Marketing

Typically, our production is sold at the wellhead to unaffiliated third party purchasers. Crude oil is sold at prices based on posted prices or NYMEX plus or minus market differentials for the respective area. Natural gas and NGLs are sold under contract at a negotiated price which is based on the market price for the area or at published prices for specified locations or pipelines and then discounted by the purchaser back to the wellhead based upon a number of factors normally considered in the industry (such as distance from the well to the central market location, well pressure, quality of natural gas and prevailing supply and demand conditions). ~~We have made the strategic decision~~Natural gas is generally delivered to ~~sell as much of our natural gas production~~a midstream processing entity at the wellhead ~~as possible, so that we can concentrate our efforts~~or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and ~~resources on exploration and production which we believe are more consistent with our competitive expertise, rather than~~processes the natural gas ~~gathering, processing, transportation~~ and ~~marketing. In each case, we~~remits proceeds for the resulting sales of NGLs and residue gas. We sell at competitive market prices based on a differential to several market locations. In instances of depressed oil and gas prices, we may elect to shut-in wells until commodity prices are more favorable. We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and gas we produce because we believe other purchasers are available in all our areas of operations.

Our marketing objective is to receive competitive wellhead prices for our product. There are a variety of factors that affect the market for oil and gas generally, including:

demand for oil and gas;

the extent of supply of oil and gas and, in particular, domestic production and imports;

the proximity and capacity of natural gas pipelines and other transportation facilities;

the marketing of competitive fuels; and

the effects of state and federal regulations on oil and gas production and sales.

See “Item 1A. Risk Factors—Oil and gas prices are highly volatile, and continued low oil and gas prices or further price decreases will negatively affect our financial position, planned capital expenditures and results of operations,” “—We are subject to various environmental risks and governmental regulations, including those relating to benzene emissions, hydraulic fracturing and global climate change, and future regulations may be more stringent resulting in increased operating costs and decreased demand for the oil and gas that we produce,” and “—If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell oil and natural gas and receive market prices for our oil and natural gas may be adversely affected by pipeline and gathering system capacity constraints.”

~~In addition to selling our production at the wellhead, we~~We work with various pipeline companies to procure and to assure capacity for our natural gas. For further discussion of this matter, see “Item 1A. Risk Factors—If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell oil and natural gas and receive market prices for our oil and natural gas may be adversely affected by pipeline and gathering system capacity constraints.” We have entered into various long-term gathering, processing, and transportation contracts with various parties which require us to deliver fixed, determinable quantities of production over specified periods of time. Certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. As of the filing of this report, we do not expect any material shortfalls in our delivery commitments. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations” and “Note 8. Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for ~~additional details regarding our financial commitments under these contracts.~~

further discussion.

Competition and Technological Changes

We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven ~~properties.~~properties, obtaining necessary equipment, supplies and services, and recruiting and retaining skilled employees. Many of our competitors are large, well-established companies that have been engaged in the oil and gas business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Regulation

Oil and gas operations are subject to various federal, state, local and international environmental regulations that may change from time to time, including regulations governing oil and gas production and transportation, federal and state regulations governing

environmental quality and pollution control and state limits on allowable rates of production by well or proration unit. These regulations may affect the amount of oil and gas available for sale, the availability of adequate pipeline and other regulated processing and transportation facilities and the marketing of competitive fuels. For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and gas, protect rights to produce oil and gas between owners in a common reservoir, control the amount of oil and gas produced by assigning allowable rates of production, provide nondiscriminatory access to common carrier pipelines and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted.

The following discussion summarizes the regulation of the United States oil and gas industry. We believe we are in substantial compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although we cannot assure you that this is or will remain the case. Moreover, those statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and any such changes or reinterpretations could materially adversely affect our results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which our operations may be subject.

Regulation of Natural Gas and Oil Exploration and Production

Our operations are subject to various types of regulation at the federal, state and local levels that:

require permits for the drilling of wells;

mandate that we maintain bonding requirements in order to drill or operate wells; and

regulate the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, groundwater sampling requirements prior to drilling, the plugging and abandoning of wells and the disposal of fluids used in connection with operations.

Our operations are also subject to various conservation laws and regulations. These regulations govern the size of drilling and spacing units or proration units, setback rules, the density of wells that may be drilled in oil and gas properties and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states (including Texas) rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws that establish maximum rates of production from oil and gas wells generally prohibit the venting or flaring of natural gas and impose specified requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our profitability. Because these laws and regulations are frequently expanded, amended and reinterpreted, we are unable to predict the future cost or impact of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas

Federal legislation and regulatory controls have historically affected the price of natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (“NGA”), the Federal Energy Regulatory

Commission (“FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas, including all of our sales of our own production. As a result, all of our domestically produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC’s jurisdiction over interstate natural gas transportation, however, was not affected by the Decontrol Act.

Under the NGA, facilities used in the production or gathering of natural gas are exempt from the FERC’s jurisdiction. We own certain natural gas pipelines that we believe satisfy the FERC’s criteria for establishing that these are all gathering facilities not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.

One of our pipeline subsidiaries, Hondo Pipeline Inc., may exercise the power of eminent domain and is a regulated public utility within the meaning of Section 101.003 (“GURA”) and Section 121.001 (the “Cox Act”) of the Texas Utilities Code. Both GURA and the Cox Act prohibit unreasonable discrimination in the transportation of natural gas and authorize the Texas Railroad Commission to regulate gas transportation rates. However, GURA provides for negotiated rates with transportation, industrial or similar large-volume contract customers so long as neither party has an unfair negotiating advantage, the negotiated rate is

substantially the same as that negotiated with at least two other customers under similar conditions, or sufficient competition existed when the rate was negotiated.

Although we do not own or operate any pipelines or facilities that are directly regulated by the FERC, its regulations of third-party pipelines and facilities could indirectly affect our ability to market our production. Beginning in the 1980s, the FERC initiated a series of major restructuring orders that required pipelines, among other things, to perform open access transportation, “unbundle” their sales and transportation functions, and allow shippers to release their pipeline capacity to other shippers. As a result of these changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. It remains to be seen, however, what effect the FERC’s other activities will have on access to markets, the fostering of competition and the cost of doing business. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities.

In the past, Congress has been very active in the area of natural gas regulation. However, the more recent trend has been in favor of deregulation or “lighter handed” regulation and the promotion of competition in the gas industry. In light of this increased reliance on competition, the Energy Policy Act of 2005 amended the NGA to prohibit any forms of market manipulation in connection with the transportation, purchase or sale of natural gas. In addition to the regulations implementing these prohibitions, the FERC has established new regulations that are intended to increase natural gas pricing transparency through, among other things, expanded dissemination of information about the availability and prices of gas sold and new regulations that require both interstate pipelines and certain non-interstate pipelines to post daily information regarding their design capacity and daily scheduled flow volumes at certain points on their systems. The Energy Policy Act of 2005 also significantly increased the penalties for violations of the NGA and the FERC’s regulations to up to $1.0 million per day for each violation. This maximum penalty authority established by statute has been and will continue to be adjusted periodically to account for inflation.

Oil Price Controls and Transportation Rates

Our sales of crude oil, condensate and NGLs are not currently regulated and are made at market prices. The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to specified conditions and limitations. These regulations may tend to increase the cost of transporting crude oil and NGLs by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2015, to implement the latest required five-yearly re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes. For the five-year period beginning July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. Under FERC’s regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. We are not able at this time to predict the effects of this indexing system or any new FERC regulations on the transportation costs associated with oil production from our oil producing operations.

There regularly are legislative proposals pending in the federal and state legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by

Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, we cannot predict whether or to what extent the trend toward federal deregulation of the petroleum industry will continue, or what the ultimate effect on our sales of oil, gas and other petroleum products will be.

Environmental Regulations

Our operations are subject to numerous international, federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on specified lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations. The failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of investigatory or remedial obligations or the issuance of injunctions prohibiting or limiting the extent of our operations. Public interest in the protection of the environment has increased dramatically in recent years. The trend of applying more expansive and stricter environmental legislation and regulations to the oil and gas industry could continue, resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

We currently own or lease numerous properties that for many years have been used for the exploration and production of oil and gas. Although we believe that we have generally implemented appropriate operating and waste disposal practices, prior owners and operators of these properties may not have used similar practices, and hydrocarbons or other waste may have been disposed of or released on or under the properties we own or lease or on or under locations where such waste has been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other waste was not under our control. These properties and the waste disposed thereon may be subject to the federal Resource Conservation and Recovery Act (“RCRA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), and analogous state laws as well as state laws governing the management of oil and gas waste. Under these laws, we could be required to remove or remediate previously disposed waste (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

We generate waste that may be subject to RCRA and comparable state statutes. The U.S. Environmental Protection Agency ~~(“EPA”~~(the “EPA”) and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous waste. Furthermore, certain waste generated by our oil and gas operations that are currently exempt from treatment as “hazardous waste” may in the future be designated as “hazardous waste” and therefore become subject to more rigorous and costly operating and disposal requirements.

CERCLA, also known as the “Superfund” law, and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on specified classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These classes of persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. 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.

Our operations may be subject to the Clean Air Act and comparable state and local requirements. In 1990 Congress adopted amendments to the Clean Air Act containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have developed and continue to develop regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Moreover, changes in environmental laws and regulations occur frequently, and stricter laws, regulations or enforcement policies could significantly increase our compliance costs. Further, stricter requirements could negatively impact our production and operations. For example, on October 1, 2015, the EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion (“ppb”) to 70 ppb. ~~The EPA may designate~~None of the ~~areas~~Texas counties in which we operate have been designated by the EPA as nonattainment areas under this revised standard. However, areas in which we operate could be designated as nonattainment in the future if the EPA were to further reduce ozone standards. States that contain any areas designated nonattainment, and any tribes that choose to do so, ~~will be~~are required to develop state implementation plans demonstrating how the area will attain the standard within a prescribed period of time. These plans may require the installation of additional equipment

to control emissions. Similar initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state, and federal levels.

Additionally, the EPA has established new air emission control requirements for natural gas and NGLs production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are required to use completion combustion device equipment (i.e., flaring) by October 15, 2012 if emissions cannot be directed to a gathering line. Further, the final rules under NESHAPS include maximum achievable control technology (“MACT”) standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. In June 2016, the EPA published updates to new source performance standard requirements that would impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. ~~The~~In October 2018, the EPA ~~is currently reconsidering this~~published a proposed rule that would amend certain requirements of the June 2016 rule. Among other things, the proposed rule would reduce monitoring frequencies for fugitive emissions and ~~has proposed to stay its~~clarify and streamline certain other requirements. However, the 2016 rule currently remains in effect. Similarly in November 2016, the Bureau of Land Management (“BLM”) issued rules requiring additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands. In ~~December 2017,~~February 2018, the BLM ~~issued~~proposed to repeal certain requirements of the 2016 rules. In September 2018, BLM published a final ~~stay~~rule that largely adopted the February 2018 proposal and rescinded several requirements. The September 2018 rule was challenged in the U.S. District Court for the Northern District of California almost immediately after issuance. The challenge is still pending. Compliance with the ~~rules that temporarily suspends~~November 2016 rule or ~~delays their requirements until January 2019, while~~ the ~~BLM considers revising or rescinding the requirements. However, if these requirements go into effect, compliance~~revised September 2018 rule may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (“OPA”) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners and operators of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. The OPA also requires owners and operators of offshore facilities that could be the source of an oil spill into federal or state waters, including wetlands, to post a bond, letter of credit or other form of financial assurance in amounts ranging from $10.0 million in specified state waters to $35.0 million in federal outer continental shelf waters to cover costs that could be incurred by governmental authorities in responding to an oil spill. These financial assurances may be increased by as much as $150.0 million if a formal risk assessment indicates that the increase is warranted. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.

Our operations are also subject to the federal Clean Water Act (“CWA”) and analogous state laws that impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as U.S. waters. Pursuant to the requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits or seek coverage under an EPA general permit. Like OPA, the CWA and analogous state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the ground. Similarly, the U.S. Congress has considered legislation to subject hydraulic fracturing operations to federal regulation and to require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. Please read “Item 1A. Risk Factors-We are subject to various environmental risks and governmental regulations, including those relating to benzene emissions, hydraulic fracturing and global climate change, and future regulations may be more stringent resulting in increased operating costs and decreased demand for the oil and gas that we produce.”

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of our operations are located in or near areas that may be designated as habitats for endangered or threatened species, such as the Attwater’s prairie chicken. In these areas, we may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could restrict drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we operate could result in increased costs of or limitations on our ability to perform operations and thus have an adverse effect on our business. We believe that we are in substantial compliance with the ESA, and we are not aware of any proposed listings that will affect our operations. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

The Safe Drinking Water Act (“SDWA”) and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced

oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities. We believe that we substantially comply with the SDWA and related state provisions.

We also are subject to a variety of federal, state, local and foreign permitting and registration requirements relating to protection of the environment. We believe we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on our financial position or results of operations.

Global Climate Change

There is increasing attention in the United States and worldwide being paid to the issue of climate change and the contributing effect of greenhouse gas (“GHG”) emissions. The EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, regulates GHG emissions from certain large stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA also expanded its existing GHG emissions reporting rule to apply to the oil and gas source category, including oil and natural gas production facilities and natural gas processing, transmission, distribution and storage facilities. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year were required to report annual GHG emissions to the EPA, for the first time by September 28, 2012. In addition, in June 2016, the EPA published updates to new source performance standard requirements that would impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development and production operations, including hydraulic fracturing and other well completion activity. ~~The~~In October 2018, the EPA ~~is currently reconsidering this~~published a proposed rule that would amend certain requirements of the June 2016 rule. Among other things, the proposed rule would reduce monitoring frequencies for fugitive emissions and ~~has proposed to stay its~~clarify and streamline certain other requirements. However, the 2016 rule currently remains in effect.

The U.S. Congress has considered a number of legislative proposals to restrict GHG emissions and more than 20 states, either individually or as part of regional initiatives, have begun taking actions to control or reduce GHG emissions. Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In April 2016, the United States signed the Paris Agreement, which requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in August of 2017, the United States informed the United Nations of its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020.

While it is not possible at this time to predict how regulation that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States in which we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy sources) could have a negative impact on our business if such incentives reduce demand for oil and gas.

In addition to the effects of future regulation, the meteorological effects of global climate change could pose additional risks to our operations in the form of more frequent and/or more intense storms and flooding, which could in turn adversely affect our cost of doing business.

Title to Properties

We believe we currently have satisfactory title to all of our producing properties in the specific areas in which we operate in accordance with standards generally accepted in the oil and gas industry, except where failure to do so would not have a material adverse effect on our business and operations in such area, taken as a whole. Individual properties may be subject to burdens such as royalty and overriding royalty interests, working and other outstanding interests customary in the industry. Additionally, substantially all of our producing properties are subject to mortgage liens securing our obligations under our senior secured revolving credit facility. For additional information, please see “Item 1A. Risk Factors—We may incur losses as a result of title deficiencies.”

Customers

The following table presents customers that ~~represent~~represented 10% or more of our total revenues for at least one of the ~~years ended December 31, 2017, 2016 and 2015:~~periods presented:


	Years Ended December 31,			Years Ended December 31,
	2017	2016	2015	2018	2017	2016
Shell Trading (US) Company	69%	56%	65%	73%	69%	56%
Flint Hills Resources, LP	7%	15%	9%	*	*	15%

Item 1A. Risk Factors

Oil and gas prices are highly volatile, and low oil and gas prices or further price decreases will negatively affect our financial position, planned capital expenditures and results of operations.

Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and gas. Historically, the markets for oil and gas have been volatile, and those markets are likely to continue to be volatile in the future. Oil and gas commodity prices are affected by events beyond our control, including changes in market supply and demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In the past, we have reduced or curtailed ~~production~~activity to mitigate the impact of low oil and gas prices. Particularly in recent years, decreases in both oil and gas prices led us to suspend or curtail drilling and other exploration activities, which will limit our ability to produce oil and gas and therefore impact our revenues. ~~Beginning the second half of 2014 and continuing into 2016, oil prices declined significantly.~~ We are particularly dependent on the production and sale of oil and this commodity price decline has had, and may continue to have, an adverse effect on us. Further volatility in oil and gas prices or a continued prolonged period of low oil or gas prices may materially adversely affect our financial position, liquidity (including our borrowing capacity under our revolving credit facility), ability to finance planned capital expenditures and results of operations.

It is impossible to predict future oil and gas price movements with certainty. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control. These factors include, but are not limited to:

the level of consumer product demand;

the levels and location of oil and gas supply and demand and expectations regarding supply and demand, including the supply of oil and natural gas due to increased production from resource plays;

overall economic conditions;

weather conditions;

domestic and foreign governmental relations, regulations and taxes;

the price and availability of alternative fuels;

political conditions or hostilities and unrest in oil producing regions;

the level and price of foreign imports of oil and liquefied natural gas;

the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree upon and maintain production constraints and oil price controls;

the extent to which U.S. shale producers become “swing producers” adding or subtracting to the world supply;

technological advances affecting energy consumption;

speculation by investors in oil and gas; and

variations between product prices at sales points and applicable index prices.

The profitability of wells, particularly in the shale plays in which we primarily operate, is generally reduced or eliminated as commodity prices decline. In addition, certain wells that are profitable may not meet our internal return targets. Based on our current estimates of drilling and completion costs, ultimate recoveries per well, differentials and operating costs, we believe a portion of our acreage if drilled would not be economical at commodity prices existing in ~~2017 and most would not be economical at the commodity price lows seen in early 2016.~~2018. There can be no assurance, however, that any wells, including wells drilled on our Eagle Ford and Delaware Basin acreage, will actually be profitable at any estimated prices. The sustained declines in commodity prices have caused us to significantly reduce our exploration and development activity which may adversely affect our results of operations, cash flows and our business.

Oil and gas drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

Our success will be largely dependent upon the success of our drilling program. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments.

Drilling for oil and gas involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:

unexpected or adverse drilling conditions;

elevated pressure or irregularities in geologic formations;

equipment failures or accidents;

adverse weather conditions;

fluctuations in the price of oil and gas;

surface access restrictions;

loss of title or other title related issues;

compliance with governmental requirements; and

shortages or delays in the availability of midstream transportation, drilling rigs, crews and equipment.

Because we identify the areas desirable for drilling in certain areas from 3-D seismic data covering large areas, we may not seek to acquire an option or lease rights until after the seismic data is analyzed or until the drilling locations are also identified; in those cases, we may not be permitted to lease, drill or produce oil or gas from those locations.

Even if drilled, our completed wells may not produce reserves of oil or gas that are economically viable or that meet our earlier estimates of economically recoverable reserves. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial position by reducing our available cash and resources. The potential for production decline rates for our wells could be greater than we expect. Because of the risks and uncertainties of our business, our future performance in exploration and drilling may not be comparable to our historical performance described herein.

We may not adhere to our proposed drilling schedule.

Our final determination of whether to drill any wells will be dependent on a number of factors, including:

the results of our exploration efforts and the acquisition, review and analysis of the seismic data;

the availability and cost of sufficient capital resources to us and the other participants for the drilling of the prospects;

the approval of the prospects by the other participants after additional data has been compiled;

economic and industry conditions at the time of drilling or completion, including prevailing and anticipated prices for oil and gas and the availability and prices of drilling rigs, drilling and hydraulic fracturing crews and equipment, other services, supplies and equipment, and pipeline system and transportation constraints;

lease expirations;

access to water supplies or restrictions on water disposal;

regulatory approvals; and

the availability of leases and permits on reasonable terms for the prospects.

Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells that are currently part of our capital plan may be based on statistical results of drilling activities in other 3-D project areas that we believe are geologically similar rather than on analysis of seismic or other data in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from those statistical results. In addition, our drilling schedule may vary from our expectations because of future uncertainties. We may not be able to raise the capital required to drill all of our identified or budgeted wells. In addition, our ability to produce oil and gas may be significantly affected by the availability and prices of hydraulic fracturing equipment and crews. There can be no assurance that these projects

can be successfully developed or that any identified drill sites or budgeted wells will, if drilled, encounter reservoirs of commercially productive oil or gas. We may seek to sell or reduce all or a portion of our interest in a project area or with respect to prospects or budgeted wells within such project area.

Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future.

There are uncertainties inherent in estimating oil and gas reserves and their estimated value, including many factors beyond the control of the producer. The reserve data included herein represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. These include subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and

operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Reserve estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. Additionally, in recent years, there has been increased debate and disagreement over the classification of reserves, with particular focus on proved undeveloped reserves. The interpretation of SEC rules regarding the classification of reserves and their applicability in different situations remain unclear in many respects. Changing interpretations of the classification standards of reserves or disagreements with our interpretations could cause us to write down reserves.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe. We have deferred some of our exploration activities in response to the severe price downturn beginning in the summer of 2014 and such continued deferral may increase the impact of this requirement.

As of December 31, ~~2017,~~2018, approximately ~~58%~~60% of our proved reserves were proved undeveloped. Moreover, some of the producing wells included in our reserve reports as of December 31, ~~2017~~2018 had produced for a relatively short period of time as of that date. Because most of our reserve estimates are calculated using volumetric analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development schedule and plans. Lack of reasonable certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.

The discounted future net cash flows included herein are not necessarily the same as the current market value of our estimated oil and gas reserves. As required by the current requirements for oil and gas reserve estimation and disclosures, the estimated discounted future net cash flows from proved reserves are based on the average of the sales price on the first day of each month during the trailing 12-month period prior to December 31, ~~2017,~~2018, with costs determined as of the date of the estimate. If commodity prices remain at their current levels, the estimated discounted future net cash flows from our proved reserves would generally be expected to ~~increase~~decrease as earlier months with ~~lower~~higher commodity sales prices will be removed from this calculation in the future.

Actual future net cash flows also will be affected by factors such as:

the actual prices we receive for oil and gas;

our actual operating costs in producing oil and gas;

the amount and timing of actual production;

supply and demand for oil and gas;

increases or decreases in consumption of oil and gas; and

changes in governmental regulations or taxation.

In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board Accounting Standards Codification Topic 932, “Extractive Activities-Oil and Gas” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and gas production is, therefore, highly dependent on our level of success in developing, finding or acquiring additional reserves that are economically recoverable. There can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such undeveloped properties or wells.

Our future acquisitions may yield revenues or production that varies significantly from our projections.

In acquiring producing properties, we assess the recoverable reserves, current and future oil and gas prices, development and operating costs, potential environmental and other liabilities and other factors relating to the properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition

assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems and we may be forced to assume liabilities that we did not accurately quantify. We may increase our emphasis on producing property acquisitions. We have relatively less experience in such acquisitions as our past acquisition focus has been primarily on nonproducing acreage. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial position and future results of operations.

~~We may not be able to achieve the expected benefits of the ExL Acquisition and may have difficulty integrating the ExL Properties.~~

There can be no assurance that the ExL Acquisition will be beneficial to us. We may not be able to integrate and develop the ExL Properties without increases in costs, losses in revenues or other difficulties. Any unexpected costs or delays incurred in connection with the integration and development of the ExL Properties could have an adverse effect on our business, results of operations, financial condition and prospects, as well as the market price of our common stock.

The market price of our common stock may decline as a result of the ExL Acquisition if, among other things, the integration and development of the ExL Properties is unsuccessful or if the liabilities, expenses, title, environmental and other defects, or transaction costs related to the ExL Acquisition are greater than expected or the ExL Properties do not yield the anticipated returns. The market price of our common stock may decline if we do not achieve the perceived benefits of the ExL Acquisition as rapidly or to the extent anticipated by us or by securities market participants or if the effect of the ExL Acquisition, including the obligations incurred to finance the ExL Acquisition, on our business results of operations or financial condition or prospects is not consistent with our expectations or those of securities market participants.

~~Upon consummation of the ExL Acquisition, our~~Our overall level of debt and Preferred Stock obligations ~~increased, which~~ could adversely affect us.

~~Upon consummation~~As of ~~the ExL Acquisition, our overall~~December 31, 2018, we had a level of outstanding debt ~~level increased after giving effect to the ExL Acquisition~~ and ~~our senior notes offering. In connection with the ExL Acquisition, we issued~~ Preferred Stock ~~with an aggregate initial liquidation preference of $250.0 million (subsequently reduced to $200.0 million)~~ that requires us, upon request of holders of a majority of the then-outstanding shares of Preferred Stock, to redeem the Preferred Stock, in whole or in part, on or after the seventh anniversary of its issuance and upon certain defaults and changes of control. Our increased level of debt and other obligations could have significant adverse consequences on our business and future prospects, including the following:

we may not be able to obtain financing in the future on acceptable terms or at all for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;

less-levered competitors could have a competitive advantage because they have lower debt service requirements;

credit rating agencies could downgrade our credit ratings ~~following the ExL Acquisition~~ below currently expected levels; ~~and~~

we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our ~~competitors.~~competitors;

we may be required to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and Preferred Stock and the service of interest costs and dividends associated with our debt and Preferred Stock, rather than to productive investments; and

we may be vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

A future issuance, sale or exchange of our stock or warrants could trigger a limitation on our ability to utilize net operating loss carryforwards.

Our ability to utilize U.S. net operating loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited under Section 382 of the Code upon the occurrence of ownership changes resulting from issuances of our stock or the sale or exchange of our stock by certain shareholders if, as a result, there is an aggregate change of more than 50% in the beneficial ownership of our stock during any three-year period. For this purpose, “stock” includes certain preferred stock and common stock warrants (including the Preferred Stock and the Warrants issued to finance in part, the ExL Acquisition). In the event of such an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these loss carryforwards. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. We do not believe we have a Section 382 limitation on the ability to utilize our U.S. loss carryforwards as of December 31, ~~2017.~~2018. However, future issuances, sales or exchanges of our stock (including, potentially, relatively small transactions and transactions beyond our control) could, taken together with prior transactions with respect to our stock, trigger an ownership change under Section 382 of the Code and therefore a limitation on our ability to utilize our U.S. loss carryforwards. Any such limitation could cause some of such loss carryforwards to expire before we would be able to utilize them to reduce taxable income in future periods, possibly resulting in a substantial income tax expense or write down of our tax assets or both.

Holders of the Preferred Stock have rights that may restrict our ability to operate our business or be adverse to holders of our common stock.

The Statement of Resolutions Establishing Series of 8.875% Redeemable Preferred Stock of Carrizo Oil & Gas, Inc. (the “Statement of Resolutions”) contains covenants that, among other things, so long as the GSO Funds (as defined below) and their affiliates beneficially own more than 50% of the outstanding Preferred Stock, limit our ability to, without the written consent of a designated representative of the Preferred Stock, but subject to certain exceptions, (i) issue stock senior to or on parity with the Preferred Stock, (ii) incur indebtedness that would cause us to exceed a specified leverage ratio, (iii) amend, modify, alter or supplement our articles of incorporation or the Statement of Resolutions in a manner that would adversely affect the rights, preferences or privileges of the Preferred Stock, (iv) enter into or amend certain debt agreements that would be more restrictive on the payment of dividends on, or redemption of, the Preferred Stock than those existing on the Preferred Stock closing and (v) pay distributions on, purchase or redeem our common stock or other stock junior to the Preferred Stock that would cause us to

exceed a specified leverage ratio. We can be required to redeem the Preferred Stock (i) after the seventh anniversary of its initial issuance or (ii) at any time we fail to pay a dividend, subject to limited cure rights.

Holders of the Preferred Stock will, in certain circumstances, have additional rights in the event we fail to timely pay dividends, fail to redeem the Preferred Stock upon a change of control if required or fail to redeem the Preferred Stock upon request of the holders of the Preferred Stock following the seventh anniversary of the date of issuing the Preferred Stock. These rights include, subject to certain exceptions, (i) that holders of a majority of the then-outstanding Preferred Stock will have the exclusive right, voting separately as a class, to appoint and elect up to two directors to our board of directors, (ii) that approval of the holders of a majority of the then-outstanding Preferred Stock will be required prior to incurring indebtedness subject to a leverage ratio, declaring or paying prohibited distributions or issuing equity of subsidiaries to third parties; and (iii) that holders of a majority of the then-outstanding Preferred Stock will have the right to increase dividend payments and the ability to require us to pay dividends in common stock.

Holders of the Preferred Stock also have limited voting rights, including those with respect to potential amendments to our articles of incorporation or the Statement of Resolutions that have an adverse effect on the existing terms of the Preferred Stock and in certain other limited circumstances or as required by law.

We participate in oil and gas leases with third parties and these third parties may not be able to fulfill their commitments to our projects.

We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of the other working interest owners such as nonpayment of costs and liabilities arising from the actions of the other working interest owners. Some of these working interest owners may experience liquidity and cash flow problems. These problems may lead these parties to attempt to delay the pace of drilling or project development in order to preserve cash. A working interest owner may be unable or unwilling to pay its share of project costs. In some cases, a working interest owner may declare bankruptcy. In the event any of these third party working interest owners do not pay their share of such costs, we would likely have to pay

those costs, and we may be unsuccessful in any efforts to recover these costs from such parties, which could materially adversely affect our financial position.

Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage or we timely exercise our contractual rights to extend the terms of such leases by continuous operations or the payment of lease extension payments or delay rentals.

Leases on oil and natural gas properties typically have a primary term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established, applicable lease extension payments or delay rentals are made, or such lease is otherwise maintained pursuant to any applicable continuous operations provision. If our leases on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. If commodity prices remain low, we may be required to delay our drilling plans and, as a result, may lose our right to develop the related properties.

We have substantial capital requirements that, if not met, may hinder operations.

We have experienced and expect to continue to experience substantial capital needs as a result of our active exploration and development program and acquisitions. We expect that additional external financing will be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our existing revolving credit facility or new credit facilities may not be available in the future. Even if additional capital becomes available, it may not be on terms acceptable to us. As in the past, without additional capital resources, we may be forced to limit or defer our planned oil and gas exploration and development drilling program by releasing rigs or deferring fracturing, completion and hookup of the wells to pipelines and thereby adversely affect our production, cash flow, and the recoverability and ultimate value of our oil and gas properties, in turn negatively affecting our business, financial position and results of operations.

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell oil and natural gas and receive market prices for our oil and natural gas may be adversely affected by pipeline and gathering system capacity ~~constraints.~~constraints, including insufficient transportation capacity in the Delaware Basin.

Market conditions or the unavailability of satisfactory oil and gas transportation arrangements may hinder our access to oil and gas markets or delay our production. The availability of a ready market for our oil and gas production depends on a number

of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. However, such trucking and compression facilities may not always be available to us in acceptable terms or at all. Such restrictions on our ability to sell our oil or gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production. Pipeline and gathering constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. Our lease terms may require us to pay royalties on such flared gas to maintain our leases, which could adversely affect our business.

There is currently limited pipeline and gathering system capacity in areas where we operate. See “-Interruption to crude oil and natural gas gathering systems, pipelines and transportation and processing facilities we do not own could result in the loss of production and revenues.” This capacity shortage is particularly pronounced in the Delaware Basin and this area of operation has been characterized by periods when oil production has surpassed local transportation capacity, resulting in substantial discounts to the price received for crude oil prices quoted for WTI oil. During the year ended December 31, 2018, the Delaware Basin market crude oil price has experienced a substantial discount to WTI-Cushing prices, primarily due to limited pipeline capacity constraining transportation of crude oil out of the Delaware Basin to major marketing hubs. The amount of oil and gas being produced by us and others could continue to exceed the capacity of, and result in strains on, the various gathering and transportation systems, pipelines, processing facilities, and other infrastructure available in that area. It will be necessary for additional infrastructure, pipelines, gathering and transportation systems and processing facilities to be expanded, built, or developed to accommodate anticipated production from these areas. The expansion and construction of pipeline facilities that could alleviate transportation restrictions are affected by the availability and costs of necessary equipment, supplies, labor and other services, as well as the length of time to complete such projects. In addition, these projects can be affected by changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil and natural gas and any materials or products used to expand or construct pipeline facilities, such as certain imported steel mill products that are currently subject to an additional global tariff. All of these factors could negatively impact our realized oil prices, as well as actual results of our operations.

Historically, when available we have generally delivered our oil and gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our oil and gas production may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. In the Delaware Basin, we have entered into firm transportation agreements for a portion of our production in such areas in order to assure our ability, and that of our purchasers, to successfully market the oil and gas that we produce. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements.

A portion of our oil and gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss or unavailability of pipeline or gathering system access and capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions, including low oil and gas prices. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash

flow. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.

Interruption to crude oil and natural gas gathering systems, pipelines and transportation and processing facilities we do not own could result in the loss of production and revenues.

Our operations are dependent upon the availability, proximity and capacity of pipelines, natural gas gathering systems and transportation and processing facilities we do not own. Any significant change affecting these infrastructure facilities could materially harm our business. The lack of available capacity of gathering systems, pipelines and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. These systems and facilities may be temporarily unavailable due to adverse weather conditions or operational issues or may not be available to us in the future. See “-Our operations are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.” Additionally, activists or other efforts may delay or halt the construction of additional pipelines or facilities. To the extent these services are unavailable, we would be unable to realize revenue from wells served by such systems and facilities until suitable arrangements are made to market our production. As a result, we could experience reductions in revenue that could reduce or eliminate the funds available for our exploration and development programs and acquisitions, or result in the loss of property.

Instability in the global financial system or in the oil and gas industry sector may have impacts on our liquidity and financial condition that we currently cannot predict.

Instability in the global financial system or in the oil and gas industry sector may have a material impact on our liquidity and our financial condition. We rely upon access to both our revolving credit facility and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by the cash flow from operations or other sources. Our ability to access the capital markets or borrow money may be restricted or made more expensive at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. The economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us, and on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments. Also, market conditions, including with respect to commodity prices such as for oil and gas, could have an impact on our oil and gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, challenges in the economy have led and could further lead to reductions in the demand for oil and gas, or further reductions in the prices of oil and gas, or both, which could have a negative impact on our financial position, results of operations and cash flows.

The risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.

We have demands on our cash resources, including interest expense, operating expenses and funding of our capital expenditures. Our level of long-term debt, the demands on our cash resources and the provisions of the credit agreement governing our revolving credit facility and the indentures governing our ~~7.50% Senior Notes, our~~ 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) and our 8.25% Senior Notes may have adverse consequences on our operations and financial results, including:

placing us at a competitive disadvantage compared to our competitors that have lower debt service obligations and significantly greater operating and financial flexibility than we do;

limiting our financial flexibility, including our ability to borrow additional funds, pay dividends, make certain investments and issue equity on favorable terms or at all;

limiting our flexibility in planning for, and reacting to, changes in business conditions;

increasing our interest expense on our variable rate borrowings if interest rates increase;

requiring us to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities;

requiring us to modify our operations, including by curtailing portions of our drilling program, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing, which may be on unfavorable terms; and

making us more vulnerable to downturns in our business or the economy, including a decline in oil prices.

In addition, the provisions of our revolving credit facility and our ~~7.50% Senior Notes, our~~ 6.25% Senior Notes and our 8.25% Senior Notes place restrictions on us and certain of our subsidiaries with respect to incurring additional indebtedness and liens, making dividends and other payments to shareholders, repurchasing our common stock, repurchasing or redeeming our ~~7.50% Senior Notes, our~~ 6.25% Senior Notes and our 8.25% Senior Notes, making investments, acquisitions, mergers and asset

dispositions, entering into hedging transactions and other matters. Our revolving credit facility also requires compliance with covenants to maintain specified financial ratios. Our business plan and our compliance with these covenants are based on a number of assumptions, the most important of which is relatively stable oil and gas prices at economically sustainable levels. If the prices that we receive for our oil and gas production continue to remain at low levels or to decline, it could lead to further reduced revenues, cash flow and earnings, which in turn could lead to a default under certain financial covenants contained in our revolving credit facility, including the covenants related to working capital and the ratios described above. Also, a further decline in or sustained low oil and gas prices could result in a lowering of our credit ratings by rating agencies, which could adversely impact the pricing of, or our ability to issue, new debt instruments. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period as the amounts outstanding under our revolving credit facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings. If a further decline in oil or gas prices were to occur in the future or if low prices continue for an extended period, it could further increase the risk of a lowering in our credit rating or our inability to comply with covenants to maintain specified financial ratios. Additionally, these ratios may have the effect of restricting us from borrowing the full amount available under the borrowing base for our revolving credit facility. In order to provide a margin of comfort with regard to these financial covenants, we may seek to further reduce our capital expenditure plan, sell additional non-strategic assets or opportunistically modify or increase our derivative instruments to the extent permitted under our revolving credit facility. We cannot assure you that we will be able to successfully

execute any of these strategies, or if executed, that they will be sufficient to avoid a default under our revolving credit facility if a further decline in oil or gas prices were to occur in the future or if low prices continue for an extended period.

The terms of our Preferred Stock have many of the same effects as our debt and terms of our debt agreements. See “—~~Upon consummation of the ExL Acquisition, our~~Our overall level of debt and Preferred Stock obligations ~~increased, which~~ could adversely affect us.” and “—Holders of the Preferred Stock have rights that may restrict our ability to operate our business or be adverse to holders of our common stock.”

The borrowing base under our revolving credit facility may be reduced below the amount of borrowings outstanding under such facility.

Under the terms of our revolving credit facility, our borrowing base is subject to redeterminations at least semi-annually based in part on assumptions of the administrative agent with respect to, among other things, crude oil and natural gas prices. A negative adjustment could occur if the crude oil and natural gas prices used by the banks in calculating the borrowing base are significantly lower than those used in the last redetermination, including as a result of a decline in crude oil prices or an expectation that such reduced prices will continue. The next redetermination of our borrowing base is scheduled to occur in Spring ~~2018.~~2019. In addition, the portion of our borrowing base made available to us is subject to the terms and covenants of our revolving credit facility, including compliance with the ratios and other financial covenants of such facility. In the event the amount outstanding under our revolving credit facility exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell a portion of our assets.

We may face difficulties in securing and operating under authorizations and permits to drill, complete or operate our wells.

The recent growth in oil and gas exploration in the United States has drawn intense scrutiny from environmental and community interest groups, regulatory agencies and other governmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations that may make it difficult or impossible to obtain permits and other needed authorizations to drill, complete or operate, result in operational delays, or otherwise make oil and gas exploration more costly or difficult than in other countries.

Many of our properties are in areas that may have been partially depleted or drained by our existing wells or other offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.

Many of our properties are in areas that may have already been partially depleted or drained by earlier drilling, including offset drilling by other operators. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could inhibit our ability to find or recover commercial quantities of oil and adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, may result in an acceleration in the decline in production of our wells and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our producing wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they recommence production. We have no control over the operations or activities of offsetting operators.

We have only limited experience drilling wells in the Delaware Basin and less information regarding reserves and decline rates in these shale formations than in some other areas of our operations.

We have limited exploration and development experience in the Delaware Basin. We have participated in the drilling of only 40117 gross ~~(20.3~~(48.4 net) operated and non-operated wells in the Delaware Basin. Other operators in these areas have significantly more experience in the drilling of wells, including the drilling of horizontal wells. As a result, we have less information with respect to the ultimate recoverable reserves, the production decline rate and other matters relating to the exploration, drilling and development of the Delaware Basin than we have in our Eagle Ford area in which we operate.

If we are unable to acquire adequate supplies of water for our ~~drilling~~ operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules, our ability to produce oil and gas commercially and in commercial quantities could be impaired.

We use a substantial amount of water in our ~~drilling operations.~~operations, including in the hydraulic fracturing process. Our inability to locate sufficient amounts of water, or to treat and dispose of water after drilling at a reasonable cost, could adversely impact our operations. Moreover, the imposition of

new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas. Furthermore, future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for

hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial performance. For example, in June 2016, the EPA established pretreatment standards for disposal of wastewater produced from unconventional oil and natural gas extraction facilities into publicly owned treatment works. In response to these actions, operators including us have begun to rely more on recycling of flowback and produced water from well sites as a preferred alternative to disposal.

We may not increase our acreage positions in areas with exposure to oil, condensate and NGLs.

If we are unable to increase our acreage positions in the Eagle Ford and Delaware Basin, this may detract from our efforts to realize our growth strategy in crude oil plays. Additionally, we may be unable to find or consummate other opportunities in these areas or in other areas with similar exposure to oil, condensate and NGLs on similar terms or at all.

Restricted land access could reduce our ability to explore for and develop oil and gas reserves.

Our ability to adequately explore for and develop oil and gas resources is affected by a number of factors related to access to land. Examples of factors which reduce our access to land include, among others:

new municipal or state land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;

local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;

landowner or foreign governments’ opposition to infrastructure development;

regulation of federal land by the U.S. Department of the Interior Bureau of Land Management or other federal government agencies;

anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, disruption of drilling, or damage to equipment;

disputes regarding leases; and

disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements.

Loss of access to land for which we own mineral rights could result in a reduction in our proved reserves and a negative impact on our results of operations and cash flows. Reduced ability to obtain new leases could constrain our future growth and opportunity set by limiting the expansion of our operations.

We face strong competition from other oil and gas companies.

We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the oil and gas business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory projects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on favorable terms. These companies may also have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the current commodity price environment, and to absorb the burden of current and future governmental regulations and taxation. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.

We may not be able to keep pace with technological developments in our industry.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological

advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

Part of our strategy involves drilling existing or emerging shale plays using some of the latest available seismic, horizontal drilling and completion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production. As a result, the value of our undeveloped acreage could decline if drilling results are unsuccessful.

We rely to a significant extent on seismic data and other advanced technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to drilling and completing a well, whether oil or natural gas is present or may be produced economically.

Many of our operations involve drilling and completion techniques developed by us or our service providers in order to maximize cumulative recoveries. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore, and being able to run tools and recover equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools and other equipment the entire length of the well bore during completion operations, being able to recover such tools and other equipment, and successfully cleaning out the well bore after completion of the final fracture stimulation.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, commodity price decline, or other reasons, then the return on our investment for a particular project may not be as attractive as we anticipated and the value of our undeveloped acreage could decline in the future.

We are subject to various environmental risks and governmental regulations, including those relating to benzene emissions, hydraulic fracturing and global climate change, and future regulations may be more stringent resulting in increased operating costs and decreased demand for the oil and gas that we produce.

Oil and gas operations are subject to various federal, state, local and foreign laws and government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, well testing, plug and abandonment requirements and bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Other federal, state, local and foreign laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations, including drilling fluids and wastewater. We may incur costs arising out of property damage, including environmental damage caused by previous owners or operators of property we purchase or lease or relating to third party sites, or injuries to employees and other persons. As a result, we may incur substantial liabilities to third parties or governmental entities and may be required to incur substantial remediation costs. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted. Compliance with existing, new or modified laws and regulations could result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, financial position and results of operations.

Moreover, changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time. Increased scrutiny of our industry may also occur as a result of the EPA’s 2017-2019 National Enforcement Initiative (“NEI”), “Ensuring Energy Extraction Activities Comply with Environmental Laws,” through which the EPA will address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health or the environment. However, the EPA has proposed a 2020-2023 National Compliance Initiative (formerly referred to as an NEI) that would transition the 2017-2019 NEI to focus on significant sources of volatile organic compounds that have a substantial impact on air quality, without regard to sector. Stricter laws, regulations or enforcement policies could significantly increase our compliance costs and negatively impact our production and operations, which could have a material adverse effect on our results of operations and cash flows. See “Item 1. Business-Additional Oil and Gas Disclosures-Regulation-Environmental Regulations” for additional information.

There is increasing attention in the United States and worldwide to the issue of climate change and the contributing effect of GHG emissions. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing oil and gas exploration in the areas in which we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. See “Item 1. Business-Additional Oil and Gas Disclosures-Regulation- Global Climate Change” for additional information.

Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock

formations to stimulate oil and gas production. The U.S. Congress has considered legislation to subject hydraulic fracturing operations to federal regulation and to require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. The EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel under the federal Safe Drinking Water Act and has released permitting guidance for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. In addition, in March 2015, the BLM issued a final rule to regulate hydraulic fracturing on federal and Indian land. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. ~~Further, the EPA issued an Advanced Notice of Proposed Rulemaking in May 2014 seeking comments relating~~The rescission rule is currently subject to ~~the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and mechanisms for obtaining this information.~~legal challenge. A number of federal agencies are also analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, in December 2016, the EPA released the final results of a study of the potential impacts of hydraulic fracturing activities on drinking water resources in the states where the EPA is the permitted authority. The study concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. These ongoing or proposed studies, depending on their course and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other regulatory mechanisms.

State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Texas, have modified their regulations to account for induced seismicity. Regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. A 2012 report published by the National Academy of Sciences concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity; and a 2015 report by researchers at the University of Texas has suggested that the link between seismic activity and wastewater disposal may vary by region. In March 2016, the United States Geological Survey (the “USGS”) identified states with the most significant hazards from induced seismicity, which included Texas. ~~A 2017 study conducted by the~~Subsequent USGS ~~similarly identified a high~~ seismic hazard ~~for areas~~forecasts have continued to include Texas, but have found greater probability of ~~several states, including north Texas.~~seismic hazards in other states. A number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our operations and on our and our contractors’ waste disposal activities.

Several states, including states where we operate such as Texas, have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing through additional permit requirements, public disclosure of fracturing fluid contents, water sampling requirements, and operational restrictions. Further, some states and local governments have adopted or are considering adopting bans on drilling. For example, the City of Denton, Texas adopted a moratorium on hydraulic fracturing in November 2014, which was later lifted in 2015. We use hydraulic fracturing extensively and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the state of Texas, could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations. See “Item 1. Business-Additional Oil and Gas Disclosures-Regulation-Regulation of Natural Gas and Oil Exploration and Production” and “-Environmental Regulations” for additional information.

From time to time legislation is introduced in the U.S. Congress that, if enacted into law, would make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial position and results of operations.

We face various risks associated with the trend toward increased anti-development activity.

As new technologies have been applied to our industry, we have seen significant growth in oil and gas supply in recent years, particularly in the U.S. With this expansion of oil and gas development activity, opposition toward oil and gas drilling and development activity has been growing both in the U.S. and globally. Companies in the oil and gas industry, such as us, can be the target of opposition to development from certain stakeholder groups. These anti-development efforts could be focused on:

limiting oil and gas development;

reducing access to federal and state owned lands;

delaying or canceling certain projects such as shale development and pipeline construction;

limiting or banning the use of hydraulic fracturing;

denying air-quality permits for drilling; and

advocating for increased regulations on shale drilling and hydraulic fracturing.

Future anti-development efforts could result in the following:

blocked development;

denial or delay of drilling permits;

shortening of lease terms or reduction in lease size;

restrictions on installation or operation of gathering or processing facilities;

restrictions on the use of certain operating practices, such as hydraulic fracturing;

reduced access to water supplies or restrictions on water disposal;

limited access or damage to or destruction of our property;

legal challenges or lawsuits;

increased regulation of our business;

damaging publicity and reputational harm;

increased costs of doing business;

reduction in demand for our products; and

other adverse effects on our ability to develop our properties and expand production.

Our need to incur costs associated with responding to these initiatives or complying with any new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations. In addition, the use of social media channels can be used to cause rapid, widespread reputational harm.

Our operations are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.

The oil and gas business involves operating hazards such as:

well blowouts;

mechanical failures;

explosions;

pipe or cement failures and casing collapses, which could release oil, natural gas, drilling fluids or hydraulic fracturing fluids;

uncontrollable flows of oil, natural gas or well fluids;

fires;

geologic formations with abnormal pressures;

spillage handling and disposing of materials, including drilling fluids and hydraulic fracturing fluids and other pollutants;

pipeline ruptures or spills;

releases of toxic gases;

adverse weather conditions, including drought, flooding, winter storms, snow, hurricanes or other severe weather events; and

other environmental hazards and risks including conditions caused by previous owners and lessors of our properties.

Any of these hazards and risks can result in substantial losses to us from, among other things, injury or loss or life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. As a result we could incur substantial liabilities

or experience reductions in revenue that could reduce or eliminate the funds available for our exploration and development programs and acquisitions.

We may not have enough insurance to cover all of the risks we face.

We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that management believes to be prudent; however, insurance against all operational risks is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if management believes that the cost of available insurance is excessive relative to the risks presented. In addition, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure you that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

We conduct a portion of our operations through a joint venture, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position and our results of operations.

We conduct a portion of our operations through a joint venture with GAIL. We may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance of these third party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected.

Our joint venture arrangements may involve risks not otherwise present when exploring and developing properties directly, including, for example:

our joint venture partners may share certain approval rights over major decisions;

our joint venture partners may not pay their share of the joint venture’s obligations, leaving us liable for their shares of joint venture liabilities;

we may incur liabilities as a result of an action taken by our joint venture partners;

we may be required to devote significant management time to the requirements of and matters relating to the joint ventures;

our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and

disputes between us and our joint venture partners may result in delays, litigation or operational impasses.

The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn negatively affect our financial condition and results of operations. The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn negatively affect our financial condition and results of operations. The agreements under which we formed certain joint ventures may subject us to various risks, limit the actions we may take with respect to the properties subject to the joint venture and require us to grant rights to our joint venture partners that could limit our ability to benefit fully from future positive developments. Some joint ventures require us to make significant capital expenditures. If we do not timely meet our financial commitments or otherwise do not comply with our joint venture agreements, our rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of our joint venture partners may have greater financial resources than we have and we may not be able to secure the funding necessary to participate in operations our joint venture partners propose, thereby reducing our ability to benefit from the joint venture.

We cannot control the activities on properties we do not operate.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues or could create liability for us for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards. With respect to properties that we do not operate:

the operator could refuse to initiate exploration or development projects;

if we proceed with any of those projects the operator has refused to initiate, we may not receive any funding from the operator with respect to that project;

the operator may initiate exploration or development projects on a different schedule than we would prefer;

the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a project than we have funds for, which may mean that we cannot participate in those projects or participate in a substantial amount of the revenues from those projects; and

the operator may not have sufficient expertise or resources.

Any of these events could significantly and adversely affect our anticipated exploration and development activities.

Our business may suffer if we lose key personnel.

We depend to a large extent on the services of certain key management personnel, including our executive officers and other key employees, the loss of any of whom could have a material adverse effect on our operations. We have entered into employment agreements with many of our key employees as a way to assist in retaining their services and motivating their performance. We do not maintain key-man life insurance with respect to any of our employees. Our success will also be dependent on our ability to continue to employ and retain skilled technical personnel.

We may experience difficulty in achieving and managing future growth.

We have experienced growth in the past primarily through the expansion of our drilling program. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:

our ability to obtain leases or options on properties, including those for which we have 3-D seismic data;

our ability to acquire additional 3-D seismic data;

our ability to identify and acquire new exploratory prospects;

our ability to develop existing prospects;

our ability to continue to retain and attract skilled personnel;

our ability to maintain or enter into new relationships with project partners and independent contractors;

the results of our drilling program;

hydrocarbon prices; and

our access to capital.

We may not be successful in upgrading our technical, operations and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial position and results of operations.

We may continue to enter into or exercise commodity derivative transactions to manage the price risks associated with our production, which may expose us to risk of financial loss and limit the benefit to us of increases in prices for oil and gas.

Because oil and gas prices are unstable, we periodically enter into price-risk-management transactions such as fixed-rate swaps, costless collars, three-way collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and gas production and thereby to achieve a more predictable cash flow. Additionally, insome of our ~~ExL Acquisition, we entered into~~agreements for both the acquisition and disposition of oil and gas properties include arrangements whereby we will be required to make or entitled to receive additional payments if ~~oil~~commodity prices exceed specified levels for certain periods of time. ~~We have also entered into arrangements in some of our disposition transactions where we similarly receive such payments.~~ The use of these arrangements limits our ability to benefit from increases in the prices of oil and gas. Additionally, some derivative transactions may help to assure favorable pricing in the near term, but at the cost of limiting our ability to benefit from price increases that occur in subsequent years. At any given time our derivative arrangements may apply to only a portion of our production, including following the exercise of any then-existing derivative instruments, thereby providing only partial protection against declines in oil and gas prices. These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of oil and gas or a sudden, unexpected event materially impacts oil or gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us or there may be an adverse change in the expected differential between

the underlying price in the derivative instrument and the actual prices received for our production. During periods of declining commodity prices, our commodity price derivative positions increase, which increases our counterparty exposure.

As our derivatives expire, more of our future production will be sold at market prices unless we enter into additional derivative transactions. If we are unable to enter into new derivative contracts in the future at favorable pricing and for a sufficient amount of our production, our financial condition and results of operations could be materially adversely affected. It is also possible that a larger percentage of our future production will not be hedged as our derivative policies may change, which would result in our oil and gas revenue becoming more sensitive to commodity price changes.

The ~~CFTC~~Commodity Futures Trading Commission has promulgated regulations to implement statutory requirements for swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. While we believe that our use of swap transactions exempt us from certain regulatory requirements, the changes to the swap market due to increased regulation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Periods of high demand for oil field services and equipment and the ability of suppliers to meet that demand may limit our ability to drill and produce our oil and gas properties.

Our industry is cyclical and, from time to time, well service providers and related equipment and personnel may be in short supply. These shortages can cause escalating prices, delays in drilling and other exploration activities and the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures may increase the actual cost of services, extend the time to secure such services and add costs for damages due to any accidents sustained from the overuse of equipment and inexperienced personnel. After a period of general declines in oilfield service and equipment costs following commodity price decreases, such costs could increase as commodity prices rise and may limit our ability to drill and produce our oil and gas properties.

If crude oil and natural gas prices decline to near or below the low levels experienced in 2015 and 2016 we could be required to record additional impairments of proved oil and gas properties that would constitute a charge to earnings and reduce our shareholders’ equity.

At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (A) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (B) the costs of unproved properties not being amortized, and (C) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of proved oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.

The estimated future net revenues used in the cost center ceiling are calculated using the 12-Month Average Realized Price. ~~Primarily~~We recognized no impairments of proved oil and gas properties for the years ended December 31, 2018 and December 31, 2017, but did recognize an impairment of $576.5 million for the year ended December 31, 2016, primarily due to declines in the 12-Month Average Realized Price of crude ~~oil, we recognized no impairments of proved oil and gas properties for the year ended December 31, 2017 and $576.5 million for the year ended December 31, 2016.~~oil. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters would result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in ~~additional~~ impairments of proved oil and gas properties.

Unproved properties, not being amortized, are assessed on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs along with associated capitalized interest are added to the oil and gas property costs subject to amortization. This assessment requires the use of judgment and estimates all of which may prove to be inaccurate. If crude oil and natural gas prices decline from their current levels, we may need to write down the carrying value of our unproved oil and gas properties, which will result in increased DD&A for future periods.

An impairment does not impact cash flows from operating activities but does reduce earnings and our shareholders’ equity and increases the balance sheet leverage as measured by debt-to-total capitalization. The risk that we will be required to recognize impairments of our proved oil and gas properties increases during periods of low or declining oil or gas prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues, as further discussed under “-Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future.” We have in the past and could in the future incur additional impairments of oil and gas properties, particularly if oil and natural gas prices decline or remain at low levels.

A valuation allowance on a deferred tax asset could reduce our earnings.

Deferred tax assets are recorded for net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. We assess the realizability of the deferred tax assets each period by considering whether it is more likely than not that all or a portion of our deferred tax assets will not be realized. If we conclude that it is more likely than not that the deferred tax assets will not be realized, we record a valuation allowance against the net deferred tax asset, which has occurred since 2015 where we recorded a valuation allowance, reducing the net deferred tax asset to zero. This valuation allowance reduces earnings and our shareholders’ equity and increases the balance sheet leverage as measured by debt-to-total capitalization. The valuation allowance remained as of December 31, ~~2017,~~2018, and will remain until such time, if ever, that we can determine that the net deferred tax assets are more likely than not to be realized.

The taxation of independent producers is subject to change, and federal and state proposals being considered could increase our cost of doing business.

From time to time, legislative proposals are made that would, if enacted into law, make significant changes to United States tax laws, including the elimination or postponement of certain key United States federal income tax incentives currently available to independent producers of oil and natural gas. Proposals that would significantly affect us could include a repeal of the expensing of intangible drilling costs, a repeal of the percentage depletion allowance and an increase in the amortization period of geological and geophysical expenses. These changes, if enacted, will make it more costly for us to explore for and develop our oil and natural gas resources.

We may incur losses as a result of title deficiencies.

We purchase working and revenue interests in the oil and gas leasehold interests upon which we will perform our exploration activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available and, in all instances, we forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. Even then, the cost of performing detailed title work can be expensive. We may choose to forgo detailed title examination by title lawyers on a portion of the mineral leases that we place in a drilling unit or conduct less title work than we have traditionally performed. As is customary in our industry, we generally rely upon the judgment of oil and gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract. We, in some cases, perform curative work to correct deficiencies in the marketability or adequacy of the title to us. The work might include obtaining affidavits of heirship or causing an estate to be administered. In cases involving more serious title problems, the amount paid for affected oil and gas leases can be generally lost and the target area can become undrillable. The failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

The threat and impact of terrorist attacks, cyber attacks or similar hostilities may adversely impact our operations.

We face various security threats ~~including attempts by third parties to gain unauthorized access to sensitive information or to render data or systems unusable; threats~~ to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts and acts of war. We also face cyber security and other threats including attempts by third parties to gain unauthorized access to sensitive information or to render data or systems unusable. These threats relate both to information relating to us and to third parties with whom we do business including landowners, employees, suppliers, customers and others. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows.

In particular, the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling activities, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data. We ~~depend~~rely extensively on digital technology, including information technology systems and related infrastructure as well as internet sites, computer software, data hosting facilities, cloud application and services and other hardware and platforms, some of which are hosted by third parties to store, transmit, process and record sensitive information (including trade secrets, employee information and financial and operating data), communicate with our employees and business ~~partners,~~associates, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. The complexity of the technologies needed to explore for and develop oil ~~natural~~and gas ~~and NGLs~~ makes certain information ~~more~~particularly attractive to thieves.

Our business ~~partners,~~associates, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital ~~technology. Some of these business partners~~technology and some may be provided limited access to our sensitive information or our information systems and related infrastructure in the ordinary course of business.

As dependence on digital technologies has increased so has the risk of cyber incidents, including deliberate attacks and unintentional events. Cybersecurity threat actors are becoming more sophisticated and coordinated in their attempts to access other parties’ information technology systems and data, including those of cloud providers and third parties with which such other parties conduct business. Our technologies, systems and networks, and those of others with whom we do business, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. These may result from among other things, unauthorized access, denial-of-service attacks, malicious software, data privacy and other breaches by employees, or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions. A cyber incident involving our information systems and related infrastructure, or that of our business associates, could disrupt our business plans and negatively impact our operations in a variety of ways, including, but no limited to, the following:

Unauthorized access to seismic data, reserves information and other operational incidents, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and natural gas resources;

Data corruption, or other operational disruption during drilling or completion activities could result in failure to reach the intended target or a drilling or other operational incident, personal injury, damage to equipment or the subsurface or otherwise adversely affect our operations;

Data corruption or operational disruptions of production-related infrastructure could result in a loss of production, accidental discharge, and other operational incidents;

A cyber attack on, or other disruptions to a vendor or service provider or other third party could result in disruptions which could delay or halt our operations;

A cyber attack on third-party gathering, pipeline, or other transportation systems could delay or prevent us from transporting and marketing our production;

A cyber attack on our automated and surveillance systems could cause a loss in production, potential environmental hazards and other operational problems; and

A corruption or loss of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties.

In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. ~~A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.~~ We may be the target of such attacks and, as cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any security vulnerabilities. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

We cannot assess the extent of either the threat or the potential impact of future terrorist or cyber security attacks on the energy industry in general, and on us in particular, either in the short-term or in the long-term. Uncertainty surrounding such attacks may affect our operations in unpredictable ways.

Certain anti-takeover provisions may affect your rights as a shareholder.

Our articles of incorporation authorize our board of directors to set the terms of and issue preferred stock without shareholder approval. Our board of directors could use the preferred stock as a means to delay, defer or prevent a takeover attempt that a shareholder might consider to be in our best interest. In addition, our revolving credit facility, our indentures governing our senior notes and our existing Preferred Stock contain terms that may restrict our ability to enter into change of control transactions, including requirements to repay borrowings under our revolving credit facility and to offer to repurchase senior notes or to redeem our Preferred Stock, in either event upon a change in control, as determined under the relevant documents relating to such indebtedness or Preferred Stock. Furthermore, provisions in our bylaws, among other things, impose requirements on shareholders who wish to make nominations for the election of directors, propose other actions at shareholder meetings or take action to call shareholder meetings. These provisions, along with specified provisions of the Texas Business Organizations Code and our articles of incorporation and bylaws, may discourage or impede transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common stock.

Failure to adequately protect critical data and technology systems and the impact of data privacy regulation could materially affect ~~our operations.~~us.

Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or ~~cancellation of customer orders,~~canceling or impeding processing of transactions and reporting financial results, resulting in the unintentional

disclosure of ~~customer,~~ employee, royalty owner, or other third party or our information, or damage to our reputation. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our operations, financial condition, results of operations or cash flows. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information, including the European Union General Data Protection Regulation and recent California legislation, pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information regarding our properties is included in “Item 1. Business” above and in “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 4. Property and Equipment, Net” of the Notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data,” which information is incorporated herein by reference.

Item 3. Legal Proceedings

From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not currently expect these matters to have a materially adverse effect on our financial position or results of operations.

Barrow-Shaver Litigation

On September 24, 2014 an unfavorable jury verdict was delivered against the Company in a case entitled Barrow-Shaver Resources Company v. Carrizo Oil & Gas, Inc. in the amount of $27.7 million. On January 5, 2015, the court entered a judgment awarding the verdict amount plus $2.9 million in ~~attorney~~attorneys’ fees plus pre-judgment interest. On January 31, 2017, the Twelfth Court of Appeals at Tyler, Texas reversed the trial court decision and rendered judgment in favor of the Company, declaring that the plaintiff take nothing on any of its claims. The plaintiff ~~has filed a motion for rehearing with the Twelfth Court of Appeals at Tyler, Texas and has~~ petitioned the Texas Supreme Court ~~to accept the case for review. Although the Texas Supreme Court has not accepted the case~~ for review, ~~it has asked the parties for briefing~~which was granted, and oral arguments were held on ~~the merits of the dispute.~~December 4, 2018. The payment of damages per the

original judgment was superseded by posting a bond in the amount of $25.0 million, which will remain outstanding pending resolution of the appeals process (which could take an extended period of time) or agreement of the parties.

The case was filed September 19, 2012 in the 7th Judicial District Court of Smith County, Texas and arises from an agreement between the plaintiff and the Company whereby the plaintiff could earn an assignment of certain of the Company’s leasehold interests in Archer and Baylor counties, Texas for each commercially productive oil and gas well drilled by the plaintiff on acreage covered by the agreement. The agreement contained a provision that the plaintiff had to obtain the Company’s written consent to any assignment of rights provided by such agreement. The plaintiff subsequently entered into a purchase and sale agreement with a third-party purchaser allowing the third-party purchaser to purchase rights in approximately 62,000 leasehold acres, including the rights under the agreement with the Company, for approximately $27.7 million. The plaintiff requested the Company’s consent to make the assignment to the third-party purchaser and the Company refused. The plaintiff alleged that, as a result of the Company’s refusal, the third-party purchaser terminated such purchase and sale agreement. The plaintiff sought damages for breach of contract, tortious interference with existing contract and other grounds in an amount not to exceed $35.0 million plus exemplary damages and ~~attorney’s~~attorneys’ fees. As mentioned previously, the Twelfth Court of Appeals at Tyler, Texas found in favor of the Company on all grounds.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Information. Our common stock, par value $0.01 per share, trades on the NASDAQ Global Select Market under the symbol “CRZO.” ~~The following table sets forth the high and low intraday sales prices per share of our common stock on the NASDAQ Global Select Market for the periods indicated.~~

High Low
2017
First Quarter
$39.48

$26.08
Second Quarter 30.19
15.05
Third Quarter 18.46
11.10
Fourth Quarter 22.21
14.36
2016
First Quarter
$32.45

$16.10
Second Quarter 42.49
28.51
Third Quarter 41.17
29.52
Fourth Quarter 43.96
32.00

~~Owners of Record.~~ ~~The closing market price of our common stock on February 23, 2018 was $18.44 per share.~~ As of February ~~23, 2018,~~22, 2019, there were an estimated 6349 owners of record of our common stock. See “Note 10. Shareholders’ Equity” of the Notes to our Consolidated Financial Statements for further discussion.

Common Stock Dividends. We have not paid any dividends on our common stock in the past and do not intend to pay such dividends in the foreseeable future. We currently intend to retain any earnings for the future operation and development of our business, including exploration, development and acquisition activities. Our revolving credit facility, our senior notes and the terms of our preferred stock restrict our ability to pay dividends. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Purchases of Equity Securities by the Issuer and Affiliated Purchasers. For the year ended December 31, ~~2017,~~2018, there were no purchases made by the Company or affiliated purchasers (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of shares of the Company’s common stock.

Common Stock Total Return Performance Graph. The following performance graph contained in this section is not deemed to be “soliciting material” or to be “filed” with the SEC, and will not be incorporated by reference into any other filings under the Securities Act of 1933, as amended (the “Securities Act”) or Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates it by reference into such filing. Shareholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.

The performance graph below presents a comparison of the yearly percentage change in the cumulative total return on our common stock over the period from December 31, ~~2012~~2013 to December 31, ~~2017~~2018, with the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index, over the same period.

The graph assumes an investment of $100 (with reinvestment of all dividends) was invested on December 31, ~~2012,~~2013, in our common stock at the closing market price at the beginning of this period and in each of the other two indexes.


	CRZO	S&P 500	DJ U.S. E&P	CRZO	S&P 500	DJ U.S. E&P
December 31, 2012	$100	$100	$100
December 31, 2013	$214	$132	$132	$100	$100	$100
December 31, 2014	$199	$151	$117	$93	$114	$89
December 31, 2015	$141	$153	$90	$66	$115	$68
December 31, 2016	$179	$171	$111	$83	$129	$85
December 31, 2017	$102	$208	$113	$48	$157	$86
December 31, 2018				$25	$150	$71

See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters” for information regarding shares of common stock authorized for issuance under our stock incentive plans.

Item 6. Selected Financial Data

Our financial information set forth below for each of the five years in the period ended December 31, ~~2017,~~2018, has been derived from information included in our audited consolidated financial statements. This information should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and related Notes included in “Item 8. Financial Statements and Supplementary Data.”


	Years Ended December 31,															Years Ended December 31,
	2017			2016			2015			2014			2013			2018			2017			2016			2015			2014
	(In thousands, except per share data)															(In thousands, except per share amounts)
Statements of Operations Information:
Total revenues		$745,888			$443,594			$429,203			$710,187			$520,182			$1,065,942			$745,888			$443,594			$429,203			$710,187
Total costs and expenses	654,748			1,119,068			1,727,963			359,977			485,421			656,342			654,748			1,119,068			1,727,963			359,977
Income (loss) from continuing operations	87,110			(675,474		)	(1,157,885		)	222,283			21,858			404,427			87,110			(675,474		)	(1,157,885		)	222,283
Net income (loss) attributable to common shareholders	78,467			(675,474		)	(1,155,154		)	222,283			21,858			376,076			78,467			(675,474		)	(1,155,154		)	226,343
Income (loss) from continuing operations per common share:
Basic		$1.19			($11.27	)		($22.50	)		$4.90			$0.54			$4.73			$1.19			($11.27	)		($22.50	)		$4.90
Diluted		$1.18			($11.27	)		($22.50	)		$4.81			$0.53			$4.64			$1.18			($11.27	)		($22.50	)		$4.81
Net income (loss) attributable to common shareholders per common share:
Basic		$1.07			($11.27	)		($22.45	)		$4.90			$0.54			$4.40			$1.07			($11.27	)		($22.45	)		$4.99
Diluted		$1.06			($11.27	)		($22.45	)		$4.81			$0.53			$4.32			$1.06			($11.27	)		($22.45	)		$4.90
Weighted average common shares outstanding:
Basic	73,421			59,932			51,457			45,372			40,781			85,509			73,421			59,932			51,457			45,372
Diluted	73,993			59,932			51,457			46,194			41,355			87,143			73,993			59,932			51,457			46,194

Statements of Cash Flows Information:
Net cash provided by operating activities from continuing operations		$422,981			$272,768			$378,735			$502,275			$367,474			$653,555			$422,981			$272,768			$378,735			$502,275
Net cash used in investing activities from continuing operations	(1,159,452		)	(619,832		)	(673,376		)	(940,676		)	(509,885		)	(795,968		)	(1,159,452		)	(619,832		)	(673,376		)	(940,676		)
Net cash provided by financing activities from continuing operations	741,817			308,340			330,767			300,290			120,326			135,155			741,817			308,340			330,767			300,290

Balance Sheet Information:
Working capital		($249,944	)		($138,971	)		($50,636	)		($141,278	)		($32,138	)
Total assets	2,778,304			1,626,327			2,007,246			2,962,305			2,094,364			3,185,100			2,778,304			1,626,327			2,007,246			2,962,305
Long-term debt	1,629,209			1,325,418			1,236,017			1,332,175			883,851			1,633,591			1,629,209			1,325,418			1,236,017			1,332,175
Preferred stock	214,262			—			—			—			—			174,422			214,262			—			—			—
Total shareholders’ equity	370,897			23,458			444,054			1,103,441			841,604			980,904			370,897			23,458			444,054			1,103,441

8. Commitments and Contingencies

From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. Pursuant to various purchase and sale agreements related to our divested assets in the Eagle Ford Shale, Marcellus Shale, Utica Shale, and Niobrara Formation, the Company has indemnified the respective purchasers against certain liabilities that they may incur with respect to the assets acquired from the Company. The Company believes such indemnities are customary in purchase and sale transactions in our industry. Such indemnities may include, among others, breach of representations and warranties, tax liabilities, employee compensation, litigation, personal injury, transport or disposal of hazardous substances, calculation and payments of royalties, environmental matters and rights-of-way.

While the outcome of these events cannot be predicted with certainty, as of December 31, 2018, management does not ~~currently~~ expect these ~~matters~~indemnifications to have a materially adverse effect on the financial position or results of operations of the Company.

The financial position and results of operations ~~and financial position~~ of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and gas production, imports and exports, ~~natural gas regulation,~~ tax ~~legislation,~~changes, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.

Rent expense included in general and administrative expense, net for the years ended December 31, 2018, 2017 and 2016 ~~and 2015~~ was $1.4 million, $1.7 million, ~~$2.0 million,~~ and ~~$2.2~~$2.0 million, respectively, and includes rent expense for the Company’s corporate ~~office~~ and field offices. The table below presents total minimum commitments associated with long-term, non-cancelable ~~operating and capital~~ leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of natural gas or produced water to be delivered, as of December 31, 2017. The total minimum commitments related to the drilling rig contracts represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs.2018.

2018 2019 2020 2021 2022 2023 and Thereafter Total
(In thousands)
Operating leases
$5,038

$4,895

$4,637

$4,450

$1,854

$—

$20,874
Capital leases 1,823
1,800
1,050
—
—
—
4,673
Drilling rig contracts 23,885
8,881
—
—
—
—
32,766
Delivery commitments 3,657
3,676
2,757
2,438
10
26
12,564
Total
$34,403

$19,252

$8,444

$6,888

$1,864

$26

$70,877



	2019		2020		2021		2022		2023		2024 and Thereafter		Total
	(In thousands)
Operating leases		$10,024		$9,154		$6,249		$3,639		$3,680		$20,978		$53,724
Drilling rig contracts ⁽¹⁾	37,077		16,867		813		—		—		—		54,757
Delivery commitments ⁽²⁾	3,726		2,807		2,487		30		7		19		9,076
Produced water disposal commitments ⁽³⁾	18,139		20,894		20,898		20,954		10,471		9,769		101,125
Other	1,800		1,050		—		—		—		—		2,850
Total		$70,766		$50,772		$30,447		$24,623		$14,158		$30,766		$221,532

In connection with the ExL Acquisition, the Company has agreed to a contingent payment of $50.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2021 with a cap of $125.0 million, which is not included in the table above.

~~Contractual Obligations Executed Subsequent to December 31, 2017~~


(1)	Drilling rig contracts represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will generally be billed for their working interest share of such costs.


(2)	Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas.

In January and February 2018, the Company extended two of its drilling rig contracts for terms of one and two years. The gross contractual obligations for these extended drilling rig contracts are approximately $22.2 million. Additionally, in January and February 2018, the Company entered into four produced water disposal contracts for terms between five and six years, which require delivery of minimum volumes. The gross contractual obligations for these new produced water disposal contracts, which reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water, are approximately $111.6 million. The gross contractual obligations associated with these drilling rig and produced water disposal contracts are not included in the table above as they were entered into subsequent to December 31, 2017.


(3)	Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.

9. Preferred Stock and Common Stock Warrants

On ~~June 28,~~August 20, 2017, the Company ~~entered into a Preferred Stock Purchase Agreement with certain funds managed or sub-advised by GSO Capital Partners LP~~closed on the issuance and ~~its affiliates (the “GSO Funds”) to issue and sell~~sale in a private placement of (i) $250.0 million initial liquidation preference (250,000 shares) of 8.875% redeemable preferred stock, par value $0.01 per share (the “Preferred Stock”) and (ii) warrants for 2,750,000 shares of the Company’s common stock, with a term of ten years and an exercise price of $16.08 per share, exercisable only on a net share settlement basis (the “Warrants”), for a cash purchase price equal to $970.00 per share of Preferred ~~Stock. The Company paid the~~Stock to certain funds managed or sub-advised by GSO ~~Funds $5.0 million as a commitment fee upon signing the Preferred Stock Purchase Agreement.~~Capital Partners LP and its affiliates (the “GSO Funds”). The closing ~~of the private placement~~ occurred ~~on August 10, 2017,~~ contemporaneously with the closing of the ExL Acquisition. The Company used the ~~net~~ proceeds of approximately $236.4 million, net of issuance costs to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. The Company also entered into a registration rights agreement with the GSO Funds at the closing of the private placement, which provided certain registration and other rights for the benefit of the GSO Funds. During the fourth quarter of 2017, the Company filed a registration statement with the SEC to register the resale of

Net proceeds were allocated between the Preferred Stock and the ~~common stock that may be issued in respect~~Warrants based on their relative fair values at the issuance date, with $213.4 million allocated to the Preferred Stock and $23.0 million allocated to the Warrants. The fair value of the Preferred Stock was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation included the per share cash purchase price, redemption premiums, and ~~that underlie~~liquidation preference, all as discussed further below, as well as redemption assumptions provided by the ~~Warrants.~~ Company. The fair value of the Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:



	Issuance Date Fair Value Assumptions
Exercise price	$16.08
Expected term (in years)	10.0
Expected volatility	62.9	%
Risk-free interest rate	2.2	%
Dividend yield	—	%

See “Note ~~3. Acquisitions and Divestitures of Oil and Gas Properties”~~13. Fair Value Measurements” for further ~~details~~discussion of the ~~ExL Acquisition.~~significant inputs used in the Preferred Stock fair value calculation.

The Preferred Stock is presented as temporary equity in the consolidated balance sheets with the issuance date fair value accreted to the initial liquidation preference using the effective interest method. The Warrants are presented in “Additional paid-in capital” in the consolidated balance sheets at their issuance date fair value.

The following table sets forth a reconciliation of changes in the carrying amount of Preferred Stock for the years ended December 31, 2018 and 2017:



	Years Ended December 31,
	2018			2017
	(In thousands)
Preferred Stock, beginning of period		$214,262			$—
Relative fair value at issuance	—			213,400
Redemption of Preferred Stock	(42,897		)	—
Accretion on Preferred Stock	3,057			862
Preferred Stock, end of period		$174,422			$214,262

The Preferred Stock has a liquidation preference of $1,000.00 per share and bears an annual cumulative dividend rate of 8.875%, payable on March 15, June 15, September 15 and December 15 of any given year. The Company may elect to pay all or a portion

of the Preferred Stock dividends in shares of its common stock in decreasing percentages as follows with respect to any preferred stock dividend declared by the Company’s Board of Directors and paid in respect of a quarter ending:



Period	Percentage
~~On or after December 15, 2017 and on or prior to September 15, 2018~~	~~100~~	%
On or after December 15, 2018 and on or prior to September 15, 2019	75	%
On or after December 15, 2019 and on or prior to September 15, 2020	50	%

If the Company fails to satisfy the Preferred Stock dividend on the applicable dividend payment date, then the unpaid dividend will be added to the liquidation preference until paid.

The Preferred Stock outstanding is not mandatorily redeemable, but can be redeemed at the Company’s option and, in certain circumstances, at the option of the holders of the Preferred Stock. On or prior to August 10, 2018, the Company had the right to redeem up to 50,000 shares of Preferred Stock, in cash, at $1,000.00 per share, plus accrued and unpaid dividends in an amount

not to exceed the sum of the cash proceeds of divestitures of oil and gas properties and related assets, the sale or issuance of the Company’s common stock and the sale of any of the Company’s wholly owned subsidiaries. On January 24, 2018, the Company redeemed 50,000 shares of Preferred Stock for $50.5 million with a portion of the proceeds from the divestitures of oil and gas properties. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the divestitures of oil and gas properties.

In addition, at any time on or prior to August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at a redemption premium of 104.4375%, plus accrued and unpaid dividends and the present value on the redemption date of all quarterly dividends that would be payable from the redemption date through August 10, 2020. After August 10, 2020, the Company may redeem all or part of the Preferred Stock in cash at redemption premiums, as presented in the table below, plus accrued but unpaid dividends.



Period	Percentage
After August 10, 2020 but on or prior to August 10, 2021	104.4375	%
After August 10, 2021 but on or prior to August 10, 2022	102.21875	%
After August 10, 2022	100	%

The holders of the Preferred Stock have the option to cause the Company to redeem the Preferred Stock under the following conditions:

Upon the Company’s failure to pay a quarterly dividend within three months of the applicable payment date;

On or after August 10, 2024, if the Preferred ~~Stock~~Shares remain outstanding; or

Upon the occurrence of certain changes of ~~control~~control.

For the first two conditions described above, the Company has the option to settle any such redemption in cash or shares of its common stock and the holders of the Preferred Stock may elect to revoke or reduce the redemption if the Company elects to settle in shares of common stock.

The Preferred Stock are non-voting shares except as required by the Company’s articles of incorporation or bylaws. However, so long as the GSO Funds beneficially own more than 50% of the Preferred Stock, the consent of the holders of the Preferred Stock will be required prior to issuing stock senior to or on parity with the Preferred Stock, incurring indebtedness subject to a leverage ratio, agreeing to certain restrictions on dividends on, or redemption of, the Preferred Stock and declaring or paying dividends on the Company’s common stock in excess of $15.0 million per year subject to a leverage ratio. Additionally, if the Company does not redeem the Preferred Stock before August 10, 2024, in connection with a change of control or failure to pay a quarterly dividend within three months of the applicable payment date, the holders of the Preferred Stock are entitled to additional rights including:

Increasing the dividend rate to 12.0% per annum until August 10, 2024 and thereafter to the greater of 12.0% per annum and the one-month LIBOR plus 10.0%;

~~Causing the election of~~Electing up to two directors to the Company’s Board of Directors; and

Requiring approval by the holders of the Preferred Stock to incur indebtedness subject to a leverage ratio, declaring or paying dividends on the Company’s common stock in excess of $15.0 million per year or issuing equity of the Company’s subsidiaries to third parties.

~~The table below summarizes~~Loss on Redemption of Preferred Stock ~~activity for~~

During the ~~year ended December 31, 2017:~~



	~~December 31, 2017~~
~~For the Year Ended December 31, 2017~~
~~Preferred Stock, beginning~~first quarter of 2018, the Company redeemed 50,000 shares of ~~period~~		$—
~~Relative fair value of Preferred Stock at issuance~~	~~213,400~~
~~Accretion of discount on Preferred Stock~~	~~862~~
~~Preferred Stock, end of period~~		~~$214,262~~

~~Net proceeds were allocated between the~~ Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, for $50.5 million, consisting of the ~~Warrants based~~$50.0 million redemption price and accrued and unpaid dividends of $0.5 million. The Company recognized a $7.1 million loss on ~~their relative fair values at~~ the ~~issuance date, with $213.4 million allocated~~redemption due to the ~~Preferred Stock and $23.0~~excess of the $50.0 million ~~allocated to~~redemption price over the ~~Warrants. The fair~~$42.9 million redemption date carrying value of the Preferred Stock was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation of the Preferred Stock included the per share cash purchase price, redemption premiums, and liquidation preference, all as discussed above, as well as redemption assumptions provided by the Company. The fair value of the Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:



	~~Issuance Date Fair Value Assumptions~~
~~Exercise price~~		~~$16.08~~
~~Expected term (in years)~~	~~10.0~~
~~Expected volatility~~	~~62.9~~		%
~~Risk-free interest rate~~	~~2.2~~		%
~~Dividend yield~~	—		%

~~See “Note 12. Fair Value Measurements” for further discussion of the significant inputs used in the Preferred Stock and Warrants fair value calculations.~~

~~Preferred Stock Dividends and Accretion~~

For the year ended December 31, 2017, the Company declared and paid an aggregate of $7.8 million of dividends, in cash, to the holders of record of the Preferred Stock on September 1, 2017 and December 1, 2017.

~~For the year ended December 31, 2017, the Company recorded accretion of the Preferred Stock of $0.9 million, which is presented with the dividends in the consolidated statements of operations.~~Stock.

10. Shareholders’ Equity ~~and Stock Based Compensation~~

Increase in Authorized Common Shares

At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved an amendment to the Company’s Amended and Restated Articles of Incorporation to increase the number of authorized shares of common stock from 90,000,000 to 180,000,000.

~~Sale~~Sales of Common Stock

On August 17, 2018, the Company completed a public offering of 9.5 million shares of its common stock at a price per share of $22.55. The Company used the proceeds of $213.7 million, net of offering costs, to fund the Devon Acquisition and for general corporate purposes. Pending the closing of the Devon Acquisition, the Company used the net proceeds to temporarily repay a portion of the borrowings outstanding under the revolving credit facility.

On July 3, 2017, the Company completed a public offering of 15.6 million shares of its common stock at a price per share of $14.28. The Company used the ~~net~~ proceeds of $222.4 million, net of offering costs, to fund a portion of the ~~purchase price of the~~ ExL Acquisition and for general corporate purposes. ~~See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.~~

On October 28, 2016, the Company completed a public offering of 6.0 million shares of its common stock at a price per share of $37.32. The Company used the ~~net~~ proceeds of $223.7 million, net of offering costs, to fund the Sanchez Acquisition and repay borrowings under the revolving credit facility. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.

~~On October 21, 2015, the Company completed a public offering~~See “Note 3. Acquisitions and Divestitures of 6.3 million shares of its common stock at a price per share of $37.80. The Company used the net proceeds of $238.8 million, net of offering costs, to repay borrowings under the Company’s revolving credit facilityOil and Gas Properties” for ~~general corporate purposes.~~

On March 20, 2015, the Company completed a public offering of 5.2 million shares of its common stock at a price per share of $44.75. The Company used the net proceeds of $231.3 million, net of offering costs, to repay a portionfurther details of the ~~borrowings under the Company’s revolving credit facility and for general corporate purposes.~~acquisitions discussed above.

11. Stock-Based Compensation

~~At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved~~Equity-based incentive awards are granted under the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”)~~, which~~ and the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”). The 2017 Incentive Plan replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”)~~. From~~ and, from the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive ~~Plan, however,~~Plan. However, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. Under the 2017 Incentive Plan, the Compensation Committee of the Board of Directors (the “Committee”) may grant restricted stock awards and units, stock appreciation rights that can be settled in cash or shares of common stock, performance shares, and stock options to employees, independent contractors, and non-employee directors. Under the Cash SAR Plan, the Committee may grant stock appreciation rights that may only be settled in cash to employees and independent contractors.

The 2017 Incentive Plan provides that up to 2,675,000 shares of the Company’s common stock, plus the shares remaining available for awards under the Prior Incentive Plan ~~may be issued.~~

Asat the effective date of ~~December 31, 2017, there were 1,750,908 common shares remaining available for grant under~~ the 2017 Incentive ~~Plan.~~Plan, may be granted (the “Maximum Share Limit”). Each restricted stock award ~~restricted stock~~and unit orand performance share granted under the 2017 Incentive Plan counts as 1.35 shares ~~while a~~against the Maximum Share Limit. Each stock option ~~or stock-settled~~and stock appreciation right to be settled in shares of common stock granted under the 2017 Incentive Plan counts as 1.00 share against the ~~number~~Maximum Share Limit. Cash SARs granted under the 2017 Incentive Plan and the Cash SAR Plan do not count against the Maximum Share Limit. There have been no grants of stock appreciation rights to be settled in shares of common stock and there are no outstanding stock options. As of December 31, 2018, there were 258,785 shares of common stock available for grant under the 2017 Incentive Plan.

Restricted Stock Awards and ~~Units.~~ Restricted stock awards can be granted to employees and independent contractors and restricted stock units can be granted to employees, independent contractors, and non-employee directors. As of December 31, 2017, unrecognized compensation costs related to unvested restricted stock awards and units was $21.3 million and will be recognized over a weighted average period of 1.9 years.Units

The table below summarizes restricted stock award and unit activity for the years ended December 31, 2018, 2017 ~~2016~~ and ~~2015:~~2016:


	Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value		Restricted Stock Awards and Units		Weighted Average Grant Date Fair Value
For the Year Ended December 31, 2015
Unvested restricted stock awards and units, beginning of period	1,335,682			$34.55
Granted	401,421			$51.45
Vested	(671,417	)		$32.96
Forfeited	(23,689	)		$43.36
Unvested restricted stock awards and units, end of period	1,041,997			$44.22
For the Year Ended December 31, 2016
Unvested restricted stock awards and units, beginning of period	1,041,997			$44.22	1,041,997			$44.22
Granted	887,254			$27.80	887,254			$27.80
Vested	(811,136	)		$36.32	(811,136	)		$36.32
Forfeited	(6,405	)		$34.46	(6,405	)		$34.46
Unvested restricted stock awards and units, end of period	1,111,710			$36.93	1,111,710			$36.93
For the Year Ended December 31, 2017
Unvested restricted stock awards and units, beginning of period	1,111,710			$36.93	1,111,710			$36.93
Granted	1,020,465			$25.63	1,020,465			$25.63
Vested	(635,965	)		$39.62	(635,965	)		$39.62
Forfeited	(13,555	)		$29.11	(13,555	)		$29.11
Unvested restricted stock awards and units, end of period	1,482,655			$28.07	1,482,655			$28.07
For the Year Ended December 31, 2018
Unvested restricted stock awards and units, beginning of period					1,482,655			$28.07
Granted					1,458,421			$15.49
Vested					(621,399	)		$31.48
Forfeited					(53,010	)		$17.72
Unvested restricted stock awards and units, end of period					2,266,667			$19.28

~~11.~~12. Derivative Instruments

Commodity Derivative Instruments

The Company uses commodity derivative instruments to ~~reduce its exposure to~~mitigate the effects of commodity price volatility for a portion of its forecasted ~~crude oil, NGL, and natural gas~~sales of production and ~~thereby~~ achieve a more predictable level of cash ~~flows to support~~flow. Since the Company derives a significant portion of its revenues from sales of crude oil, crude oil price volatility represents the Company’s ~~drilling, completion, and infrastructure capital expenditure program.~~most significant commodity price risk. While the use of commodity derivative instruments limits or partially reduces the downside risk of adverse commodity price movements, such use also limits the upside from favorable commodity price movements. The Company does not enter into commodity derivative instruments for speculative ~~or trading~~ purposes.

The Company’s commodity derivative instruments, which settle on a monthly basis over the term of the contract for contracted volumes, consist of ~~fixed~~over-the-counter price ~~swaps, basis~~ swaps, three-way collars, ~~and purchased and~~ sold call options and basis swaps, each of which ~~are~~is described below.

~~Fixed~~ Price ~~Swaps:~~ swaps~~The Company receives~~ are settled based on differences between a fixed price and the settlement price of a referenced index. If the settlement price of the referenced index is below the fixed price, the Company receives the difference from the counterparty. If the referenced settlement price is above the fixed price, the Company pays ~~a variable market price~~the difference to the ~~counterparties over specified periods for contracted volumes.~~counterparty.

~~Basis Swaps:~~ Three-way collarsThe Company receives a variable NYMEX settlement price, plus or minus a fixed differential price, and pays a variable published index price to the counterparties over specified periods for contracted volumes.

~~Three-Way Collars:~~ ~~A three-way collar is a combination~~ consist of ~~options including~~ a purchased put option ~~(fixed floor~~(floor price), a sold call option ~~(fixed ceiling~~(ceiling price) and a sold put option ~~(fixed sub-floor~~(sub-floor price). These contracts offer a higher fixed ceiling price relative to a costless collar but limit the Company’s protection from decreases in commodity prices below the fixed floor price. At settlement, if the market price is and are settled based on differences between the ~~fixed~~floor or ceiling prices and the settlement price of a referenced index or the difference between the floor price and ~~the fixed~~ sub-floor ~~price or is above the fixed ceiling price, the Company receives the fixed floor price or pays the market price, respectively.~~price. If the ~~market~~settlement price of the referenced index is below the ~~fixed~~ sub-floor price, the Company receives the ~~market~~difference between the floor price ~~plus~~and sub-floor price from the counterparty. If the settlement price of the referenced index is between the floor price and sub-floor price, the Company receives the difference between the ~~fixed~~ floor price and the ~~fixed sub-floor price.~~settlement price of the referenced index from the counterparty. If the ~~market~~settlement price of the referenced index is between the ~~fixed~~ floor price and ~~fixed~~ ceiling price, no payments are due to or from either party. If the settlement price of the referenced index is above the ceiling price, the Company pays the difference to the counterparty.

Sold call options are settled based on differences between the ceiling price and the settlement price of a referenced index. If the settlement price of the referenced index is above the ceiling price, the Company pays the difference to the counterparty. If the settlement price of the referenced index is below the ceiling price, no payments are due to or from either party. Premiums

from the sale of call options have been used to enhance the fixed price of certain contemporaneously executed price swaps. Purchased call options executed contemporaneously with sold call options in order to increase the ceiling price of existing sold call options have been presented on a net basis in the table below.

Basis swaps are settled based on differences between a fixed price differential and the differential between the settlement prices of two referenced indexes. If the differential between the settlement prices of the two referenced indexes is greater than the fixed price differential, the Company receives the difference from the counterparty. If the differential between the settlement prices of the two referenced indexes is less than the fixed price differential, the Company pays the difference to the counterparty.

The referenced index of the Company’s price swaps, three-way collars and sold call options is U.S. New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) for crude oil and NYMEX Henry Hub for natural gas, as applicable. The prices received by the Company for the sale of its production generally vary from these referenced index prices due to adjustments for delivery location (basis) and other factors. The referenced indexes of the Company’s basis swaps, which are used to mitigate location price risk for a portion of its production, are Argus WTI Cushing (“WTI Cushing”) and the applicable index price of the Company’s crude oil sales contracts is Argus WTI Midland (“WTI Midland”) for its Delaware Basin crude oil production and Argus Light Louisiana Sweet (“LLS”) for its Eagle Ford crude oil production.

The Company has incurred premiums on certain of ~~these contracts~~its commodity derivative instruments in order to obtain a higher floor price and/or ~~ceiling price.~~

~~Sold Call Options~~: These contracts give the counterparties the right, but not the obligation, to buy contracted volumes from the Company over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the counterparties to pay premiums to the Company that represent the fair value of the call option as of the date of purchase.

~~Purchased Call Options~~: These contracts give the Company the right, but not the obligation, to buy contracted volumes from the counterparties over specified periods and prices in the future. At settlement, if the market price exceeds the fixed price of the call option, the counterparties pay the Company the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. These contracts require the Company to pay premiums to the counterparties that represent the fair value of the call option as of the date of purchase.

All of the Company’s purchased call options were executed contemporaneously with sales of call options to increase the fixed price on a portion of the existing sold call options and therefore are presented on a net basis in the “Net Sold Call Options” table below.

~~Premiums~~: In order to increase the fixed price on a portion of the Company’s existing sold call options, as mentioned above, the Company incurred premiums on its purchased call options. Additionally, the Company has incurred premiums on certain of its three-way collars in order to obtain a higher ~~floor price and/or~~ ceiling price. ~~The payment~~Payment of these premiums ~~associated with the Company’s purchased call options and certain of the three-way collars~~ are deferred until the applicable contracts settle on a monthly ~~basis. When~~basis over the term of the contract or, in some cases, during the final 12 months of the contract and are referred to as deferred premium obligations.

As of December 31, 2018, the Company ~~has entered into three-way collars which span multiple years,~~had the ~~Company has elected to defer payment of certain of the premiums until the final year’s contracts settle on a monthly basis.~~

~~The~~ following ~~tables set forth a summary of the Company’s~~ outstanding commodity derivative ~~positions~~instruments at weighted average contract ~~prices as of December 31, 2017:~~

~~Crude Oil Fixed Price Swaps~~volumes and prices:

Period Volumes (Bbls/d) NYMEX Price ($/Bbl)
FY 2018 6,000

$49.55

~~Crude Oil Basis Swaps~~

Period Volumes (Bbls/d) LLS-NYMEX Price Differential ($/Bbl)
FY 2018 6,000

$2.91

Period Volumes (Bbls/d) Midland-NYMEX Price Differential ($/Bbl)
FY 2018 6,000

($0.10 )



Commodity	Period	Type of Contract	Index	Volumes (Bbls per day)	Sub-Floor Price ($ per Bbl)		Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)		Fixed Price Differential ($ per Bbl)
Crude oil	1Q19	Three-Way Collars	NYMEX WTI	27,000		$41.67		$50.96		$74.23	—
Crude oil	1Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—			$5.16
Crude oil	1Q19	Basis Swaps	WTI Midland-WTI Cushing	5,500	—		—		—			($5.24	)
Crude oil	1Q19	Sold Call Options	NYMEX WTI	3,875	—		—			$81.07	—

Crude oil	2Q19	Three-Way Collars	NYMEX WTI	27,000		$41.67		$50.96		$74.23	—
Crude oil	2Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—			$5.16
Crude oil	2Q19	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—			($5.38	)
Crude oil	2Q19	Sold Call Options	NYMEX WTI	3,875	—		—			$81.07	—

Crude oil	3Q19	Three-Way Collars	NYMEX WTI	27,000		$41.67		$50.96		$74.23	—
Crude oil	3Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—			$5.16
Crude oil	3Q19	Basis Swaps	WTI Midland-WTI Cushing	7,000	—		—		—			($5.56	)
Crude oil	3Q19	Sold Call Options	NYMEX WTI	3,875	—		—			$81.07	—

Crude oil	4Q19	Three-Way Collars	NYMEX WTI	27,000		$41.67		$50.96		$74.23	—
Crude oil	4Q19	Basis Swaps	LLS-WTI Cushing	6,000	—		—		—			$5.16
Crude oil	4Q19	Basis Swaps	WTI Midland-WTI Cushing	11,000	—		—		—			($3.84	)
Crude oil	4Q19	Sold Call Options	NYMEX WTI	3,875	—		—			$81.07	—

Crude oil	2020	Basis Swaps	WTI Midland-WTI Cushing	13,000	—		—		—			($1.27	)
Crude oil	2020	Sold Call Options	NYMEX WTI	4,575	—		—			$75.98	—

Crude oil	2021	Basis Swaps	WTI Midland-WTI Cushing	6,000	—		—		—			$0.03

~~Crude Oil Three-Way Collars~~

NYMEX Prices
Period
Volumes
(Bbls/d)

Sub-Floor Price
($/Bbl)

Floor Price
($/Bbl)

Ceiling Price
($/Bbl)
FY 2018 24,000

$39.38

$49.06

$60.14
FY 2019 12,000

$40.00

$48.40

$60.29

~~Crude Oil Net Sold Call Options~~

Period Volumes (Bbls/d) NYMEX Ceiling Price ($/Bbl)
FY 2018 3,388

$71.33
FY 2019 3,875

$73.66
FY 2020 4,575

$75.98

~~NGL Fixed Price Swaps~~

OPIS Purity Ethane
Mont Belvieu
Non-TET

OPIS Propane
Mont Belvieu
Non-TET

OPIS Normal Butane
Mont Belvieu
Non-TET

OPIS Isobutane
Mont Belvieu
Non-TET

OPIS Natural Gasoline
Mont Belvieu
Non-TET
Period
Volumes
(Bbls/d)

Price
($/Bbl)

Volumes
(Bbls/d)

Price
($/Bbl)

Volumes
(Bbls/d)

Price
($/Bbl)

Volumes
(Bbls/d)

Price
($/Bbl)

Volumes
(Bbls/d)

Price
($/Bbl)
FY 2018 2,200

$12.01
1,500

$34.23
200

$38.85
600

$38.98
600

$55.23

~~Natural Gas Sold Call Options~~

Period Volumes (MMBtu/d) NYMEX Ceiling Price ($/MMBtu)
FY 2018 33,000

$3.25
FY 2019 33,000

$3.25
FY 2020 33,000

$3.50



Commodity	Period	Type of Contract	Index	Volumes (MMBtu per day)	Sub-Floor Price ($ per MMBtu)	Floor Price ($ per MMBtu)	Ceiling Price ($ per MMBtu)		Fixed Price Differential ($ per MMBtu)
Natural gas	1Q19	Sold Call options	NYMEX Henry Hub	33,000	—	—		$3.25	—

Natural gas	2Q19	Sold Call options	NYMEX Henry Hub	33,000	—	—		$3.25	—

Natural gas	3Q19	Sold Call options	NYMEX Henry Hub	33,000	—	—		$3.25	—

Natural gas	4Q19	Sold Call options	NYMEX Henry Hub	33,000	—	—		$3.25	—

Natural gas	2020	Sold Call options	NYMEX Henry Hub	33,000	—	—		$3.50	—

The Company typically has numerous ~~hedge positions~~commodity derivative instruments outstanding with a counterparty that ~~span several~~were executed at various dates, for various contract types, commodities and time periods ~~and~~ often ~~result~~resulting in both ~~fair value~~commodity derivative asset and liability positions ~~held~~ with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty, along with any deferred premium obligations, to a single asset or liability pursuant to ~~ISDA master agreements,~~ISDAs, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.

Counterparties to the Company’s commodity derivative instruments who are ~~also lenders under the Company’s credit agreement~~a Lender Counterparty allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with ~~its counterparties~~the Lender Counterparty with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties to the Company’s commodity derivative instruments who are ~~not lenders under the Company’s credit agreement~~a Non-Lender Counterparty can require commodity derivative ~~contracts~~instruments to be novated to a ~~lender~~Lender Counterparty if the Company’s net liability position exceeds the Company’s unsecured credit limit with ~~that counterparty~~the Non-Lender Counterparty and therefore do not require the posting of cash collateral.

Because ~~the counterparties have~~each Lender Counterparty has an investment grade credit ~~ratings, or~~rating and the Company has obtained ~~guarantees~~a guaranty from ~~the applicable counterparty’s~~each Non-Lender Counterparty’s parent company which has an investment grade ~~parent company,~~credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with seventeen counterparties ~~and~~to minimize its ~~counterparty’s parent company, as applicable.~~credit exposure to any individual counterparty.

Contingent Consideration Arrangements

~~As part~~The purchase and sale agreements of the ExL Acquisition ~~the Company agreed to the Contingent ExL Consideration that will require payment of $50.0 million per year for each~~and divestitures of the years of 2018 through 2021, with a cap of $125.0 million, if the EIA WTI average price is greater than $50.00 per barrel for the respective year. As of December 31, 2017, the estimated fair value of the Contingent ExL Consideration was $85.6 million and was classified as non-current “Derivative liabilities” in the consolidated balance sheets.

~~As part of the divestiture of the~~ Company’s Utica assets, the Company agreed to the Contingent Utica Consideration in which the Company will receive $5.0 million per year for each of the years of 2018 through 2020, if the EIA WTI average price is greater than $50.00, $53.00, and $56.00 for the years of 2018, 2019, and 2020, respectively. The Company recorded the Contingent Utica Consideration at its divestiture date fair value of $6.1 million in the consolidated financial statements. As of December 31, 2017, the estimated fair value of the Contingent Utica Consideration was $8.0 million and was classified as non-current “Other assets” in the consolidated balance sheets.

As part of the divestiture of the Company’s Marcellus assets, the Company agreed to the Contingent Marcellus Consideration in which the Company will receive $3.0 million per year for each of the years of 2018 through 2020, with a cap of $7.5 million, if the CME HH average price is greater than $3.13, $3.18, and $3.30 for the years of 2018, 2019, and 2020, respectively. The Company recorded the Contingent Marcellus Consideration at its divestiture date fair value of $2.7 million in the consolidated financial statements. As of December 31, 2017, the estimated fair value of the Contingent Marcellus Consideration was $2.2 million and was classified as non-current “Other assets” in the consolidated balance sheets.

~~The following table summarizes the combined contingent consideration recorded in the consolidated financial statements:~~

Consolidated
Balance Sheets

Consolidated
Statements of Operations
December 31, 2017 Year Ended December 31, 2017

Other Assets -
Non-Current

Derivative Liabilities -
Non-Current
(Gain) Loss on Derivatives, Net
(In thousands)
Contingent ExL Consideration
$—

($85,625 )
$33,325
Contingent Utica Consideration 7,985
—
(1,840 )
Contingent Marcellus Consideration 2,205
—
455
Contingent consideration
$10,190

($85,625 )
$31,940

~~Subsequent to December 31, 2017, the Company closed on the sale of substantially all of its~~ assets in the Niobrara, ~~Formation. As part of the divestiture,~~Marcellus and Utica, included contingent consideration arrangements that require the Company ~~agreed~~ to pay or entitle the ~~Contingent Niobrara Consideration.~~Company to receive specified amounts if commodity prices exceed specified thresholds, which are summarized in the table below. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further ~~details.~~discussion.



Contingent Consideration Arrangements	Years	Threshold ⁽¹⁾		Contingent Receipt (Payment) - Annual			Contingent Receipt (Payment) - Aggregate Limit
				(In thousands)
Contingent ExL Consideration	2018		$50.00		($50,000	)
	2019	50.00		(50,000		)
	2020	50.00		(50,000		)
	2021	50.00		(50,000		)		($125,000	)

Contingent Niobrara Consideration	2018		$55.00		$5,000
	2019	55.00		5,000
	2020	60.00		5,000			—

Contingent Marcellus Consideration	2018		$3.13		$3,000
	2019	3.18		3,000
	2020	3.30		3,000				$7,500

Contingent Utica Consideration	2018		$50.00		$5,000
	2019	53.00		5,000
	2020	56.00		5,000			—

(1)

The price used to determine whether the specified threshold for each year has been met for the Contingent ExL Consideration, Contingent Niobrara Consideration and Contingent Utica Consideration is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration. The price used to determine whether the specified threshold for each year has been met for the Contingent Marcellus Consideration is the average monthly settlement price per MMBtu of Henry Hub natural gas for the next calendar month, as determined on the last business day preceding each calendar month as measured by the CME Group Inc.

Derivative Assets and Liabilities

~~All derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value.~~ The ~~deferred premium obligations associated with the Company’s commodity derivative instruments are recorded in the period in which they are incurred and are netted with the commodity~~ derivative instrument asset and liability fair ~~value asset or liability pursuant to the netting arrangements described above. The combined derivative instrument fair value assets and liabilities, including deferred premium obligations,~~values recorded in the consolidated balance sheets as of December 31, ~~2017~~2018 and ~~2016~~December 31, 2017 are summarized below:


	December 31, 2017									December 31, 2018
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets			Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)									(In thousands)
Commodity derivative instruments		$4,869			($4,869	)		$—			$50,406			($20,502	)		$29,904
Deferred premium obligations	—			—			—
Other current assets		$4,869			($4,869	)		$—
Contingent Niobrara Consideration										5,000			—			5,000
Contingent Utica Consideration										5,000			—			5,000
Derivative assets											$60,406			($20,502	)		$39,904
Commodity derivative instruments	9,505			(9,505		)	—			6,083			(4,236		)	1,847
Deferred premium obligations	—			—			—
Contingent consideration	10,190			—			10,190
Other assets-non current		$19,695			($9,505	)		$10,190
Contingent Niobrara Consideration										2,035			—			2,035
Contingent Marcellus Consideration										1,369			—			1,369
Contingent Utica Consideration										2,501			—			2,501
Other long-term assets											$11,988			($4,236	)		$7,752

Commodity derivative instruments		($52,671	)		$4,869			($47,802	)		($15,345	)		$10,140			($5,205	)
Deferred premium obligations	(9,319		)	—			(9,319		)	(10,362		)	10,362			—
Contingent ExL Consideration										(50,000		)	—			(50,000		)
Derivative liabilities-current		($61,990	)		$4,869			($57,121	)		($75,707	)		$20,502			($55,205	)
Commodity derivative instruments	(24,609		)	9,505			(15,104		)	(10,751		)	518			(10,233		)
Deferred premium obligations	(11,603		)	—			(11,603		)	(3,718		)	3,718			—
Contingent consideration	(85,625		)	—			(85,625		)
Contingent ExL Consideration										(30,584		)	—			(30,584		)
Derivative liabilities-non current		($121,837	)		$9,505			($112,332	)		($45,053	)		$4,236			($40,817	)


	December 31, 2016									December 31, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets			Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)									(In thousands)
Commodity derivative instruments		$7,990			($6,753	)		$1,237			$4,869			($4,869	)		$—
Deferred premium obligations	—			—			—
Other current assets		$7,990			($6,753	)		$1,237
Derivative assets											$4,869			($4,869	)		$—
Commodity derivative instruments	3,882			(3,882		)	—			9,505			(9,505		)	—
Deferred premium obligations	—			—			—
Contingent consideration	—			—			—
Other assets-non current		$3,882			($3,882	)		$—
Contingent Marcellus Consideration										2,205			—			2,205
Contingent Utica Consideration										7,985			—			7,985
Other long-term assets											$19,695			($9,505	)		$10,190

Commodity derivative instruments		($27,346	)		$6,753			($20,593	)		($52,671	)		($4,450	)		($57,121	)
Deferred premium obligations	(2,008		)	—			(2,008		)	(9,319		)	9,319			—
Derivative liabilities-current		($29,354	)		$6,753			($22,601	)		($61,990	)		$4,869			($57,121	)
Commodity derivative instruments	(28,841		)	3,882			(24,959		)	(24,609		)	(2,098		)	(26,707		)
Deferred premium obligations	(2,569		)	—			(2,569		)	(11,603		)	11,603			—
Contingent consideration	—			—			—
Contingent ExL Consideration										(85,625		)	—			(85,625		)
Derivative liabilities-non current		($31,410	)		$3,882			($27,528	)		($121,837	)		$9,505			($112,332	)



Texas		76-0415919
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

500 Dallas Street, Suite 2300 Houston, Texas		77002
(Principal executive offices)		(Zip Code)



Common Stock, $0.01 par value		NASDAQ Global Select Market
(Title of class)		(Name of exchange on which registered)



Large accelerated filer	þ		Accelerated filer	¨

Non-accelerated filer	¨	~~(Do not check if a smaller reporting company)~~	Smaller reporting company	¨

			Emerging growth company	¨




Forward-Looking Statements	3
PART I
Item 1. Business	5
Item 1A. Risk Factors	2625
Item 1B. Unresolved Staff Comments	42
Item 2. Properties	42
Item 3. Legal Proceedings	42
Item 4. Mine Safety Disclosures	4342
PART II
Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	4442
Item 6. Selected Financial Data	4644
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	4745
Item 7A. Qualitative and Quantitative Disclosures about Market Risk	6360
Item 8. Financial Statements and Supplementary Data	6462
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosures	6462
Item 9A. Controls and Procedures	6462
Item 9B. Other Information	6563
PART III
Item 10. Directors, Executive Officers and Corporate Governance	6563
Item 11. Executive Compensation	6563
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	6563
Item 13. Certain Relationships and Related Transactions, and Director Independence	6563
Item 14. Principal Accounting Fees and Services	6564
PART IV
Item 15. Exhibits and Financial Statement Schedules	6564


	Proved Reserves		Proved Reserves
	December 31, 2017	December 31, 2016	December 31, 2018	December 31, 2017
Region	(MMBoe)		(MMBoe)
Eagle Ford ⁽¹⁾	167.0	162.3	149.1	167.0
Delaware Basin	90.9	11.7	180.3	90.9
Niobrara ⁽²⁾	3.8	2.7
Marcellus	—	21.8
Utica and other	—	1.7
Other ⁽²⁾			—	3.8
Total	261.7	200.2	329.4	261.7


(1)	Included in the December 31, 2017 proved reserves are 10.9 MMBoe associated with a portion of our assets in the Eagle Ford that were divested in January 2018.


(2)	In January 2018, we closed on the divestiture of substantially all of our Niobrara assets.


	Capital Expenditures					Capital Expenditures
	2018 Plan ⁽¹⁾		2017 Actual			2019 Plan ⁽¹⁾		2018 Actual
	(In millions)					(In millions)
Drilling, completion, and infrastructure
DC&I
Eagle Ford		$439.0		$464.0			$325.0		$522.9
Delaware Basin	336.0		160.2			225.0		321.2
All other regions	—		27.8
Total drilling, completion, and infrastructure	775.0		652.0		⁽²⁾
Other						—		0.3
Total DC&I						550.0		844.4
Leasehold and seismic ⁽³⁾⁽²⁾	—		65.4			—		22.4
Total ⁽⁴⁾⁽³⁾		$775.0		$717.4			$550.0		$866.8


(1)	Represents the midpoint of our ~~2018 drilling, completion, and infrastructure~~2019 DC&I capital expenditure plan of ~~$750.0~~$525.0 million to ~~$800.0~~$575.0 million.


(2)	Includes amounts related to the divested assets in the Utica, Marcellus, Niobrara and Eagle Ford of approximately $30.2 million, which consists of drilling and completion capital expenditures incurred between the effective date and close date of the divestitures.


~~(3)~~	~~In the second quarter of 2017, Carrizo disclosed that it was no longer providing~~We do not provide guidance for leasehold and seismic capital expenditures given the ~~limited visibility and highly~~ discretionary nature of this spending.


~~(4)~~(3)	Our capital expenditure plan and the actual capital expenditures exclude acquisitions of oil and gas properties, capitalized general and administrative expense, interest expense and asset retirement costs.



	Eagle Ford			Delaware Basin		Niobrara ⁽¹⁾		Other		Total
Proved reserves by product
Crude oil (MMBbls)	124.2			40.4		2.8		—		167.4
NGLs (MMBbls)	21.7			20.4		0.5		—		42.6
Natural gas (Bcf)	126.7			180.5		3.3		—		310.5
Total proved reserves (MMBoe)	167.0		⁽²⁾	90.9		3.8		—		261.7

Proved reserves by classification (MMBoe)
Proved developed	77.6			27.6		3.8		—		109.0
Proved undeveloped	89.4			63.3		—		—		152.7
Total proved reserves	167.0		⁽²⁾	90.9		3.8		—		261.7

Percent of total reserves	64%			35%		1%		—		100%

2017 production (MMBoe)	13.8		⁽³⁾	2.5		0.9		2.4		19.6

Percent of total production	70%			13%		5%		12%		100%

	Eagle Ford ⁽⁴⁾			Delaware Basin		Niobrara ⁽¹⁾		Other		Total
Operated Well Data	Gross	Net		Gross	Net	Gross	Net	Gross	Net	Gross	Net
Year Ended December 31, 2017
Drilled	91	77.5		14	11.0	—	—	—	—	105	88.5
Completed	88	80.9		14	11.6	—	—	—	—	102	92.5

December 31, 2017
Drilled but uncompleted	37	31.3		6	4.6	—	—	—	—	43	35.9
Producing	538	477.9		34	28.1	130	57.7	—	—	702	563.7


~~(1)~~	~~In January 2018, we closed on the divestiture of substantially all of our Niobrara assets.~~


~~(2)~~	~~Included in the December 31, 2017 proved reserves are 10.9 MMBoe associated with a portion of our assets in the Eagle Ford that were divested in January 2018.~~



	Crude Oil (MBbls)	NGLs (MBbls)	Natural Gas (MMcf)	Total (MBoe)	PV-10 (In millions)
Proved developed	69,632	17,447	131,355	108,972		$1,621.0
Proved undeveloped	97,742	25,151	179,115	152,745		$1,017.4
Total Proved	167,374	42,598	310,470	261,717		$2,638.4



	As of December 31,
	2018			2017			2016
Proved developed reserves
Crude oil (MBbls)	75,267			69,632			51,062
NGLs (MBbls)	25,809			17,447			9,387
Natural Gas (MMcf)	178,941			131,355			187,054
Total proved developed reserves (MBoe)	130,899			108,972			91,625

Proved undeveloped reserves
Crude oil (MBbls)	104,469			97,742			77,256
NGLs (MBbls)	43,314			25,151			14,550
Natural Gas (MMcf)	304,120			179,115			100,391
Total proved undeveloped reserves (MBoe)	198,470			152,745			108,538

Total proved reserves
Crude oil (MBbls)	179,736			167,374			128,318
NGLs (MBbls)	69,123			42,598			23,937
Natural Gas (MMcf)	483,061			310,470			287,445
Total proved reserves (MBoe)	329,369			261,717			200,163
Proved developed reserves %	40		%	42		%	46		%
Proved undeveloped reserves %	60		%	58		%	54		%

Reserve data (In millions):
Standardized measure of discounted future net cash flows (GAAP)		$3,635.6			$2,465.1			$1,303.4
PV-10 (Non-GAAP):
Proved developed PV-10		$2,383.9			$1,621.0			$854.3
Proved undeveloped PV-10	1,707.5			1,017.4			449.1
Total PV-10 (Non-GAAP)		$4,091.4			$2,638.4			$1,303.4



	Crude Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total (MBoe)
PUDs as of December 31, 2016	77,256		14,550		100,391		108,538
Extensions and discoveries	45,995		12,862		92,546		74,281
Purchases of reserves in place	11,071		3,204		34,915		20,094
Divestitures of reserves in place	—		—		(43,782	)	(7,297	)
Removed due to changes in development plan	(10,670	)	(1,851	)	(10,684	)	(14,302	)
Revisions of previous estimates	(5,655	)	490		30,191		(133	)
Converted to proved developed reserves	(20,255	)	(4,104	)	(24,462	)	(28,436	)
PUDs as of December 31, 2017	97,742		25,151		179,115		152,745



	Crude Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved reserves as of December 31, 2017	167,374		42,598		310,470		261,717
Extensions and discoveries	65,352		30,195		212,758		131,007
Revisions of previous estimates	(31,287	)	1,936		(6,006	)	(30,352	)
Purchases of reserves in place	2,205		967		7,953		4,498
Sales of reserves in place	(9,676	)	(2,872	)	(17,475	)	(15,461	)
Production	(14,232	)	(3,701	)	(24,639	)	(22,040	)
Proved reserves as of December 31, 2018	179,736		69,123		483,061		329,369


~~(3)~~	~~Included in 2017 production is 1.3 MMBoe associated with a portion of our assets in the Eagle Ford that were divested in January 2018.~~


~~(4)~~	Included in the well counts above are 5 gross (3.8 net) drilled wells, 5 gross (3.8 net) completed wells, and 96 gross (77.4 net) producing wells associated with a portion of our assets in the Eagle Ford that were divested in January 2018.


~~(2)~~	~~Includes lease operating expenses but excludes production taxes and ad valorem taxes.~~


(1)	Includes 37 gross (6.3 net) productive exploratory wells which were part of the divestitures of substantially all of our assets in the Utica, Marcellus, and Niobrara, as well as a portion of our assets in the Eagle Ford.


(2)	Includes 5 gross (3.8 net) productive development wells which were part of the divestiture of a portion of our assets in the Eagle Ford.



	Company Operated		Non-Operated		Total
	Gross	Net	Gross	Net	Gross	Net
Crude oil ⁽¹⁾	692	555.7	326	28.0	1,018	583.7
Natural gas ⁽²⁾	10	8.0	17	0.6	27	8.6
Total	702	563.7	343	28.6	1,045	592.3


(1)	~~Includes 217 gross (127.9 net) and 296 gross (24.7 net) operated and~~All wells included in Other were non-operated ~~wells, respectively, which were part of the divestitures of substantially all of our assets in the Niobrara as well as a portion of our assets in the Eagle Ford.~~


~~(2)~~	~~Includes 9 gross (7.2 net) operated productive natural gas wells which were part of the divestiture of a portion of our assets in the Eagle Ford.~~wells.


	Developed Acreage		Undeveloped Acreage		Total Acreage ⁽¹⁾		Percent of Net Undeveloped Acreage Expiring									Developed Acreage		Undeveloped Acreage		Total Acreage		Net Undeveloped Acreage Expiring
	Gross	Net	Gross	Net	Gross	Net	2018			2019			2020			Gross	Net	Gross	Net	Gross	Net	2019		2020		2021
Eagle Ford	102,387	84,806	24,736	18,310	127,123	103,116	30	%	⁽²⁾	18	%	⁽³⁾	9	%	⁽³⁾	76,644	63,970	15,126	12,492	91,770	76,462	3,228	⁽¹⁾	1,499	⁽¹⁾	—
Delaware Basin	24,725	16,789	43,441	25,328	68,166	42,117	23	%	⁽⁴⁾	23	%	⁽³⁾	44	%	⁽³⁾	39,533	28,076	30,802	17,928	70,335	46,004	1,760	⁽²⁾	11,563	⁽²⁾	348	⁽²⁾
Niobrara ⁽⁵⁾	40,435	14,603	54,798	16,027	95,233	30,630	8	%		14	%		12	%
Other ⁽⁶⁾	1,174	437	60,980	45,421	62,154	45,858	7	%		9	%		—	%
Other																2,467	404	72,847	42,900	75,314	43,304	2,920	⁽³⁾	—		1,234	⁽³⁾
Total	168,721	116,635	183,955	105,086	352,676	221,721	15	%		15	%		14	%		118,644	92,450	118,775	73,320	237,419	165,770	7,908		13,062		1,582


(3)	~~Proved undeveloped reserves associated with the net undeveloped acres scheduled to expire in 2019 and 2020 are scheduled to be developed prior to the acreage expiration.~~


~~(4)~~	Of the approximate 5,800 net undeveloped acres scheduled to expire in 2018 in the Delaware Basin, approximately 3,600 net undeveloped acres will be held due to development activity or extended by lease extension payments.


~~(5)~~	~~In January 2018, we closed on the divestiture of substantially all of our Niobrara assets.~~



	High		Low
2017
First Quarter		$39.48		$26.08
Second Quarter	30.19		15.05
Third Quarter	18.46		11.10
Fourth Quarter	22.21		14.36
2016
First Quarter		$32.45		$16.10
Second Quarter	42.49		28.51
Third Quarter	41.17		29.52
Fourth Quarter	43.96		32.00


◦	~~public offering of 15.6 million shares of our common stock at a price per share of $14.28 for net proceeds of $222.4 million, net of offering costs;~~


◦	~~public offering of $250.0 million aggregate principal amount of 8.25% Senior Notes due 2025 for net proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs; and~~


◦	issuance and sale of (i) $250.0 million (250,000 shares) of 8.875% redeemable preferred stock and (ii) warrants for 2,750,000 shares of our common stock for net proceeds of $236.4 million, net of issuance costs


	Years Ended December 31,				2017 Period Compared to 2016 Period					Years Ended December 31,			Amount Change Between				Percent Change Between
	2017		2016		Increase (Decrease)			% Increase (Decrease)		2018	2017	2016	2018/2017		2017/2016		2018/2017		2017/2016
Total production volumes
Crude oil (MBbls)	12,566		9,423		3,143			33	%	14,232	12,566	9,423	1,666		3,143		13	%	33	%
NGLs (MBbls)	2,327		1,788		539			30	%	3,701	2,327	1,788	1,374		539		59	%	30	%
Natural gas (MMcf)	28,472		25,574		2,898			11	%	24,639	28,472	25,574	(3,833	)	2,898		(13	%)	11	%
Total barrels of oil equivalent (MBoe)	19,639		15,473		4,166			27	%	22,040	19,639	15,473	2,401		4,166		12	%	27	%

Daily production volumes by product
Crude oil (Bbls/d)	34,428		25,745		8,683			34	%	38,992	34,428	25,745	4,564		8,683		13	%	34	%
NGLs (Bbls/d)	6,376		4,885		1,491			31	%	10,139	6,376	4,885	3,763		1,491		59	%	31	%
Natural gas (Mcf/d)	78,006		69,873		8,133			12	%	67,503	78,006	69,873	(10,503	)	8,133		(13	%)	12	%
Total barrels of oil equivalent (Boe/d)	53,805		42,276		11,529			27	%	60,382	53,805	42,276	6,577		11,529		12	%	27	%

Daily production volumes by region (Boe/d)
Eagle Ford	37,825		30,664		7,161			23	%	37,591	37,825	30,664	(234	)	7,161		(1	%)	23	%
Delaware Basin	6,713		1,115		5,598			502	%	22,609	6,713	1,115	15,896		5,598		237	%	502	%
Niobrara	2,558		2,931		(373		)	(13	%)
Marcellus	6,122		6,329		(207		)	(3	%)
Utica and other	587		1,237		(650		)	(53	%)
Other										182	9,267	10,497	(9,085	)	(1,230	)	(98	%)	(12	%)
Total barrels of oil equivalent (Boe/d)	53,805		42,276		11,529			27	%	60,382	53,805	42,276	6,577		11,529		12	%	27	%

Average realized prices
Crude oil ($ per Bbl)		$50.39		$40.12		$10.27		26	%
NGLs ($ per Bbl)	20.37		12.54		7.83			62	%
Natural gas ($ per Mcf)	2.29		1.69		0.60			36	%
Total average realized price ($ per Boe)		$37.98		$28.67		$9.31		32	%

Revenues (In thousands)
Crude oil		$633,233		$378,073		$255,160		67	%
NGLs	47,405		22,428		24,977			111	%
Natural gas	65,250		43,093		22,157			51	%
Total revenues		$745,888		$443,594		$302,294		68	%


~~(1)~~	The new derivative positions executed during 2017 and 2016 were in a loss due to an upward shift in the futures curve of forecasted commodity prices for crude oil, NGLs and natural gas subsequent to the respective contract executions.



	Years Ended December 31,				2016 Period Compared to 2015 Period
	2016		2015		Increase (Decrease)			% Increase (Decrease)
Total production volumes
Crude oil (MBbls)	9,423		8,415		1,008			12	%
NGLs (MBbls)	1,788		1,352		436			32	%
Natural gas (MMcf)	25,574		21,812		3,762			17	%
Total barrels of oil equivalent (MBoe)	15,473		13,402		2,071			15	%

Daily production volumes by product
Crude oil (Bbls/d)	25,745		23,054		2,691			12	%
NGLs (Bbls/d)	4,885		3,705		1,180			32	%
Natural gas (Mcf/d)	69,873		59,758		10,115			17	%
Total barrels of oil equivalent (Boe/d)	42,276		36,719		5,557			15	%

Daily production volumes by region (Boe/d)
Eagle Ford	30,664		26,377		4,287			16	%
Delaware Basin	1,115		104		1,011			972	%
Niobrara	2,931		2,957		(26		)	(1	%)
Marcellus	6,329		5,850		479			8	%
Utica and other	1,237		1,431		(194		)	(14	%)
Total barrels of oil equivalent (Boe/d)	42,276		36,719		5,557			15	%

Average realized prices
Crude oil ($ per Bbl)		$40.12		$44.69		($4.57	)	(10	%)
NGLs ($ per Bbl)	12.54		11.54		1.00			9	%
Natural gas ($ per Mcf)	1.69		1.72		(0.03		)	(2	%)
Total average realized price ($ per Boe)		$28.67		$32.03		($3.36	)	(10	%)

Revenues (In thousands)
Crude oil		$378,073		$376,094		$1,979		1	%
NGLs	22,428		15,608		6,820			44	%
Natural gas	43,093		37,501		5,592			15	%
Total revenues		$443,594		$429,203		$14,391		3	%


	Three Months Ended									Year Ended			Three Months Ended								Year Ended
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017			December 31, 2017			March 31, 2018		June 30, 2018		September 30, 2018		December 31, 2018		December 31, 2018
	(In thousands)												(In thousands)
Drilling, completion, and infrastructure
DC&I
Eagle Ford		$111,472		$129,933		$122,281		$100,323			$464,009			$135,677		$101,249		$149,386		$136,644		$522,956
Delaware Basin	10,360		11,727		36,055		102,078			160,220			73,892		116,743		91,761		38,768		321,164
All other regions	6,412		6,734		6,698		7,951			27,795
Total drilling, completion, and infrastructure	128,244		148,394		165,034		210,352		⁽¹⁾	652,024		⁽¹⁾
Other													284		—		—		—		284
Total DC&I													209,853		217,992		241,147		175,412		844,404
Leasehold and seismic	14,516		34,447		11,819		4,549			65,331			5,520		6,129		6,668		4,034		22,351
Total ⁽²⁾⁽¹⁾		$142,760		$182,841		$176,853		$214,901			$717,355			$215,373		$224,121		$247,815		$179,446		$866,755