties. Certain new producing properties with inadequate historical production data were forecast using analogy or a combination of methods. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods.

To estimate economically recoverable proved oil and natural gas reserves and related future net cash flows, Ryder Scott considered many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that

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establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

Summary of Reserves. The following table presents our estimated net proved reserves as of December 31, 2016, 2015 and 2014, 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,
	2016	2015	2014
Proved Developed Reserves:
Oil (MBbls)	11,916	4,848	1,529
Natural gas (MMcf)	6,566	2,547	1,319
NGLs (MBbls)	1,491	621	288
Total equivalent proved developed reserves (MBoe)	14,501	5,894	2,037
Proved Undeveloped Reserves:
Oil (MBbls)	18,490	5,645	389
Natural gas (MMcf)	12,953	3,610	310
NGLs (MBbls)	2,545	870	77
Total equivalent proved undeveloped reserves (MBoe)	23,194	7,117	518
Total Proved Reserves:
Oil (MBbls)	30,406	10,493	1,918
Natural gas (MMcf)	19,519	6,157	1,629
NGLs (MBbls)	4,036	1,491	365
Total equivalent proved reserves (MBoe)	37,695	13,011	2,555

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, transportation 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 for 2016, 2015 and 2014.



	At December 31,
	2016		2015		2014
Oil price per Bbl	$	39.33	$	46.26	$	84.54
Gas price per Mcf	$	2.22	$	2.36	$	4.21
NGL price per Bbl	$	15.48	$	16.49	$	31.17

Estimated proved reserves at December 31, 2016 were 37.7 MMBoe, compared to 13.0 MMBoe and 2.6 MMBoe at December 31, 2015 and 2014, respectively. The increases in proved reserves during 2016 and the year ended December 31, 2015 were primarily related to drilling activities. During 2016, we drilled and completed 11 gross (10.9 net) wells and added 25 PUD locations. We also drilled, or were in the process of drilling, 10 gross (9.9 net) additional wells. This activity resulted in a combined increase of 25.2 MMBoe through extensions and discoveries. We acquired two wells and an additional 25% working interest in another section, which added a combined 0.5 MMBoe. Over this time period, we also had approximately 1.1 MMBoe of upward revisions to prior forecasts due to increased performance from our wells, despite negative impacts from the decline in average oil and natural gas pricing between periods.

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Proved Undeveloped Reserves

Proved undeveloped reserves (“PUDs”) are included in the previous table of total proved reserves. The following table summarizes the changes in our estimated PUDs during 2016:



	(in MBoe)
Proved undeveloped reserves at December 31, 2015	7,117
Converted to developed	(3,034	)
Additions	18,651
Net revisions	460
Proved undeveloped reserves at December 31, 2016	23,194

We saw a net increase of 16.1 MMBoe in PUD reserves during the year ended December 31, 2016. The increase in PUD reserves included 25 new PUD locations, totaling 18.7 MMBoe, that were added as a result of offset drilling. Development drilling resulted in the reclassification of 3.0 MMBoe to proved developed reserves.

During 2016, we converted approximately 3.0 MMBoe of PUDs to proved developed reserves at a total capital cost of approximately $43.7 million. Our estimated total capital costs to develop our remaining proved undeveloped reserves at December 31, 2016 are approximately $278.2 million.

As of December 31, 2016, all of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. Additionally, as of December 31, 2016, 1.5 MMBoe of our proved developed reserves were classified as proved developed non-producing, and related to two wells that began producing in February 2017.

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,
	2016		2015		2014
Production:
Oil (MBbls)	1,702		718		189
Natural gas (MMcf)	953		404		172
NGLs (MBbls)	194		89		35
Total (MBoe)	2,054		874		253
Average sales price:
Oil (per Bbl)	$	41.18	$	43.92	$	77.28
Natural gas (per Mcf)	$	2.32	$	2.35	$	3.76
NGLs (per Bbl)	$	15.81	$	14.93	$	29.40
Total (per Boe)	$	36.68	$	38.69	$	64.35
Average sales price after impact of cash-settled derivatives:
Oil (per Bbl)	$	39.84	$	52.19	$	81.32
Natural gas (per Mcf)	$	2.32	$	2.35	$	3.76
NGLs (per Bbl)	$	15.81	$	14.93	$	29.40
Total (per Boe)	$	35.57	$	45.48	$	67.37
Operating expenses per Boe:
Lease operating expenses	$	3.65	$	3.62	$	8.07
Gathering and transportation expenses	$	0.51	$	0.20	$	0.48
Production and ad valorem taxes	$	2.12	$	2.57	$	3.64

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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, 2016. 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

4,587

4,475

67,719

61,918

72,306

66,393

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. Substantially all of the leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 120 to 180 days after the completion of the last well drilled on such lease, without the requirement of a lease extension payment. 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 locations associated with proved undeveloped reserves 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, 2016, approximately 31% of our total net acreage was held by production or drilling operations.

The following table sets forth the number of net undeveloped acres as of December 31, 2016 that will expire unless production is established within the spacing units covering the acreage prior to the expiration dates, or unless such acreage is extended or renewed. As of December 31, 2016, all of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.



Area	2017	2018	2019	Thereafter
Southern Delaware Basin	9,866	10,224	15,149	9,766

Drilling Results

The following table sets forth information with respect to the number of wells completed 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.



	2016		2015		2014
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells
Productive⁽¹⁾	—	—	—	—	—	—
Dry⁽²⁾	—	—	1.0	1.0	—	—
Total Exploratory	—	—	1.0	1.0	—	—
Development Wells
Productive⁽¹⁾	11.0	10.9	7.0	6.4	5.0	4.8
Dry⁽³⁾	—	—	—	—	—	—
Total Development	11.0	10.9	7.0	6.4	5.0	4.8
Total Wells
Productive⁽¹⁾	11.0	10.9	7.0	6.4	5.0	4.8
Dry	—	—	1.0	1.0	—	—
Total	11.0	10.9	8.0	7.4	5.0	4.8

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(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.


(2)	Relates to a vertical test well drilled to an unproductive shallow horizon.


(3)	Does not include one gross (one net) wellbore temporarily abandoned in 2016 due to mechanical failure.

The figures in the table above do not include 10 gross (9.9 net) wells that were in the process of being drilled or completed, or which were awaiting completion at December 31, 2016.

Productive Wells

As of December 31, 2016, we owned a 98% average working interest in 50 gross (49.0 net) productive wells. Our wells are oil wells that 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 gathering agreement entered into in 2015 pursuant to which we have dedicated all of our oil production from our Whiskey River and Cochise acreage. We sell substantially all of our oil production pursuant to short-term marketing agreements. 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 and Big Tex acreage pursuant to a gathering and processing agreement expiring in the fall of 2017, with substantially all of such natural gas transported from the wellhead by third-party gathering lines to natural gas processing facilities. None of our sales and transportation agreements contain minimum volume commitments or other similar provisions.

In October 2016, we entered into a long-term natural gas gathering and processing agreement for our Whiskey River acreage. We began selling natural gas under this agreement in early 2017.

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 2016, revenues from Trafigura Trading, LLC and Sunoco Partners Marketing accounted for approximately 57% and 31%, respectively, of our total revenue. During 2016, no other purchaser accounted for 10% or more of our revenue. The loss of either of these purchasers could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas 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 crude oil and natural gas are fungible products with well-established markets.

Infrastructure

Our infrastructure strategy includes owning sufficient tracts of surface acreage to (i) allow us to control fresh water supply for drilling and completions, (ii) provide ease of pipeline installation, (iii) allow construction of storage for both fresh and produced water and (iv) simplify construction of 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 services from adjacent landowners. As of December 31, 2016, we had approximately 3,895 surface acres on which our installed and contracted capacities were (i) 4.7 million barrels of water storage capacity, (ii) 10.5 miles of fresh water pipelines and 63.6 miles of produced water pipelines, which allows us to largely eliminate water trucking in all phases of our operation, (iii) 162 thousand barrels per day of water sourcing capacity and (iv) 86 thousand barrels per day of water disposal capacity. Accordingly, we have disposal capacity more than three times our current produced water volumes and sufficient sources of fresh water to support our current drilling program, and we believe our water infrastructure is scalable to support additional rigs. This infrastructure position provides important cost advantages compared to utilizing third-party services.

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

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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. In addition, 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 affect the demand for, and prices of, oil and natural gas. Due to colder weather, demand for oil and natural gas is typically higher in the fourth and first quarters, resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

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 rights-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. The lessor royalties and other leasehold burdens on our properties generally range from 22.5% to 25.0%, resulting in a net revenue interest to us generally ranging from 75.0% to 77.5%.

Regulation of the Oil and Natural Gas Industry

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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. All of the jurisdictions in which we own or operate producing oil and natural gas properties have 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. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. In addition, policies, proposals and proceedings that affect the oil and natural gas industry may change under the new Presidential Administration. 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.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Texas, which regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, 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 and NGLs, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures 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 in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate transportation of oil, including natural gas liquids, under the Interstate Commerce Act (“ICA”). Prices received from the sale of oil liquids may be affected by the cost of transporting those products to market. The ICA requires that pipelines 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,

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that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. 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 Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act (“NGPA”), and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

The Energy Policy Act of 2005 (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 to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of 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, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, 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 the extent such transactions utilize, contribute to, or may contribute to the formation of price indices to FERC on Form No. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case by case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional

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transmission 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 a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of the gathering facilities we use are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission (“CFTC”). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas 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

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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 U.S. Environmental Protection Agency (the “EPA”) or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration 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 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.

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. To the extent the Clean Water 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. The rule has been challenged in court on the grounds that it unlawfully expands the reach of the Clean Water Act, and implementation of the rule has been stayed pending resolution of the court challenge. 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

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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 (“OPA”), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Air Emissions

The 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 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. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. 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. The federal Bureau of Land Management (“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

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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 and proposed rules could result in increased compliance costs on our operations.

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 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. 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 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 (“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 Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming struck down the final rule, finding that the BLM lacked congressional authority to promulgate the rule. The BLM has appealed this decision, and a final decision remains pending. 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 are either underway or being 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 ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

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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 Railroad Commission of Texas 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 Railroad Commission of Texas 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. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from drilling wells.

ESA and Migratory Birds

The Endangered Species Act (“ESA”) and, in some cases, comparable state laws were established to protect endangered and threatened species. Because listing a 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. As a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to determine whether to list more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. 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. Additionally, the Department of the Interior has maintained that the Migratory Bird Treaty Act prohibits death of and injury to migratory birds resulting from activities such as oil and gas development. The federal government has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The presence of, or potential presence of, threatened or endangered species, critical habitat, or migratory birds 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 2016, nor do we anticipate that such expenditures will be material in 2017 or 2018.

Related Insurance

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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 1125 17th Street, Suite 2400, Denver, Colorado, 80202, and our telephone number at that address is (720) 215-3700.

As of December 31, 2016, we had 36 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.

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 Exchange Act. The public may read and copy any materials that we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file or furnish electronically with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov.

We also make available free of charge through our website, www.jaggedpeakenergy.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this 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, 2014 through February 28, 2017, the WTI spot price for oil declined from a high of $107.95 per Bbl on June 20, 2014, to $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas declined from a high of $8.15 per MMBtu on February 10, 2014, to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. 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 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;

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•	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.

Beginning in 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand, which has continued through 2016, resulting in a sustained decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begin to decline, prices will likely remain under pressure. The U.S. dollar has also strengthened relative to other leading currencies, which has caused oil prices to weaken, as they are U.S. dollar-denominated. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and remained weak throughout 2015 and 2016. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The continued duration and magnitude of these commodity price declines cannot be accurately predicted.

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 West Texas Intermediate 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 proved undeveloped reserves 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.

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 2017 capital budget for drilling, completion and recompletion activities and facilities costs is expected to range from $555.0 million to $605.0 million, excluding potential acquisitions. In addition, our production costs may increase as we continue to use enhanced recovery techniques 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 from

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current levels 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;


•	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; and


•	the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. 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 unevaluated properties and the value of our undeveloped acreage could decline in the future.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our 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. For a discussion of the uncertainty involved in these processes, 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:

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•	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;


•	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.

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, 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, 2016, we had identified 1,303 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, consisting of laterals with an average length of 7,375 feet. 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 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

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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, 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 generally 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.

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.

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 credit agreement contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:


•	incur additional indebtedness;


•	incur liens;


•	make investments;

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•	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.

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—Credit Facility,” we are required to maintain a ratio of current assets to current liabilities of not less than 1.0 to 1.0.

Further, under our credit agreement, we are only permitted to hedge up to the greater of 85% of our proved reserves and 75% of our reasonably anticipated production for up to 24 months in the future, and up to the greater of 75% of our proved reserves and 50% of our reasonably anticipated production for 25 to 60 months in the future, provided that no hedges may have a term beyond five years.

The restrictions in our credit agreement 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 under our credit agreement impose on us.

A breach of any covenant in our credit agreement would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under our credit agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under 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 on April 1 and October 1. The borrowing base depends on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties 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.” 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. Our borrowing base was $160.0 million as of December 31, 2016; however, we entered into an amended and restated credit facility in connection with the IPO with an initial borrowing base of $180.0 million. Our next scheduled borrowing base redetermination will occur on or about April 1, 2017.

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.

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.

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As of December 31, 2016, approximately 31% of our total net acreage was held by production or 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. 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:


•	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 may negatively affect our operating results and our ability to conduct drilling activities.

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, 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.

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 both the drilling and hydraulic fracturing processes. Drought conditions have persisted in Texas in past years. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations or dispose of or recycle water used in operations, o 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.

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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, 2016, 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 $21 per barrel in August 2014. If the Midland-Cushing differential, or other price differentials pursuant to which our production is subject, were to widen due to oversupply or other factors, our revenue could be negatively impacted.

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, 2016, approximately 62% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated

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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.

We depend upon several significant purchasers 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 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 several significant purchasers 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

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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;


•	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 micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. 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.

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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 imposes certain limitations on our ability to enter into mergers or combination transactions. Our credit agreement also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

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 had 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, had 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. Decreased levels of drilling activity in the oil and natural gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, 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.

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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, the 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 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 and the increased occurrence of seismic activity, 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 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and natural gas extraction. In addition, a number of lawsuits have been filed in other states, most recently in Oklahoma, 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 of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an

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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.

We dispose of large volumes of produced water gathered from our drilling 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 new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise 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 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. 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.

The termination of employment of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

Our 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.

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.

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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 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.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development. Additionally, future federal, state or local legislation may impose new or increased taxes or fees on oil and natural gas extraction.

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.

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 of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our 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 are in the process of promulgating other rules, required to implement the derivatives regulatory provisions of the Dodd-Frank Act.

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Among the rules currently proposed for adoption by the CFTC are proposed 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 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 any 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.

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 to be adopted 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 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.

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 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 will be reflected in future standardized measure computations.

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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.

Our business is difficult to evaluate because we have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion.

Jagged Peak Energy LLC was formed in 2013. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

In addition, we have grown rapidly over the last several years. Our management believes future success depends on our ability to manage the rapid growth we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:


•	increased responsibilities for our executive level personnel;


•	increased administrative burden;


•	increased capital requirements; and


•	increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.

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

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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.

Quantum beneficially owns approximately 68.7% 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 a 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 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 intend to 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 will 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, five of our directors, Messrs. Davidson, Linn, VanLoh, Jr., Verma and Webster, serve as Venture Partner, Senior Advisor, Founder and Chief Executive Officer, President and

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Managing Director, respectively, of Quantum Energy Partners, which 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 will, among other things:


•	permit Quantum and its affiliates and our non-employee directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and


•	provide that if Quantum or any of its affiliates who is also one of our non-employee 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 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.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, President Obama signed into law the JOBS Act. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues at the end of any fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates measured as of June 30, or issue more than $1.0 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging

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growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

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.


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

The Company’s common stock began trading on the NYSE under the symbol “JAG” on January 27, 2017. Prior to that, there was no public market for our common stock. As a result, we have not set forth quarterly information with respect to the high and low prices for our common stock for the two most recent fiscal years or provided a performance graph.

On March 17, 2017, the closing price of our common stock as reported by the NYSE was $12.18 per share, and we had approximately 40 holders of record.

Dividends

We have not declared or paid any cash dividends since our inception. Covenants contained in our credit agreement place restrictions on our ability to pay cash dividends. We currently intend to retain future earnings, if any, to finance our operations and the growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant.

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ITEM 6.	SELECTED FINANCIAL DATA

The following tables show selected historical consolidated financial data, for the periods and as of the dates indicated, of JPE LLC, our accounting predecessor. 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 financial statements and related notes, each of which is included in this report.



	Year Ended December 31,
	2016			2015			2014
	(in thousands, except per share data)
Statements of Operations Data:
Revenues:
Oil sales	$	70,078		$	31,534		$	14,605
Natural gas sales	2,213			948			646
NGL sales	3,068			1,329			1,029
Other operating revenues	1,163			40			—
Total revenues	76,522			33,851			16,280
Operating expenses:
Lease operating expenses	7,505			3,165			2,041
Gathering and transportation expenses	1,046			171			121
Production and ad valorem taxes	4,345			2,244			920
Depletion, depreciation, amortization and accretion	40,417			22,685			8,444
Impairment of oil and natural gas properties and dry hole costs	1,564			6,489			1,414
Other operating expenses	1,941			261			64
General and administrative	11,690			7,446			7,330
Total operating expenses	68,508			42,461			20,334
Income (loss) from operations	8,014			(8,610		)	(4,054		)
Other income (expense):
Gain (loss) on commodity derivatives	(15,145		)	1,323			5,375
Interest expense and other	(2,629		)	(197		)	—
Total other income (expense)	(17,774		)	1,126			5,375
Net income (loss)	$	(9,760	)	$	(7,484	)	$	1,321

Pro Forma C-Corporation Data (unaudited)⁽¹⁾:
Net income (loss) before taxes	$	(9,760	)
Pro forma income tax (expense) benefit	2,989
Pro forma net income (loss)	$	(6,771	)

Pro Forma Per-Share Data (unaudited)⁽¹⁾:
Net income (loss) per common share:
Basic	$	(0.03	)
Diluted	$	(0.03	)

Cash Flow Data:
Net cash provided by operating activities	$	32,083		$	20,372		$	7,615
Net cash used in investing activities	$	(195,425	)	$	(110,232	)	(187,067		)
Net cash provided by financing activities	$	160,904		$	70,397		199,800

Other Financial Data:
Adjusted EBITDAX⁽²⁾	$	48,995		$	26,510		$	6,631

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	December 31,
	2016		2015		2014
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	11,727	$	14,165	$	33,628
Total oil and gas properties, net	$	473,592	$	302,726	$	214,188
Total assets	$	518,392	$	327,732	$	257,084
Senior secured revolving credit facility	$	132,000	$	20,000	$	—
Other long-term liabilities	$	3,859	$	779	$	850
Total members' equity	$	326,112	$	284,330	$	240,814

_______________________________________________________________________________

(1)

JPE Inc. is a Subchapter C corporation (“C-corp”) under the Internal Revenue Code of 1986, as amended (the “Code”), and is subject to U.S. federal, state and local income taxes. Although our predecessor was subject to franchise tax in the State of Texas, it generally passed through its taxable income to its owners for other income tax purposes and thus was not subject to U.S. federal income taxes or other state or local income taxes. The Company computed a pro forma tax provision for 2016 as if our predecessor was subject to income taxes since January 1, 2016. We have included pro forma financial data to give effect to income taxes assuming the earnings (losses) of our predecessor had been subject to federal income tax as a C-corp during 2016. We have also included pro forma per share data, assuming the weighted-average number of shares of common stock outstanding was calculated as if the common shares issued in the IPO, 212,938 (in thousands), had been outstanding since January 1, 2016. The unaudited pro forma data is presented for informational purposes only and does not purport to project our results of operations for any future period or our financial position as of any future date. The pro forma tax provision has been calculated at a rate based on upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences.


(2)	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 and dry hole costs, exploration expenses, stock-based compensation expense, income taxes, gains or losses on derivatives, net, 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 and book values of assets, capital structures 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 and exploration expenses, 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,
	2016			2015			2014
	(in thousands)
Reconciliation of Net income (loss) to Adjusted EBITDAX:
Net income (loss)	$	(9,760	)	$	(7,484	)	$	1,321
Interest expense, net of capitalized interest	2,629			197			—
Depletion, depreciation, amortization and accretion	40,417			22,685			8,444
Impairment of oil and natural gas properties and dry hole costs	1,564			6,489			1,414
Exploration expenses⁽¹⁾	1,292			11			64
Stock-based compensation expense	—			—			—
Income tax expense (benefit)	—			—			—
(Gain) loss on commodity derivatives, net, less net cash from derivative settlements⁽²⁾	15,145			(1,323		)	(5,375		)
Adjusted EBITDAX	$	48,995		$	26,510		$	6,631

_______________________________________________________________________________


(1)	Primarily includes delay rental costs to maintain leases.


(2)	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 financial statements and related notes included elsewhere in this report. The following discussion contains forward-looking statements that reflect 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,” all of which are difficult to predict. 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.

Jagged Peak Energy Inc. and Our Predecessor

Jagged Peak Energy Inc. was formed in September 2016 and does not have historical operating results. For purposes of this Annual Report, our accounting predecessor reflects the results of Jagged Peak Energy LLC (our “predecessor”), which was formed in 2013 to engage in the acquisition, development, exploration and exploitation of oil and natural gas reserves in the Permian Basin. In connection with the IPO, a corporate reorganization took place whereby Jagged Peak Energy LLC became a wholly owned subsidiary of Jagged Peak Energy Inc.

Factors Affecting the Comparability of Our Results of Operations to the Historical Results of Our Predecessor

Our future results of operations may not be comparable to the historical results of operations of our predecessor for the periods presented, primarily for the reasons described below.

Public Company Expenses

We incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including, but not limited to, 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 the predecessor’s historical results of operations.

Income Taxes

Jagged Peak Energy LLC, our predecessor, was not subject to federal income taxes. Accordingly, the financial data attributable to our predecessor contain no provision for federal income taxes because the tax liability with respect to our taxable income was passed through to our predecessor’s owners. Our predecessor was subject to franchise tax in the state of Texas at a statutory rate of up to 1.00% of a portion of gross revenues apportioned to Texas. Conversely, we are taxed as a C-corp under the Code and subject to income taxes at a blended statutory rate of approximately 35.5% of pretax earnings.

Corporate Reorganization

The corporate reorganization that was completed immediately prior to the closing of the IPO provided a mechanism by which the shares of our common stock were to be allocated amongst the owners of the predecessor, including the holders of our management incentive units. The management incentive units were accounted for under FASB Accounting Standards Codification (“ASC”) Topic 710, Compensation–General, and were not deemed probable at December 31, 2016, therefore no expense was recognized. As a result of the IPO, the satisfaction of all conditions relating to certain management incentive units in JPE LLC held by the current and former officers and employees who owned equity interests in JPE LLC, was deemed probable. As a result, based on our IPO price of $15.00 per share, compensation expense of $532.6 million will be recognized, all of which will be noncash except for $14.7 million related to a management incentive advance payment made in April 2016.

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Increased Drilling Activity

Our board of directors approved a capital budget for 2017 which is projected to range from $555.0 million to $605.0 million, excluding acquisitions. We expect to allocate between $510.0 million and $550.0 million of our 2017 capital budget for the drilling and completion of operated and non-operated wells. At the midpoint, our 2017 capital budget represents a 170% increase over our 2016 capital spending of $215.1 million, which includes $7.5 million of proved property acquisition costs. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results.

Overview

We are a growth-oriented, 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, a sub-basin of the Permian Basin and one of the most prolific unconventional resource plays in North America. 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. We divide our current areas of operation into three distinct areas: Cochise, Whiskey River and Big Tex. As of December 31, 2016, we held 31,386 net acres in the Whiskey River area and 21,688 net acres in the Big Tex area. In addition, we held 13,319 net acres in the Cochise area.

As of December 31, 2016, our estimated proved reserves were approximately 37.7 MMBoe, consisting of 81% oil. We seek to maintain operational control of our properties in order to better execute on our strategy of enhancing returns through operating improvements and cost efficiencies. As the operator of approximately 98% 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

The oil and gas industry is cyclical and commodity prices can be volatile. In the second half of 2014, oil prices began a rapid and significant decline as global supply began to outpace demand. During 2015 and through the first quarter of 2016, global oil supply continued to outpace demand resulting in further deterioration in realized oil prices. While oil prices have continued to be erratic, they have improved. It is likely that oil prices will remain erratic due to the ongoing global supply and demand imbalance, high inventories and geopolitical factors.

Due to an imbalance between supply and demand across North America, prices for domestic natural gas and NGLs began to decline during the third quarter of 2014 and continued to be weak through the first quarter of 2016. Beginning late in the second quarter of 2016, prices for natural gas and NGLs have strengthened, however, future prices will likely continue to fluctuate.

Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL production. Compared to 2015, our realized oil price for 2016 decreased 6% to $41.18 per barrel, and our realized natural gas price declined 1% to $2.32 per Mcf for the same period. Conversely, our realized price for NGLs improved by 6% to $15.81 per barrel. 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 weak commodity prices, we 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 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.

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2016 Summary of Operating and Financial Results

Our predecessor’s financial and operating performance for 2016 included the following results:


•	Successfully drilled and completed 11 gross (10.9 net) wells, all within the Southern Delaware Basin;


•	Increased average daily production by 134% to 5,613 Boe/d, comprised of 83% oil;


•	Oil production grew 136% to 4,649 barrels per day, natural gas volumes increased by 136% to 2.6 MMcf/d and NGL volumes rose 117% to 530 barrels per day;


•	Production revenues increased 123% to $75.4 million;


•	Increased our commercial bank syndicate from one bank to five banks, expanding our borrowing base from $20 million to $160 million. In January 2017, the borrowing base further increased to $180 million;


•	Added 25.2 MMBoe of proved reserves from extensions and discoveries;


•	Cash flow from operating activities of $32.1 million was 57% higher than the previous year;


•	Impacted by a $15.1 million loss on derivative instruments; and


•	Incurred noncash impairments to our unproved properties of $0.4 million related to acreage expirations and dry hole costs of $1.2 million related to a vertical test well drilled to an unproductive shallow horizon.

In addition, in January 2017, we completed our IPO, selling 31.6 million shares at $15.00 per share and raising $474.0 million in gross proceeds. Of the 31.6 million shares issued to the public, 28.3 million shares were sold by the Company and 3.3 million shares were sold by the selling stockholders. The proceeds of the IPO to the Company were approximately $425.0 million, which resulted in net proceeds of $397.4 million after deducting expenses and underwriting discounts and commissions. We did not receive any proceeds from the sale of 3.3 million shares by the selling stockholders.

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 2016, our production revenues were derived 93% from oil sales, 3% from natural gas sales and 4% 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 growth are highly dependent on the commodity prices we receive. Oil, natural gas and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors. A $1.00 per barrel change in our realized oil price would have resulted in a $1.7 million change in oil revenues. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.1 million change in our natural gas revenues. A $1.00 per barrel change in NGL prices would have changed NGL revenue by $0.2 million.

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,
	2016		2015		2014
Crude Oil (per Bbl):
Average NYMEX price	$	43.29	$	48.76	$	92.91
Realized price, before the effects of derivative settlements	$	41.18	$	43.92	$	77.28
Realized price, after the effects of derivative settlements	$	39.84	$	52.19	$	81.32
Natural Gas (per Mcf):
Average NYMEX price	$	2.52	$	2.63	$	4.26
Realized price	$	2.32	$	2.35	$	3.76
NGLs (per Bbl):
Average realized NGL price	$	15.81	$	14.93	$	29.40

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 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.

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In addition to sales of oil, natural gas, and NGLs, we derive a minimal portion of our revenues from third party sales of fresh water and water disposal services. These revenues are reflected as other operating revenues in the consolidated statements of operations.

Production Results

The following table presents historical production volumes for our properties for 2016, 2015 and 2014:



	Year Ended December 31,
	2016	2015	2014
Oil (MBbls)	1,702	718	189
Natural gas (MMcf)	953	404	172
NGLs (MBbls)	194	89	35
Total (MBoe)	2,054	874	253
Average net daily production (Boe/d)	5,613	2,395	693

As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add 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 drilling projects 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. As of December 31, 2016, we owned interests in 50 gross producing wells.

Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water transportation, injection and disposal, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed 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.

We monitor our operations to ensure that we are incurring LOE at an acceptable level, including monitoring our LOE on a per Boe basis to determine if any wells or properties should be shut in, repaired, recompleted or sold. This unit rate also allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers. Although we strive to reduce 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 Transportation Expenses. Gathering and transportation expenses largely consist of contractual costs to gather, transport and process our natural gas and NGLs. These costs relate to the preparation and transportation of production from the wellhead to a specified sales point and natural gas processing costs. These costs will fluctuate with increases or decreases in production volumes, contractual fees and changes in fuel and compression costs.

Production and Ad Valorem Taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by federal, state or local 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 also trend with oil and natural gas prices and vary across the different counties in which we operate.

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 of oil and natural gas properties, and deplete these costs

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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 Oil and Natural Gas Properties and Dry Hole Costs. Impairment of oil and natural gas properties and dry hole costs represent (i) the cost to reduce impaired proved oil and gas properties to their fair value, (ii) the cost of unproved properties that will no longer be held by production or extensions of leases and (iii) the costs of unsuccessful exploratory wells. The financial statements included herein reflect certain costs described in clauses (ii) and (iii) above.

Other Operating Expenses. Other operating expenses represent delay rentals for leases on certain unproved properties, 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”) consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services and legal compliance.

Interest Expense. We financed 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. We reflect interest paid to the lenders under our credit facility in interest expense. Interest expense is reflected net of capitalized interest.

Derivative Activity

Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. Due to this volatility, we expect to use commodity derivative instruments, such as collars, swaps and basis swaps to hedge price risk associated with our oil production. These hedging instruments will allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. This will 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. We may seek to hedge price risk associated with our natural gas and NGL production in the future. 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 credit agreement as of December 31, 2016, we are required to hedge a minimum of 75% of our projected oil volumes from PDP reserves for each calendar month on a two-year rolling basis. Under the amended and restated credit agreement, effective February 2017, we are not subject to any minimum hedging requirements, however, the credit agreement permits us to hedge up to the greater of 85% of our proved reserves and 75% of our reasonably anticipated production for up to 24 months in the future, and up to the greater of 75% of our proved reserves and 50% of our reasonably anticipated production for 25 to 60 months in the future, provided that no hedges may have a term beyond five years.

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Results of Operations

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Oil and Natural Gas Revenues. The following table provides the components of our production revenues for the years ended December 31, 2016 and 2015, as well as each period’s respective average prices and production volumes:



	Year Ended December 31,
(in thousands or as indicated)	2016		2015		Change			% Change
Production Revenues:
Oil sales	$	70,078	$	31,534	$	38,544		122	%
Natural gas sales	2,213		948		1,265			133	%
NGL sales	3,068		1,329		1,739			131	%
Total production revenues	$	75,359	$	33,811	$	41,548		123	%
Average sales price⁽¹⁾:
Oil (per Bbl)	$	41.18	$	43.92	$	(2.74	)	(6	)%
Natural gas (per Mcf)	$	2.32	$	2.35	$	(0.03	)	(1	)%
NGLs (per Bbl)	$	15.81	$	14.93	$	0.88		6	%
Total (per Boe)	$	36.68	$	38.69	$	(2.01	)	(5	)%
Production volumes:
Oil (MBbls)	1,702		718		984			137	%
Natural gas (MMcf)	953		404		549			136	%
NGLs (MBbls)	194		89		105			118	%
Total (MBoe)	2,054		874		1,180			135	%
Average daily production volume:
Oil (Bbls/d)	4,649		1,967		2,682			136	%
Natural gas (Mcf/d)	2,603		1,107		1,496			135	%
NGLs (Bbls/d)	530		244		286			117	%
Total (Boe/d)	5,613		2,395		3,218			134	%

_______________________________________________________________________________


(1)	Average prices shown in the table reflect prices before the effects of our realized commodity derivative transactions.

As reflected in the table above, our total production revenue for 2016 was 123%, or $41.5 million, higher than that of 2015. The increase is primarily due to higher sales volumes, partially offset by decreased revenues from lower realized commodity prices during 2016. Our aggregate production volumes in 2016 were 2,054 MBoe, comprised of 83% oil, 8% natural gas and 9% NGLs. This represents an increase of 135% over 2015 aggregate production volumes of 874 MBoe, made up of 82% oil, 8% natural gas and 10% NGLs.

Increased production volumes accounted for an approximate $46.0 million increase in year-over-year production revenues, and decreases in our total equivalent prices accounted for an approximate $4.5 million decrease in year-over-year production revenues. Production increases are largely related to our active drilling program, which added 10.9 net wells that began production during 2016.

Oil sales increased 122%, or $38.5 million, due to a 137% increase in production volumes, partially offset by a 6% decrease in the average realized price for 2016 as compared to the prior year. Natural gas sales increased 133%, or $1.3 million, primarily due to a 136% increase in volumes in 2016, somewhat offset by a 1% decrease in the average sales price. NGL sales increased 131%, or $1.7 million, primarily due to a 118% increase in sales volumes, as well as a 6% increase in the average realized price for 2016.

Other operating revenues relate to third party sales of fresh water and water disposal services. During 2016 and 2015, we recognized other operating revenue of $1.2 million and $40 thousand, respectively. The increase year-over-year is due to increased sales of our excess fresh water and water disposal capacity between periods.

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Operating Expenses. We present per-Boe information because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis.

The following table summarizes our expenses for the periods indicated:



	Year Ended December 31,									Per Boe
(in thousands)	2016		2015		Change			% Change		2016		2015
Operating expenses:
Lease operating expenses	$	7,505	$	3,165	$	4,340		137	%	$	3.65	$	3.62
Gathering and transportation expenses	1,046		171		875			512	%	$	0.51	$	0.20
Production and ad valorem taxes	4,345		2,244		2,101			94	%	$	2.12	$	2.57
Depletion, depreciation, amortization and accretion	40,417		22,685		17,732			78	%	$	19.67	$	25.94
Impairment of oil and natural gas properties and dry hole costs	1,564		6,489		(4,925		)	(76	)%	NM		NM
Other operating expenses	1,941		261		1,680			644	%	$	0.94	$	0.30
General and administrative	11,690		7,446		4,244			57	%	$	5.69	$	8.52
Total operating expenses	$	68,508	$	42,461	$	26,047		61	%	$	33.35	$	48.57

_______________________________________________________________________________

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 137% to $7.5 million in 2016, as compared to $3.2 million in 2015. The increase was primarily related to higher production between periods, which resulted in additional costs for contract labor, chemicals and electricity. In addition, in 2016 we enhanced our repair and maintenance program for our operated wells, resulting in an overall increase in workover LOE costs. While our LOE costs increased 137% overall from 2015 to 2016, our 2016 LOE per Boe of $3.65 increased only slightly compared with 2015.

Gathering and Transportation Expenses. Gathering and transportation expenses increased $0.9 million during 2016 as compared to 2015 due to increased production as well as an increase in our per unit gathering and transportation expense. The period over period increase in our per unit gathering and transportation expense was due to a shift away from marketing our natural gas under percent-of-proceeds contracts toward marketing a larger portion of our natural gas under fixed fee contracts. Under percent-of-proceeds contracts, we receive a percentage of the total proceeds received by the marketer, which is net of transportation expense and do not book a separate charge for gathering and transportation expense. Conversely, under our fixed fee natural gas marketing contracts, we receive a topline revenue amount and are separately charged for the associated gathering and transportation expense.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 94% during 2016, from $2.2 million in 2015 to $4.3 million in 2016. The increase is primarily due to an increase in revenues and the addition of several new high-volume wells.

Depletion, Depreciation, Amortization and Accretion. Our DD&A expense increased $17.7 million, or 78%, from 2015 to 2016. The increase in DD&A 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 24% to $19.67 per Boe, compared to $25.94 per Boe in 2015. The decrease in our DD&A rate was largely due to an increase in reserve volumes due to successful drilling activities, partly offset by an increase in capitalized costs in proved property from these same activities.

Impairment of Oil and Natural Gas Properties and Dry Hole Costs. We incurred $1.6 million of impairment and dry hole costs in 2016, which was primarily due to dry hole costs of $1.2 million related to a vertical test well drilled to a shallow horizon we no longer consider prospective. Also during 2016, we incurred $0.4 million of impairment costs related to the expiration of certain leases on unproved properties. In 2015 we recorded $6.5 million of impairment expense related to the expiration of certain leases on unproved properties. No impairments were recorded on proved properties during 2016 and 2015.

Other Operating Expenses. Our other operating expenses increased by $1.7 million from 2015 to 2016. We incurred $1.9 million of other operating expenses in 2016 primarily due to $1.3 million in delay rentals on certain unproved properties. Additionally, 2016 also includes $0.4 million of costs related to sales of fresh water and water disposal to third parties, and

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$0.2 million for the early termination of a rig contract. In 2015, we incurred $0.3 million of other operating expenses in conjunction with the early termination of a rig contract.

General and Administrative. G&A increased 57% to $11.7 million for the year-ended December 31, 2016, from $7.4 million for the same period of 2015. The increase was primarily due to a $2.6 million increase in employee and contractor costs required to manage our expanding capital program and production levels. The remaining increase was principally due to a $1.0 million employee separation payment paid in the first quarter of 2016, and $0.4 million of additional legal, audit, and tax expenses.

Other Income and Expense. The following table summarizes our other income and expenses for the periods indicated:



	Year Ended December 31,
(in thousands)	2016			2015			Change
Other income (expense):
Gain (loss) on commodity derivatives	$	(15,145	)	$	1,323		$	(16,468	)
Interest expense and other	(2,629		)	(197		)	(2,432		)
Total other income (expense)	$	(17,774	)	$	1,126		$	(18,900	)

Gain (loss) on Commodity Derivatives. Net gains and losses on our derivative instruments, as reflected in our statements of operations, are a function of fluctuations in the underlying commodity prices and the monthly settlement, if any, of the instruments. As a result, settlements on the contracts are included as a component of other income and expense as either a net gain or loss on noncash derivative instruments. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have noncash mark-to-market losses.

The following table sets forth the net gain (loss) from settlements and changes in the fair value of our derivative contracts, as well as the cash settlements (received) paid for the years ended December 31, 2016 and 2015.



(in thousands)	2016			2015
Gain (loss) on derivatives instruments, net	$	(15,145	)	$	1,323
Cash settlements of derivatives (received) paid	$	2,292		$	(5,935	)

Interest Expense and Other. Interest expense relates to interest on our credit facility and amortization of financing costs on this facility. During 2016 and 2015, we recorded $2.6 million and $0.2 million, respectively, of interest expense related to the borrowings on our credit facility. Interest expense for these periods was net of capitalized interest of $0.1 million and $0.03 million, respectively. The increase in interest expense in 2016 is due to additional borrowings on our credit facility, as we began borrowing on our credit facility in July 2015.

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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

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 prices and production volumes:



	Year Ended December 31,
(in thousands or as indicated)	2015		2014		Change			% Change
Production Revenues:
Oil sales	$	31,534	$	14,605	$	16,929		116	%
Natural gas sales	948		646		302			47	%
NGL sales	1,329		1,029		300			29	%
Total production revenues	$	33,811	$	16,280	$	17,531		108	%
Average sales price⁽¹⁾:
Oil (per Bbl)	$	43.92	$	77.28	$	(33.36	)	(43	)%
Natural gas (per Mcf)	$	2.35	$	3.76	$	(1.41	)	(38	)%
NGLs (per Bbl)	$	14.93	$	29.40	$	(14.47	)	(49	)%
Total (per Boe)	$	38.69	$	64.35	$	(25.66	)	(40	)%
Production volumes:
Oil (MBbls)	718		189		529			280	%
Natural gas (MMcf)	404		172		232			135	%
NGLs (MBbls)	89		35		54			154	%
Total (MBoe)	874		253		621			245	%
Average daily production volume:
Oil (Bbls/d)	1,967		518		1,449			280	%
Natural gas (Mcf/d)	1,107		471		636			135	%
NGLs (Bbls/d)	244		96		148			154	%
Total (Boe/d)	2,395		693		1,702			246	%

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(1)	Average prices shown in the table reflect prices before the effects of our realized commodity derivative transactions.

As reflected in the table above, our total production revenue for 2015 was 108%, or $17.5 million, higher than that of 2014. The increase is primarily due to higher sales volumes, partially offset by decreased revenues from lower realized commodity prices during 2015. Our aggregate volumes in 2015 were 874 Boe, comprised of 82% oil, 8% natural gas and 10% NGLs. This compares to 2014 aggregate production volumes of 253 MBoe, made up of 75% oil, 11% natural gas and 14% NGLs.

Increased production volumes accounted for an approximate $43.3 million increase in year-over-year production revenues, which was offset by decreases in our total equivalent prices which accounted for an approximate $25.8 million decrease in year-over-year production revenues. Production increases resulted from our active drilling program, as we had 6.4 net wells that began production during 2015.

Oil sales increased 116%, or $16.9 million, due to a 280% increase in production volumes, partially offset by a 43% decrease in average sales price for 2015 as compared to the prior year. Natural gas sales increased 47%, or $0.3 million, primarily due to a 135% increase in production volumes attributable to new completed wells in 2015, partially offset by a 38% decrease in average sales price as compared to the prior year. NGL sales increased 29%, or $0.3 million, primarily due to a 154% increase in production volumes attributable to new completed wells in 2015, partially offset by a 49% decrease in average sales price as compared to 2014.

Other operating revenues relate to third party sales of fresh water and water disposal services. During 2015 we recognized other operating revenue of $40 thousand. We began offering our excess fresh water and water disposal capacity to third-parties in 2015.

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Operating Expenses. The following table summarizes our expenses for the periods indicated:



	Year Ended December 31,								Per Boe
(in thousands)	2015		2014		Change		% Change		2015		2014
Operating expenses:
Lease operating expenses	$	3,165	$	2,041	$	1,124	55	%	$	3.62	$	8.07
Gathering and transportation expenses	171		121		50		41	%	$	0.20	$	0.48
Production and ad valorem taxes	2,244		920		1,324		144	%	$	2.57	$	3.64
Depletion, depreciation, amortization and accretion	22,685		8,444		14,241		169	%	$	25.94	$	33.38
Impairment of oil and natural gas properties and dry hole costs	6,489		1,414		5,075		359	%	NM		NM
Other operating expenses	261		64		197		308	%	$	0.30	$	0.25
General and administrative	7,446		7,330		116		2	%	$	8.52	$	28.97
Total operating expenses	$	42,461	$	20,334	$	22,127	109	%	$	48.57	$	80.37

_______________________________________________________________________________

NM—Not meaningful.

Lease Operating Expenses. LOE increased 55%, or $1.1 million, in 2015 as compared to 2014, due primarily to higher production between periods, resulting in increased needs for utilities, produced water disposal, repairs and maintenance. While our LOE increased overall, LOE per Boe decreased by $4.45, or 55%, from $8.07 in 2014 to $3.62 in 2015, due primarily to a higher percentage of our production coming from new high-producing, low-operating cost wells.

Gathering and Transportation Expenses. Gathering and transportation expenses increased 41%, or $0.1 million, in 2015 compared to 2014, primarily due to an increase in production volumes, as well as an increase in the amount of natural gas being sold under sales contracts that provided for certain gathering and transportation costs to be passed through to the producer.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 144% to $2.2 million in 2015, from $0.9 million in 2014. The increase was largely due to higher production revenue. Production and ad valorem taxes as a percentage of our revenue was 6.6% for 2015 compared to 5.7% for 2014. In addition, ad valorem taxes increased largely because of the completion of several new high-value wells.

Depletion, Depreciation, Amortization and Accretion. Our DD&A expense was $22.7 million in 2015, a 169% increase from $8.4 million in 2014. The increase in DD&A resulted from increased production in 2015, partially offset by a decrease in our DD&A rate. The DD&A rate per Boe decreased 22% to $25.94 in 2015 from $33.38 in 2014. The decrease in the DD&A rate was largely due to an increase in reserve volumes due to successful drilling activities, offset by an increase in capitalized costs in proved properties from these same activities.

Impairment of Oil and Natural Gas Properties and Dry Hole Costs. Impairment of oil and natural gas properties and dry hole costs increased $5.1 million in 2015 compared to 2014. In 2015 and 2014, we recorded $6.5 million and $1.4 million, respectively, of impairment expense related to the expiration of certain leases on unproved properties. No impairments were recorded on proved properties during 2015 or 2014.

Other Operating Expenses. Other operating expenses increased by $0.2 million in 2015 as compared to 2014. We incurred $0.3 million of other operating expenses in 2015 primarily related to the early termination of a rig contract. We incurred $0.1 million of other operating expenses in 2014, primarily due to delay rentals on certain unproved properties.

General and Administrative. G&A in 2015 increased 2%, or $0.1 million, as compared to 2014, primarily due to increased employee and contractor costs required to manage our growing production and capital program.

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Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:



	Year Ended December 31,
(in thousands)	2015			2014		Change			% Change
Other income (expense):
Gain on commodity derivatives	$	1,323		$	5,375	$	(4,052	)	(75	)%
Interest expense and other	(197		)	—		(197		)	(100	)%
Total other income (expense)	$	1,126		$	5,375	$	(4,249	)	(79	)%

Gain on Commodity Derivatives. Net gains and losses on our derivative instruments, as reflected in our statements of operations, are a function of fluctuations in the underlying commodity prices and the monthly settlement, if any, of the instruments. As a result, settlements on the contracts are included as a component of other income and expense as either a net gain or loss on derivative instruments. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains, while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

The following table sets forth the net gain from settlements and changes in the fair value of our derivative contracts, as well as the cash settlements (received) for the years ended December 31, 2015 and 2014.



(in thousands)	2015			2014
Gain on derivatives instruments, net	$	1,323		$	5,375
Cash settlements of derivatives (received)	$	(5,935	)	$	(763	)

Interest Expense and Other. Interest expense relates to interest on our credit facility and amortization of financing costs on this facility. We entered into the agreement on this credit facility in June 2015, and first borrowed on that credit facility in July 2015. We incurred $0.2 million of interest expense in 2015 resulting from borrowings under our credit facility. Interest expense in 2015 was net of capitalized interest of $0.03 million. We had no borrowings or interest expense in 2014.

Liquidity and Capital Resources

Historically, our predecessor’s primary sources of liquidity were capital contributions from our equity owners, borrowings under our predecessor’s credit facility and cash flows from operations. In 2016, our predecessor’s primary sources of liquidity were borrowings under the predecessor’s credit facility of $112.0 million, proceeds from the issuance of equity interests of $51.5 million and cash flows from operations of $32.1 million. Historically, our predecessor’s primary use of cash has been for the development and acquisition of oil, natural gas and NGL properties, as well as for development of water handling and treatment infrastructure. 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 and production will be highly dependent on the capital resources available to us.

For the year ended December 31, 2016, our total capital expenditures were approximately $215.1 million, including drilling and completion costs of $158.3 million, leasehold acquisition costs of $47.6 million, and other capital expenditures of $1.7 million. During 2016, we completed and began production on 11 gross (10.9 net) wells, all of which we operated. At year-end, we were in the process of drilling four gross (4.0 net) wells and had six gross (5.9 net) wells waiting on completion.

Our 2017 capital budget is projected to range from $555.0 million to $605.0 million, excluding potential acquisitions. We expect to allocate between $510.0 million and $550.0 million of our 2017 capital budget for the drilling and completion of operated and non-operated wells. Based on our 2017 capital budget, we anticipate that we will spud approximately 54 to 58 gross operated wells, and approximately 11 to 15 gross 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

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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 our drilling program, we may lose a portion of our acreage through lease expirations. In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be proved reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

In January 2017, we completed our IPO, which resulted in net proceeds of $397.4 million after deducting expenses and underwriting discounts and commissions. We used a portion of the net proceeds from our IPO to fully repay our credit facility and the remainder of the IPO proceeds will be used largely to fund our 2017 capital program. Our borrowing base under our credit facility was $160.0 million as of December 31, 2016, and was subsequently increased to $180.0 million in January 2017. As of the date of this filing, we had no amounts drawn under the credit facility such that the full $180.0 million borrowing base remains available.

Based on current expectations and after giving effect to the IPO, 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 2017 capital program, excluding any potential acquisitions. 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 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 current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves.

Working Capital

Our working capital, which we define as current assets minus current liabilities, 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. Our working capital was a deficit of $31.0 million at December 31, 2016, compared to a surplus of $0.05 million at December 31, 2015.

We may incur additional working capital deficits in the future due to liabilities that accrue related to our drilling program. 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 $11.7 million and $14.2 million at December 31, 2016 and 2015, respectively. We expect that our cash flows from operating activities and availability under our credit facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

Cash Flows

The following table summarizes our cash flows for the periods indicated:



	Year Ended December 31,
(in thousands)	2016			2015			2014
Net cash provided by operating activities	$	32,083		$	20,372		$	7,615
Net cash used in investing activities	$	(195,425	)	$	(110,232	)	$	(187,067	)
Net cash provided by financing activities	$	160,904		$	70,397		$	199,800

Operating Activities. Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs, production volumes and changes in working capital. The increase in net cash provided by operating activities in 2016 compared to 2015 is primarily due to a 126%, or $42.7 million, increase in revenues. This was primarily due to increases in production during 2016. Net cash provided by operating activities also increased in 2016 due to a favorable change in operating assets and liabilities of $7.5 million. These increases were partially offset by a $14.7 million nonrecurring management incentive advance, an $8.2 million decrease in net cash received for settlements of derivatives, and higher operating costs primarily due to increased production.

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The increase in net cash provided by operating activities for the year ended December 31, 2015 as compared to the prior-year period is primarily due to a $17.5 million increase in total revenues and a $5.2 million increase in net cash received for settlements of derivatives, partially offset by a $7.0 million decrease in operational assets and liabilities and higher operating costs largely due to an increase in production.

Investing Activities. Net cash used in investing activities was $195.4 million for 2016 compared to $110.2 million for 2015 and $187.1 million for 2014. The 77% increase from 2015 to 2016 was due to $139.6 million of investments in developing our acreage and $54.7 million of investments related to the acquisition of undeveloped acreage. In 2015, net cash used for investing activities included $96.7 million and $13.7 million, respectively, for the development and acquisition of oil and natural gas properties. In 2014, net cash used for investing activities included $124.3 million and $64.5 million, respectively, for the acquisition and development of oil and natural gas properties, and $1.1 million of other property, plant and equipment, partially offset by proceeds from asset sales of $2.9 million.

Financing Activities. Net cash provided by financing activities in 2016 was primarily due to $112.0 million of borrowings under our credit facility and $51.5 million of proceeds from the issuance of equity interests. Net cash provided by financing activities in 2015 included $51.0 million of cash provided by equity issuances and $20.0 million of borrowings under our credit facility. Net cash provided by financing activities in 2014 consisted of $199.8 million of cash provided by equity issuances.

Credit Facility

On June 19, 2015, our predecessor entered into a credit agreement (as amended to date, the “credit agreement”) with Wells Fargo Bank, National Association, as administrative agent and issuing lender, and the lenders named therein, that provides for a senior secured revolving credit facility (the “credit facility”) with an aggregate commitment of $500.0 million (subject to the then-effective borrowing base). As of December 31, 2016, the borrowing base under our predecessor’s credit facility was $160.0 million, with $132.0 million outstanding, and $28.0 million of additional borrowing capacity available. In January 2017, our predecessor amended the credit facility which increased the aggregate principal commitment to $1.0 billion and the borrowing base to $180.0 million. In connection with our IPO, the Company, as parent guarantor, and our predecessor, as borrower, entered into an amendment to the credit facility with Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto. The amended and restated credit facility matures on February 1, 2022. After giving effect to the amendment, the borrowing base under the credit facility remained at $180.0 million, with the next scheduled borrowing base redetermination to occur on or about April 1, 2017. Also in connection with the IPO, our predecessor fully repaid the outstanding borrowings under the credit facility. As of the date of this filing, we had no amounts drawn under the credit facility, such that the full $180.0 million borrowing base remains available.

The amount available to be borrowed under our credit facility is subject to a borrowing base that is redetermined semiannually by each April 1 and October 1 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, 2016, the weighted average interest rate on borrowings under our credit facility was approximately 3.99%. We also pay a commitment fee on unused amounts of our credit facility of 0.500%. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.

Our credit agreement 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.

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At December 31, 2016, our credit agreement also requires us to maintain compliance 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 asset retirement obligations and derivatives) to our consolidated current liabilities (excluding the current portion of long-term debt under our credit agreement and noncash liabilities related to asset retirement 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, 2016, our predecessor was in compliance with its financial covenants.

The amended and restated credit facility permits JPE LLC to hedge up to the greater of 85% of proved reserves and 75% of JPE LLC’s reasonably anticipated production for up to 24 months in the future, and up to the greater of 75% of our proved reserves and 50% of our reasonably anticipated production for 25 to 60 months in the future, provided that no hedges may have a term beyond five years. It does not contain any minimum hedging requirements.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2016 is provided in the following table:



	Payments Due by Period for the Year Ending December 31,
(in thousands)	2017		2018		2019		2020		2021		Thereafter		Total
Credit facility⁽¹⁾	$	—	$	—	$	—	$	132,000	$	—	$	—	$	132,000
Operating leases⁽²⁾	815		525		—		—		—		—		1,340
Service and purchase contracts⁽³⁾	468		8		1		—		—		—		477
Rig contracts⁽⁴⁾	18,239		—		—		—		—		—		18,239
Total	$	19,522	$	533	$	1	$	132,000	$	—	$	—	$	152,056

_______________________________________________________________________________

(1)

This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on our credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. As of December 31, 2016, we had $132.0 million outstanding under our credit facility and $28.0 million of additional borrowing capacity available. The outstanding balance out on credit facility was fully repaid using proceeds from our IPO in January 2017.


(2)	Primarily relates to the lease of our corporate offices.


(3)	Primarily relates to our obligation to purchase lease automatic custody transfer units in conjunction with oil gathering for current and future wells.


(4)	Relates to five drilling rig contracts entered into at December 31, 2016. If we were to terminate these contracts at December 31, 2016, we would be required to pay early termination penalties of approximately $8.1 million.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our predecessor’s consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our predecessor’s 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. The predecessor evaluates its estimates and assumptions on a regular basis. The predecessor bases its estimates on historical experience and various other assumptions that were 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 the predecessor’s consolidated financial statements. The predecessor’s more significant accounting policies and estimates include: successful efforts method of accounting for oil and natural gas activities, impairment of oil and natural gas properties, oil and natural gas reserve quantities, derivative instruments, and asset retirement

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obligations. We provide an expanded discussion of the predecessor’s more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect the predecessor’s more significant estimates and assumptions used in the preparation of our consolidated financial statements.

A complete list of our predecessor’s significant accounting policies are described in Note 2, Significant Accounting Policies and Related Matters, to our predecessor’s consolidated financial statements for the year ended December 31, 2016.

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

Our oil and natural gas exploration and developments costs are accounted for using the successful efforts method. Under the successful efforts 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 if and when the well is determined not to have recoverable reserves in commercial quantities. Other items charged to expenses generally include geological and geophysical costs, delay rentals and lease and well operating costs.

Proved Oil and Natural Gas Properties. 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 obligations, are depleted based on proved developed reserves on a field basis. 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.

Unproved 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 undeveloped leasehold or reserves are otherwise attributable 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.

Exploration Costs. Exploration costs consist of costs incurred to identify and evaluate areas that are prospective for oil and natural gas reserves. Explorations costs include geological and geophysical costs, delay rentals and the cost of unsuccessful exploratory wells.

Exploratory Well Costs. Exploratory well costs are capitalized as incurred pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

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.

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Oil and Natural Gas Reserve Quantities

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 each year-end. For purposes of depletion and impairment, reserve quantities are adjusted in accordance with GAAP for the impact of additions and dispositions. 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 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.

Derivative Instruments

We utilize commodity derivative instruments to manage our exposure to commodity price volatility. All of 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. The fair values of the our fixed price crude oil swaps were measured using option pricing models. These models use certain variables including forward prices and volatility curves and the strike prices for the instruments. 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.

Asset Retirement Obligations

Our asset retirement obligations relate 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 asset retirement obligation liability is required to be recognized in the period in which it is incurred, while the associated asset retirement cost is capitalized in proved oil and natural gas property as part of the carrying cost of the oil and natural gas asset. The recognition of the asset retirement obligation 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. In periods subsequent to the initial measurement of the asset retirement obligation, we recognize accretion of the discounted liability and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the asset retirement obligation liability impact net earnings through accretion expense, while the related capital cost, including revisions thereto, is charged to expense through depletion. Both accretion of the liability and depletion of the asset are included in depletion, depreciation, amortization and accretion expense on the consolidated statements of operations.

Recently Issued Accounting Pronouncements

Please refer to Note 2, Significant Accounting Policies and Related Matters – Recent Accounting Pronouncements, to the consolidated financial statements included elsewhere in this report for a discussion of recent accounting pronouncements and their anticipated effect on our business.

Off-Balance Sheet Arrangements

We had no material off-balance sheet arrangements as of December 31, 2016. Please read Note 9, Commitments and Contingencies, included in notes to the consolidated 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

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our 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. NGL prices generally correlate to the price of oil, and accordingly prices for these products have likewise declined and are likely to continue following that market. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and 2016. The prices we receive for our oil, natural gas and NGLs 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.”

A $1.00 per barrel change in our realized oil price would have resulted in a $1.7 million change in oil revenues for 2016. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.1 million change in our natural gas revenues for 2016. A $1.00 per barrel change in NGL prices would have changed NGL revenue by $0.2 million for 2016. Oil sales contributed 93% of our total production revenues for 2016. Natural gas sales contributed 3% and NGL sales contributed 4% of our total production revenues for 2016. Our oil, natural gas and NGL revenues do not include the effects of derivatives.

Due to this volatility, we expect to use commodity derivative instruments such as collars, swaps and basis swaps to hedge price risk associated with our oil production. These hedging instruments will allow us to reduce, but not eliminate, the potential variability in cash flow from operations due to fluctuations in oil prices. This provides 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. We may seek to hedge price risk associated with our natural gas and NGL production in the future.

Under our credit agreement as of December 31, 2016, we were required to hedge a minimum of 75% of our projected oil volumes from PDP reserves for each calendar month on a two-year rolling basis. However, our amended and restated credit facility entered into in connection with the Company’s IPO does not contain similar minimum hedging requirements. However, the Company is permitted to hedge up to the greater of 85% of our proved reserves and 75% of our reasonably anticipated production for up to 24 months in the future, and up to the greater of 75% of our proved reserves and 50% of our reasonably anticipated production for 25 to 60 months in the future, provided that no hedges may have a term beyond five years.

At December 31, 2016, we had a net liability position of $12.9 million related to our oil swap derivatives in place for the years 2017 through 2018. Based on our open oil derivative positions at December 31, 2016, a 10% increase in the NYMEX WTI price would increase our net oil derivative liability by approximately $11.9 million, while a 10% decrease in the NYMEX WTI price would decrease our net oil derivative liability by approximately $11.9 million.

See Note 3, Derivative Instruments, and Note 4, Fair Value Measurements, to our consolidated 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.

Counterparty and Customer 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 members of our bank credit facility.

Our 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 several

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significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our credit facility. At December 31, 2016, we had $132.0 million of debt outstanding, all of which was under our credit facility, with a weighted average interest rate of 3.99%. As of December 31, 2016, the terms of our credit facility provide for interest on borrowings at the greatest of (a) the prime rate in effect plus an applicable margin, (b) the federal funds rate in effect plus one half of 1.0%, or (c) the daily London Interbank Offered Rate (“LIBOR”), plus an applicable margin. The applicable margins associated with the prime rate or the federal funds rate vary based on the utilization percentage of the credit facility, and are 1.5% to 2.5% for base rate loans and 2.5% to 3.5% for LIBOR loans. We are required to pay a commitment fee based on the unused portion of the outstanding borrowing base. The commitment fee rate at December 31, 2016 was 0.500% for all utilization levels of the credit facility. In connection with our IPO, we entered into an amended and restated credit facility that decreased the margins associated with LIBOR loans to a range of 2.25% to 3.25%.

Under the amended and restated credit facility, borrowings will bear interest, at the Company’s option, at either (i) the greatest of (ia) the prime rate as determined by the administrative agent, (ib) the federal funds effective rate plus 0.50%, and (ic) the thirty-day adjusted LIBOR plus 1.0%, in each case, plus a margin that varies from 1.25% to 2.25% per annum according to the total facility utilization, (ii) the adjusted LIBOR rate plus a margin that varies from 2.25% to 3.25% per annum according to the total facility utilization or (iii) the applicable LIBOR market index rate plus a margin that varies from 2.25% to 3.25% per annum according to the Company’s total facility utilization. The commitment fee on the unutilized portion of the new amendment remains at 0.500%.

Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $1.3 million per year. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.


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 Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2016. 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, 2016 at the reasonable assurance level. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objective and management necessarily applies its judgment in evaluating the cost-benefit relationship of all possible controls and procedures.

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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 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

This annual report does not include a report on management’s assessment regarding internal control over financial reporting due to a transition period established by the rules of the SEC for newly public companies.

Attestation Report of the Registered Public Accounting Firm

This annual report does not include an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies. Further, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.


ITEM 9B.	OTHER INFORMATION

None.

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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 2017 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, 2016.

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 will provide a copy of this document to any person, without charge, upon request, by writing to us at Jagged Peak Creek Energy Inc., Investor Relations, 1125 17th Street, Suite 2400, Denver, Colorado 80202. We intend to satisfy the disclosure requirement under Item 406(c) 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 2017 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, 2016.


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 2017 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, 2016.


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 2017 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, 2016.


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 2017 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, 2016.

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PART IV


ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules

The consolidated 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††			Master Reorganization Agreement, dated January 25, 2017, by and among Jagged Peak Energy LLC, Q-Jagged Peak Energy Investment Partners LLC, Jagged Peak Energy Inc., JPE Merger Sub LLC, JPE Management Holdings LLC and the management members named therein (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed with the SEC on January 31, 2017).
3.1			Amended and Restated Certification of Incorporation of Jagged Peak Energy Inc., filed with the Secretary of State of the State of Delaware on February 1, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed with the SEC on February 7, 2017).
3.2			Amended and Restated Bylaws of Jagged Peak Energy Inc., effective February 1, 2017 (incorporated by reference to Exhibit 3.2 to the Company’s Form 8-K filed with the SEC on February 7, 2017).
4.1			Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company’s Amended Registration Statement on Form S-1/A (File No. 001-37995) filed with the SEC on January 6, 2017).
4.2			Registration Rights Agreement, dated as of February 1, 2017, by and among Jagged Peak Energy Inc. and the stockholders named therein (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed with the SEC on February 7, 2017).
4.3			Stockholders’ Agreement, dated as of February 1, 2017, by and among Jagged Peak Energy Inc., Q-Jagged Peak Energy Investment Partners, LLC, JPE Management Holdings LLC, and the individuals party thereto (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed with the SEC on February 7, 2017).
10.1			Amended and Restated Credit Agreement, dated as of February 1, 2017, by and among Jagged Peak Energy Inc., as parent guarantor, Jagged Peak Energy LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent and issuing lender, and the lenders named therein (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed with the SEC on February 7, 2017).
10.2			Amended and Restated Limited Liability Company Agreement of JPE Management Holdings LLC, dated February 1, 2017 (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed with the SEC on February 7, 2017).
10.3†			Jagged Peak Energy Inc. 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed with the SEC on January 31, 2017).
10.4†			Form of Indemnification Agreement between Jagged Peak Energy Inc. and each of the directors and officers thereof (incorporated by reference to Exhibit 10.8 to the Registrant’s Amended Registration Statement on Form S-1/A (File No. 333-215179), filed with the SEC on January 6, 2017).
10.5†			Executive Employment Agreement, dated April 3, 2013, between Jagged Peak Energy Management LLC and Joseph. N. Jaggers (incorporated by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-1 (File No. 333-215179), filed with the SEC on December 19, 2016).
10.6†			Executive Employment Agreement, dated April 3, 2013, between Jagged Peak Energy Management LLC and Gregory S. Hinds (incorporated by reference to Exhibit 10.9 to the Company’s Registration Statement on Form S-1 (File No. 333-215179), filed with the SEC on December 19, 2016).
21.1			List of subsidiaries of Jagged Peak Energy Inc. (incorporated by reference to Exhibit 21.1 to the Company’s Amended Registration Statement on Form S-1/A (File No. 333-215179), filed with the SEC on January 6, 2017).
23.1			Consent of KPMG LLP.
23.2			Consent of KPMG LLP.
23.3			Consent of Ryder Scott Company, LP.
31.1			Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2			Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1			Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

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32.2			Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
99.1			Ryder Scott Company, LP, Summary of Reserves at December 31, 2016.



†			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.


ITEM 16.	FORM 10-K SUMMARY

None.

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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:	March 23, 2017	By:	/s/ JOSEPH N. JAGGERS
			Name:	Joseph N. Jaggers
			Title:	Chairman, 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/ JOSEPH N. JAGGERS	Chairman, Chief Executive Officer and President	March 23, 2017
Joseph N. Jaggers	(Principal Executive Officer)

/s/ ROBERT W. HOWARD	Executive Vice President, Chief Financial Officer	March 23, 2017
Robert W. Howard	(Principal Financial Officer)

/s/ SHONN D. STAHLECKER	Controller	March 23, 2017
Shonn D. Stahlecker

/s/ CHARLES D. DAVIDSON	Director	March 23, 2017
Charles D. Davidson

/s/ ROGER L. JARVIS	Director	March 23, 2017
Roger L. Jarvis

/s/ JAMES J. KLECKNER	Director	March 23, 2017
James J. Kleckner

/s/ MICHAEL C. LINN	Director	March 23, 2017
Michael C. Linn

/s/ JOHN R. SULT	Director	March 23, 2017
John R. Sult

/s/ S. WIL VANLOH, JR.	Director	March 23, 2017
S. Wil VanLoh, Jr.

/s/ DHEERAJ VERMA	Director	March 23, 2017
Dheeraj Verma

/s/ BLAKE A. WEBSTER	Director	March 23, 2017
Blake A. Webster

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INDEX TO FINANCIAL STATEMENTS



	Page
Jagged Peak Energy Inc.
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheet as of December 31, 2016	F-3
Notes to Balance Sheet	F-4

Jagged Peak Energy LLC (Predecessor)
Report of Independent Registered Public Accounting Firm	F-6
Consolidated Balance Sheets as of December 31, 2016 and 2015	F-7
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014	F-8
Consolidated Statements of Members' Equity for the Years Ended December 31, 2016, 2015 and 2014	F-9
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014	F-10
Notes to Consolidated Financial Statements	F-11

Supplemental information to consolidated financial statements
Supplemental Oil and Natural Gas Disclosures (Unaudited)	F-26
Supplemental Quarterly Financial Data (Unaudited)	F-30

F-1

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Report of Independent Registered Public Accounting Firm

The Board of Directors

Jagged Peak Energy Inc.:

We have audited the accompanying balance sheet of Jagged Peak Energy Inc. as of December 31, 2016. This balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Jagged Peak Energy Inc. as of December 31, 2016, in conformity with U.S. generally accepted accounting principles.



	/s/ KPMG LLP

Denver, Colorado
March 23, 2017

F-2

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JAGGED PEAK ENERGY INC.

BALANCE SHEET



	December 31, 2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—
TOTAL ASSETS	$	—
LIABILITIES AND SHAREHOLDER’S EQUITY
TOTAL LIABILITIES
Total liabilities	$	—
SHAREHOLDER’S EQUITY
Common stock, $0.01 par value, authorized 1,000 shares issued and outstanding	10
Less receivable from Jagged Peak Energy LLC	10
Total shareholder’s equity	—
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY	$	—

The accompanying Notes are an integral part of this balance sheet.

F-3

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JAGGED PEAK ENERGY INC.

Notes to Balance Sheet

Note 1—Nature of Operations

Jagged Peak Energy Inc. (the “Company”) is a Delaware corporation formed as a wholly owned subsidiary of Jagged Peak Energy LLC (“JPE LLC”) on September 20, 2016. The Company was formed to become the holding company of JPE LLC in connection with the Company’s initial public offering (the “IPO”). The Company has no prior operating activities.

Note 2—Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

This balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Separate Statements of Operations, Changes in Stockholder’s Equity and of Cash Flows have not been presented because the Company has had no business transactions or activities to date, except for the initial capitalization of the Company which was funded by a receivable from JPE LLC. In this regard, general and administrative costs associated with the formation and daily management of the Company have been determined by the Company to be insignificant.

Estimates

The preparation of the balance sheet, in accordance with GAAP, requires management to make estimates and assumptions that affect the amounts reported in the balance sheet and accompanying notes. Actual results could differ from those estimates.

Receivable from Jagged Peak Energy LLC

The receivable from JPE LLC represents an amount of $10 due for the issuance of 1,000 shares of $0.01 par value common stock to JPE LLC. Prior to payment by JPE LLC, this receivable will be recorded as a reduction of shareholder’s equity.

Income Taxes

The Company is a subchapter C corporation and is subject to U.S. federal and state 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 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. 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. Net deferred tax assets are then reduced by a valuation allowance if the Company believes it is more-likely-than-not such net deferred tax assets will not be realized. As the Company had no business transactions or activities to date, aside from the initial capitalization described above, there is no provision for income taxes as of December 31, 2016.

Note 3—Shareholder’s Equity

Upon formation, the Company authorized share capital of 1,000 common shares with $0.01 par value. On September 20, 2016, all 1,000 shares were issued and acquired by JPE LLC for consideration of an amount of $10 receivable from JPE LLC. Each share has one voting right.

Note 4—Subsequent Events

The Company has evaluated subsequent events through the date this balance sheet was issued. The Company determined there were no events, other than as described below, that required disclosure or recognition in these notes to balance sheet.

On January 27, 2017, the Company completed the IPO of common stock to the public. As part of 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,

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were approximately $425.0 million, which resulted in net proceeds to the Company of $397.4 million after deducting expenses and underwriting discounts and commissions of approximately $27.6 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 will be used to fund a portion of the Company’s 2017 capital expenditures program, and for other general corporate purposes. As a result of the IPO, there are 212,937,746 common shares of the Company issued and outstanding as of March 17, 2017.

Immediately prior to the IPO, certain members of management and employees who held management incentive units (“MIUs”) in JPE LLC, contributed unvested or unallocated MIUs to JPE Management Holdings LLC, a newly formed limited liability company. Also immediately prior to the IPO, a corporate reorganization took place whereby the Company, initially formed as a subsidiary of JPE LLC, formed JPE Merger Sub LLC as a subsidiary of the Company. 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 the Company.

Following the IPO and the corporate reorganization, JPE LLC amended its senior secured revolving credit facility (the “amended and restated credit facility”) to include the Company as parent guarantor, JPE LLC as borrower, and Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto. Among other things, the amended and restated credit facility (i) increased the maximum commitment to $1.0 billion from $500.0 million, (ii) maintained the borrowing base at $180.0 million, (iii) lowered the interest rate on amounts borrowed, (iv) removed the minimum hedging requirements and (v) allowed for the corporate reorganization that was completed simultaneously with the closing of the IPO.

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Report of Independent Registered Public Accounting Firm

The Board of Directors

Jagged Peak Energy LLC:

We have audited the accompanying consolidated balance sheets of Jagged Peak Energy LLC (Predecessor) and its subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, members’ equity, and cash flows for each of the years in the three year period ended December 31, 2016. These consolidated financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Jagged Peak Energy LLC and its subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.



	/s/ KPMG LLP
Denver, Colorado
March 23, 2017

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

CONSOLIDATED BALANCE SHEETS

(in thousands)



	December 31,
	2016			2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	11,727		$	14,165
Accounts receivable	10,327			8,005
Other current assets	3,412			504
Total current assets	25,466			22,674
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method	531,121			333,067
Accumulated depletion, depreciation and amortization	(57,529		)	(30,341		)
Total oil and gas properties, net	473,592			302,726
Other property and equipment, net	3,001			1,663
Total property and equipment, net	476,593			304,389
OTHER NONCURRENT ASSETS
Unamortized debt issuance costs	1,503			542
Other assets	14,830			127
Total noncurrent assets	16,333			669
TOTAL ASSETS	$	518,392		$	327,732
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	7,629		$	2,452
Accrued liabilities	39,225			20,171
Derivative instruments	9,567			—
Total current liabilities	56,421			22,623
LONG-TERM LIABILITIES
Senior secured revolving credit facility	132,000			20,000
Derivative instruments	3,287			—
Asset retirement obligations	448			490
Other long-term liabilities	124			289
Total long-term liabilities	135,859			20,779
Commitments and contingencies
MEMBERS’ EQUITY
Common units	346,098			294,556
Accumulated deficit	(19,986		)	(10,226		)
Total members’ equity	326,112			284,330
TOTAL LIABILITIES AND MEMBERS’ EQUITY	$	518,392		$	327,732

The accompanying Notes are an integral part of these consolidated financial statements.

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)



	Year Ended December 31,
	2016			2015			2014
REVENUES
Oil sales	$	70,078		$	31,534		$	14,605
Natural gas sales	2,213			948			646
NGL sales	3,068			1,329			1,029
Other operating revenues	1,163			40			—
Total revenues	76,522			33,851			16,280
OPERATING EXPENSES
Lease operating expenses	7,505			3,165			2,041
Gathering and transportation expenses	1,046			171			121
Production and ad valorem taxes	4,345			2,244			920
Depletion, depreciation, amortization and accretion	40,417			22,685			8,444
Impairment of oil and natural gas properties and dry hole costs	1,564			6,489			1,414
Other operating expenses	1,941			261			64
General and administrative expenses	11,690			7,446			7,330
Total operating expenses	68,508			42,461			20,334
INCOME (LOSS) FROM OPERATIONS	8,014			(8,610		)	(4,054		)
OTHER INCOME (EXPENSE)
Gain (loss) on commodity derivatives	(15,145		)	1,323			5,375
Interest expense and other	(2,629		)	(197		)	—
Total other income (expense)	(17,774		)	1,126			5,375
NET INCOME (LOSS)	$	(9,760	)	$	(7,484	)	$	1,321

The accompanying Notes are an integral part of these consolidated financial statements.

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

(in thousands)



	Common Units		Accumulated Deficit			Total Members’ Equity
BALANCE AT DECEMBER 31, 2013	$	43,756	$	(4,063	)	$	39,693
Capital contributions	199,800		—			199,800
Net income	—		1,321			1,321
BALANCE AT DECEMBER 31, 2014	243,556		(2,742		)	240,814
Capital contributions	51,000		—			51,000
Net loss	—		(7,484		)	(7,484		)
BALANCE AT DECEMBER 31, 2015	294,556		(10,226		)	284,330
Capital contributions	51,542		—			51,542
Net loss	—		(9,760		)	(9,760		)
BALANCE AT DECEMBER 31, 2016	$	346,098	$	(19,986	)	$	326,112

The accompanying Notes are an integral part of these consolidated financial statements.

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(9,760	)	$	(7,484	)	$	1,321
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization and accretion expense	40,417			22,685			8,444
Management incentive unit advance	(14,712		)	—			—
Impairment of oil and natural gas properties and dry hole costs	1,564			6,489			1,414
Amortization of debt issuance costs	260			61			—
(Gain) loss on commodity derivatives	15,145			(1,323		)	(5,375		)
Net cash receipts (payments) on settled derivatives	(2,292		)	5,935			763
Other	(160		)	(155		)	(150		)
Change in operating assets and liabilities:
Accounts receivable and other current assets	(2,588		)	(5,997		)	(2,376		)
Other assets	11			17			(28		)
Accounts payable and accrued liabilities	4,198			144			3,602
Net cash provided by operating activities	32,083			20,372			7,615
CASH FLOWS FROM INVESTING ACTIVITIES
Leasehold and acquisition costs	(54,681		)	(13,716		)	(124,328		)
Development of oil and natural gas properties	(139,571		)	(96,743		)	(64,545		)
Other capital expenditures	(1,969		)	(213		)	(1,073		)
Proceeds from sale of oil and natural gas properties	796			440			2,879
Net cash used in investing activities	(195,425		)	(110,232		)	(187,067		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from common units issued	51,542			51,000			199,800
Proceeds from senior secured revolving credit facility	112,000			20,000			—
Debt issuance costs	(1,220		)	(603		)	—
Deferred offering costs	(1,418		)	—			—
Net cash provided by financing activities	160,904			70,397			199,800
NET CHANGE IN CASH AND CASH EQUIVALENTS	(2,438		)	(19,463		)	20,348
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	14,165			33,628			13,280
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	11,727		$	14,165		$	33,628
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid, net of capitalized interest	$	2,190		$	95		$	—
Cash paid for income taxes	—			—			—
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	$	36,581		$	17,720		$	10,809
Asset retirement obligations	(100		)	189			50
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Accrued deferred offering costs	$	1,224		$	—		$	—

The accompanying Notes are an integral part of these consolidated financial statements.

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

Note 1—Organization, Operations and Basis of Presentation

Organization and Operations

Jagged Peak Energy LLC (together with its subsidiaries, the “Predecessor”), a Delaware limited liability company and considered the predecessor of Jagged Peak Energy Inc. (“JPE Inc.” or the “Company”), is a growth-oriented, 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, a sub-basin of the Permian Basin of West Texas. The Predecessor’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. The Predecessor was formed by an affiliate of Quantum Energy Partners (“Quantum”), a leading energy private equity firm, and key members of its management team.

Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

The accompanying consolidated financial statements include the accounts of Jagged Peak Energy LLC and its wholly owned subsidiaries. All significant intercompany amounts have been eliminated in consolidation.

Certain reclassifications have been made to prior period amounts to conform to the current presentation.

Industry Segment and Geographic Information

The Predecessor has 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 Predecessor’s assets are located in the United States, and all of its revenues are attributable to customers located in the United States.

Note 2—Significant Accounting Policies and Related Matters

Use of Estimates

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue 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 financial statements include, among other things, (1) estimates relating to certain oil and natural gas revenue and costs, (2) estimates of oil and natural gas reserve quantities, which impact depreciation, depletion and amortization and impairment calculations, (3) estimates of timing and costs used in calculating asset retirement obligations and impairment, (4) estimates used in developing fair value assumptions and estimates, and (5) estimates and assumptions used in the disclosure of commitments and contingencies. Changes in the assumptions could have a significant impact on results in future periods.

Fair Value Measurements

The Predecessor’s financial instruments are measured at estimated fair value, and consist of derivative instruments, cash and cash equivalents, accounts payable and accrued expenses. The Predecessor’s derivative instruments are measured at fair value on a recurring basis. The carrying amounts of the Predecessor’s other financial instruments are considered to be representative of their fair market value due to their short-term nature.

The Predecessor also applies fair value accounting guidance to measure nonfinancial assets and liabilities, such as the acquisition or impairment of proved oil and gas properties and the inception value of asset retirement obligations. These assets

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. See Note 4, Fair Value Measurements, for further discussion.

Cash and Cash Equivalents

The Predecessor considers all liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Predecessor’s cash balances held at commercial banks may at times exceed the Federal Deposit Insurance Corporation limit. The Predecessor has not experienced any credit losses to date.

Revenue Recognition

Revenue is recognized when production is delivered to a purchaser at a fixed and/or determinable price, title has transferred and the collectability of the revenue is probable. Oil, natural gas and NGL revenue is recorded using the sales method. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. As of December 31, 2016 and 2015, the Predecessor had no assets or liabilities recorded for oil, natural gas or NGL imbalances.

Accounts Receivable

The Predecessor’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 Predecessor operates, and from derivative settlements receivable shortly after the balance sheet date. The Predecessor monitors the financial strength of its customers, partners, and counterparties. At December 31, 2016 and 2015, the Predecessor did not have any reserves for doubtful accounts and did not incur any bad debt expense in any period presented.

At December 31, 2016 and 2015, accounts receivable was comprised of the following:



	December 31,
	2016		2015
	(in thousands)
Oil and gas sales	$	8,861	$	5,133
Trade and other	1,466		2,872
Total accounts receivable	$	10,327	$	8,005

Significant Customers

The Predecessor’s share of oil, natural gas and NGL production is sold to a relatively small number of customers. For the year ended December 31, 2016, two purchasers each accounted for more than 10% of the Predecessor’s total production revenue: Trafigura Trading, LLC (57%) and Sunoco Partners Marketing (31%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of the Predecessor’s total production revenue: Sunoco Partners Marketing (68%) and Shell Trading (US) Company (21%). For the year ended December 31, 2014, two purchasers each accounted for more than 10% of the Predecessor’s total production revenue: Shell Trading (US) Company (72%) and Plains Marketing LP (15%). The loss of any single purchaser could materially and adversely affect our revenues in the short-term; however, the Predecessor 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.

Derivative Instruments

The Predecessor 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 Predecessor’s expected oil and natural gas production, and the Predecessor does not enter into such instruments for speculative trading purposes. The Predecessor does not designate any derivative instruments as hedges for accounting purposes. The Predecessor records all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. The Predecessor records gains and losses from the change in fair value of derivative instruments in current earnings as they occur. The Predecessor currently does not utilize any derivative instruments to manage exposure to variable interest rates, but may do so in the future.

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

The cash flow impact of the Predecessor’s derivative activities is reflected as cash flows from operating activities. See Note 3, Derivative Instruments, for a more detailed discussion of the Predecessor’s derivative activities.

Oil and Natural Gas Properties

A summary of the Predecessor’s oil and natural gas properties, net is as follows:



	December 31,
	2016			2015
	(in thousands)
Proved oil and natural gas properties	$	375,129		$	204,154
Unproved oil and natural gas properties	155,992			128,913
Total oil and natural gas properties	531,121			333,067
Less: Accumulated depletion	(57,529		)	(30,341		)
Total oil and natural gas properties, net	$	473,592		$	302,726

Proved Oil and Natural Gas Properties

The Predecessor 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 if and when the well is determined not to have recoverable reserves in commercial quantities. Other items charged to expense generally include geological and geophysical costs, delay rentals and lease and well operating costs. 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, 2016, 2015 and 2014, the Predecessor recorded depletion for oil and natural gas properties of $39.4 million, $22.2 million and $8.1 million, respectively. Depletion expense is included in depletion, depreciation, amortization and accretion expense on the accompanying consolidated 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 Predecessor 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 Predecessor 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, as further discussed in Note 4, Fair Value Measurements. The Predecessor did not record any impairment expenses associated with its proved properties during the years ended December 31, 2016, 2015 and 2014.

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 Predecessor 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 $0.4 million, $6.5 million and $1.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. Additionally, during 2016 the Predecessor incurred dry hole costs of $1.2 million related to a vertical test well drilled to an unproductive shallow horizon. There were no dry hole costs

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

incurred in 2015 or 2014. Impairments and dry hole costs are presented within impairment of oil and natural gas properties and dry hole costs in the consolidated 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 Predecessor’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 Predecessor’s oil and natural gas reserves.

Other Property and Equipment

The following table presents the components of other property and equipment, net:



	December 31,
	2016			2015
	(in thousands)
Other property and equipment	$	4,760		$	2,491
Less: Accumulated depreciation	(1,759		)	(828		)
Total other property and equipment, net	$	3,001		$	1,663

Other property and equipment includes equipment used in drilling and completion activities, the Predecessor’s field office location, 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 2 to 20 years. When property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounting records.

Unamortized Debt Issuance Costs

The Predecessor incurred legal and bank fees in connection with obtaining its senior secured revolving credit facility and incurs such fees when increasing bank commitments in conjunction with redetermining an increase in its borrowing base. These costs are stated on the balance sheet as a noncurrent asset at cost, net of amortization, which is computed over the life of the credit facility using the straight-line method and recognized as interest expense in the consolidated statements of operations.

Other Noncurrent Assets

Other noncurrent assets primarily consists of a $14.7 million cash advance to management incentive unit advance recipients, which is reviewed for recoverability at each reporting period or when changes in circumstances indicate the asset may no longer be recoverable. The advance will be recognized in the statements of operations as compensation expense if the asset is no longer recoverable or upon the occurrence of a vesting event. See Note 6, Members’ Equity, for more information on the management incentive unit advance.

Asset Retirement Obligations

The Predecessor 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

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

probabilities, amounts and timing of settlements, credit-adjusted risk-free discount rates and inflation rates. Revisions to estimated ARO can result from changes in retirement cost estimates and changes in the 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.

Income Taxes

The Predecessor is treated as a partnership for federal and state income tax purposes, with each partner taxed separately on its allocated share of the Predecessor’s taxable income. Accordingly, the accompanying consolidated financial statements do not include a provision or liability for federal income taxes. The Predecessor’s operations in Texas are subject to an entity-level tax, the Texas franchise tax, at a statutory rate of up to 1.0% of a portion of gross revenues apportioned to Texas. The Predecessor did not have taxable net income for purposes of calculating 2016 and 2015 Texas franchise tax, and did not have a franchise tax liability at December 31, 2016 or 2015.

In accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 740, Income Taxes, the Predecessor found no uncertain tax positions and recorded no related liabilities as of December 31, 2016 and 2015. The Predecessor recognizes interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2016 and 2015, the Predecessor made no provision for interest or penalties related to uncertain tax positions. The Predecessor files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway, and the Predecessor’s U.S. federal income tax returns and various state tax returns remain open to examination by the taxing authorities for tax years 2013 through 2015.

Deferred Offering Costs

Incremental costs directly related to the IPO were capitalized as deferred offering costs within other current assets until the common shares were issued or the potential offering was terminated. Upon issuance of common shares, these costs were offset against the proceeds received. The IPO was completed in January 2017.

Other Current Assets and Accrued Liabilities

The components of other current assets and accrued liabilities are shown below:



	December 31,
	2016		2015
	(in thousands)
Other current assets
Prepaid expenses	$	255	$	459
Deferred offering costs	2,642		—
Other current assets	515		45
Total other current assets	$	3,412	$	504

Accrued liabilities
Accrued capital expenditures	$	28,490	$	15,170
Accrued liabilities	3,312		1,037
Revenue payable	2,653		1,690
Other current liabilities	4,770		2,274
Total accrued liabilities	$	39,225	$	20,171

Recent Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606), which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new guidance will require a company to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-11, which rescinds SEC accounting guidance regarding the use of the entitlements method for

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

recognition of natural gas revenues. The new standards are effective for the Predecessor on January 1, 2018. Early adoption is permitted for fiscal years beginning after December 31, 2016. The standards can be adopted using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Predecessor intends to adopt this standard on January 1, 2018, but has not yet selected a transition method. The Predecessor does not believe the effect of adoption will be material to its financial statements because it follows the sales method of accounting for its oil, natural gas and NGL production, which is generally consistent with the new revenue recognition model. However, the Predecessor anticipate the new standard will result in expanded disclosure requirements, although it cannot yet determine the extent of those disclosure requirements on the Predecessor.

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest-Imputation of Interest-Presentation and Subsequent Measurement of Debt Issuance Costs associated with Line-of-Credit Arrangements in August 2015. These ASUs simplify the presentation of debt issuance costs by requiring such costs (except for those related to revolving credit facilities) to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability rather than as an asset. These ASUs are effective for the Predecessor on January 1, 2017, and are required to be adopted retrospectively. Early adoption is permitted. The Predecessor adopted these ASUs at December 31, 2016. Through December 31, 2016, the Predecessor’s debt was comprised solely of obligations under our revolving credit facility. Accordingly, the debt issuance costs related to the revolving credit facility continue to be classified as assets on the Predecessor’s consolidated balance sheets. At December 31, 2016 and 2015, the Predecessor had $1.5 million and $0.5 million, respectively, of unamortized debt issuance costs associated with its credit facility which were recorded as unamortized debt issuance costs on the consolidated balance sheet.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires all leases with a term greater than one year to be recognized on the balance sheet as lease assets and lease liabilities. This ASU 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. The new standard is effective for the Predecessor on January 1, 2019. Although early adoption is permitted, the Predecessor does not plan to early adopt the standard. The ASU requires use of the modified retrospective approach, whereby lessees will be required to recognize and measure leases at the beginning of the earliest period presented. The Predecessor is still in the process of evaluating the impact of this new standard; however, the Predecessor believes the initial impact of adopting the standard will result in increases to its assets and liabilities on the consolidated balance sheets, and changes to the presentation of certain operating expenses on its consolidated statements of operations.

Note 3—Derivative Instruments

The Predecessor hedges a portion of its crude oil sales using fixed price swap agreements based on futures price contracts for WTI crude oil. This exposes the Predecessor to market basis differential risk if the WTI price does not move in parity with the Predecessor’s underlying sales of crude oil produced in the Southern Delaware Basin.

The Predecessor’s derivative instruments are carried at fair value on the consolidated balance sheets. The Predecessor 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 Predecessor’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 4, Fair Value Measurements.

The following table summarizes the Predecessor’s derivative contracts as of December 31, 2016:

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements



Contract Period	Volumes (Bbls)	Wtd Avg Price (NYMEX WTI) ($/Bbl)
Oil Swaps:
First quarter 2017	337,675	$	48.02
Second quarter 2017	314,675	$	48.28
Third quarter 2017	307,450	$	48.52
Fourth quarter 2017	275,200	$	48.53
Year ending December 31, 2017	1,235,000	$	48.33
Year ending December 31, 2018	974,100	$	52.90

The Predecessor 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. The changes in fair value of these instruments are recognized through earnings as other income or expense rather than deferred until the anticipated transaction affects earnings. 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 Predecessor’s contracts are included in cash flows from operating activities in the Predecessor’s statements of cash flows.

Subsequent to December 31, 2016, the Predecessor entered into the following derivative contracts:



Contract Period	Volumes (Bbls)	Wtd Avg Price ($/Bbl)
Oil Swaps⁽¹⁾:
First quarter 2017	60,500	$	54.72
Second quarter 2017	182,000	$	54.87
Third quarter 2017	391,000	$	54.74
Fourth quarter 2017	460,000	$	54.68
Year ending December 31, 2017	1,093,500	$	54.74
Year ending December 31, 2018	1,186,750	$	54.74
Year ending December 31, 2019	365,000	$	55.55
Oil Basis Swaps⁽²⁾:
Year ending December 31, 2018	365,000	$	(1.39	)

_______________________________________________________________________________


(1)	The index prices for the oil swaps are based on the NYMEX–WTI monthly average futures price.


(2)	The basis differential price is between Midland–WTI and Cushing–WTI.

The Predecessor recognized the following gains (losses) in earnings for the years ended December 31, 2016, 2015 and 2014:



	2016			2015			2014
	(in thousands)
Gain (loss) on derivatives instruments, net	$	(15,145	)	$	1,323		$	5,375
Cash settlements of derivatives (received) paid	$	2,292		$	(5,935	)	$	(763	)

The Predecessor’s derivative contracts are carried at their fair value on the Predecessor’s consolidated balance sheets using Level 2 inputs, and are subject to industry standard master netting arrangements, which allow the Predecessor to offset recognized asset and liability fair value amounts on contracts with the same counterparty. The Predecessor’s policy is to not offset these positions in its consolidated balance sheets.

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

The following table presents the amounts and classifications of the Predecessor’s derivative assets and liabilities as of December 31, 2016. The Predecessor did not have any outstanding derivative contracts as of December 31, 2015.



December 31, 2016	Balance Sheet Location	Asset		Liability
		(in thousands)
Commodity contracts	Current liabilities	$	—	$	9,567
Commodity contracts	Noncurrent liabilities	—		3,287
Total gross amounts presented in accompanying balance sheets		$	—	$	12,854

Commodity Price Risk

The Predecessor’s principal market risks are its exposure to changes in commodity prices, particularly to the prices of oil and natural gas. The prices of oil and natural gas are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond the Predecessor’s control. The Predecessor 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 Predecessor’s cash flows, the Predecessor 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 Predecessor typically receives an agreed upon fixed price for a specified notional quantity of oil or natural gas, and the Predecessor 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. The Predecessor’s commodity derivatives may expose it to the risk of financial loss in certain circumstances. The Predecessor’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 Predecessor has hedged, the Predecessor will receive less income on the hedged volumes than it would receive in the absence of hedges.

Derivative Counterparty Risk

Where the Predecessor is exposed to credit risk in its financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. Generally, the Predecessor does not require collateral and does not anticipate nonperformance by its counterparties.

The Predecessor’s counterparty credit exposure related to commodity derivative instruments is represented by contracts with a net positive fair value at the reporting date. These outstanding instruments, if any, expose the Predecessor to credit risk in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of the Predecessor’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 Predecessor may sustain a loss and its cash receipts could be negatively impacted.

At December 31, 2016, the Predecessor had commodity derivative contracts with three counterparties, all of which were part of the Predecessor’s credit facility and all of which had investment grade credit ratings. As a result of all the Predecessor’s derivative contracts being in a liability position at December 31, 2016, the Predecessor does not have any exposure related to nonperformance from its counterparties.

Note 4—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). Financial assets and liabilities are measured at fair value on a recurring basis. Nonfinancial assets and liabilities, such as the initial measurement of asset retirement obligations and proved oil and natural gas properties upon acquisition or impairment, are recognized at fair value on a nonrecurring basis.

The Predecessor 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:

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

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.

Assets and liabilities measured on a recurring basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Predecessor’s derivative instruments. The fair values of the Predecessor’s fixed price crude oil swaps were measured using option pricing models. These models use certain variables including forward prices and volatility curves and the strike prices for the instruments. The fair value estimates are adjusted relative to non-performance risk as appropriate. These valuations are Level 2 inputs.

The following table is a listing of the Predecessor’s assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2016 and 2015.



	Level 2
	December 31, 2016		December 31, 2015
	(in thousands)
Assets from commodity derivative contracts	$	—	$	—
Liabilities from commodity derivative contracts	12,854		—

Assets and liabilities measured on a nonrecurring basis

The Predecessor applies the provisions of the fair value measurement standard on a nonrecurring basis to its nonfinancial assets and liabilities, such as the acquisition or impairment of proved and unproved 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.

The Predecessor 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 Predecessor 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 Predecessor 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. No impairments were recorded on proved properties during the years ended December 31, 2016, 2015 and 2014.

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

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 Predecessor uses a market approach, and takes into account future development plans, remaining lease term, drilling results, and reservoir performance. The Predecessor recorded impairment of unproved oil and gas properties expense of $0.4 million, $6.5 million and $1.4 million for the years ended December 31, 2016, 2015 and 2014, respectively, resulting from lease expirations.

The inception value of the Predecessor’s AROs 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 inflows and outflows. Given the unobservable nature of these inputs, they represent within Level 3 inputs.

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation approach based on inputs that are non-observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These inputs require significant judgments and estimates by the Predecessor’s management at the time of the valuation.

Fair Value of Other Financial Instruments

The Predecessor has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, other current assets, accounts payable, and accrued liabilities that approximate fair value due to the nature of the instrument and the short-term maturities of these instruments.

Note 5—Debt Obligations

In June 2015, the Predecessor entered into a five-year $500.0 million senior secured revolving credit facility (the “credit facility”). The credit facility had an initial borrowing base of $20.0 million and has semiannual borrowing base redeterminations by April 1 and October 1 each year. The Predecessor has the option to request up to two additional redeterminations per year between October 1, 2015 and October 1, 2017. Future borrowing bases will be determined in the discretion of the lending syndicate based on proved oil and natural gas reserves, hedge positions and estimated future cash flow from those reserves, as well as any other outstanding debt.

At December 31, 2015, borrowings under the credit facility were to bear interest at the greatest of (a) the prime rate in effect plus an applicable margin, (b) the federal funds rate in effect plus one half of 1.0%, or (c) the daily London Interbank Offered Rate (“LIBOR”), plus an applicable margin. The applicable margins associated with the prime rate or the federal funds rate varied based on the utilization percentage of the credit facility, and was 0.5% to 1.5% for base rate loans and 1.5% to 2.5% for LIBOR loans. The Predecessor also pays an annual commitment fee based on the unused portion of the outstanding borrowing base. The commitment fee rate was either 0.375% or 0.500%, depending on the utilization percentage of the credit facility.

In April 2016, the Predecessor entered into an amendment of its credit facility that increased the borrowing base to $65.0 million and increased the number of lenders from one bank to five banks. Additionally, as a result of the amendment, the prime rate and federal funds rate, which vary based on the utilization percentage of the credit facility, were adjusted to 1.5% to 2.5% for base rate loans and 2.5% to 3.5% for LIBOR loans. The commitment fee rate was set to 0.500% for all utilization levels of the credit facility.

In September 2016, the Predecessor entered into an amendment that increased the credit facility borrowing base to $160.0 million.

The credit facility is secured by oil and natural gas properties representing at least 80% of the value of the Predecessor’s proved reserves. The credit facility contains certain covenants, including among others, restrictions on indebtedness, restrictions on liens, restrictions on investments, restrictions on mergers, restrictions on sales of assets, restrictions on dividends and payments to the Predecessor’s capital interest holders, and restrictions on the Predecessor’s hedging activity. The financial covenants require the Predecessor to maintain compliance with the following financial ratios:

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

•

a current ratio, which is the ratio of the Predecessor’s consolidated current assets (including unused commitments under the credit facility and excluding noncash assets related to asset retirement obligations and derivatives) to consolidated current liabilities (excluding the current portion of long-term debt under the credit agreement and noncash liabilities related to asset retirement 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 consolidated Debt (as defined in our 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 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, 2016, the Predecessor was in compliance with its financial covenants.

As of December 31, 2016, the Predecessor had an outstanding balance under the credit facility of $132.0 million, with a weighted average interest rate of 3.99%, and $28.0 million in borrowing capacity. As of December 31, 2015, the Predecessor had an outstanding balance under the credit facility of $20.0 million, with a weighted average interest rate of 2.10%, and $15.0 million in borrowing capacity. The Predecessor capitalized $0.1 million and $0.03 million of interest during the years ended December 31, 2016 and 2015, respectively.

In January 2017, the Predecessor amended the credit facility which increased the borrowing base to $180.0 million, and increased the number of lenders from five banks to nine banks.

In February 2017, the Company, as parent guarantor, and the Predecessor, as borrower, entered into an amendment to the credit facility with Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto. After giving effect to the amendment, the borrowing base under the credit facility remained at $180.0 million. Additionally, borrowings under the new amendment will bear interest, at the Company’s option, at either (i) the greatest of (ia) the prime rate as determined by the administrative agent, (ib) the federal funds effective rate plus 0.50%, and (ic) the thirty-day adjusted LIBOR plus 1.0%, in each case, plus a margin that varies from 1.25% to 2.25% per annum according to the total facility utilization, (ii) the adjusted LIBOR rate plus a margin that varies from 2.25% to 3.25% per annum according to the total facility utilization or (iii) the applicable LIBOR market index rate plus a margin that varies from 2.25% to 3.25% per annum according to the Company’s total facility utilization. The commitment fee on the unutilized portion of the new amendment remains at 0.50%. Further, the amended credit facility no longer contains the minimum hedging requirements.

Note 6—Members’ Equity

Capital Interests

The Predecessor is a limited liability company with capital interests owned by Quantum and certain officers of the Predecessor. The total capital commitment from all Predecessor capital members is $405.9 million, with Quantum representing 98.55% of the total capital commitment. Capital interests in the Predecessor consist of a single class of units, which receive an internal rate of return threshold of 8% prior to distributions to any other class of equity interests.

Contributions

Capital calls approved by the board of directors are funded on a pro rata basis by all of the capital members. During the years ended December 31, 2016 and 2015, the Predecessor received $51.5 million and $51.0 million, respectively, of capital contributions from its capital members to fund acquisitions, operations and the MIU advance (defined below).

As of December 31, 2016, the Predecessor had remaining capital commitments of approximately $59.8 million.

Management Incentive Units

The Predecessor established an incentive pool plan, whereby the Predecessor granted Management Incentive Units (“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 are achieved by the capital interests) following a qualifying initial public offering, sale, merger, or other qualifying transaction involving the stock or assets of the Predecessor (“Vesting Event”).

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

Compensation expense for the MIUs will be recognized when all performance, market and service conditions are probable of being satisfied, which is generally upon a Vesting Event. At the grant dates and subsequent reporting periods, the Predecessor did not deem it probable that a Vesting Event would occur, therefore, no compensation expense was recorded for the years ended December 31, 2016, 2015 or 2014.

As of December 31, 2016 and 2015, 2,392,813 and 2,350,000 MIUs, respectively, were outstanding from the total pool of 2,600,000 authorized MIUs.

Immediately prior to the Company’s IPO, the MIUs were converted into shares of the Company’s common stock. A portion of these vested and a portion of these vest subject to the terms and conditions of the amended and restated JPE Management Holdings LLC limited liability company agreement.

Distributions

On March 25, 2016, the Predecessor and certain MIU holders (“MIU advance recipients”) entered into the First Amendment to the Limited Liability Company Agreement (the “Distribution Agreement”) under which the Predecessor made a $14.7 million cash advance to MIU advance recipients in April 2016 (the “MIU advance”). Under the terms of the Distribution Agreement, the distribution was treated as an advance and dollar for dollar offset distributions otherwise payable to MIU advance recipients, including with respect to the IPO. The MIU advance was deferred as a long-term asset within other noncurrent assets on the consolidated balance sheets. Compensation expense for the MIU advance will be recognized if the MIU advance asset is no longer recoverable or upon the occurrence of a Vesting Event. In January 2017, the Predecessor completed a qualified IPO and the repayment provision of the MIU advance was satisfied in full.

Aside from the MIU advance, the Predecessor did not make any distributions of capital during the years ended December 31, 2016, 2015 and 2014.

Note 7—Asset Retirement Obligations

The following table summarizes the changes in asset retirement obligations for the years ended December 31, 2016 and 2015. Any asset retirement obligation classified as current is included in accrued liabilities on the consolidated balance sheets.



	2016			2015
	(in thousands)
Asset retirement obligations at January 1,	$	608		$	401
Liabilities incurred and assumed	138			64
Liability settlements and disposals	(127		)	(25		)
Revisions of estimated liabilities	(224		)	125
Accretion	53			43
Asset retirement obligations at December 31,	448			608
Less current portion of obligation	—			(118		)
Long-term asset retirement obligations	$	448		$	490

In 2016 and 2015, the Predecessor recognized revisions of estimated liabilities totaling $0.2 million and $0.1 million, respectively, which were due to changes in abandonment cost and timing estimates.

Note 8—Employee Benefit Plans

The Predecessor sponsors a 401(k) defined contribution plan under which it makes matching contributions for participating employees based on a percentage of the employee contributions. Matching contributions totaled approximately $0.2 million during each of the years ended December 31, 2016, 2015 and 2014. Benefits under this plan are available to all employees, and employees are fully vested in the employer contribution upon receipt.

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JAGGED PEAK ENERGY LLC

(PREDECESSOR)

Notes to Consolidated Financial Statements

Note 9—Commitments and Contingencies

Commitments

The table below shows the Predecessor’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2016.



	Total		2017		2018		2019		2020		2021
	(in thousands)
Operating leases⁽¹⁾	$	1,340	$	815	$	525	$	—	$	—	$	—
Service and purchase contracts⁽²⁾	477		468		8		1		—		—
Rig contracts	18,239		18,239		—		—		—		—
Total	$	20,056	$	19,522	$	533	$	1	$	—	$	—

_______________________________________________________________________________


(1)	Primarily relates to the lease of the Predecessor’s corporate offices


(2)	Primarily relates to an obligation to purchase Lease Automatic Custody Transfer (LACT) units in conjunction with oil gathering for current and future wells

Lease commitments

The Predecessor leases its corporate office space in Denver, Colorado under an agreement expiring in 2018. The Predecessor also finances certain office equipment under operating leases, which expire over the next two years. Rent expense with respect to these lease commitments was approximately $0.6 million for each of the years ended December 31, 2016, 2015 and 2014.

Drilling rig commitments

The Predecessor had five drilling rig contracts at December 31, 2016, which it plans to use in its development plan. If the Predecessor were to terminate these contracts at December 31, 2016, it would be required to pay early termination penalties of $8.1 million. In 2016 and 2015, the Predecessor terminated one drilling rig in each year and incurred early termination charges of approximately $0.2 million and $0.3 million, respectively. These charges are reflected as other operating costs in the consolidated statements of operations.

Contingencies

Legal Matters

In the ordinary course of business, the Predecessor 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 Predecessor’s financial position, results of operations or cash flows.

Environmental Matters

The Predecessor 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, 2016 and 2015, the Predecessor had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

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Note 10—Related Party Transactions

Quantum employs certain members of the Predecessor’s board of directors, had significant capital interests in the Predecessor at December 31, 2016 and beneficially owns 68.7% of its outstanding common stock.

Quantum owns a 41.5% interest in Oryx Midstream Services, LLC (together with Oryx Southern Delaware Holdings, LLC, “Oryx”). The Predecessor has a 12-year crude oil gathering agreement with Oryx whereby Oryx provides midstream gathering services to the Predecessor, who, in turn, has the right to designate, and has designated, a third-party shipper to market the Predecessor’s crude oil. During the year ended December 31, 2016 the Predecessor’s third-party shipper paid Oryx $2.1 million in transportation fees pursuant to this agreement. In addition, during the years ended December 31, 2016 and 2015, the Predecessor paid fees to Oryx of $1.8 million and $0.4 million, respectively, for the purchase and maintenance of connecting equipment. The Predecessor did not use Oryx’s services in 2014, and paid no fees during that year.

Quantum also owns a 61% interest in Phoenix Lease Services, LLC (“Phoenix”), and an indirect interest in Trident Water Services, LLC (“Trident”), a wholly owned subsidiary of Phoenix. The Predecessor regularly leases frac tanks and other oil field equipment from Phoenix, and also regularly uses water transfer services provided by Trident. The Predecessor is under no obligation to use either provider, and both provide services only when selected as a vendor through the normal bidding process. In 2016, the Predecessor paid fees of $0.3 million and $0.6 million related to such services provided by Phoenix and Trident, respectively. During 2015, such costs were $0.4 million and $1.0 million, respectively. In 2014, fees paid to Phoenix and Trident were $0.2 million and $0.3 million, respectively.

At December 31, 2016 and 2015, the Predecessor had outstanding payables to the aforementioned related parties of $0.7 million and $0.4 million, respectively.

Note 11—Subsequent Events

The Predecessor has evaluated subsequent events through the date these financial statements were issued. The Predecessor determined there were no events, other than as described below, that required disclosure or recognition in these financial statements.

On January 27, 2017, the Company completed the IPO of common stock to the public. As part of the IPO, 31,599,334 shares of common stock were sold at $15.00 per share, raising $474.0 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 were approximately $425.0 million, which resulted in net proceeds of $397.4 million after deducting expenses and underwriting discounts and commissions of approximately $27.6 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 the Predecessor’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 will be used to fund a portion of the 2017 capital expenditure program, and for other general corporate purposes. As a result of the IPO, there are 212,937,746 common shares of the Company outstanding as of March 17, 2017.

In connection with the IPO, certain members of management and employees who held MIUs in the Predecessor, contributed unvested or unallocated MIUs to JPE Management Holdings LLC, a newly formed limited liability company. Also in connection with the IPO, a corporate reorganization took place whereby the Company, initially formed as a subsidiary of the Predecessor, formed JPE Merger Sub LLC as a subsidiary of the Company. The Predecessor merged into JPE Merger Sub LLC with the Predecessor as the surviving entity. As a result, the Predecessor became a wholly owned subsidiary of the Company.

As a result of the IPO, the MIUs experienced a Vesting Event. As a result, the Predecessor will recognize a $532.6 million charge related to compensation expense, all of which will be noncash except for the $14.7 million related to the MIU advance. Please refer to Note 6, Members’ Equity, for more details on MIUs.

As described in Note 5, Debt Obligations, the Predecessor amended its credit facility twice thus far in 2017. In January 2017, the credit facility was amended to increase the borrowing capacity to $180.0 million and add four additional lenders. In February 2017, the credit facility was amended to include the Company, as parent guarantor, and the Predecessor as borrower, and Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto. Among other things, the amended credit facility (i) increased the maximum commitment to $1.0 billion from $500.0 million, (ii) maintained the borrowing base at

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$180.0 million, (iii) lowered the interest rate on amounts borrowed, (iv) removed the minimum hedging requirements and (v) allowed for the corporate reorganization that was completed simultaneously with the closing of the IPO. See Note 5, Debt Obligations, for more details around the most recent amendment.

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Supplemental Oil and Natural Gas Disclosures (Unaudited)

Oil and Gas Exploration and Production Activities

The Predecessor has only one reportable operating segment, which is oil and gas development, exploration and production in the United States. See the Predecessor’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities. The amounts shown include the Predecessor’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 Predecessor’s oil and natural gas producing activities at December 31, 2016 and 2015 were as follows:



	December 31,
	2016			2015
	(in thousands)
Proved property	$	375,129		$	204,154
Unproved property	155,992			128,913
	531,121			333,067
Accumulated depletion, depreciation and amortization	(57,529		)	(30,341		)
Net capitalized costs	$	473,592		$	302,726

Costs Incurred for Oil and Gas Activities

Costs incurred for the Predecessor’s oil and natural gas activities for the years ended December 31, 2016, 2015 and 2014 were as follows:



	Year Ended December 31,
	2016		2015		2014
	(in thousands)
Acquisition costs:
Proved property	$	7,482	$	—	$	21,431
Unproved property	47,618		11,437		103,355
Development costs	158,349		115,492		73,829
Exploration costs	1,673		852		64
Total costs incurred⁽¹⁾	$	215,122	$	127,781	$	198,679

_______________________________________________________________________________


(1)	Includes amounts related to estimated asset retirement costs of $0.02 million, $0.2 million and $0.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. The decrease to the Predecessor’s asset retirement estimate for the year ended December 31, 2016, as compared to 2015, is primarily due to a reduction in the future estimated abandonment costs.

Oil and Natural Gas Reserve Quantities

The Predecessor’s proved oil and natural gas reserves are all located in the United States, within the Permian Basin of West Texas. All of the estimates of the proved reserves at December 31, 2016, 2015 and 2014 are based on reports prepared by Ryder Scott Company, LP, the Predecessor’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., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. A variety of methodologies are used to determine the Predecessor’s proved reserve estimates. The primary methodologies used are decline curve analysis, advance production type curve matching, petro physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates across substantially all the Predecessor’s properties. Reserve estimates ar

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e inherently imprecise, and estimates of undeveloped locations are more imprecise than estimates of established proved producing locations. Accordingly, the Predecessor’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 natural gas liquids volumes, the benchmark WTI posted price is adjusted for quality, transportation fees and regional price differentials. For gas volumes, the Henry Hub spot price is adjusted for energy content, transportation fees and regional price 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. The following table summarizes the average adjusted product prices for 2016, 2015 and 2014.



	2016		2015		2014
Oil price per Bbl	$	39.33	$	46.26	$	84.54
Gas price per Mcf	$	2.22	$	2.36	$	4.21
NGL price per Bbl	$	15.48	$	16.49	$	31.17

In addition, the SEC requires that reserves classified as proved undeveloped be capable of conversion into proved developed within five years of classification unless specific circumstances justify a longer time. The Predecessor’s development plans at December 31, 2016 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 sets forth information regarding the Predecessor’s estimated net total proved and proved developed oil and natural gas reserve quantities:



	Oil (MBbls)		Gas (MMcf)		NGLs (MBbls)		Total (MBoe)
Proved reserves:
Balance December 31, 2013	—		—		—		—
Acquisitions of reserves	837		707		109		1,064
Extensions, discoveries and other additions	1,270		1,094		291		1,744
Production	(189	)	(172	)	(35	)	(253	)
Balance December 31, 2014	1,918		1,629		365		2,555
Extensions, discoveries and other additions	8,734		4,906		1,226		10,778
Revisions of previous estimates	559		26		(11	)	552
Production	(718	)	(404	)	(89	)	(874	)
Balance December 31, 2015	10,493		6,157		1,491		13,011
Acquisitions of reserves	340		430		54		466
Extensions, discoveries and other additions	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
Proved developed reserves:
December 31, 2014	1,529		1,319		288		2,037
December 31, 2015	4,848		2,547		621		5,894
December 31, 2016	11,916		6,566		1,491		14,501
Proved undeveloped reserves:
December 31, 2014	389		310		77		518
December 31, 2015	5,645		3,610		870		7,117
December 31, 2016	18,490		12,953		2,545		23,194

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2016 Activity. During 2016, the Predecessor’s estimated proved reserves increased by 24.7 MMBoe to 37.7 MMBoe, compared to 13.0 MMBoe at year-end 2015. The increase in proved reserves during 2016 was largely due to 25.2 MMBoe added through extensions and discoveries, due to new wells completed in 2016 and adding 25 PUD locations.

2015 Activity. Estimated proved reserves at December 31, 2015 were 13.0 MMBoe, compared to 2.6 MMBoe at December 31, 2014. The increase in proved reserves during 2015 was primarily related to the Predecessor’s drilling activities. During 2015, the Predecessor drilled and completed seven wells and added nine PUD locations, leading to a combined increase of 10.8 MMBoe of extensions and discoveries.

2014 Activity. Estimated proved reserves at December 31, 2014 were 2.6 MMBoe, and at December 31, 2013, the Predecessor had not yet recorded proved reserves. The proved reserve quantities for the year ended December 31, 2014 were partly due to the Predecessor acquiring 28 producing wells during 2014, and partly due to the Predecessor’s operated drilling program. The acquired wells contributed 1.1 MMBoe as of December 31, 2014. As part of the Predecessor’s drilling program, the Predecessor completed an additional five wells during 2014, which added 1.1 MMBoe of proved developed reserves. The Predecessor also added an additional 0.6 MMBoe from one PUD location added during 2014.

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 Predecessor’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 Predecessor’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. With regard to the future income taxes, the Predecessor is a limited liability company, therefore is 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 as the Predecessor is not subject to federal income taxes. The Predecessor is, 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 gas reserves as of December 31, 2016, 2015 and 2014.



	2016			2015			2014
	(in thousands)
Future cash inflows	$	1,301,702		$	524,538		$	180,425
Future production costs	(382,999		)	(146,779		)	(53,560		)
Future development costs	(278,229		)	(90,661		)	(9,519		)
Future tax expense	(8,671		)	(3,467		)	(1,201		)
Future net cash flows	631,803			283,631			116,145
10% annual discount	(360,857		)	(151,910		)	(51,279		)
Standardized measure of discounted future net cash flows	$	270,946		$	131,721		$	64,866

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A summary of principal sources of changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2016, 2015 and 2014 is as follows:



	2016			2015			2014
	(in thousands)
Standardized measure of discounted future net cash flows, beginning of period	$	131,721		$	64,866		$	—
Sales of oil and natural gas, net of production costs and taxes	(62,453		)	(28,264		)	(13,197		)
Extensions, discoveries and improved recovery, less related costs	160,238			118,532			51,089
Revisions of previous quantity estimates	14,315			5,187			—
Net changes in prices and production costs	(36,752		)	(41,264		)	—
Previously estimated development costs incurred during the period	36,996			34			—
Changes in estimated future development costs	1,019			1,898			—
Accretion of discount	13,347			6,552			—
Acquisitions of reserves	3,373			—			27,626
Sales of reserves	(1,506		)	—			—
Net change in taxes	(2,674		)	(1,042		)	(652		)
Changes in timing and other	13,322			5,222			—
Standardized measure of discounted future net cash flows, end of period	$	270,946		$	131,721		$	64,866

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Supplemental Quarterly Financial Data (Unaudited)

The following table provides selected quarterly financial data derived from the Predecessor’s consolidated financial statements for the years ended December 31, 2016 and 2015.



	Quarter
2016	First			Second			Third		Fourth
	(in thousands, except per share data)
Revenues	$	10,245		$	19,336		$	22,064	$	24,877
Operating expenses	16,403			15,729			17,623		18,753
Operating income (loss)	$	(6,158	)	$	3,607		$	4,441	$	6,124
Net income (loss)	$	(7,450	)	$	(5,749	)	$	5,410	$	(1,971	)



	Quarter
2015	First			Second			Third		Fourth
	(in thousands)
Revenues	$	4,622		$	7,528		$	10,843	$	10,858
Operating expenses	7,307			7,395			9,999		17,760
Operating income (loss)	$	(2,685	)	$	133		$	844	$	(6,902	)
Net income (loss)	$	(2,075	)	$	(836	)	$	2,212	$	(6,785	)

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Jagged Peak Energy Inc. - FORM 10-K - March 23, 2017

Attached files

Jagged Peak Energy Inc. Reports