UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Jagged Peak Energy Inc.

The information in this Form 10-K includes “forward-looking statements.” All statements, other than statements of historical fact included in or incorporated by reference into this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Item 1A. Risk Factors” in this Annual Report on Form 10-K.

Forward-looking statements include statements about:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under “Item 1A. Risk Factors” in this Annual Report on Form 10-K.

Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could impact our strategy and change the

Should one or more of the risks or uncertainties described in this Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report on Form 10-K.

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 certainformer members of our management team.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”).

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) growing production and reserves through the development of our multi-year inventory, (ii) expanding and improving the resource potential of our existing acreage position, (iii) growing our acreage position through acquisitions and leasing efforts and (iv) balancing the long-term development of our assets with a focus on generating attractive corporate-level returns.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, 2017:2018:

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, 2017,2018, we operated approximately 97% of our net acreage and held an average 86%87% working interest in approximately 87,60091,600 gross (75,200(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 onto increase capital efficiency by reducing drilling and completion cycle times, optimizing completions and reducing costs. We expect that further optimization in the field, which maywill include increased drilling of longerlong and extra-long laterals, pad drilling, shared facilities and zipper fracs (i.e. fracturing adjacent wells in parallel, with one or more wells holding frac pressure while the adjacent well is fractured) will continue to improve our well economics.

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 approximate acreage by project area asaverage 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, 2017:

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 2,083approximately 1,800 gross horizontal drilling locations as of December 31, 2017, 87%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.

During 2017,In conjunction with developing our acreage for optimized production of our oil and natural gas reserves, we operated an averagehave also developed our own water system, which enables us to source, store and dispose of approximately six horizontal rigs, compared to an average of approximately two during 2016. During this same period, our average daily production has grown from 4,102 Boe/d in the first quarter of 2016 to 24,037 Boe/d in the fourth quarter of 2017. During 2017, we completed, or participated in completing, and began production on 51 gross (46.1 net) wells, of which we operated 46 gross (44.3 net) wells.water efficiently. As of December 31, 2017,2018, 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 100 gross (94.0 net) producing wells. At year end, we wereavailable 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 the process of drilling nine gross (8.6 net) wells2018, and had seven gross (6.4 net) wells waiting on completion, including three gross (2.8 net) wells that wereopportunities to leverage surplus capacities will be evaluated in process of being completed. At December 31, 2017, we were operating six horizontal rigs.2019.

Proved Reserves

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 meetmet 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,realized commodity prices and operating and development costs. James T. Jaggers, our Reservoir EngineeringOur Planning and Reserves Manager is primarily responsible for overseeing the preparation of all of ourthe Company’s reserve estimates. James T. JaggersOur Planning and Reserves Manager is a reservoir engineer with over 12more than 17 years of reservoir and operations experience and has been licensed by the Texas Board of Professional Engineers since 2009.

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 transportationand 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 forused in our reserve estimates as of December 31, 2018, 2017 2016 and 2015:2016:

Total proved reserves at December 31, 20172018 were 118.9 MMBoe, compared to 82.4 MMBoe compared toat December 31, 2017, and 37.7 MMBoe at December 31, 2016, and 13.0 MMBoe at December 31, 2015.2016. The increasesincrease in total proved reserves during 2017 were2018 was primarily related to increasedour drilling and completion activities. During 2017,2018, we drilled and completed, or participated in drilling and completing, 51began production on 59 gross (46.1(48.0 net) wells and added 49 gross (45.0 net) PUD locations.wells. This activity resulted in a combined increase of 51.835.7 MMBoe through extensions and discoveries.due to infill reserves from a proved field. Over this time period, we also had approximately 1.012.7 MMBoe of downwardupward revisions to prior estimates, due primarily to 2.211.2 MMBoe of negative revisions related to higher operating costs, partially offset by positive revisions due to pricing (0.6 MMBoe) and technical revisions (0.6 MMBoe).performance revisions.

Proved Undeveloped Reserves

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 in the previous tableseismic 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 reserves. undeveloped locations to development spacing areas that are immediately adjacent to developed spacing areas.

The total number of 10.4 MMBoePUD 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 proved developed reserves.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.

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:

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, 2017.2018. Acreage related to royalty, overriding royalty and other similar interests is excluded from this table.

Many of theOur mineral 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 or held by

locations associated with proved undeveloped reservesPUDs 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, 2017,2018, approximately 52%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, 20172018 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.

Drilling Results

The following table sets forth information with respect to the number of wells completedthat began producing hydrocarbons during the periods indicated, regardless of when drilling was initiated. Each of these wells was drilled in the southern Delaware Basin. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

Productive Wells

As of December 31, 2017,2018, we owned an average unweighted working interest of 94%89% in 100160 gross (94.0(143.0 net) productive wells and a minimal royalty interest in 1924 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.

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. InThis agreement was amended in May 2017 we amended our oil gathering agreement to include all of our Big Tex acreage. We sell substantially all of our oil production pursuant to short-terma long-term marketing agreements. 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.

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 2018.2019. Substantially all of our natural gas production is 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.

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 2017,2018, revenues from Trafigura Trading, LLC and Sunoco Partners Marketing accounted for approximately 78% and 11%, respectively,85% of our total revenue. During 2017,revenue and no other purchaser accounted for 10% or more of our revenue. The loss of either of these purchasersthis 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.

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 treated produced water and (iv) simplify construction ofallow 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 services from surface acreage owned by adjacent landowners.landowners as needed. As of December 31, 2017,2018, we hadowned approximately 4,5275,100 net surface acres on which our installed and contracted capacities wereacres. Our water infrastructure consists of approximately (i) 8.19.3 MMBbl of water storage capacity, (ii) 30 miles of fresh water pipelines, and 80(iii) 130 miles of produced water pipelines, which(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 operation, (iii) 250 MBbl/d of water sourcing capacity and (iv) 190 MBbl/d of water disposal capacity.operations. Accordingly, we have available disposal capacity of approximately two times our current produced water volumes and sufficient sources of fresh water to support our drilling program,current and we believe ouranticipated development program. Surplus fresh water infrastructure is sufficientand surplus disposal capacity generated approximately $0.8 million revenue in 2018, and opportunities to support double our current rig count. This infrastructure position provides important cost advantages compared to utilizing third-party services.leverage surplus capacities will be evaluated in 2019.

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. In addition, becauseBecause 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.

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 prevailingcurrent and future expectations of future supply and demand factors, including current domestic and worldwide storage of each commodity and may not follow a seasonal pattern. Due to seasonal fluctuations or the other above factors impacting pricing, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

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-wayright-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.

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.

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 weWe own or operate producing oil and natural gas properties havein 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

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 chargedwe can charge for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the variousTexas state legislatureslegislature 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 ismay also be subject to rate and access regulation. FERC regulates interstate transportation of oil, including natural gas liquids, under the Interstate Commerce Act (“ICA”(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 on interstate common carrier pipelinesfor 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 permitted and market basedusing 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 TransportationSales and SalesTransportation 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

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, which now includes the annual reporting requirements under Order 704, described below.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 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 FERC on Form No. 552. The definitions accompanying the extent suchform state that reportable physical natural gas transactions utilize,are only those transactions that either use an index, or that contribute to, or may contribute to the formation of price indices to FERC on Form No. 552.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.

Gathering service, which occurs upstreamIntrastate 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 jurisdictional transmission services, is regulatedTexas 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 states onshoreRRC and must provide transportation service without discrimination as to rates and terms of service. Violation of these rules may result in state waters. Section 1(b)civil and administrative penalties. The RRC is responsible for establishing and promulgating rates, though in practice its regulation of the NGA exemptsrates is primarily on a complaint basis. The RRC has broad authority to establish safety standards for intrastate pipelines transporting crude oil and natural gas gathering facilities from regulationliquids and has adopted by FERC as a natural gas company underreference minimum safety standards promulgated by 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 transmission facilities as non-jurisdictional gathering facilities,Pipeline and depending on the scope of that decision, our costs of getting natural gas to point of sale locations may increase. We believe theHazardous Materials Safety Administration (the “PHMSA”).

Intrastate natural gas pipelines located in the gathering systems we use meet the traditional tests FERC has used to establish a pipeline’s status as a gathererTexas that are 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 determinationsregulated 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.

Insofar as such regulation within a particular stateTexas 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 statesTexas, 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.

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 U.S. Environmental Protection Agency (the “EPA”)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

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. TheOn August 16, 2018, the U.S. District Court for South Carolina found that the EPA intendsand the Corps failed to proposecomply 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 withthat would differently revise the definition of waters“waters of the Unites States.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 theany 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. The EPA’s rule delaying the applicability date of the new definition of waters of the United States has been challenged in federal court. 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 (“OPA”(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.

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 EPA has proposed a 2-year stay ofamendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the effective dates of several requirements of the rules.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 and proposed rules could result in increased compliance costs on our operations. The rules are at issue in active litigation in federal court. In December 2017,On September 28, 2018, the BLM published a final rule to temporarily suspend or delay certainthat revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements until January 2019 (the “Suspension Rule”).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 Suspension Rule was immediately challengednew 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 federal court and, on February 22, 2018, the United States District Court for the Northern District of California enjoined the Suspension Rule, putting the original BLM venting and flaring rules into immediate effect.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.

Finally, increasing concentrations of GHGs in the Earth’searth’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 (“SDWA”(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 Railroad Commission of TexasRRC 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

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 2018 or 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.

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, 2017,2018, we had 5994 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.

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”). 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.

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, 20142016 through February 28, 2018,January 31, 2019 the WTI spot price for oil declinedranged from a high of $107.95$77.41 per Bbl on June 20, 2014,27, 2018, to a low of $26.19 per Bbl on February 11, 2016, and the Henry Hub spot price for natural gas declinedranged from a high of $8.15$6.24 per MMBtu on February 10, 2014,January 2, 2018, to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutene,isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices.also experienced price fluctuations. The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access to capital, future rate of growth and carrying value of our properties. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:

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 20182019 capital budget for drilling, completion and recompletion activities and facilities costs is expected to range from $560.0$600.0 million to $615.0$660.0 million, excluding potential acquisitions. In addition, our production costs may increase as we continue to use enhanced recovery techniques, including gas lifts and electric submersible pumps, and other new drilling and completion technologies, which are capital intensive and may not produce oil and natural gas in paying quantities or at all. Further, we regularly evaluate potential acquisition opportunities as an important aspect of our growth strategy, and any such acquisitions we pursue could require substantial capital expenditures. We expect to fund our capital expenditures with cash on hand, cash generated by operations and borrowings under our credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to our other stockholders. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital are subject to a number of variables, including:

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.

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:

Risks that we face while completing our wells include the following:

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated, we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.

Our decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. In addition, the analogies we draw from available data from other wells, including type curves from such wells, and more fully explored locations may not be applicable to our drilling locations. For a discussion of the uncertainty involved in these processes,the process of making reserve estimates, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

For example, in 2017 we experienced completion delays related to frac fleet equipment reliability from our service providers, which resulted in increased completed well costs and reduced our total number of well completions. Furthermore, the results of any drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production.

As of December 31, 2017,2018, we had identified 2,083approximately 1,800 gross horizontal drilling locations on our acreage based on approximately 880-foot spacing in an offset pattern with five to six wells across a 640-acre section, consisting of laterals with an average length of 9,094 feet.section. As a result of the limitations described above, we may be unable to drill many of our identified locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “—Our acquisition and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.” Any drilling activities we are able to conduct on these locations may not

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.

The process of estimating reserves is complex. It requires interpretations of available technical data and many assumptions, including current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, estimated ultimate recoveries, well type curves, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected and production declines may be greater than we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.

It should not be assumed that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We 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.

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

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.

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

In addition, our credit agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. For example, as described in greater detail in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Senior Secured Revolving Credit Facility,” we are required to maintain a ratio of current assets to current liabilities of not less than 1.0 to 1.0, as defined by the senior secured revolving credit facility, which was amended and restated in February 2017 (the “Amended and Restated Credit Agreement.Facility”).

Further, under our credit agreement as of December 31, 2017,2018, we were only permitted to hedge up to the greater of 85% of our production from proved reserves and 75% of our reasonably anticipated forecasted future production for up to 2436 months in the future, and up to the greater of 75% of our production from our proved reserves and 50%60% of our reasonably anticipated forecasted production for 2537 to 60 months in the future, provided that no hedges may have a term beyond five years.

The restrictions in our credit agreementdebt agreements may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants in our credit agreementdebt agreements impose on us.

A breach of any covenant in our credit agreementdebt agreements would result in a default under the applicable agreement after any applicable cure and grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under

Our credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually onby April 1 and October 1, or during an elected quarterly redetermination. The borrowing base depends on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties

securing our loan. The value of our proved reserves is dependent upon, among other things, the prevailing and expected market prices of the underlying commodities in our estimated reserves. See “—Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments” and “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” During a borrowing base redetermination, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. OurAs of December 31, 2018, our borrowing base was $425.0$900.0 million, as of December 31, 2017. The most recent redetermination was completed in March 2018 and resulted in a borrowing base increase towhich our elected commitments were $540.0 million.

In the future, we may not be able to access adequate funding under our credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

As of December 31, 2017,2018, approximately 52%58% of our total net acreage was held by production or continuous drilling operations. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions of the leases or the leases are renewed. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. This could result in impairment of remaining costs, a reduction in our reserves and our growth opportunities (or the incurrence of significant costs) and therefore could have an adverse effect on our financial results. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.

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:

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

Adverse weather conditions and other natural disasters may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations. For example, in 2017 industry infrastructure impacts from Hurricane Harvey caused a portion of our wells to be shut-in for a short period of time, which reduced production and revenue from such wells for that period.

Water is an essential component of deep shale oil and natural gas development during both the drilling, and hydraulic fracturing and production processes. Drought conditions in Texas 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, or if the prices of water or water disposal increases dramatically, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

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, 2017,2018, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. For example, since our production originates near Midland, Texas, our realizations on sales of our oil production may be affected by the Midland-Cushing price differential, which reflects the difference between the price of crude at Midland, Texas, versus the price of crude at Cushing, Oklahoma, a major hub where oil production from Midland is often transported via pipeline. The price we currently realize on barrels of oil we sell is reduced by the value of the Midland-Cushing differential, which reached as high as $21$16.21 per barrel in August 2014.September 2018. If the Midland-Cushing differential, or other price differentials pursuant to which our production is subject, were to widen due to oversupply or other factors, our revenue could be negatively impacted.

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 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.

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.

As of December 31, 2017,2018, approximately 54%40% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reservesPUDs may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells within five years after their respective dates of booking.

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.

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.

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports and exports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon severala significant purchaserspurchaser 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 are subject to stringent and complex federal, state and local laws and regulations governing the discharge, release or emission of materials into the environment, health and safety aspects of our operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements our business, prospects, financial condition or results of operations could be materially adversely affected.

We 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:

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:

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 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-seismicseismic 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:

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 imposesand indenture impose certain limitations on our ability to enter into mergers or combination transactions. Our credit agreement and indenture also limitslimit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses or assets.

The successful acquisition of producing properties requires an assessment of several factors, including:

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.

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 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 hadhas 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, hadhas 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.

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. These costs may rise faster than increases in our revenue if commodity prices rise, or they may rise without a corresponding increase in commodity prices, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.

Under the EP Act of 2005, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Items 1 and 2. Business and Properties—Regulation of the Oil and Natural Gas Industry.”

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.

See “Items 1 and 2.—Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters—Regulation of “Greenhouse Gas” Emissions.”

See “Items 1 and 2.—Business and Properties—Regulation of Environmental and Occupational Safety and Health Matters—Hydraulic Fracturing Activities.”

State and federal regulatory agencies recently have focused on a possible connection between the disposal of wastewater in underground injection wells, or to a lesser extent the hydraulic fracturing of oil and gas wells, and the increased occurrence of seismic activity in certain areas, and regulatory agencies at all levels are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. For example, in 2016, the Texas state legislature provided nearly $5 million to the University of Texas to develop and manage an earthquake monitoring system in Texas. In addition, a number of lawsuits have been filed in otherseveral 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 or operation of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma’s Corporation Commissions Oilin 2014, the RRC adopted a new rule governing the permitting of disposal wells that requires, among other things, the submittal of information on seismic events occurring within a specified radius of the disposal well as well as logs, geologic cross sections and Gas Division is implementing an ongoing response plan that includes reducingstructure maps for the amount of wastewater into certain injection areas. In March 2016, the response plan was updated to target western Oklahoma’s Arbuckle disposal wells.area. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific

We dispose of large volumes of produced water gathered from our drilling, completion and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or operating prohibitions or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. In addition, the enforcement of existing laws and regulations could delay our receipt of the necessary permits and result in a material adverse effect on our business, financial condition and results of operations. The adoption and implementation of any new laws or regulations or the imposition of any orders or requirements that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities by limiting volumes, disposalinjection pressures or rates, producing or 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.

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. WeIn addition, because of our smaller size compared to some of our competitors, such competitors may be in a better position to secure oilfield services and equipment on a timelier basis or on more favorable terms. Furthermore, we may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

Our future success depends to a large extent on the services of our senior management and key employees. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

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.

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.species. Seasonal restrictions to protect wildlife may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered or threatened species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered or the designation of critical habitat for threatened or endangered species in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.

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 promulgatingmay continue to promulgate other rules, required to implement the derivatives regulatory provisions of the Dodd-Frank Act. Among theThe CFTC has adopted certain position aggregation rules currently proposed for adoption by the CFTC are proposedand re-proposed certain other rules that would place limits on positions in certain core futures and economically equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. These new position limit rules are not yet final, and the impact of the final position rules on us is uncertain at this time.

The Dodd-Frank Act also made the clearing of certain swaps over a derivatives clearing organization mandatory and the execution of cleared swaps over a board of trade or swap execution facility mandatory, subject to certain exemptions. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. As of the date hereof, the CFTC has not yet issued notices designating anycertain 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

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 adoptedrequired under the Dodd-Frank Act have been adopted and fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act, the existing rules and any new rules could increase compliance and documentation burdens on our business or on our counterparties, significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act’s swap regulatory provisions and the related rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act’s swap regulatory provisions were intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us and our financial condition.

In addition, the European Union and other non-U.S. jurisdictions have implemented or may implement regulations with respect to the derivatives market, some of which impose mechanisms and restrictions similar to those arising under the Dodd-Frank Act and related rules. If we enter into swaps with counterparties based in foreign jurisdictions, we may become subject to such regulations, which could have adverse effects on our operations similar to the possible effects on our operations of the Dodd-Frank Act’s swap regulatory provisions and the rules of the CFTC, SEC and U.S. banking regulators.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received.

In addition, our predecessor generally passed through its taxable income to its owners for income tax purposes and was not subject to U.S. federal, state or local income taxes other than franchise tax in the State of Texas. Accordingly, our standardized measure as of December 31, 2016 and 2015 does not provide for U.S. federal, state or local income taxes other

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.