General

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

JPE LLC, a Delaware limited liability company, was formed in April 2013 by an affiliate of Quantum Energy Partners (“Quantum”) and former members of our management team at the time. Jagged Peak was formed and incorporated in the state of Delaware in September 2016. In January 2017, pursuant to a corporate reorganization completed in connection with the IPO, JPE LLC became a wholly-owned subsidiary of Jagged Peak (the “corporate reorganization”).

Business Overview

We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil and associated liquids-rich natural gas reserves in the southern Delaware Basin. We are focused on increasing stockholder value by (i) balancing the long-term development of our assets with a focus on generating attractive corporate-level returns, (ii) growing production and reserves through the development of our multi-year inventory, (iii) expanding and improving the resource potential of our existing acreage position, (iv) growing our acreage position through acquisitions and leasing efforts and (v) increasing cash flows relative to the amount of capital expenditures incurred during a given period.

The following table summarizes information regarding our operations as of of for the year ended December 31, 2018 :

During 2018 , our average daily production of 34,207 Boe/d consisted of 77% oil, 12% NGLs and 11% natural gas.

Our Properties and Operations

Our acreage is located on large, contiguous blocks in the adjacent West Texas counties of Winkler, Ward, Reeves and Pecos, with significant original oil-in-place within multiple stacked hydrocarbon-bearing formations. As of December 31, 2018 , we operated approximately 97% of our net acreage and held an average 87% working interest in approximately 91,600 gross ( 79,500 net) acres. This operational control gives us flexibility in development strategy and pace. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus to increase capital efficiency by reducing drilling and completion cycle times, optimizing completions and reducing costs. We expect that further optimization in the field, which will include drilling long and extra-long laterals, pad drilling, shared facilities and zipper fracs will continue to improve our well economics.

We divide our current area of operation within the southern Delaware Basin into three distinct project areas: Cochise, Whiskey River and Big Tex. The Cochise project area lies in the northern part of our acreage position and straddles Ward and Winkler Counties. Whiskey River is in the central part of our overall leasehold position and primarily lies just west of the junction between Ward, Reeves and Pecos Counties in Texas. The Big Tex project area is our southernmost leasehold position and lies in northern Pecos County.

The following table summarizes our approximate acreage by project area as of December 31, 2018 :

During 2018 , we operated an average of approximately five horizontal rigs, compared to an average of approximately six during 2017 . During this same period, our average daily production grew from 9,785  Boe/d in the first quarter of 2017 to 38,413 Boe/d in the fourth quarter of 2018 . During 2018 , we began production on 59 gross ( 48.0 net) wells, of which we operated 45 gross ( 42.4 net) wells. As of December 31, 2018 , we have 160 gross ( 143.0 net) producing wells. At year end, we were in the process of drilling 11 gross ( 10.4 net) wells and had eight gross ( 8.0 net) wells waiting on completion, including four gross ( 4.0 net) wells that were in process of being completed. At December 31, 2018 , we were operating seven horizontal rigs, two of which were released in January 2019.

Through December 31, 2018 , we have drilled, completed and are producing from 112 gross ( 106.9 net) operated horizontal wells in eight distinct targets: 2 ^nd Bone Spring, 3 ^rd Bone Spring, Upper Wolfcamp A, Lower Wolfcamp A, Upper Wolfcamp B, Lower Wolfcamp B, Wolfcamp C and Woodford. While we have producing wells in these distinct targets, the formations primarily targeted have been the Lower and Upper Wolfcamp A and the 3 ^rd Bone Spring. Of the 45 gross operated wells that we began producing from during 2018 , 36 were in the Lower Wolfcamp A and five were in the 3 ^rd Bone Spring. Other operators continue to maintain active drilling and completion operations on acreage offsetting our acreage position. We monitor this offset activity, especially with respect to downspacing pilots, and will adjust our future development plans to allow for the optimal development of our acreage position. We also believe potential development opportunities exist on portions of our acreage in the Brushy Canyon, Avalon Shale, 1 ^st Bone Spring and Pennsylvanian aged formations.

Our contiguous acreage position enables the drilling of long laterals, resulting in significant drilling efficiencies that enhance the economic development of our acreage position. Of our approximately 1,800 gross horizontal drilling locations as of December 31, 2018 , 86% are classified as long or extra-long. We consider laterals of 5,640 feet and lower as standard length, laterals between 5,640 feet and 8,000 feet to be long, and laterals greater than 8,000 feet to be extra-long. The ability to drill long-lateral wells improves our returns by (i) increasing our EUR per well, (ii) allowing us to contact more reservoir rock with fewer vertical wellbores (thus reducing drilling and completion costs on a per unit basis) and (iii) allowing us to hold by production more acreage per horizontal well drilled. Additionally, the contiguous nature of our acreage provides economies of scale by allowing us to better share our infrastructure among wells across our acreage position.

In conjunction with developing our acreage for optimized production of our oil and natural gas reserves, we have also developed our own water system, which enables us to source, store and dispose of water efficiently. As of December 31, 2018 , we had approximately 5,100 net surface acres, which allows us the operational and financial control to source, dispose, store and transport water. Our water infrastructure includes approximately (i) 9.3 MMBbl of water storage capacity, (ii) 30 miles of fresh water pipelines and 130 miles of produced water pipelines, which allows us to largely eliminate water trucking in all phases of our operation, (iii)  150 MBbl/d of water sourcing capacity and (iv)  200 MBbl/d of water disposal capacity. Accordingly, we have available disposal capacity and sufficient sources of fresh water to support our current development program. Surplus fresh water and disposal capacity generated approximately $0.8 million of other operating revenues in 2018 , and opportunities to leverage surplus capacities will be evaluated in 2019.

Proved Reserves

Internal Controls Over Reserve Estimating Process.     Our proved reserve estimates as of December 31, 2018 , 2017 and 2016 , were prepared by Ryder Scott Company, LP (“Ryder Scott”), our third party, independent engineering firm. Within Ryder Scott, the technical person primarily responsible for preparing the estimates set forth in the Ryder Scott reserves report incorporated herein is Mr. Stephen E. Gardner. Mr. Gardner, a Licensed Professional Engineer in the States of Colorado and Texas, has been practicing consulting petroleum engineering at Ryder Scott since 2006 and has more than 13 years of practical experience in the estimation and evaluation of petroleum reserves. He graduated from Brigham Young University in 2001 (summa cum laude) with a Bachelor of Science Degree in Mechanical Engineering. Mr. Gardner meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and is proficient in judiciously applying industry standard practices to evaluations as well as applying Securities and Exchange Commission (“SEC”) and other industry reserves definitions and guidelines. Ryder Scott does not own an interest in any of our properties, and is not employed by us on a contingent basis. A copy of Ryder Scott’s proved reserve report as of December 31, 2018 is included as an exhibit to this Form 10-K.

The preparation of our proved reserve estimates was completed in accordance with our internal control procedures. These procedures are intended to ensure reliability of reserve estimations. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an internal review of assumptions used in the estimation as well as ultimate approval of our capital budget and review of our development plan by our senior management. The development plan underlying the Company’s proved undeveloped reserves (“PUDs”) is further subject to internal controls, including (i) a comparison of future development costs to our historical expenditures, our future development plan, and financial capabilities and (ii) an evaluation of the estimated profitability of each location at the time the report is prepared. The development plan underlying the Company’s PUDs, adopted every year by senior management, is based on the best information available at the time of adoption. As factors such as commodity price, service costs, performance data and asset mix are subject to change, the Company occasionally revises its development plan. Development plan revisions include deferrals, removals and substitutions of previously scheduled

PUD reserve locations. These occasional changes achieve the purpose of maximizing profitability and are in the best interest of the Company’s shareholders.

Our internal professional staff worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to Ryder Scott for our properties, such as ownership interest, oil and natural gas production, realized commodity prices and operating and development costs. Our Planning and Reserves Manager is primarily responsible for overseeing the preparation of the Company’s reserve estimates. Our Planning and Reserves Manager is a reservoir engineer with more than 17 years of reservoir and operations experience and has been licensed by the Texas Board of Professional Engineers since 2005.

Estimation of Proved Reserves.     The estimates of proved reserves as of December 31, 2018 are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic and analogy methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, which were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment.

Summary of Reserves.     The following table sets forth the Company’s estimated net proved reserves as of December 31, 2018 , 2017 and 2016 , based on the proved reserve report as of such dates by Ryder Scott, prepared in accordance with the rules and regulations of the SEC. All of our proved reserves are located in the United States.

The above reserve estimates were determined using the trailing 12-month index prices in accordance with SEC guidance. These prices were adjusted for gravity, quality, local conditions, gathering and processing fees and distance from market. All prices are held constant throughout the lives of the properties. The following table summarizes the average adjusted product prices used in our reserve estimates as of December 31, 2018 , 2017 and 2016 :

Total proved reserves at December 31, 2018 were 118.9 MMBoe, compared to 82.4 MMBoe at December 31, 2017 , and 37.7 MMBoe at December 31, 2016 . The increase in total proved reserves during 2018 was primarily related to our drilling and completion activities. During 2018 , we began production on 59 gross ( 48.0 net) wells. This activity resulted in a combined increase of 35.7 MMBoe due to infill reserves from a proved field. Over this time period, we also had approximately 12.7  MMBoe of upward revisions to prior estimates, due primarily to 11.2 MMBoe of positive performance revisions.

Proved Undeveloped Reserves

PUDs include those reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Undrilled locations may be classified as proved reserves on acreage directly offsetting developed wells if the PUD locations are reasonably certain of production when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having PUDs only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. As of December 31, 2018 , all 60 of our PUD drilling locations are scheduled to be developed within five years of their initial booking.

For PUD locations that are more than one development spacing area from developed producing locations, we utilized reliable geologic and engineering technology when booking PUDs. We incorporated public and proprietary data from multiple sources to establish geologic continuity of each formation and their producing properties. This included seismic data and interpretations (3-D and micro seismic), open hole log information (collected both vertically and horizontally) and petrophysical analysis of that log data, mud logs, gas sample analyses, measurements of total organic content, thermal maturity, test production, fluid properties, core data and significant statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas where both established geologic consistency and sufficient statistical performance data could be demonstrated to provide reasonably certain results. In all other areas, we restricted proved undeveloped locations to development spacing areas that are immediately adjacent to developed spacing areas.

The following table summarizes the changes in our estimated PUDs during 2018 :

Conversions. The 26.6 MMBoe of PUDs converted to proved developed reserves in 2018 were converted at a total capital cost of approximately $487.0 million . Our estimated total capital costs to develop our remaining PUDs at December 31, 2018 are approximately $670.1 million .

Infill reserves in an existing proved field. We added 29.3 MMBoe in 2018 as a result of our infill PUDs.

Net revisions of previous estimates. Revisions of previous estimates reflect our ongoing evaluation of our asset portfolio. During 2018 , PUDs were revised downward by 18.0 MBoe as illustrated in the table below.

The total number of PUD locations at December 31, 2018 is 60 , compared with 63 at December 31, 2017 . As of  December 31, 2018 , none of our PUDs were on acreage expected to expire or on acreage that was not expected to be held through renewal before the targeted completion date.

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.

Developed and Undeveloped Acreage

Developed acreage consists of acres spaced or assigned to productive wells and does not include all undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

The following table sets forth the gross and net acres of both developed and undeveloped leases held by Jagged Peak as of December 31, 2018 . Acreage related to royalty, overriding royalty and other similar interests is excluded from this table.

Our mineral leases expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date or held by continuous development operations, under which circumstances the lease will remain in effect until the cessation of production. Substantially all of the leases governing our acreage have continuous development clauses that require us to initiate additional development within 120 to 180 days after the completion of the last well drilled on such lease in order to continue to hold the acreage after the expiration of the primary term. Thereafter, the lease is held with additional development every 120 to 180 days until the entire lease is held by production. None of our horizontal drilling

locations associated with PUDs are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule or primary term. As of December 31, 2018 , approximately 58% of our total net acreage was held by production or continuous development operations.

The following table sets forth the number of net undeveloped acres as of December 31, 2018 that will expire over the next three years unless production is established or development is continued within the spacing units covering the acreage prior to the expiration dates, or unless such acreage is extended or renewed.

Of the net acres that are set to expire in the next three years, acreage in the Big Tex project area represents 90%, 87% and 82% of the expiring acreage in 2019, 2020 and 2021, respectively. During 2018, we recognized unproved oil and natural gas impairment expense of $28.2 million on certain Big Tex acreage that largely resulted from our ongoing evaluation of our undeveloped Big Tex acreage and our current plan to not drill on certain of these leases before they expire. The acreage in the table above, and throughout this Form 10-K, includes the impaired Big Tex acreage, as it has not yet expired.

Productive Wells

As of December 31, 2018 , we owned an average working interest of 89% in 160 gross ( 143.0 net) productive wells and a minimal royalty interest in 24 additional productive wells. Our wells are oil wells that also produce associated liquids-rich natural gas. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities.

Transportation and Marketing

We are party to a long-term oil gathering agreement entered into in 2015 pursuant to which we dedicated all of our oil production from our Whiskey River and Cochise acreage. This agreement was amended in May 2017 to include our Big Tex acreage. We sell substantially all of our oil production pursuant to a long-term marketing agreement that expires on December 31, 2020. Additionally, in November 2018, we entered into a 5-year oil marketing agreement that is expected to take effect at the commencement of commercial operations on the Cactus II pipeline and will link a portion of our oil production to Gulf Coast pricing.

Historically, our sales and transportation agreements were based on acreage dedications and did not contain any minimum volume commitments or other similar provisions; however, our Gulf Coast pricing oil agreement entered into in November 2018, commencing in late 2019 or early 2020, specifies a minimum gross volume commitment for oil of 30,000 barrels per day on a monthly basis. We expect to be able to meet this commitment that will be sourced from our properties in the southern Delaware Basin.

We sell substantially all of our natural gas from our Cochise acreage under a long-term gathering and processing agreement entered into in September 2015, and substantially all of our natural gas from our Whiskey River acreage under a long-term gathering and processing agreement entered into in October 2016. We sell substantially all of our natural gas from our Big Tex acreage pursuant to a short-term gathering and processing agreement expiring in the fall of 2019. Substantially all of our natural gas production is transported from the wellhead by third-party gathering lines to natural gas processing facilities.

Major Customers

We sell our oil, natural gas and NGL production to purchasers at market prices. We sell our production to a relatively small number of customers, as is customary in our business. For 2018 , revenues from Trafigura Trading, LLC accounted for approximately 85% of our total revenue and no other purchaser accounted for 10% or more of our revenue. The loss of this purchaser could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil, natural gas and NGLs, and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil, natural gas and NGLs are fungible products with well-established markets.

Infrastructure

Our infrastructure strategy includes owning sufficient tracts of surface acreage to (i) allow us to control water supply for drilling and completions, (ii) provide ease of pipeline installation, (iii) allow construction of storage for both fresh and treated produced water and (iv) allow us to control facilities for disposal of flowback and produced water. In addition, we have supplemental agreements that provide for fresh water sourcing and produced water storage and disposal from surface acreage owned by adjacent landowners as needed. As of December 31, 2018 , we owned approximately 5,100 net surface acres. Our water infrastructure consists of approximately (i) 9.3 MMBbl of water storage capacity, (ii) 30 miles of fresh water pipelines, (iii) 130 miles of produced water pipelines, (iv)  150 MBbl/d of water sourcing capacity and (v)  200 MBbl/d of water disposal capacity. Our infrastructure allows us to largely eliminate water trucking in all phases of our operations. Accordingly, we have available disposal capacity and sufficient sources of fresh water to support our current and anticipated development program. Surplus fresh water and surplus disposal capacity generated approximately $0.8 million revenue in 2018 , and opportunities to leverage surplus capacities will be evaluated in 2019.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation.

Seasonality of Business

Weather conditions can affect the demand for, and prices of, oil and natural gas and refinery turnaround, and summer driving season affects demand for, and prices of, crude oil. The prices of both oil and natural gas are heavily dependent on current and future expectations of supply and demand factors, including current domestic and worldwide storage of each commodity and may not follow a seasonal pattern. Due to seasonal fluctuations or the other above factors impacting pricing, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises, including flared gas. The lessor royalties and other leasehold burdens on our properties generally approximate 25%, resulting in a net revenue interest to us generally approximating 75%, subject to proportionate reduction in the event we own less than 100% working interest.

Regulation of the Oil and Natural Gas Industry

General

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. We own or operate producing oil and natural gas properties in Texas, which has statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past noncompliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. In addition, policies, proposals and proceedings that affect the oil and natural gas industry may continue to change under the current political environment. We cannot predict when or whether any such proposals may become effective. We do not believe we would be affected by any such action materially differently than similarly situated competitors.

Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and

reports concerning operations. We own interests in properties located in Texas, which regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density and plugging and abandonment of wells. In Texas, flaring and venting of natural gas are regulated by the Railroad Commission of Texas (the “RRC”) and the Texas Commission on Environmental Quality (the “TCEQ”). The RRC regulations strive to maximize production and minimize waste, while the TCEQ regulations focus on limiting air pollution. The RRC allows an operator to flare gas while drilling a well and for up to 10 days after a well’s completion so that operators can conduct well potential testing. However, for most short-term and any extended flaring requests the RRC requires operators to obtain a permit. The TCEQ regulates flaring by issuing air permits on behalf of the Environmental Protection Agency (the “EPA”). The TCEQ permits require air pollution controls and process designs that limit venting and flaring of gas from production facilities.

The effect of these regulations could limit the amount of oil and natural gas that we can produce from our wells and could limit the number of wells or the locations at which we can drill, although we can at times apply for exceptions to such regulations or to have reductions in well spacing. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. We do not believe we are impacted any differently by these regulations than similarly situated competitors. The failure to comply with these rules and regulations can result in substantial penalties.

Regulation of Sales and Transportation of Oil

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil, condensate and NGLs sales, or the prices we can charge for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the Texas state legislature and what effect, if any, the proposals might have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil may also be subject to rate and access regulation. FERC regulates interstate transportation of oil, including natural gas liquids, under the Interstate Commerce Act (the “ICA”). This includes movements of oil or natural gas liquids through any pipelines, including those located solely in one state, that are providing part of the continuous movement of the products in interstate commerce for a shipper. Prices received from the sale of oil and natural gas liquids may be affected by the cost of transporting those products to market. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service for jurisdictional movements be “just and reasonable.” In general, interstate oil pipeline rates must be cost-based, although negotiated rates with at least one nonaffiliated shipper and settlement rates agreed to by all shippers who on the day of the filing of the proposed rate are using the service covered by the rate, are permitted. Additionally, market-based rates may be permitted in certain circumstances. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of Sales and Transportation of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While first sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed price controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (the “NGA”), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

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

basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transportation facilities as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting natural gas to point of sale locations may increase. We believe the natural gas pipelines in the gathering systems we use meet the traditional tests FERC has used to establish a pipeline’s status as gathering facilities not subject to regulation under the NGA. However, the distinction between FERC-regulated transportation services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of the gathering facilities we use are subject to change based on future determinations by FERC, the courts or Congress.

The price at which we sell natural gas is not currently subject to federal rate regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the Energy Policy Act of 2005 (the “EP Act of 2005”) and under the Commodity Exchange Act (the “CEA”), and regulations promulgated thereunder by the Commodity Futures Trading Commission (the “CFTC”). The price manipulation provisions of the CEA make it unlawful for any person, directly or indirectly, to manipulate or attempt to manipulate the price of any swap, or of any commodity in interstate commerce, or for future delivery on or subject to the rules of any registered entity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading reports concerning market information or conditions that affect or tend to affect the price of any commodity in interstate commerce, knowing, or acting in reckless disregard of the fact that such report is false, misleading or inaccurate. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, any market participant that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to FERC on Form No. 552. The definitions accompanying the form state that reportable physical natural gas transactions are only those transactions that either use an index, or that contribute to, or may contribute to the formation of a gas index during the calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies in Texas. Entities transporting crude oil and natural gas liquids in the State of Texas in intrastate commerce as common carriers may be subject to state regulation under the Texas Natural Resources Code (the “TNRC”) and the rules of the RRC. Such common carriers are required to publish tariffs under rules set by the RRC and must provide transportation service without discrimination as to rates and terms of service. Violation of these rules may result in civil and administrative penalties. The RRC is responsible for establishing and promulgating rates, though in practice its regulation of rates is primarily on a complaint basis. The RRC has broad authority to establish safety standards for intrastate pipelines transporting crude oil and natural gas liquids and has adopted by reference minimum safety standards promulgated by the Pipeline and Hazardous Materials Safety Administration (the “PHMSA”).

Intrastate natural gas pipelines located in Texas that are not regulated by FERC may be subject to state regulation as common purchasers under the TNRC or as gas utilities as defined in the Texas Utilities Code and must comply with certain rules of the RRC. These statutes and rules prohibit common purchasers and gas utilities from discriminating among similarly situated shippers and require that transportation be provided under just and reasonable terms and conditions. The RRC has the authority to regulate rates on a complaint basis and may assess administrative penalties against common purchasers and gas utilities determined to be in violation of its rules. Upon request by the RRC, common purchasers and gas utilities are obligated to provide their books and records to the RRC for audit purposes; gas utilities must also disclose to the RRC certain information about their

contracts with customers. The RRC has broad authority to establish safety standards for intrastate natural gas pipelines and has adopted by reference minimum safety standards promulgated by PHMSA. The RRC has also enacted safety measures applicable to natural gas pipelines, including additional reporting requirements and pipeline integrity testing.

Insofar as regulation within Texas will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe the regulation of similarly situated intrastate natural gas transportation in Texas, in which we operate and ship natural gas on an intrastate basis, will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.

Regulation of Environmental and Occupational Safety and Health Matters

Our oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to directly control the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us and result in CERCLA liability.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of the Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

We currently own, lease or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Regulation

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near certain regulated waters, including navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including certain wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”) potentially following review or input by the EPA. In June 2015, the EPA and the Corps issued a new rule known as the Clean Water Rule clarifying the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated. In February 2018, the EPA issued a rule that delays the applicability of the new definition of the waters of the United States until 2020. On August 16, 2018, the U.S. District Court for South Carolina found that the EPA and the Corps failed to comply with the Administrative Procedure Act and struck the 2018 rule that attempted to delay the applicability date of the 2015 Clean Water Rule. Other district courts, however, have issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself. Taken together, the 2015 Clean Water Rule is currently in effect in 23 states, and temporarily stayed in the remaining states, including Texas and New Mexico. In those remaining states, the 1986 rule and guidance remain in effect. On December 11, 2018, the EPA and the Corps issued a proposed new rule that would differently revise the definition of “waters of the Unites States” and essentially replace both the 1986 rule and the 2015 Clean Water Rule. According to the agencies, the proposed new rule is “intended to increase CWA program predictability and consistency by increasing clarity as to the scope of ‘waters of the United States’ federally regulated under the Act”. If finalized, this new definition of “waters of the United States” will likely be challenged and sought to be enjoined in federal court. To the extent any new rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in certain areas. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for the unauthorized discharge of dredge and fill material and oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We are currently undertaking a review of our properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (the “OPA”), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Air Emissions

The Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as storage tanks and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, comply with stringent air permit or other requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound and methane emissions from certain fractured and refractured natural gas and oil wells for which well completion operations must be conducted through the use of reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from various equipment and processes, including production-related wet seal and reciprocating compressors pneumatic controllers and storage vessels. More recently, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. See also “—Regulation of “Greenhouse Gas” Emissions.” Compliance with these and other air pollution control and permitting requirements, including at the state level, has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant.

Regulation of “Greenhouse Gas” Emissions

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under the Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources of GHGs. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rules impose leak detection and repair requirements intended to address methane leaks known as “fugitive emissions” from equipment, such as valves, connectors, open-ended lines, pressure-relief devices, compressors, instruments and meters. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance. On September 11, 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency for monitoring fugitive emissions at well sites and compressor stations. The federal Bureau of Land Management (the “BLM”) also finalized similar rules regarding the control of methane emissions in November 2016 that apply to oil and natural gas exploration and development activities on federal and Indian leases, including committed state and private tracts in a federally approved unit or communitized agreement. The rules seek to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements. These new rules could result in increased compliance costs on our operations. On September 28, 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detections and repairs. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant legislative activity at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated

with our operations. Demand for our products may also be adversely affected by conservation plans and efforts undertaken in response to global climate change, including plans developed in connection with the recent Paris climate conference in December 2015, which the U.S. ratified in September 2016. In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement. Pursuant to the terms of the Paris Agreement, the earliest any country can withdraw is November 2020. Many governments also provide, or may in the future provide, tax advantages and other subsidies to support the use and development of alternative energy technologies. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

Finally, increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, increased volatility in seasonal temperatures, and other climatic events; if any such effects were to occur, they could have a material adverse effect on our operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have asserted jurisdiction over certain aspects of the process. The EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (the “SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also taken the following actions: issued final regulations under the Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and, in June 2016, published an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The BLM rescinded the rule in December 2017; however, the BLM’s rescission of the rule has been challenged by several states in the United States District Court for the Northern District of California. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.

Certain governmental reviews have been conducted or proposed that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing activities related to water use and disposal at the federal level. These studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the RRC issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. The RRC also published a rule in October 2014 governing the permitting of disposal wells that requires the submission of detailed information related to seismicity. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In July 2018, the EPA and the State of New Mexico entered into a Memorandum of Understanding to clarify the existing regulatory and permitting frameworks related to the way wastewater from oil and natural gas extraction activities can be re-used, recycled, and renewed for other purposes. A work group will be convened to develop a white paper that synthesizes the existing regulatory framework under state and federal law in New Mexico and identifies potential opportunities for the beneficial use of treated water. In November 2018, the EPA and the non-profit organization known as the State Review of Oil and Natural Gas Environmental Regulations (“STRONGER”) entered into a Memorandum of Understanding pursuant to which the EPA has affirmed its commitment to meaningful participation in STRONGER’s efforts to develop guidelines for state oil and natural gas environmental regulatory programs, conduct reviews of such programs, and publish reports on those reviews. If new or more stringent federal, state or local legal restrictions relating to

the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from drilling wells.

ESA

The Endangered Species Act (“ESA”) and, in some cases, comparable state laws were established to protect endangered and threatened species. Because listing a fish or wildlife species as threatened or endangered pursuant to the ESA prohibits death and harassment of, and injury and harm to, the species, a listing has the effect of restricting activities that adversely affect the species and its habitat. We may conduct operations on oil and natural gas leases in areas where threatened or endangered species may exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. Under the ESA, the U.S. Fish and Wildlife Service also may designate as critical habitat areas it determines are essential for the conservation of a threatened or endangered species. A critical habitat designation results in additional material restrictions to federal agency actions and authorizations, such as federal land management decisions and federal permits on non-federal lands such as permits under section 404 of the Clean Water Act. Therefore, a critical habitat designation may materially delay or prohibit land access for oil and natural gas development. The presence of, or potential presence of, threatened or endangered species, or critical habitat in areas where operations are conducted could cause us to incur increased costs from species protection measures or could result in limitations on activities that could adversely impact our ability to develop and produce reserves. If a portion of our leases are designated as critical habitat, it could adversely impact the value of our leases.

OSHA

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

We have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We did not have any material capital or other nonrecurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2017 or 2018, nor do we anticipate that such expenditures will be material in 2019.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

Principal Executive Offices and Employees

Our principal executive offices are located at 1401 Lawrence Street, Suite 1800, Denver, Colorado, 80202, and our telephone number at that address is (720) 215-3700.

As of December 31, 2018 , we had 94 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.

Availability of Public Filings and Internet Website

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”). Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge on our website at www.jaggedpeakenergy.com and on the SEC’s website at www.SEC.gov as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.