10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Annual Report Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2017

Commission File Number 000-29187-87

Carrizo Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

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)

Registrant’s telephone number, including area code: (713) 328-1000

Securities Registered Pursuant to Section 12(b) of the Act:

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

YES  þ    NO  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

YES  ¨    NO  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    YES  þ    NO  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    YES  þ    NO  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	þ		Accelerated filer	¨
Non-accelerated filer	¨	(Do not check if a smaller reporting company)	Smaller reporting company	¨
			Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    YES  ¨    NO  þ

At June 30, 2017, the aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $1.1 billion based on the closing price of such stock on such date of $17.42.

At February 23, 2018, the number of shares outstanding of the registrant’s Common Stock was 81,469,593.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Registrant’s 2018 Annual Meeting of Shareholders are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the U.S. Securities and Exchange Commission not later than 120 days subsequent to December 31, 2017.

TABLE OF CONTENTS

Forward-Looking Statements	3
PART I
Item 1. Business	5
Item 1A. Risk Factors	26
Item 1B. Unresolved Staff Comments	42
Item 2. Properties	42
Item 3. Legal Proceedings	42
Item 4. Mine Safety Disclosures	43
PART II
Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	44
Item 6. Selected Financial Data	46
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
Item 7A. Qualitative and Quantitative Disclosures about Market Risk	63
Item 8. Financial Statements and Supplementary Data	64
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosures	64
Item 9A. Controls and Procedures	64
Item 9B. Other Information	65
PART III
Item 10. Directors, Executive Officers and Corporate Governance	65
Item 11. Executive Compensation	65
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	65
Item 13. Certain Relationships and Related Transactions, and Director Independence	65
Item 14. Principal Accounting Fees and Services	65
PART IV
Item 15. Exhibits and Financial Statement Schedules	65

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Forward-Looking Statements

This annual report contains statements concerning our intentions, expectations, projections, assessments of risks, estimations, beliefs, plans or predictions for the future, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among others, statements regarding:

• our growth strategies;

• our ability to explore for and develop oil and gas resources successfully and economically;

• our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;

• our estimates regarding timing and levels of production;

• changes in working capital requirements, reserves, and acreage;

• commodity price risk management activities and the impact on our average realized prices;

• anticipated trends in our business;

• availability of pipeline connections and water disposal on economic terms;

• effects of competition on us;

• our future results of operations;

• profitability of drilling locations;

• our liquidity and our ability to finance our exploration and development activities, including accessibility of borrowings under our revolving credit facility, our borrowing base, modification to financial covenants and the result of any borrowing base redetermination;

• our planned expenditures, prospects and capital expenditure plan;

• future market conditions in the oil and gas industry;

• our ability to make, integrate and develop acquisitions and realize any expected benefits or effects of completed acquisitions;

• the benefits, effects, availability of and results of new and existing joint ventures and sales transactions;

• our ability to maintain a sound financial position;

• receipt of receivables, drilling carry and proceeds from sales;

• our ability to complete planned transactions on desirable terms; and

• the impact of governmental regulation, taxes, market changes and world events.

You generally can identify our forward-looking statements by the words “anticipate,” “believe,” budgeted,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “scheduled,” “should,” or other similar words. Such statements rely on assumptions and involve risks and uncertainties, many of which are beyond our control, including, but not limited to, those relating to a worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, impairments of proved oil and gas properties, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, the timing and amount of borrowing base determinations (including determinations by lenders) and availability under our revolving credit facility, evaluations of us by lenders under our revolving credit facility, other actions by lenders, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, acquisition risks, availability of equipment and crews, actions by midstream and other industry participants, weather, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our joint ventures, actions by joint venture

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parties, results of exploration activities, the availability, market conditions and completion of land acquisitions and dispositions, costs of oilfield services, completion and connection of wells, and other factors detailed in this annual report.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under Part I, “Item 1A. Risk Factors” and in other sections of this annual report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update or revise any forward-looking statement.

Certain terms used herein relating to the oil and gas industry are defined in “Glossary of Certain Industry Terms” included under Part I, “Item 1. Business.”

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PART I

Item 1. Business

General Overview

Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, “Carrizo,” the “Company” or “we”), is actively engaged in the exploration, development, and production of crude oil, NGLs, and gas from resource plays located in the United States. Our current operations are principally focused in proven, producing oil and gas plays in the Eagle Ford Shale in South Texas and the Delaware Basin in West Texas.

Significant Developments in 2017

Acquisitions. In the third quarter of 2017, we closed on an acquisition of 16,508 net acres located in the Delaware Basin in Reeves and Ward Counties, Texas (the “ExL Properties”) from ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”) for aggregate net consideration of $679.8 million (the “ExL Acquisition”). In addition, we have 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.

Divestitures. In the fourth quarter of 2017, we closed on divestitures of substantially all of our assets in the Utica and Marcellus Shales for aggregate net proceeds of approximately $137.0 million, subject to post-closing adjustments. In addition, we could receive combined contingent consideration from the two divestitures of up to $8.0 million per year with a cap of $22.5 million if crude oil and natural gas prices exceed specified thresholds for each of the years of 2018 through 2020.

Also in the fourth quarter of 2017, we entered into purchase and sale agreements to sell substantially all of our assets in the Niobrara Formation and a portion of our assets in the Eagle Ford. Carrizo has received aggregate net proceeds of $382.8 million, subject to post-closing adjustments, for these divestitures, both of which closed in January 2018. In addition, we could receive contingent consideration of $5.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2020 as part of the Niobrara Formation divestiture.

See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Notes to our Consolidated Financial Statements for further details of the transactions discussed above.

Liquidity and financings. In the third quarter of 2017, we completed a number of financing transactions to fund the ExL Acquisition. On July 3, 2017, we completed a 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. On July 14, 2017, we closed on a public offering of $250.0 million aggregate principal amount of 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”) for net proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs. On August 10, 2017, we closed on the issuance and sale of (i) $250.0 million (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 our 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 net proceeds of $236.4 million, net of issuance costs.

In the fourth quarter of 2017, we redeemed $150.0 million of the $600.0 million aggregate principal amount outstanding of 7.50% Senior Notes due 2020 (the “7.50% Senior Notes”). The proceeds for the redemption were primarily from the Utica and Marcellus divestitures discussed above.

During 2017, the borrowing base under our revolving credit facility was increased from $600.0 million to $900.0 million primarily as a result of our continued development of our Eagle Ford and Delaware Basin assets as well as our ExL Acquisition. The $900.0 million borrowing base in place at December 31, 2017 was supported solely by the reserves of our Eagle Ford and Delaware Basin assets.

See “Note 6. Long-Term Debt”, “Note 9. Preferred Stock and Warrants” and “Note 10. Shareholders’ Equity and Stock Based Compensation” of the Notes to our Consolidated Financial Statements for further details regarding the financings discussed above.

Production and proved reserves. Crude oil production in 2017 was 34,428 Bbls/d, an increase of 34% as compared to 25,745 Bbls/d in 2016, primarily driven by strong performance from our new wells in the Eagle Ford and Delaware Basin and the addition of production from our acquisition of oil and gas properties located in the Eagle Ford Shale from Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation, in the fourth quarter of 2016 (the “Sanchez Acquisition”) and the ExL Acquisition in the third quarter of 2017. Total production in 2017 increased to 53,805 Boe/d from 42,276 Boe/d in 2016 primarily due to the same reasons discussed above.

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At year-end 2017, our proved reserves of 261.7MMBoe consist of 64% crude oil, 16% natural gas liquids and 20% natural gas. Our reserves increased 61.6 MMBoe, or 31%, from our year-end 2016 proved reserves of 200.2 MMBoe primarily as a result of our ongoing drilling program in the Eagle Ford and the Delaware Basin and the ExL Acquisition described below. The following is a summary of the Company’s proved reserves as of December 31, 2017 and 2016. See “—Additional Oil and Gas Disclosures—Proved Oil and Gas Reserves” for further details of our proved reserves.

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

(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.

Recent Developments

7.50% Senior Notes. In January 2018, we called for redemption a total of $320.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. The proceeds for these redemptions were primarily from the Niobrara and Eagle Ford Shale divestitures discussed above. After these redemptions, we will have $130.0 million aggregate principal amount of 7.50% Senior Notes outstanding.

Preferred Stock. In January 2018, we redeemed 50,000 of the shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, for $50.5 million, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends. After this redemption, we will have 200,000 shares of Preferred Stock outstanding.

Borrowing Base. In January 2018, as a result of the divestiture in the Eagle Ford Shale discussed above, our borrowing base under our revolving credit facility was reduced from $900.0 million to $830.0 million; however, the elected commitment amount remained unchanged at $800.0 million.

See “Note 15. Subsequent Events (Unaudited)” of the Notes to our Consolidated Financial Statements for further details of these recent developments.

2018 Drilling, Completion, and Infrastructure Capital Expenditure Plan. Our 2018 drilling, completion, and infrastructure capital expenditure plan is currently $750.0 million to $800.0 million. This incorporates an assumed double-digit increase in oilfield service costs as well as operating two drilling rigs in the Eagle Ford Shale and three to four drilling rigs in the Delaware Basin during 2018, as well as two to three completion crews during the year. We intend to finance our 2018 capital expenditure plan primarily from cash flow from operations and our senior secured revolving credit facility as well as other sources described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” Our capital expenditure plan has the flexibility to adjust, should the commodity price environment change.

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The following is a summary of our actual capital expenditures for 2017 and our planned capital expenditures for 2018:

	Capital Expenditures
	2018 Plan (1)		2017 Actual
	(In millions)
Drilling, completion, and infrastructure
Eagle Ford		$439.0		$464.0
Delaware Basin	336.0		160.2
All other regions	—		27.8
Total drilling, completion, and infrastructure	775.0		652.0		(2)
Leasehold and seismic (3)	—		65.4
Total (4)		$775.0		$717.4

(1) Represents the midpoint of our 2018 drilling, completion, and infrastructure capital expenditure plan of $750.0 million to $800.0 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 guidance for leasehold and seismic capital expenditures given the limited visibility and highly discretionary nature of this spending.

(4) 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.

Business Strategy & Competitive Strengths

Our objective is to increase value through the execution of a business strategy focused on growth through the drill-bit complimented by opportunistic acquisitions of oil and gas properties, while maintaining a sound financial position. Key elements of our business strategy and competitive strengths which will support our efforts to successfully execute our business strategy include:

• Pursue development of high-quality resource plays. We pursue a growth strategy in crude oil plays primarily driven by the attractive relative economics associated with our core positions. All of our 2018 drilling, completion, and infrastructure capital expenditure plan is currently directed towards opportunities that we believe are predominantly prospective for crude oil development. We follow a disciplined approach to drilling wells by applying proven horizontal drilling and hydraulic fracturing technology. Additionally, we rely on advanced technologies, such as 3-D seismic and micro-seismic analysis, to better define geologic risk and enhance the results of our drilling efforts. Our successful drilling program has significantly de-risked our acreage positions in key resource plays.

We continue to focus our capital program on resource plays where individual wells tend to have lower risk, such as our operations in the Eagle Ford and, more recently, the Delaware Basin, two of the highest return plays in North America. Additionally, we continue to take advantage of opportunities to expand our core positions through leasehold acquisitions as evidenced by the ExL Acquisition described below.

• Operational efficiency and control. We emphasize efficiencies to lower our costs to find, develop and produce our oil and gas reserves. This includes concentrating on our core areas, which allows us to optimize drilling and completion techniques as well as benefit from economies of scale. In addition, as we operate a significant percentage of our properties as well as maintain a minimal level of drilling commitments in order to hold acreage, the majority of our capital expenditure plan is discretionary, allowing us the ability to reallocate or adjust the level of our spending in response to changes in market conditions. For example, we have allocated a larger portion of our 2018 capital expenditure plan as compared to our 2017 capital expenditures to the Delaware Basin primarily as a result of the ExL Acquisition, while maintaining our continued development in the Eagle Ford.

As of December 31, 2017, we operated approximately 91% of the wells in the Eagle Ford and the Delaware Basin in which we held an interest. We held an average working interest of approximately 88% in these operated wells. Our significant operational control, as well as our manageable leasehold obligations, provides us with the flexibility to align capital expenditures with cash flow and control our costs as we transition to an advanced development mode in key plays. As a further result of our operational control, we are generally able to adjust drilling plans in response to changes in commodity prices.

• Significant growth potential. Our management has continued to focus on high-quality resource plays by expanding positions and completing non-core asset sales. We have developed a significant inventory of future oil-focused drilling

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locations, primarily in our well-established positions in the Eagle Ford and the Delaware Basin. As of December 31, 2017, we owned leases covering approximately 195,289 gross (145,233 net) acres in these areas. See “—Acreage Data” for further details. Approximately 58% of our estimated proved reserves at December 31, 2017 were undeveloped.

• Maintain our financial flexibility. We are committed to preserving our financial flexibility. We have historically funded our capital program with a combination of cash generated from operations, proceeds from the divestiture of assets, proceeds from sales of securities, borrowings under our revolving credit facility and proceeds, payments or carried interest from our joint ventures. See “—General Overview” for further details of the redemptions of our 7.50% Senior Notes.

We maintain a financial profile that provides operational flexibility, and our capital structure provides us with the ability to execute our business plan. Our financial profile is designed to allow us to withstand prolonged periods of low commodity prices, but also provides the ability to accelerate activity as commodity prices recover. As of February 23, 2018, we had $141.0 million of outstanding borrowings under our revolving credit facility, with an elected commitment amount of $800.0 million, have no near-term debt maturities, and use commodity derivative instruments to reduce our exposure to commodity price volatility. We attempt to limit our exposure to volatility in commodity prices by actively hedging a portion of our forecast crude oil, NGL, and natural gas production. Our current long-term strategy is to manage exposure to commodity price volatility to achieve a more predictable level of cash flows to support current and future capital expenditure plans.

• Experienced management and professional workforce. We have an experienced staff, both employees and contractors, of oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, production and reservoir engineers and technical support staff. We believe our experience and expertise, particularly as they relate to successfully identifying and developing resource plays, is a competitive advantage.

We believe we have developed a technical advantage from our extensive experience drilling approximately 1,000 horizontal wells in various resource plays, which has allowed our management, technical staff and field operations teams to gain significant experience in resource plays and create highly efficient drilling and completion operations. We now leverage this advantage in our existing, as well as any prospective, shale trends. We plan to focus substantially all of our 2018 capital expenditures in the Eagle Ford and the Delaware Basin.

Exploration and Operation Approach

Our exploration strategy in our shale resource plays has been to accumulate significant leasehold positions in areas with known shale thickness and thermal maturity in the proximity of known or emerging pipeline infrastructures. A component of our exploration strategy is to first identify and acquire surface tracts or “well pads” from which multiple wells can be drilled. We then seek to acquire contiguous lease blocks in the areas immediately adjacent to these well pads that can be developed quickly. If conditions warrant, we next acquire 3-D seismic data over these leases to assist in well placement and development optimization. Finally, we form drilling units and utilize sophisticated horizontal drilling, multi-stage simultaneous hydraulic fracturing programs and micro-seismic techniques designed to maximize the production rate and recoverable reserves from a unit area.

We strive to achieve a balance between acquiring acreage, seismic data (2-D and 3-D) and timely project evaluation through the drillbit to ensure that we minimize the costs to test for commercial reserves while building a significant acreage position. Our first exploration wells in these trends are a limited number of horizontal wells, because they allow us to evaluate thermal maturity and rock property data, while also permitting us to test various completion techniques without incurring the cost of drilling a substantial number of horizontal wells. As discussed above, our primary focus is on crude oil to take advantage of what we believe are the attractive relative economics associated with this commodity.

We maintain a flexible and diversified approach to project identification by focusing on the estimated financial results of a project area rather than limiting our focus to any one method or source for obtaining leads for new project areas. Additionally, we monitor competitor activity and review outside prospect generation by small, independent “prospect generators.” We complement our exploratory drilling portfolio through the use of these outside sources of prospect generation and typically retain operator rights. Specific drill-sites are typically chosen by our own geoscientists or, in environmentally sensitive areas, are dictated by available leases.

Our management team has extensive experience in the development and management of exploration and development projects. We believe that the experience we have gained drilling and completing horizontal wells in multiple basins and the experience of our management team in the development, processing and analysis of 3-D projects and data, will play a significant part in our future success.

We generally seek to obtain operator rights and control over field operations, and in particular seek to control decisions regarding drilling and completion methods. As of December 31, 2017, we operated 702 gross (563.7 net) productive oil and gas

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wells. We generally seek to control operations for most new exploration and development, taking advantage of our technical staff’s experience in horizontal drilling and hydraulic fracturing. For example, during 2017, we operated 91% of the wells drilled in the Eagle Ford and the Delaware Basin where we incurred approximately 96% of our 2017 drilling, completion and infrastructure capital expenditures.

Working Interest and Drilling in Project Areas

The actual working interest we will ultimately own in a well will vary based upon several factors, including the risk of each well relative to our strategic goals, activity levels and capital availability. From time to time some fraction of these wells may be sold to industry partners either on a prospect by prospect basis or a program basis. In addition, we may also contribute acreage to larger drilling units thereby reducing prospect working interest. We have, in the past, retained less than 100% working interest in our drilling prospects. References to our interests are not intended to imply that we have or will maintain any particular level of working interest.

Summary of 2017 Proved Reserves, Production and Drilling by Area

	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.

(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.

Regional Overview

Eagle Ford Shale

The Eagle Ford is our most significant operational area. Our core Eagle Ford properties are located in LaSalle County and, to a lesser extent, in McMullen, Frio and Atascosa counties in Texas. As of December 31, 2017, we held interests in approximately 127,123 gross (103,116 net) acres (97,220 gross (79,612 net) acres after adjusting for the divestiture of a portion of our assets in the Eagle Ford which closed in January 2018 described below). We currently plan for approximately 57% of our 2018 drilling,

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completion, and infrastructure capital expenditure plan to be directed towards opportunities in the Eagle Ford where we currently expect to operate two drilling rigs during 2018.

On December 11, 2017, we entered into a purchase and sale agreement with EP Energy E&P Company, L.P. to sell a portion of our assets in the Eagle Ford for an agreed upon price of $245.0 million, with an effective date of October 1, 2017, subject to adjustment and customary terms and conditions. On December 11, 2017, we received $24.5 million as a deposit, on January 31, 2018, we received $211.7 million at closing, subject to post-closing adjustments, and on February 16, 2018, we received $10.0 million for leases that were not conveyed at closing, for aggregate net proceeds of $246.2 million, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date.

GAIL Joint Venture. In September 2011, we entered into joint venture arrangements with GAIL GLOBAL (USA) INC. (“GAIL”), a wholly owned subsidiary of GAIL (India) Limited. Under this arrangement, GAIL acquired a 20% interest in certain oil and gas properties in the Eagle Ford and an option to purchase a 20% share of acreage acquired by us after the closing located in specified areas adjacent to the initially purchased areas. We generally serve as operator of the GAIL joint venture properties. As of December 31, 2017, acres included in the GAIL joint venture cover approximately 21% of our total Eagle Ford acreage (14% after adjusting for the divestiture of a portion of our assets in the Eagle Ford which closed in January 2018).

Delaware Basin

During 2014, we began to build an acreage position in the Delaware Basin in Culberson and Reeves counties, Texas, targeting the Wolfcamp Formation. As of December 31, 2017, we held interests in approximately 68,166 gross (42,117 net) acres in the Delaware Basin. In the third quarter of 2017, we closed on the ExL Acquisition which added 16,508 net acres to our portfolio. We currently plan for approximately 43% of our 2018 drilling, completion, and infrastructure capital expenditure plan to be directed towards opportunities in the Delaware Basin where we currently expect to operate three to four drilling rigs during 2018.

Non-Core Divestitures

Niobrara Formation.During the fourth quarter of 2017, we entered into a purchase and sale agreement to sell substantially all of our assets in the Niobrara Formation for an agreed upon price of $140.0 million, with an effective date of October 1, 2017, subject to customary purchase price adjustments. On November 20, 2017, we received $14.0 million as a deposit and on January 19, 2018, we received $122.6 million at closing, subject to post-closing adjustments, for aggregate net proceeds of $136.6 million, which included preliminary purchase price adjustments primarily related to the net cash flows from the divested wells from the effective date to the closing date. We also could receive contingent consideration of $5.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2020. In conjunction with the sale, our joint ventures terminated with OIL India (USA) Inc. and IOCL (USA) Inc., wholly owned subsidiaries of OIL India Ltd. and Indian Oil Corporation Ltd., respectively, and Haimo Oil & Gas LLC, a wholly owned subsidiary of Lanzhou Haimo Technologies Co. Ltd.

Marcellus Shale. In the fourth quarter of 2017, we closed on the divestiture of substantially all of our assets in the Marcellus Shale to BKV Chelsea, LLC, a subsidiary of Kalnin Ventures LLC, for an agreed upon price of $84.0 million, with an effective date of April 1, 2017, subject to customary purchase price adjustments. On October 5, 2017, we received $6.3 million into escrow as a deposit and on November 21, 2017, we received $67.6 million at closing, subject to post-closing adjustments, for aggregate net proceeds of $73.9 million, which included preliminary purchase price adjustments primarily related to the net cash flows from the divested wells from the effective date to the closing date. In addition, we could receive contingent consideration of $3.0 million per year with a cap of $7.5 million if natural gas prices exceed specified thresholds for each of the years of 2018 through 2020.

Simultaneous with the signing of the Marcellus Shale transaction discussed above, our existing joint venture partner in the Marcellus Shale, Reliance Marcellus II, LLC (“Reliance”), a wholly owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited, entered into a purchase and sale agreement with BKV Chelsea, LLC to sell its interest in the same oil and gas properties. Simultaneous with the closing of these Marcellus Shale sale transactions, the agreements governing the Reliance joint venture were assigned to the buyer and, after giving effect to such transactions, the Reliance joint venture was terminated except for limited post-closing obligations.

Utica Shale. In the fourth quarter of 2017, we closed on the divestiture of substantially all of our assets in the Utica Shale, located primarily in Guernsey County, Ohio, for an agreed upon price of $62.0 million, with an effective date of April 1, 2017, subject to customary purchase price adjustments. On August 31, 2017, we received $6.2 million from the buyer as a deposit, on November 15, 2017, we received $54.4 million at closing, subject to post-closing adjustments, and on December 28, 2017, we received an additional $2.5 million, for aggregate net proceeds of $63.1 million, which included preliminary purchase price adjustments primarily related to the net cash flows from the divested wells from the effective date to the closing date. In addition, we could receive contingent consideration of $5.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2020.

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Additional Oil and Gas Disclosures

Proved Oil and Gas Reserves

The following table sets forth our estimated net proved reserves and PV-10 as of December 31, 2017 that were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent third party reserve engineers. For further information concerning Ryder Scott’s estimates of our proved reserves as of December 31, 2017, see the reserve report included as an exhibit to this Annual Report on Form 10-K.

The prices used in the calculation of our estimated proved reserves and PV-10 as of December 31, 2017 were based on the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the 12-month period prior to December 31, 2017 (“12-Month Average Realized Price”) in accordance with SEC rules and were $49.87 per Bbl of crude oil, $19.78 per Bbl of NGLs and $2.96 per Mcf of natural gas.

For further information concerning the present value of estimated future net revenues from these proved reserves, see “Note 2. Summary of Significant Accounting Policies” and “Note 16. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited)” of the Notes to our Consolidated Financial Statements. See also “—Other Reserve Matters” below for further discussion.

Summary of Proved Oil and Gas Reserves as of December 31, 2017

	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

Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)

We believe that the presentation of PV-10 provides greater comparability when evaluating oil and gas companies due to the many factors unique to each individual company that impact the amount and timing of future income taxes. In addition, we believe that PV-10 is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company’s financial or operating performance presented in accordance with GAAP. The definition of PV-10 as defined in “Item 1. Business—Glossary of Certain Industry Terms” may differ significantly from the definitions used by other companies to compute similar measures. As a result, PV-10 as defined may not be comparable to similar measures provided by other companies. A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented below. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.

	As of December 31, 2017
	(In millions)
Standardized measure of discounted future net cash flows (GAAP)		$2,465.1
Add: present value of future income taxes discounted at 10% per annum	173.3
PV-10 (Non-GAAP)		$2,638.4

Proved Undeveloped Reserves

The following table provides a summary of the changes in our proved undeveloped reserves (“PUDs”) for the year ended December 31, 2017.

	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

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Extensions and discoveries of 74.3 MMBoe were due to additional offset locations associated with our drilling program, of which 37.5 MMBoe were in the Eagle Ford and 36.8 MMBoe were in the Delaware Basin. We incurred $22.8 million during 2017 for certain of these PUD locations that were drilled but uncompleted as of December 31, 2017.

Purchases of reserves in place of 20.1 MMBoe were due to the ExL Acquisition in the third quarter of 2017.

Divestitures of reserves in place of 7.3 MMBoe were related to the sale of our assets in the Marcellus Shale in the fourth quarter of 2017. We had no proved undeveloped reserves associated with the Utica Shale.

We removed 14.3 MMBoe of PUDs in the Eagle Ford due to changes in our previously approved development plan, which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in our previously approved development plan were the recent ExL Acquisition and the move to a more efficient development plan which includes drilling and completing larger pads.

Revisions of previous estimates of 0.1 MMBoe included 5.8 MMBoe of negative revisions due to a downward shift of the type curve for certain PUD locations in the Eagle Ford partially offset by 5.7 MMBoe of positive revisions due to well performance in Marcellus which occurred prior to the sale in November 2017.

We converted 28.4 MMBoe of PUD reserves that were booked as PUDs as of December 31, 2016 to proved developed during 2017, of which 27.7 MMBoe were in the Eagle Ford, at a total cost of $310.2 million, or $10.92 per Boe. We converted an additional 11.4 MMBoe of PUD reserves that were booked as PUDs during 2017 to proved developed, of which 7.7 MMBoe were in the Delaware Basin, at a total cost of $129.4 million, or $11.35 per Boe. We also incurred $47.6 million during 2017 on PUD locations that were drilled but uncompleted as of December 31, 2017 that were booked as PUDs as of December 31, 2016.

As of December 31, 2017, we had 17.0 MMBoe of PUD reserves associated with wells that were drilled but uncompleted, all of which are scheduled to be completed in 2018, with the majority scheduled to be completed during the first half of 2018. We expect to incur $139.8 million of capital expenditures to complete these wells.

At December 31, 2017, we did not have any reserves that have remained undeveloped for five or more years since the date of their initial booking and all PUD locations are scheduled to be developed within five years of their initial booking.

Qualifications of Technical Persons

In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and the guidelines established by the Securities and Exchange Commission (“SEC”), Ryder Scott estimated 100% of our proved reserves as of December 31, 2017, 2016, and 2015 as presented in this Annual Report on Form 10-K. The technical persons responsible for preparing the reserves estimates meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott does not own an interest in our properties and is not employed on a contingent fee basis.

Our internal reserve engineers each have over 25 years of experience in the petroleum industry and extensive experience in the estimation of reserves and the review of reserve reports prepared by third party engineering firms. The reserve reports are also reviewed by senior management, including the Chief Executive Officer, who is a registered petroleum engineer and holds a B.S. in Mechanical Engineering and the Chief Operating Officer, who holds a B.S. in Petroleum Engineering.

Internal Controls Over Reserve Estimation Process

The primary inputs to the reserve estimation process are comprised of technical information, financial data, production data, and ownership interests. All field and reservoir technical information, which is updated annually, is assessed for validity when the internal reserve engineers hold technical meetings with our geoscientists, operations, and land personnel to discuss field performance and to validate future development plans. The other inputs used in the reserve estimation process, including, but not limited to, future capital expenditures, commodity price differentials, production costs, and ownership percentages are subject to internal controls over financial reporting and are assessed for effectiveness annually.

Our internal reserve engineers work closely with Ryder Scott to ensure the integrity, accuracy, and timeliness of the data furnished to Ryder Scott for use in their reserves estimation process. Our internal reserve engineers meet regularly with Ryder Scott to review and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates. The internal reserve engineers review the inputs and assumptions made in the reserves estimates prepared by Ryder Scott and assess them for reasonableness.

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Specific internal control procedures include, but are not limited to, the following:

• Review by our internal reserve engineers of all of our reported proved reserves at the close of each quarter, including review of all additions to PUD reserves

• Quarterly updates by our senior management to our Board of Directors regarding operational data, including production, drilling and completion activity and any significant changes in our reserves estimates

• Quarterly and annual preparation of a reserve reconciliation that is reviewed by members of our senior management

• Annual review by our senior management of our year-end reserves estimates prepared by Ryder Scott

• Annual review by our senior management and Board of Directors of our multi-year development plan and approval by the Board of Directors of our capital expenditure plan

• Review by our senior management of changes, if applicable, in our previously approved development plan

Other Reserve Matters

No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC. The reserves data set forth in this Annual Report on Form 10-K represents only estimates. See “Item 1A. Risk Factors—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.”

Our future oil and gas production is highly dependent upon our level of success in finding or acquiring additional reserves. See “Item 1A. Risk Factors—We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.” Also, the failure of an operator of our wells to adequately perform operations, or such operator’s breach of the applicable agreements, could adversely impact us. See “Item 1A. Risk Factors—We cannot control the activities on properties we do not operate.”

The prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect market prices for oil and gas production. See “Item 1A. Risk Factors—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 can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will actually be realized for such production or that existing contracts will be honored or judicially enforced.

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Oil and Gas Production, Prices and Costs

The following table sets forth certain information regarding the production volumes, average realized prices and average production costs associated with our sales of oil and gas for the periods indicated.

	Years Ended December 31,
	2017		2016		2015
Total production volumes (1)
Crude oil (MBbls)	12,566		9,423		8,415
NGLs (MBbls)	2,327		1,788		1,352
Natural gas (MMcf)	28,472		25,574		21,812
Total barrels of oil equivalent (MBoe)	19,639		15,473		13,402
Daily production volumes by product (1)
Crude oil (Bbls/d)	34,428		25,745		23,054
NGLs (Bbls/d)	6,376		4,885		3,705
Natural gas (Mcf/d)	78,006		69,873		59,758
Total barrels of oil equivalent per day (Boe/d)	53,805		42,276		36,719
Daily production volumes by region (Boe/d) (1)
Eagle Ford	37,825		30,664		26,377
Delaware Basin	6,713		1,115		104
Niobrara	2,558		2,931		2,957
Marcellus	6,122		6,329		5,850
Utica and other	587		1,237		1,431
Total barrels of oil equivalent (Boe/d)	53,805		42,276		36,719
Average realized prices
Crude oil ($ per Bbl)		$50.39		$40.12		$44.69
NGLs ($ per Bbl)	20.37		12.54		11.54
Natural gas ($ per Mcf)	2.29		1.69		1.72
Total average realized price ($ per Boe)		$37.98		$28.67		$32.03
Average production costs ($ per Boe) (2)		$7.12		$6.38		$6.72

(1) In the fourth quarter of 2017, we closed on divestitures of substantially all of our assets in the Utica and Marcellus and in the first quarter of 2018, we closed on divestitures of substantially all of our assets in the Niobrara and a portion of our assets in the Eagle Ford. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Notes to our Consolidated Financial Statements for further details of these transactions.

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

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Drilling Activity

The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2017, 2016 and 2015. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.

	Years Ended December 31,
	2017				2016		2015
	Gross		Net		Gross	Net	Gross	Net
Exploratory Wells - Productive	47	(1)	7.1	(1)	29	4.5	77	19.5
Exploratory Wells - Nonproductive	—		—		—	—	—	—
Development Wells - Productive	102	(2)	89.7	(2)	81	73.5	65	55.4
Development Wells - Nonproductive	—		—		—	—	—	—

(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.

As of December 31, 2017, we had 55 gross (40.2 net) operated and non-operated wells in various stages of drilling, completion or waiting on completion that are not included in the table above.

Productive Wells

The following table sets forth the number of productive crude oil and natural gas wells in which we owned an interest as of December 31, 2017.

	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 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.

Acreage Data

The following table sets forth certain information regarding our developed and undeveloped acreage as of December 31, 2017. Developed acreage refers to acreage on which wells have been completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves.

	Developed  Acreage		Undeveloped Acreage		Total Acreage (1)		Percent of Net Undeveloped Acreage Expiring
	Gross	Net	Gross	Net	Gross	Net	2018			2019			2020
Eagle Ford	102,387	84,806	24,736	18,310	127,123	103,116	30	%	(2)	18	%	(3)	9	%	(3)
Delaware Basin	24,725	16,789	43,441	25,328	68,166	42,117	23	%	(4)	23	%	(3)	44	%	(3)
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	%		—	%
Total	168,721	116,635	183,955	105,086	352,676	221,721	15	%		15	%		14	%

(1) Total acreage as of December 31, 2017 includes 29,903 gross (23,504 net) acres which were part of our divestiture in the Eagle Ford.

(2) Of the approximate 5,500 net undeveloped acres scheduled to expire in 2018 in Eagle Ford, approximately 2,600 net undeveloped acres were part of our divestiture in the Eagle Ford. The remaining net undeveloped acres which are set to expire do not have any associated proved undeveloped reserves.

(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.

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(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.

(6) Other includes non-core acreage principally located in Texas, Wyoming, West Virginia, Ohio, Pennsylvania, Kentucky, and Illinois, where we do not currently have planned capital expenditures. There are insignificant costs for unproved property and no proved undeveloped reserves associated with the non-core net undeveloped acreage.

Our lease agreements generally terminate if producing wells have not been drilled on the acreage within their primary term or an extension thereof (a period that can be from three to five years depending on the area). The percentage of net undeveloped acreage expiring in 2018, 2019, and 2020 assumes that no producing wells have been drilled on acreage within their primary term or have been extended. We manage our lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling drilling in order to hold leases by production or timely exercising our contractual rights to extend the terms of leases by continuous operations or the payment of lease extension payments and delay rentals. We may choose to allow some leases to expire that are no longer part of our development plans.

The proved undeveloped reserves associated with acreage expiring over the next three years are not material to the Company.

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 to sell as much of our natural gas production at the wellhead as possible, so that we can concentrate our efforts and resources on exploration and production which we believe are more consistent with our competitive expertise, rather than natural gas gathering, processing, transportation and marketing. In each case, 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 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. 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.

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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. 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

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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

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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”) 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, 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 the areas in which we operate as nonattainment areas under this revised standard. States that contain any areas designated nonattainment, and any tribes that choose to do so, will be 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

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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 EPA is currently reconsidering this rule and has proposed to stay its requirements. However, the 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, the BLM issued a final stay of the rules that temporarily suspends or delays their requirements until January 2019, while the BLM considers revising or rescinding the requirements. However, if these requirements go into effect, compliance 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

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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 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 EPA is currently reconsidering this rule and has proposed to stay its requirements. However, the 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, 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. For additional information, please see “Item 1A. Risk Factors—We may incur losses as a result of title deficiencies.”

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Customers

The following table presents customers that represent 10% or more of our total revenues for the years ended December 31, 2017, 2016 and 2015:

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

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 as other purchasers are available in our primary areas of activity. See “Additional Oil and Gas Disclosures—Marketing.”

Employees

At December 31, 2017, we had 249 full-time employees. We believe that our relationships with our employees are satisfactory. We regularly use independent contractors and consultants to perform various field and other services.

Available Information

Our website can be accessed at www.carrizo.com. We make our website content available for informational purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. Within our website’s investor relations section, we make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, including exhibits and amendments to these reports, as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street NE, Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.We also make available through our website information related to our corporate governance including the following:

• Audit Committee Charter;

• Compensation Committee Charter;

• Nominating and Corporate Governance Committee Charter;

• Code of Ethics and Business Conduct; and

• Compliance Employee Report Line.

We intend to satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Ethics and Business Conduct and any waiver from a provision of our Code of Ethics by posting such information on our website at www.carrizo.com under “About—Governance.”

Glossary of Certain Industry Terms

The definitions set forth below shall apply to the indicated terms as used herein.

3-D seismic data. Three-dimensional pictures of the subsurface created by collecting and measuring the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

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

Bbls/d. Stock tank barrels per day.

Bcf. Billion cubic feet of natural gas.

Boe. Barrels of oil equivalent. A Boe is determined using the ratio of 6 Mcf of natural gas to one Bbl of oil or NGLs which approximates their relative energy content.

Boe/d. Barrels of oil equivalent per day.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

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Carried interest.An agreement under which one party (carrying party) agrees to pay for a specified portion or for all of the drilling and completion and operating costs of another party (carried party) on a property for a specified time in which both own a portion of the working interest. The carrying party may be able to recover a specified amount of costs from the carried party’s share of the revenue from the production of reserves from the property.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, NGLs or natural gas, or in the case of a dry well, the reporting of abandonment to the appropriate authority.

Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed acreage. The number of acres allocated or assignable to productive wells or wells capable of production.

Developed oil and gas reserves. Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. Development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves, (ii) drill and equip development wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct and install, production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (iv) provide improved recovery systems.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry well. An exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Economically producible. A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of “oil and gas producing activities” as defined in Rule 4-10(a)(16) of Regulation S-X promulgated under the Securities Exchange Act of 1934, as amended.

Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition, or both. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Hydraulic fracturing. Hydraulic fracturing is a well stimulation process using a liquid (usually water with an amount of chemicals mixed in) that is forced into an underground formation under high pressure to open or enlarge fractures in reservoirs with low permeability to stimulate and improve the flow of hydrocarbons from these reservoirs. As the formation is fractured, a proppant (usually sand or ceramics) is pumped into the fractures to “prop” or keep them from closing after they are opened by the liquid. Hydraulic fracturing is a technology used in shale reservoirs and other unconventional resource plays in order to enable commercial hydrocarbon production.

MBbls. Thousand barrels of oil or other liquid hydrocarbons.

MBoe. Thousand barrels of oil equivalent.

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Mcf. Thousand cubic feet of natural gas.

Mcf/d. Thousand cubic feet of natural gas per day.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, or condensate or one Boe of NGLs, which represents the approximate energy content of oil, condensate and NGLs as compared to natural gas. Despite holding this ratio constant at six Mcf to one Bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

MMBbls. Million barrels of oil or other liquid hydrocarbons.

MMBoe. Million barrels of oil equivalent.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcf/d. Million cubic feet of natural gas per day.

MMcfe. Million cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs, which represents the approximate energy content of oil, condensate and NGLs as compared to natural gas. Despite holding this ratio constant at six Mcf to one Bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

MMcfe/d. Million cubic feet of natural gas equivalent per day.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.

Productive well. A well that is found to be capable of producing oil or gas in sufficient quantities to justify completion as an oil or gas well.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which defines proved reserves as:

The quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of a reservoir considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

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Reserves that can be produced economically, based on prices used to estimate reserves, through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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

(i) Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility, based on pricing used to estimate reserves, at greater distances.

(ii) Undrilled locations are classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

PV-10 (Non-GAAP). The present value of estimated future revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, based on prices used in estimating the proved reserves and costs in effect as of the date indicated (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, or depreciation, depletion, and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies and from period to period. This is a non-GAAP measure. See “Item 1. Business—Additional Oil and Gas Disclosures—Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)”

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to EUR with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.

Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or gas, or both, that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Standardized measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves after income taxes, calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the U.S. Securities Exchange Commission’s rules for inclusion of oil and gas reserve information in financial statements filed with the U.S. Securities Exchange Commission.

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Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

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 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. 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.

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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

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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, approximately 58% of our proved reserves were proved undeveloped. Moreover, some of the producing wells included in our reserve reports as of December 31, 2017 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, 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 as earlier months with lower 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.

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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 overall level of debt and Preferred Stock obligations increased, which could adversely affect us.

Upon consummation of the ExL Acquisition, our overall 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.

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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 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. 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

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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.

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.”

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

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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

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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 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. 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.

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 40 gross (20.3 net) 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. 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

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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

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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, “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. 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.

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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 to the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and mechanisms for obtaining this information. 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 USGS similarly identified a high seismic hazard for areas of several states, including north Texas. 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;

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• 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

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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;

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• 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, in our ExL Acquisition, we entered into arrangements whereby we will be required to make additional payments if oil 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

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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 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 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. 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.

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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, 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. 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 on digital technology, including information systems and related infrastructure as well as cloud application and services, 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, 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 gas and NGLs makes certain information more attractive to thieves.

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Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital technology. Some of these business partners 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. 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. 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 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.

We cannot assess the extent of either the threat or the potential impact of future terrorist 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. 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 could materially affect our operations.

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

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 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 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 on the merits of the dispute. The payment of damages per the

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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 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.

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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, there were an estimated 63 owners of record of our common stock.

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, 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 to December 31, 2017, with the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index, over the same period.

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The graph assumes an investment of $100 (with reinvestment of all dividends) was invested on December 31, 2012, 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
December 31, 2012	$100	$100	$100
December 31, 2013	$214	$132	$132
December 31, 2014	$199	$151	$117
December 31, 2015	$141	$153	$90
December 31, 2016	$179	$171	$111
December 31, 2017	$102	$208	$113

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.

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Item 6. Selected Financial Data

Our financial information set forth below for each of the five years in the period ended December 31, 2017, 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,
	2017			2016			2015			2014			2013
	(In thousands, except per share data)
Statements of Operations Information:
Total revenues		$745,888			$443,594			$429,203			$710,187			$520,182
Total costs and expenses	654,748			1,119,068			1,727,963			359,977			485,421
Income (loss) from continuing operations	87,110			(675,474		)	(1,157,885		)	222,283			21,858
Net income (loss) attributable to common shareholders	78,467			(675,474		)	(1,155,154		)	222,283			21,858
Income (loss) from continuing operations per common share:
Basic		$1.19			($11.27	)		($22.50	)		$4.90			$0.54
Diluted		$1.18			($11.27	)		($22.50	)		$4.81			$0.53
Net income (loss) attributable to common shareholders per common share:
Basic		$1.07			($11.27	)		($22.45	)		$4.90			$0.54
Diluted		$1.06			($11.27	)		($22.45	)		$4.81			$0.53
Weighted average common shares outstanding:
Basic	73,421			59,932			51,457			45,372			40,781
Diluted	73,993			59,932			51,457			46,194			41,355
Statements of Cash Flows Information:
Net cash provided by operating activities from continuing operations		$422,981			$272,768			$378,735			$502,275			$367,474
Net cash used in investing activities from continuing operations	(1,159,452		)	(619,832		)	(673,376		)	(940,676		)	(509,885		)
Net cash provided by financing activities from continuing operations	741,817			308,340			330,767			300,290			120,326
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
Long-term debt	1,629,209			1,325,418			1,236,017			1,332,175			883,851
Preferred stock	214,262			—			—			—			—
Total shareholders’ equity	370,897			23,458			444,054			1,103,441			841,604

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and related Notes included in “Item 8. Financial Statements and Supplementary Data.” The following discussion and analysis contains statements, including, but not limited to, statements relating to our plans, strategies, objectives, and expectations. Please see “Forward-Looking Statements” and “Item 1A. Risk Factors” for further details about these statements.

General Overview

Significant Developments in 2017

• As a result of our Spring 2017 borrowing base redetermination, our borrowing base was increased from $600.0 million to $900.0 million, with an elected commitment amount of $800.0 million.

• As a result of our Fall 2017 borrowing base redetermination, our borrowing base was established at $900.0 million, with an elected commitment amount of $800.0 million. The calculation of the $900.0 million borrowing base was supported solely by the reserves of our Eagle Ford and Delaware Basin assets.

• In the third quarter of 2017, we closed on the ExL Acquisition, which added 16,508 net acres to our portfolio, for aggregate net consideration of $679.8 million. In addition, we have 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.

• We funded the ExL Acquisition through the following financing activities during the third quarter of 2017:

◦ 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

• In the fourth quarter of 2017, we closed on divestitures of substantially all of our assets in the Utica and Marcellus Shales for aggregate net proceeds of approximately $137.0 million, subject to post-closing adjustments. In addition, we could receive combined contingent consideration from the two divestitures of up to $8.0 million per year with a cap of $22.5 million if crude oil and natural gas prices exceed specified thresholds for each of the years of 2018 through 2020.

• Also in the fourth quarter of 2017, we entered into purchase and sale agreements to sell substantially all of our assets in the Niobrara Formation and a portion of our assets in the Eagle Ford. Carrizo has received aggregate net proceeds of $382.8 million for these divestitures, subject to post-closing adjustments, both of which closed in January 2018. In addition, we could receive contingent consideration of $5.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2020 as part of the Niobrara Formation divestiture.

• In the fourth quarter of 2017, we redeemed $150.0 million of the $600.0 million aggregate principal amount outstanding of 7.50% Senior Notes due 2020.

Recent Developments

• In January 2018, we called for redemption a total of $320.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. The proceeds for these redemptions were primarily from the Niobrara and Eagle Ford Shale divestitures discussed above. After these redemptions, we will have $130.0 million aggregate principal amount of 7.50% Senior Notes outstanding.

• In January 2018, we redeemed 50,000 of the shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, for $50.5 million, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends.

• In January 2018, as a result of the divestiture in the Eagle Ford Shale discussed above, our borrowing base under our revolving credit facility was reduced from $900.0 million to $830.0 million; however, the elected commitment amount remained unchanged at $800.0 million.

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• Our 2018 drilling, completion, and infrastructure capital expenditure plan is currently $750.0 million to $800.0 million, of which 57% is allocated to the Eagle Ford and the remaining 43% allocated to the Delaware Basin. See “—Liquidity and Capital Resources—2018 Drilling, Completion, and Infrastructure Capital Expenditure Plan and Funding Strategy” for additional details.

Results of Operations

Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the years ended December 31, 2017 and 2016:

	Years Ended December 31,				2017 Period Compared to 2016 Period
	2017		2016		Increase (Decrease)			% Increase (Decrease)
Total production volumes
Crude oil (MBbls)	12,566		9,423		3,143			33	%
NGLs (MBbls)	2,327		1,788		539			30	%
Natural gas (MMcf)	28,472		25,574		2,898			11	%
Total barrels of oil equivalent (MBoe)	19,639		15,473		4,166			27	%
Daily production volumes by product
Crude oil (Bbls/d)	34,428		25,745		8,683			34	%
NGLs (Bbls/d)	6,376		4,885		1,491			31	%
Natural gas (Mcf/d)	78,006		69,873		8,133			12	%
Total barrels of oil equivalent (Boe/d)	53,805		42,276		11,529			27	%
Daily production volumes by region (Boe/d)
Eagle Ford	37,825		30,664		7,161			23	%
Delaware Basin	6,713		1,115		5,598			502	%
Niobrara	2,558		2,931		(373		)	(13	%)
Marcellus	6,122		6,329		(207		)	(3	%)
Utica and other	587		1,237		(650		)	(53	%)
Total barrels of oil equivalent (Boe/d)	53,805		42,276		11,529			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	%

Production volumes in 2017 were 53,805 Boe/d, an increase of 27% from 42,276 Boe/d in 2016. The increase is primarily due to production from our wells in the Eagle Ford and Delaware Basin and the addition of production from the Sanchez Acquisition in late 2016 and the ExL Acquisition in the third quarter of 2017, partially offset by the divestitures in the Marcellus and Utica Shales. Revenues for 2017 increased 68% to $745.9 million compared to $443.6 million in 2016 primarily due to higher commodity prices and increased production.

Lease operating expenses for 2017 increased to $139.9 million ($7.12 per Boe) from $98.7 million ($6.38 per Boe) in 2016. The increase in lease operating expenses is primarily due to increased production and increased workover costs primarily on wells acquired in the Sanchez Acquisition. The increase in lease operating expense per Boe is primarily due to the workover costs described above as well as to an increased proportion of total production from crude oil properties, which have a higher operating cost per Boe than natural gas properties.

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Production taxes increased to $32.5 million (or 4.4% of revenues) in 2017 from $19.0 million (or 4.3% of revenues) in 2016 as a result of the increase in crude oil, NGL, and natural gas revenues. The increase in production taxes as a percentage of revenues for 2017 as compared to 2016 is due primarily to a decreased proportion of total revenues attributable to Marcellus production, which is not subject to production taxes.

Ad valorem taxes increased to $7.3 million in 2017 from $5.6 million in 2016. The increase in ad valorem taxes is due to new wells drilled in the Eagle Ford and Delaware Basin in 2016 and new wells acquired in the Sanchez Acquisition in December 2016.

Depreciation, depletion and amortization (“DD&A”) expense for 2017 increased $48.6 million to $262.6 million ($13.37 per Boe) from $214.0 million ($13.83 per Boe) for 2016. The increase in DD&A expense is attributable to increased production, partially offset by the decrease in the DD&A rate per Boe. The decrease in the DD&A rate per Boe is due primarily to impairments of our proved oil and gas properties recorded during 2016, reductions in estimated future development costs as a result of reduced service costs that occurred in the fourth quarter of 2016, and the addition of crude oil reserves in the fourth quarter of 2017, partially offset by the allocation to proved oil and gas properties related to the ExL Acquisition. The components of our DD&A expense were as follows:

	Years Ended December 31,
	2017		2016
	(In thousands)
DD&A of proved oil and gas properties		$257,057		$208,849
Depreciation of other property and equipment	2,484		2,613
Amortization of other assets	1,249		1,136
Accretion of asset retirement obligations	1,799		1,364
Total DD&A		$262,589		$213,962

We did not recognize impairments of proved oil and gas properties for the year ended December 31,2017. Primarily due to declines in the 12-Month Average Realized Price of crude oil, we recognized impairments of proved oil and gas properties in 2016. Details of the 12-Month Average Realized Price of crude oil for 2017 and 2016 and impairments of proved oil and gas properties for 2016 are summarized in the table below:

	Years Ended December 31,
	2017			2016
Impairment of proved oil and gas properties (in thousands)		$—		$576,540
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period	$39.60			$47.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period	$49.87			$39.60
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period	26		%	(16	%)

General and administrative expense, net decreased to $66.2 million for 2017 from $75.0 million for 2016. The decrease was primarily due to a decrease in stock-based compensation, net as a result of a decrease in the fair value of stock appreciation rights for 2017 due to exercises and expirations and a decrease in fair value of stock appreciation rights in 2017 as compared to an increase in the fair value of stock appreciation rights in 2016, partially offset by higher compensation costs for 2017 as compared to 2016, resulting from an increase in personnel as well as higher annual bonuses awarded in the first quarter of 2017 compared to the first quarter of 2016.

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We recorded a loss on derivatives, net of $59.1 million for the year ended December 31,2017 and a loss on derivatives, net of $49.1 million for the year ended December 31,2016. The components of our (gain) loss on derivatives, net were as follows:

	Years Ended December 31,
	2017			2016
	(In thousands)
Crude oil derivative positions:
(Gain) loss due to an overall (downward) upward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period		($22,951	)		$9,664
Loss due to new derivative positions executed during the period (1)	45,790			13,945
Loss due to deferred premium obligations incurred	18,401			5,782
Natural gas derivative positions:
Gain due to downward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period	(15,399		)	—
Loss due to new derivative positions executed during the period (1)	—			19,584
Loss due to deferred premium obligations incurred	—			98
NGL derivative positions:
Loss due to new derivative positions executed during the period (1)	1,322			—
Contingent consideration (2):
Loss due to upward shift in the futures curve of forecasted commodity prices from the closing date to the end of the period	31,940			—
(Gain) loss on derivatives, net		$59,103			$49,073

(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.

(2) We have entered into agreements for acquisitions and divestitures of oil and gas properties containing contingent consideration that are required to be bifurcated and accounted for separately as derivative instruments as they are not clearly and closely related to the host contract. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further discussion of the contingent consideration.

Interest expense, net for 2017 was $80.9 million as compared to $79.4 million for 2016. The increase was primarily due to the interest expense on the $250.0 million aggregate principal amount of our 8.25% Senior Notes that were issued in July 2017 and an increase in interest expense on our revolving credit facility as a result of increased borrowings in 2017 as compared to 2016, partially offset by an increase in capitalized interest as a result of higher average balances of unevaluated leasehold and seismic costs for 2017 as compared to 2016, primarily due to the ExL Acquisition. The components of our interest expense, net were as follows:

	Years Ended December 31,
	2017			2016
	(In thousands)
Interest expense on Senior Notes		$95,272			$85,819
Interest expense on revolving credit facility	8,293			3,907
Amortization of debt issuance costs, premiums, and discounts	4,529			5,565
Other interest expense	1,029			1,138
Capitalized interest	(28,253		)	(17,026		)
Interest expense, net		$80,870			$79,403

As a result of our redemption of $150.0 million aggregate principal amount of our 7.50% Senior Notes, we recorded a loss on extinguishment of debt of $4.2 million in 2017, which includes the redemption premium paid to redeem the notes and non-cash charges of $1.3 million attributable to the write-off of unamortized premium and debt issuance costs associated with the 7.50% Senior Notes.

The effective income tax rate was 4.4% for 2017 and 0% for 2016. The variance in the effective income tax rate results from income tax expense of $4.0 million recognized during 2017 primarily as a result of the significant changes in our operations in 2017, including the ExL Acquisition in the Delaware Basin and divestitures of substantially all of our assets in the Utica and Marcellus Shales, which resulted in changes to our anticipated future state apportionment for estimated state deferred tax liabilities. For the year ended December 31, 2016, the effective income tax rate was 0% as a result of a full valuation allowance against our

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net deferred tax assets driven by the impairments of proved oil and gas properties we recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016.

For the year ended December 31,2017, we declared and paid $7.8 million of dividends, in cash, to the holders of record of the Preferred Stock, which reduced net income to compute net income attributable to common shareholders.

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

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the years ended December 31, 2016 and 2015:

	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	%

Production volumes in 2016 were 42,276 Boe/d, an increase of 15% from 36,719 Boe/d in 2015. The increase is primarily due to production from our wells in the Eagle Ford and Delaware Basin. Revenues for 2016 increased 3% to $443.6 million compared to $429.2 million in 2015 primarily due to the increase in crude oil production, partially offset by a decrease in average realized crude oil prices of 10% for 2016 as compared to 2015.

Lease operating expenses for 2016 increased to $98.7 million ($6.38 per Boe) from $90.1 million ($6.72 per Boe) in 2015. The increase in lease operating expenses is primarily due to increased production from new wells in the Eagle Ford, partially offset by reduced costs due primarily to a decrease in produced water disposal costs resulting from a higher proportion of produced water volumes being transported to disposal sites via pipeline instead of truck as well as lower costs to transport produced water to disposal sites via truck. The decrease in lease operating expense per Boe is primarily due to the lower produced water disposal costs described above.

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Production taxes increased to $19.0 million (or 4.3% of revenues) in 2016 from $17.7 million (or 4.1% of revenues) in 2015 as a result of the increase in natural gas and NGL revenues. The increase in production taxes as a percentage of revenues for 2016 as compared to 2015 is due primarily to an increased proportion of total revenues attributable to natural gas and NGLs in Eagle Ford and the Delaware Basin, which is taxed at a higher rate than crude oil.

Ad valorem taxes decreased to $5.6 million in 2016 from $9.3 million in 2015. The decrease in ad valorem taxes is due to lower property tax valuations received during 2016 as compared to 2015, partially offset by an increase attributable to new wells drilled in Eagle Ford in 2015.

DD&A expense for 2016 decreased $86.0 million to $214.0 million ($13.83 per Boe) from $300.0 million ($22.39 per Boe) for 2015. The decrease in DD&A expense is attributable to the decrease in the DD&A rate per Boe, partially offset by increased production. The DD&A rate per Boe decreased primarily due to impairments of our proved oil and gas properties recorded during 2015 and 2016 as well as reductions in estimated future development costs primarily as a result of reduced service costs that have occurred since 2015. The components of our DD&A expense were as follows:

	Years Ended December 31,
	2016		2015
	(In thousands)
DD&A of proved oil and gas properties		$208,849		$295,452
Depreciation of other property and equipment	2,613		1,932
Amortization of other assets	1,136		1,539
Accretion of asset retirement obligations	1,364		1,112
Total DD&A		$213,962		$300,035

We recognized impairments of proved oil and gas properties for the years ended December 31, 2016 and 2015 primarily due to declines in the 12-Month Average Realized Price of crude oil, as summarized in the table below: 

	Years Ended December 31,
	2016		2015
Impairment of proved oil and gas properties (in thousands)	$576,540		$1,224,367
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period	$47.24		$92.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period	$39.60		$47.24
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period	(16	%)	(49	%)

General and administrative expense, net increased to $75.0 million for 2016 from $67.2 million for 2015. The increase was primarily due to an increase in the fair value of stock appreciation rights in 2016 as compared to a decrease in fair value in 2015, partially offset by lower annual bonuses awarded in the first quarter of 2016 as compared to the first quarter of 2015.

We recorded a loss on derivatives, net of $49.1 million for 2016 and a gain on derivatives, net of $99.3 million for 2015. The components of our (gain) loss on derivatives, net were as follows:

	Years Ended December 31,
	2016		2015
	(In thousands)
Crude oil derivative positions:
(Gain) loss due to (downward) upward shift in the futures curve of forecasted crude oil prices during the period on derivative positions outstanding at the beginning of the period		$9,664		($11,462	)
(Gain) loss due to new derivative positions executed during the period (1)	13,945		(88,163		)
Loss due to deferred premium obligations incurred	5,782		4,426
Natural gas derivative positions:
Gain due to downward shift in the futures curve of forecasted natural gas prices during the period on derivative positions outstanding at the beginning of the period	—		(4,062		)
Loss due to new derivative positions executed during the period (1)	19,584		—
Loss due to deferred premium obligations incurred	98		—
(Gain) loss on derivatives, net		$49,073		($99,261	)

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

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Interest expense, net for 2016 was $79.4 million as compared to $69.2 million for 2015. The increase was primarily due to the decrease in capitalized interest as a result of lower average balances of unevaluated leasehold and seismic costs and exploratory well costs for 2016 as compared to 2015, partially offset by lower interest associated with the $650.0 million of 6.25% Senior Notes that were issued in April 2015 as compared to the interest associated with the $600.0 million of 8.625% Senior Notes that were redeemed in April 2015. The components of our interest expense, net were as follows:

	Years Ended December 31,
	2016			2015
	(In thousands)
Interest expense on Senior Notes		$85,819			$90,882
Interest expense on revolving credit facility	3,907			4,226
Amortization of debt issuance costs, premiums, and discounts	5,565			4,724
Other interest expense	1,138			1,453
Capitalized interest	(17,026		)	(32,090		)
Interest expense, net		$79,403			$69,195

The effective income tax rates for 2016 and 2015 were 0% and 10.8%, respectively. This reduction in the effective income tax rate is primarily a result of recording a full valuation allowance against our net deferred tax assets beginning in the third quarter of 2015, primarily driven by the impairments of proved oil and gas properties described above.

Liquidity and Capital Resources

2018 Drilling, Completion, and Infrastructure Capital Expenditure Plan and Funding Strategy. Our 2018 drilling, completion, and infrastructure capital expenditure plan is $750.0 million to $800.0 million. This incorporates an assumed double-digit increase in oilfield service costs as well as operating two drilling rigs in the Eagle Ford Shale and three to four drilling rigs in the Delaware Basin during 2018, as well as two to three completion crews during the year. We currently intend to finance our 2018 drilling, completion, and infrastructure capital expenditure plan primarily from the sources described below under “—Sources and Uses of Cash.” Our capital program could vary depending upon various factors, including, but not limited to, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestitures of oil and gas properties, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. The following is a summary of our 2017 capital expenditures:

	Three Months Ended									Year Ended
	March 31, 2017		June 30, 2017		September 30, 2017		December 31, 2017			December 31, 2017
	(In thousands)
Drilling, completion, and infrastructure
Eagle Ford		$111,472		$129,933		$122,281		$100,323			$464,009
Delaware Basin	10,360		11,727		36,055		102,078			160,220
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)
Leasehold and seismic	14,516		34,447		11,819		4,549			65,331
Total (2)		$142,760		$182,841		$176,853		$214,901			$717,355

(1) Includes amounts related to the divested assets in the Utica, Marcellus, Niobrara and Eagle Ford of approximately $22.1 million and $30.2 million for the three months ended December 31,2017 and for the year ended December 31,2017, respectively, which consists of drilling and completion capital expenditures incurred between the effective date and close date of the divestitures. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Notes to our Consolidated Financial Statements for further details of these divestitures.

(2) Capital expenditures exclude acquisitions of oil and gas properties, capitalized general and administrative expense, interest expense and asset retirement costs.

Sources and Uses of Cash. Our primary use of cash is related to our drilling, completion and infrastructure capital expenditures and, to a lesser extent, our leasehold and seismic capital expenditures. For the year ended December 31,2017, we funded our capital expenditures with cash provided by operations and borrowings under our revolving credit facility. Potential sources of future liquidity include the following:

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• Cash provided by operations. Cash flows from operations are highly dependent on crude oil prices. As such, we hedge a portion of our forecasted production to reduce our exposure to commodity price volatility in order to achieve a more predictable level of cash flows.

• Borrowings under revolving credit facility. As of February 23, 2018, our revolving credit facility had a borrowing base of $830.0 million, with an elected commitment amount of $800.0 million, with $141.0 million borrowings outstanding and no letters of credit issued, which reduce the amounts available under our revolving credit facility. In connection with the divestiture of a portion of our Eagle Ford acreage, the borrowing base was reduced from $900.0 million to $830.0 million effective with the closing of the divestiture on January 31, 2018; however, the elected commitment amount of $800.0 million remained unchanged. The amount we are able to borrow is subject to compliance with the financial covenants and other provisions of the credit agreement governing our revolving credit facility.

• Securities offerings. As situations or conditions arise, we may choose to issue debt, equity or other securities to supplement our cash flows. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all. See “Note 6. Long-term Debt” of the Notes to our Consolidated Financial Statements for details of the issuance of the 8.25% Senior Notes, “Note 9. Preferred Stock and Warrants” of the Notes to our Consolidated Financial Statements for details of the Preferred Stock issuance and “Note 10. Shareholders’ Equity and Stock-Based Compensation” of the Notes to our Consolidated Financial Statements for details of the recent common stock offering.

• Divestitures. We may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Notes to our Consolidated Financial Statements for further details of the divestitures that occurred in late 2017 and early 2018.

• Joint ventures. Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage or purchase a portion of interests, or both.

Overview of Cash Flow Activities. Net cash provided by operating activities from continuing operations was $423.0 million, $272.8 million and $378.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. The increase from 2016 to 2017 was driven primarily by an increase in revenues as a result of higher production and commodity prices and a decrease in working capital requirements, partially offset by a decrease in the net cash received from derivative settlements and an increase in operating expenses and cash general and administrative expense. The decrease from 2015 to 2016 was due primarily to a decrease in the net cash received from derivative settlements and an increase in working capital requirements.

Net cash used in investing activities from continuing operations was $1,159.5 million, $619.8 million and $673.4 million for the years ended December 31, 2017, 2016 and 2015, respectively. The increase from 2016 to 2017 was due primarily to funding the ExL Acquisition and increased capital expenditures, primarily in the Eagle Ford Shale and the Delaware Basin, partially offset by increased net proceeds from divestitures of oil and gas properties, which primarily related to the divestitures of substantially all of our assets in the Marcellus Shale and Utica Shale as well as deposits received in connection with the divestitures of a portion of our assets in the Eagle Ford Shale and substantially all of our assets in the Niobrara. The decrease from 2015 to 2016 was due primarily to a reduction in our capital expenditures in 2016 as compared to 2015, partially offset by an increase related to the Sanchez Acquisition in the fourth quarter of 2016.

Net cash provided by financing activities from continuing operations for the years ended December 31, 2017, 2016 and 2015 was $741.8 million, $308.3 million and $330.8 million, respectively. The increase from 2016 to 2017 was due to net proceeds related to the issuance of the 8.25% Senior Notes, the sale of Preferred Stock, the sale of common stock, and increased borrowings net of repayments under our revolving credit facility in 2017 as compared to 2016, partially offset by the redemption of $150.0 million of the 7.50% Senior Notes, increased debt issuance costs related to the amendments to the credit agreement governing the revolving credit facility and dividends paid on the Preferred Stock. The decrease from 2015 to 2016 was primarily due to the proceeds from the issuance of common stock in March and October 2015 and the issuance of the 6.25% Senior Notes in April 2015, partially offset by the tender and redemption of the 8.625% Senior Notes during the second quarter of 2015, the payment of the deferred purchase payment in February 2015, proceeds from the issuance of common stock in October 2016, and decreased borrowings net of repayments under our revolving credit facility in 2016 as compared to 2015.

Economic downturns may adversely affect our ability to access capital markets in the future. Cash flows from operations are primarily driven by crude oil production, crude oil prices, and settlements of our crude oil derivatives. We currently believe that cash flows from operations and borrowings under our revolving credit facility will provide adequate financial flexibility and will be sufficient to fund our immediate cash flow requirements.

• Revolving credit facility. The borrowing base under our revolving credit facility is affected by assumptions of the administrative agent with respect to, among other things, crude oil and natural gas prices. Our borrowing base may decrease if our administrative agent reduces the crude oil and natural gas prices from those used to determine our existing

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borrowing base. See “—Sources and Uses of Cash—Borrowings under our revolving credit facility” and “—Financing Arrangements—Senior Secured Revolving Credit Facility” for further details of our revolving credit facility.

• Divestitures. In the fourth quarter of 2017, we entered into purchase and sale agreements to sell substantially all of our assets in the Niobrara Formation and a portion of our assets in the Eagle Ford. Carrizo received aggregate net proceeds of $382.8 million for these divestitures, subject to post-closing adjustments, both of which closed in January 2018.

• Redemptions of 7.50% Senior Notes. In January 2018, we called for redemption a total of $320.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. The proceeds for these redemptions were primarily from the Niobrara and Eagle Ford divestitures discussed above. After these redemptions, we will have $130.0 million aggregate principal amount of 7.50% Senior Notes outstanding. As a result of these redemptions, we expect to record loss on extinguishment of debt of approximately $9.0 million during the first quarter of 2018.

• Redemption of Preferred Stock. In January 2018, we redeemed 50,000 of the shares of Preferred Stock for $50.5 million, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends.

• Contingent consideration. In connection with the ExL Acquisition, we 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. In connection with the sale of our Utica Shale assets, we could receive contingent consideration of $5.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2020. In connection with the sale of our Marcellus Shale assets, we could receive contingent consideration of $3.0 million per year if natural gas prices exceed specified thresholds for each of the years of 2018 through 2020 with a cap of $7.5 million. In connection with the sale of our Niobrara Formation assets, we could receive contingent consideration of $5.0 million per year if crude oil prices exceed specified thresholds for each of the years of 2018 through 2020. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Notes to our Consolidated Financial Statements for further details of each of these contingent considerations. See also “Item 7A. Qualitative and Quantitative Disclosures about Market Risk” for details of the sensitivities to commodity price of each contingent consideration.

• Hedging. To manage our exposure to commodity price risk and to provide a level of certainty in the cash flows to support our drilling, completion, and infrastructure capital expenditure plan, we hedge a portion of our forecasted production.

As of February 23, 2018, we had the following outstanding derivative positions at weighted average contract prices:

Crude Oil Fixed Price Swaps

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	)

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

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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 Fixed Price Swaps

Period	Volumes (MMBtu/d)	NYMEX Price ($/MMBtu)
March 2018 - December 2018	25,000		$3.01

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

If cash flows from operations and borrowings under our revolving credit facility and the other sources of cash described

under “—Sources and Uses of Cash” are insufficient to fund our remaining 2018 drilling, completion, and infrastructure capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer a portion of our remaining 2018 drilling, completion, and infrastructure capital expenditure plan, thereby potentially adversely affecting the recoverability and ultimate value of our oil and gas properties. Based on existing market conditions and our expected liquidity needs, among other factors, we may use a portion of our cash flows from operations, proceeds from divestitures, securities offerings or borrowings to reduce debt or Preferred Stock prior to scheduled maturities through debt or Preferred Stock repurchases, either in the open market or in privately negotiated transactions, through debt or Preferred Stock redemptions or tender offers, or through repayments of bank borrowings.

Contractual Obligations

The following table sets forth estimates of our contractual obligations as of December 31, 2017 (in thousands):

	2018		2019		2020		2021		2022		2023 and Thereafter		Total
Long-term debt (1)		$—		$—		$450,000		$—		$291,300		$904,425		$1,645,725
Cash interest on senior notes and other long-term debt (2)	98,260		95,194		95,194		61,444		61,444		83,236		494,772
Cash interest and commitment fees on revolving credit facility (3)	12,795		12,795		12,795		12,795		4,407		—		55,587
Capital leases	1,823		1,800		1,050		—		—		—		4,673
Operating leases	5,038		4,895		4,637		4,450		1,854		—		20,874
Drilling rig contracts (4)	23,885		8,881		—		—		—		—		32,766
Delivery commitments (5)	3,657		3,676		2,757		2,438		10		26		12,564
Asset retirement obligations and other (6)	2,115		479		300		132		229		22,821		26,076
Total Contractual Obligations (7)		$147,573		$127,720		$566,733		$81,259		$359,244		$1,010,508		$2,293,037

(1) Long-term debt consists of the principal amounts of the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, the 8.25% Senior Notes due 2025, other long-term debt due 2028, and borrowings outstanding under our revolving credit facility which matures in 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced on or prior to such time).

(2) Cash interest on senior notes and other long-term debt includes cash payments for interest on the 7.50% Senior Notes due 2020, the 6.25% Senior Notes due 2023, the 8.25% Senior Notes due 2025 and other long-term debt due 2028.

(3) Cash interest on our revolving credit facility was calculated using the weighted average interest rate of the outstanding borrowings under the revolving credit facility as of December 31, 2017 of 3.73%. Commitment fees on our revolving credit facility were calculated based on the unused portion of lender commitments as of December 31, 2017, at the applicable commitment fee rate of 0.375%.

(4) 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.

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(5) 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.

(6) Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of December 31, 2017. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. See “Note 2. Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for further discussion of estimates and assumptions that may affect the reported amounts.

(7) In connection with the ExL Acquisition, we have 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

In January and February 2018, we extended two of our current 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, we 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 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.

Off Balance Sheet Arrangements

We currently do not have any off balance sheet arrangements.

Financing Arrangements

Senior Secured Revolving Credit Facility

We have a senior secured revolving credit facility with a syndicate of banks that, as of December 31, 2017, had a borrowing base of $900.0 million, with an elected commitment amount of $800.0 million, and $291.3 million of borrowings outstanding at a weighted average interest rate of 3.73%. As of December 31, 2017, we had $0.4 million in letters of credit outstanding, which reduce the amounts available under the revolving credit facility. The credit agreement governing our senior secured revolving credit facility provides for interest-only payments until May 4, 2022, when the credit agreement matures (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced on or prior to such time) and any outstanding borrowings are due.

Upon issuance of the 8.25% Senior Notes (described below), in accordance with the credit agreement governing the revolving credit facility, our borrowing base was reduced by 25% of the aggregate principal amount of the 8.25% Senior Notes, reducing the borrowing base from $900.0 million to $837.5 million. As a result of the Fall 2017 borrowing base redetermination, the borrowing base was established at $900.0 million, with an elected commitment amount of $800.0 million, until the next redetermination thereof. The calculation of the Fall 2017 borrowing base was supported solely by the reserves of our Eagle Ford and Delaware Basin assets. The borrowing base under our credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base.

On May 4, 2017, we entered into a ninth amendment to our credit agreement governing the revolving credit facility to, among other things, extend the maturity date, increase the maximum credit amount, and increase the borrowing base. On June 28, 2017, we entered into a tenth amendment to the credit agreement governing the revolving credit facility to, among other things, amend certain financial and restricted payments covenants as well as amend certain definitions. On November 3, 2017, we entered into an eleventh amendment to the credit agreement governing the revolving credit facility to, among other things establish the borrowing base at $900.0 million, with an elected commitment amount of $800.0 million, and increase the general basket available for restricted payments.

See “Note 6. Long-Term Debt” of the Notes to our Consolidated Financial Statements for additional details of the ninth, tenth and eleventh amendments, rates of interest on outstanding borrowings, commitment fees on the unused portion of lender commitments, and the financial covenants we are subject to under the terms of the credit agreement.

Preferred Stock Purchase Agreement

On June 28, 2017, we entered into a Preferred Stock Purchase Agreement with the GSO Funds to issue and sell in a private placement (i) $250.0 million (250,000 shares) of Preferred Stock and (ii) Warrants for 2,750,000 shares of our common stock, with a term of ten years and an exercise price of $16.08 per share, for a cash purchase price equal to $970.00 per share of Preferred Stock purchased. We paid the GSO Funds $5.0 million as a commitment fee upon signing the Preferred Stock Purchase Agreement. The closing of the private placement occurred on August 10, 2017 contemporaneously with the closing of the ExL Acquisition. We received net proceeds of approximately $236.4 million, net of issuance costs, from the issuance and sale of the Preferred Stock

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and Warrants, which were used to fund a portion of the purchase price of the ExL Acquisition. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” of the Notes to our Consolidated Financial Statements for further details of the ExL Acquisition and “Note 9. Preferred Stock and Warrants” of the Notes to our Consolidated Financial Statements for further details regarding the Preferred Stock and Warrants.

Common Stock Offering

On July 3, 2017, we completed a public offering of 15.6 million shares of our common stock at a price per share of $14.28. We used the net proceeds of $222.4 million, net of offering costs, to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes.

8.25% Senior Notes due 2025

On July 14, 2017, we closed a public offering of $250.0 million aggregate principal amount of 8.25% Senior Notes due 2025. The 8.25% Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. We used the net proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs, to fund a portion of the purchase price for the ExL Acquisition and for general corporate purposes. See “Note 6. Long-Term Debt” of the Notes to our Consolidated Financial Statements for further details regarding the 8.25% Senior Notes.

7.50% Senior Notes due 2020

On November 28, 2017, we delivered a notice of redemption to the trustee for our 7.50% Senior Notes to call for redemption on December 28, 2017, $150.0 million aggregate principal amount of the 7.50% Senior Notes then outstanding. On December 28, 2017, we paid an aggregate redemption price of $156.0 million, which included a redemption premium of $2.8 million as well as accrued and unpaid interest of $3.2 million from the last interest payment date up to, but not including, the redemption date. As a result of the redemption, we recorded a loss on extinguishment of debt of $4.2 million, which includes the redemption premium paid to redeem the notes and non-cash charges of $1.3 million attributable to the write-off of unamortized premium and debt issuance costs associated with the 7.50% Senior Notes. See “Note 6. Long-Term Debt” of the Notes to our Consolidated Financial Statements for further details regarding the 7.50% Senior Notes. See “Note 15. Subsequent Events (Unaudited)” of the Notes to our Consolidated Financial Statements for details of the redemptions of our 7.50% Senior Notes that occurred subsequent to December 31, 2017.

Changes in Prices and Effects of Inflation

Our results of operations and operating cash flows are affected by changes in oil and gas prices. Natural gas prices have declined significantly since mid-2008 and continue to remain depressed. More recently, crude oil prices have declined significantly since 2014, which has adversely affected our results of operations. However crude oil prices have rebounded from the lowest prices in early 2016. If crude oil prices weaken from their current position, it is expected to have a significant impact on future results of operations and operating cash flows. Historically, inflation has had a minimal effect on us. However, with interest rates at historic lows and the government attempting to stimulate the economy through rapid expansion of the money supply in recent years, inflation could become a significant issue in the future.

Summary of Critical Accounting Policies

The following summarizes our critical accounting policies. See a complete list of significant accounting policies in “Note 2. Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We evaluate subsequent events through the date the financial statements are issued.

Significant estimates include volumes of proved oil and gas reserves, which are used in calculating DD&A of proved oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated costs and timing of cash outflows underlying asset retirement obligations. Oil and gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title and drilling requirements. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil and gas reserves, oil and gas prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in our estimates. Other significant estimates

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are involved in determining acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of derivative assets and liabilities, fair values of contingent consideration, preferred stock fair value upon issuance, grant date fair value of stock-based awards, and evaluating disputed claims, interpreting contractual arrangements and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling and completion, testing and production as well as subsequent changes in oil and gas prices, interest rates and the market value and volatility of our common stock.

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to cost centers established on a country-by-country basis. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either proved or unproved oil and gas properties based on the type of activity and totaled $14.8 million, $10.5 million and $15.8 million for the years ended December 31, 2017, 2016 and 2015, respectively. Internal costs related to production, general corporate overhead and similar activities are expensed as incurred.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to proved oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average DD&A per Boe of proved oil and gas properties was $13.09, $13.50 and $22.05 for the years ended December 31, 2017, 2016 and 2015, respectively.

Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Individually significant unevaluated leaseholds 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 reclassified to proved oil and gas properties. Factors we consider in our impairment assessment include drilling results by us and other operators, the terms of oil and gas leases not held by production and drilling, completion, and infrastructure capital expenditure plans. Individually insignificant unevaluated leaseholds are grouped by major area and added to proved oil and gas properties based on the average primary lease term of the properties. Geological and geophysical costs not associated with specific prospects are recorded to proved oil and gas property costs as incurred. We capitalized interest costs to unproved properties totaling $28.3 million, $17.0 million and $32.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings.

Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of proved oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For the years ended December 31, 2017, 2016 and 2015, we did not have any sales of oil and gas properties that significantly altered such relationship.

Impairment of Proved Oil and Gas Properties

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 average realized prices for sales of crude oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments as we elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment.

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We did not recognize impairments of proved oil and gas properties for the year ended December 31,2017. Primarily due to declines in the 12-Month Average Realized Prices of crude oil, we recognized impairments of proved oil and gas properties for the years ended December 31, 2016 and 2015. Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2017, 2016 and 2015 and the impairments of proved oil and gas properties for the years ended December 31, 2016 and 2015 are summarized in the table below: 

	Years Ended December 31,
	2017			2016		2015
Impairment of proved oil and gas properties (in thousands)		$—		$576,540		$1,224,367
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period	$39.60			$47.24		$92.24
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period	$49.87			$39.60		$47.24
Crude Oil 12-Month Average Realized Price percentage increase (decrease) during period	26		%	(16	%)	(49	%)

The table below presents various pricing scenarios to demonstrate the sensitivity of our December 31, 2017 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of December 31, 2017 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to December 31, 2017 that may require revisions to estimates of proved reserves. See also Part I, “Item 1A. Risk Factors—If crude oil and natural gas prices decline to near or below 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.”

	12-Month Average Realized Prices		Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
December 31, 2017 Actual	$49.87	$2.96	$677
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$55.00	$3.27	$1,212	$535
Crude Oil and Natural Gas -10%	$44.74	$2.65	$149	($528)
Crude Oil Price Sensitivity
Crude Oil +10%	$55.00	$2.96	$1,164	$487
Crude Oil -10%	$44.74	$2.96	$196	($481)
Natural Gas Price Sensitivity
Natural Gas +10%	$49.87	$3.27	$725	$48
Natural Gas -10%	$49.87	$2.65	$630	($47)

Oil and Gas Reserve Estimates

The proved oil and gas reserve estimates as of December 31, 2017 included in this document have been prepared by Ryder Scott Company, L.P., (“Ryder Scott”), independent third party reserve engineers. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on judgment and the interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires assumptions regarding drilling and operating costs, taxes and availability of funds. The oil and gas reserve estimation and disclosure requirements mandate certain of these assumptions such as existing economic and operating conditions, average crude oil and natural gas prices and the discount rate.

Proved oil and gas reserve estimates prepared by others may be substantially higher or lower than Ryder Scott’s estimates. Significant assumptions used in the proved oil and gas reserve estimates are assessed by both Ryder Scott and our internal reserve team. All reserve reports prepared by Ryder Scott are reviewed by our senior management team, including the Chief Executive Officer and Chief Operating Officer. Because these estimates depend on many assumptions, all of which may differ from actual

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results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing, and production.

It should not be assumed that the present value of future net cash flows is the current market value of our estimated proved oil and gas reserves. In accordance with the oil and gas reserve estimation and disclosure requirements, the discounted future net cash flows from proved reserves are based on the unweighted average of the first day of the month price for each month in the previous twelve-month period, using current costs and a 10% discount rate.

Our depletion rate depends on our estimate of total proved reserves. If our estimates of total proved reserves increased or decreased, the depletion rate and therefore DD&A expense of proved oil and gas properties would decrease or increase, respectively.

Derivative Instruments

We use commodity derivative instruments to reduce our exposure to commodity price volatility for a portion of our forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support our drilling, completion, and infrastructure capital expenditure program. All derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. We net our commodity derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As we have elected not to meet the criteria to qualify our derivative instruments for hedge accounting treatment, gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from operating activities. We do not enter into derivative instruments for speculative or trading purposes.

Our Board of Directors establishes risk management policies and, on a quarterly basis, reviews its commodity derivative instruments, including volumes, types of instruments and counterparties. These policies require that commodity derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board.

We have entered into agreements for acquisitions and divestitures of oil and gas properties that include obligations to pay the seller or rights to receive from the buyer, respectively, additional consideration if commodity prices exceed certain thresholds during certain specified periods in the future. These contingent consideration liabilities and assets are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheet, with subsequent changes in fair value recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. Cash payments made to settle contingent consideration liabilities are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities.

Preferred Stock and Warrants

We apply the accounting standards for distinguishing liabilities from equity when determining the classification and measurement of preferred stock. Preferred stock that is not mandatorily redeemable is excluded from liability classification and is evaluated for classification in shareholders’ equity or temporary equity. As the number of common shares that could be delivered upon the holders’ optional redemption is indeterminate, we cannot assert that we will be able to settle in shares of our common stock and, as a result, presents preferred stock as temporary equity. On a quarterly basis, we reassess the presentation of preferred stock in the consolidated balance sheets.

When preferred stock is issued in conjunction with warrants, the warrants are evaluated separately as a freestanding financial instrument to determine whether they must be recorded as a derivative instrument. We further evaluate the warrants for equity classification and have determined that the warrants qualify for equity classification and, therefore, are presented in additional paid-in capital in the consolidated balance sheets. The preferred stock and warrants are recorded based on the net proceeds received allocated to the two instrument’s relative fair values. The preferred stock is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The warrants do not require further adjustments from their relative fair value at the issuance date.

Dividends and accretion associated with preferred stock are presented in the consolidated statements of operations as reductions to net income, or increases of net loss, to derive net income (loss) attributable to common shareholders. Dividend payments are presented as a financing activity in the consolidated statement of cash flows.

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative

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temporary differences between the tax bases of assets and liabilities and their reported amounts in our financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. As a result of the 2017 Tax Cuts and Jobs Act that was enacted on December 22, 2017, the federal statutory corporate income tax rate was reduced from 35% to 21% effective January 1, 2018. The deferred tax assets and liabilities at December 31, 2017 were re-measured taking into account the new enacted federal statutory corporate income tax rate for which those deferred tax balances were expected to be realized. See “Note 5. Income Taxes” of the Notes to our Consolidated Financial Statements for further discussion. We assess the realizability of our deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. We consider all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, we evaluated possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies.

A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2017, driven primarily by the impairments of proved oil and gas properties beginning in the third quarter of 2015 and continuing through the third quarter of 2016, which limits the ability to consider other subjective evidence such as our potential for future growth. We also have estimated U.S. federal net operating loss carryforwards of $1,096.2 million as of December 31, 2017. Beginning in the third quarter of 2015, and continuing through the fourth quarter of 2017, we concluded that it was more likely than not the deferred tax assets will not be realized. As a result, the net deferred tax assets at the end of each quarter, including December 31, 2017, were reduced to zero.

As a result of adopting ASU 2016-09, we recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero and brought the valuation allowance to $580.1 million as of January 1, 2017.

During the year ended December 31,2017, the valuation allowance was reduced by $247.1 million. This was primarily due to the re-measurement of our deferred tax assets as a result of the Tax Cuts and Jobs Act as mentioned above, which resulted in a reduction of $211.7 million, as well as partial releases of $35.4 million, as a result of current year activity. After the impact of the re-measurement and the partial releases, the valuation allowance as of December 31, 2017 was $333.0 million.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income.

We classify interest and penalties associated with income taxes as interest expense. We apply the tax law ordering approach to determine the sequence in which deferred tax assets and other tax attributes are utilized.

Commitments and Contingencies

Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable. See “Note 8. Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for further detail.

Recent Accounting Pronouncements

See “Note 2. Summary of Significant Accounting Policies - Recent Accounting Pronouncements” of the Notes to our Consolidated Financial Statements for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards Board.

Volatility of Crude Oil and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial position and ability to borrow funds or obtain additional capital are substantially dependent upon prevailing prices of crude oil, which are affected by changes in market supply and demand, overall economic activity, global political environment, weather, inventory storage levels and other factors, as well as the level and prices at which we have hedged our future production.

We review the carrying value of our oil and gas properties on a quarterly basis under the full cost method of accounting. See “—Summary of Critical Accounting Policies—Impairment of Proved Oil and Gas Properties.” See also Part I, “Item 1A. Risk Factors—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” and “Note 4. Property and Equipment, Net” of the Notes to our Consolidated Financial Statements.

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We use commodity derivative instruments to reduce our exposure to commodity price volatility for a portion of our forecasted production and thereby achieve a more predictable level of cash flows to support our drilling, completion, and infrastructure capital expenditure program. We do not enter into derivative instruments for speculative or trading purposes. As of December 31, 2017, our commodity derivative instruments consisted of fixed price swaps, basis swaps, three-way collars and purchased and sold call options. See “Note 11. Derivative Instruments” of the Notes to our Consolidated Financial Statements for further details of our crude oil, NGL, and natural gas derivative positions as of December 31, 2017 and “Note 15. Subsequent Events (Unaudited)” of the Notes to our Consolidated Financial Statements for further details of our natural gas derivative positions entered into subsequent to December 31, 2017.

We determined that the Contingent ExL Consideration, the Contingent Utica Consideration, and the Contingent Marcellus Consideration are not clearly and closely related to the purchase and sale agreement for the applicable acquisition or divestiture, and therefore bifurcated these embedded features and reflected the associated assets and liabilities at fair value in the consolidated financial statements. The fair values of the contingent consideration were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” of the Notes to our Consolidated Financial Statements for further details.

Item 7A. Qualitative and Quantitative Disclosures about Market Risk

Commodity Risk

Our primary market risk exposure is the commodity pricing applicable to our oil and gas production. The prices we realize on the sale of such production are primarily driven by the prevailing worldwide price for oil and spot prices of natural gas. The effects of such pricing volatility have been discussed above, and such volatility is expected to continue. A 10% fluctuation in the price received for oil production, excluding the impact of derivative settlements, would have an approximate $63.3 million impact on our revenues and a 10% fluctuation in the price received for gas production, excluding the impact of derivative settlements, would have an approximate $6.5 million impact on our revenues for the year ended December 31, 2017.

We use commodity derivative instruments to reduce our exposure to commodity price volatility for a portion of our forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support our drilling, completion and infrastructure capital expenditure program. We do not enter into derivative instruments for speculative or trading purposes. As of December 31, 2017, our commodity derivative instruments consisted of fixed price swaps, basis swaps, three-way collars and purchased and sold call options. For the years ended December 31, 2017, 2016 and 2015, we recorded in the consolidated statements of operations a loss on derivatives, net of $59.1 million and $49.1 million and a gain on derivatives, net of $99.3 million, respectively. We also received net cash on derivative settlements of $7.8 million, $119.4 million and $194.3 million for the years ended December 31, 2017, 2016 and 2015, respectively, which are presented in the consolidated statements of cash flows.

We have entered into agreements for the acquisition and divestiture of oil and gas properties containing contingent consideration that are, or will be, required to be bifurcated and accounted for separately as derivative instruments as they are not clearly and closely related to the host contract. We record the contingent consideration in the consolidated balance sheets measured at acquisition or divestiture date fair value, with gains and losses as a result of changes in the fair value of the contingent consideration recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur.

The following table sets forth the fair values as of December 31, 2017 as well as the impact on the fair values assuming a 10% increase and a 10% decrease in the respective commodity prices:

	Contingent ExL Consideration			Contingent Utica Consideration		Contingent Marcellus Consideration
	(In thousands)
Potential (payment) receipt per year		($50,000	)		$5,000		$3,000
Maximum potential (payment) receipt		($125,000	)		$15,000		$7,500
Fair value as of December 31, 2017		($85,625	)		$7,985		$2,205
10% increase in commodity price	(96,610		)	9,405		3,050
10% decrease in commodity price	(65,765		)	5,725		1,450

Financial Instruments and Debt Maturities

In addition to our derivative instruments, our other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of our 7.50% Senior Notes, 6.25% Senior Notes, 8.25% Senior Notes and other long-term debt as of December 31, 2017 were estimated at approximately $459.5 million,

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$674.4 million, $274.4 million and $4.4 million, respectively, and were based on quoted market prices. As of December 31, 2017, scheduled maturities of debt are $450.0 million in 2020, $650.0 million in 2023, $250.0 million in 2025 and $4.4 million in 2028. We had $291.3 million of borrowings outstanding under our revolving credit facility as of December 31, 2017.

Item 8. Financial Statements and Supplementary Data

The financial statements and information required by this Item appears on pages F-1 through F-47 of this Annual Report on Form 10-K.

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosures

None.

Item 9A. Controls and Procedures

(a) Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

In accordance with Rules 13a-15(b) and 15d-15(b) under the Exchange Act, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. As described below under paragraph (b) within Management’s Annual Report on Internal Control over Financial Reporting, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

The audit report of Ernst & Young LLP which is included in this Annual Report on Form 10-K, expressed an unqualified opinion on our consolidated financial statements.

(b) Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

While “reasonable assurance” is a high level of assurance, it does not mean absolute assurance. Because of its inherent limitations, internal control over financial reporting may not prevent or detect every misstatement and instance of fraud. Controls are susceptible to manipulation, especially in instances of fraud caused by collusion of two or more people, including our senior management. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017. In making this evaluation, management used the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring

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Organizations of the Treadway Commission (“COSO”). Based on the results of our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2017.

Ernst & Young LLP, our independent registered public accounting firm that audited our consolidated financial statements, has also issued its own audit report on the effectiveness of our internal control over financial reporting as of December 31, 2017, which is filed with this Annual Report on Form 10-K.

(c) Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated herein by reference to our definitive Proxy Statement (the “2018 Proxy Statement”) for our 2018 annual meeting of shareholders to be held on May 22, 2018. The 2018 Proxy Statement will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

Item 11. Executive Compensation

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

Item 14. Principal Accounting Fees and Services

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

Refer to the Index to Consolidated Financial Statements on page F-1 of this Form 10-K for a list of all financial statements filed as part of this report.

(a)(2) Financial Statement Schedules

Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company's consolidated financial statements and related notes.

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(a)(3) Exhibits

EXHIBIT INDEX

Exhibit Number		Description
†+2.1	—	Purchase and Sale Agreement dated as of June 28, 2017 by and among ExL Petroleum Management, LLC, ExL Petroleum Operating Inc., Carrizo Oil & Gas, Inc., and Carrizo (Permian) LLC (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed June 28, 2017 (File No. 000-29187-87)).
+2.2	—	Purchase and Sale Agreement dated December 9, 2017 between Carrizo Oil & Gas, Inc., Carrizo (Eagle Ford) LLC, and EP Energy E&P Company, L.P., as amended by that certain Closing Agreement and Amendment to Purchase and Sale Agreement dated as of January 31, 2018 between the parties thereto.
†3.1	—	Amended and Restated Articles of Incorporation of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-29187-87)).
†3.2	—	Articles of Amendment to Amended and Restated Articles of Incorporation of Carrizo Oil & Gas, Inc. dated as of June 24, 2008 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 25, 2008 (File No. 000-29187-87)).
†3.3	—	Articles of Amendment to Amended and Restated Articles of Incorporation of Carrizo Oil & Gas, Inc. dated as of May 16, 2017 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on May 16, 2017 (File No. 000-29187087)).
†3.4	—	Composite Articles of Incorporation of Carrizo Oil & Gas, Inc., giving effect to all amendments through May 16, 2017 (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on May 16, 2017 (File No. 000-29187087)).
†3.5	—	Statement of Resolutions Establishing Series of 8.875% Redeemable Preferred Stock of Carrizo Oil & Gas, Inc., effective August 10, 2017 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 11, 2017 (File No. 000-29187087)).
†3.6	—	Amended and Restated Bylaws of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 19, 2015 (File No. 000-29187-87)).
†4.1	—	Indenture dated May 28, 2008 among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 28, 2008 (File No. 000-29187-87)).
†4.2	—	First Supplemental Indenture dated May 28, 2008 between Carrizo Oil & Gas, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on May 28, 2008 (File No. 000-29187-87)).
†4.3	—	Second Supplemental Indenture dated May 14, 2009 among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.21 to the Company’s Registration Statement on Form S-3 (Registration No. 333-159237)).
†4.4	—	Third Supplemental Indenture dated October 19, 2009 among Carrizo Oil & Gas, Inc., the subsidiary named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.19 to the Company’s Registration Statement on Form S-3 (Registration No. 333-159237)).
†4.5	—	Fourth Supplemental Indenture dated November 2, 2010 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on November 2, 2010 (File No. 000-29187-87)).
†4.6	—	Fifth Supplemental Indenture dated November 2, 2010 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on November 2, 2010 (File No. 000-29187-87)).
†4.7	—	Sixth Supplemental Indenture dated May 4, 2011 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 000-29187-87)).

66

†4.8	—	Seventh Supplemental Indenture dated May 4, 2011 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 000-29187-87)).
†4.9	—	Eighth Supplemental Indenture dated August 5, 2011 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 000-29187-87)).
†4.10	—	Ninth Supplemental Indenture dated August 5, 2011 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 000-29187-87)).
†4.11	—	Tenth Supplemental Indenture among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee, dated as of September 10, 2012 (incorporated herein by reference to Exhibit 4.2 to the Company Current Report on Form 8-K filed on September 13, 2012 (File No. 000-29187-87)).
†4.12	—	Eleventh Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
†4.13	—	Twelfth Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
†4.14	—	Thirteenth Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
†4.15	—	Fourteenth Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
†4.16	—	Fifteenth Supplemental Indenture dated October 30, 2014 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 30, 2014 (File No. 000-29187-87)).
†4.17	—	Sixteenth Supplemental Indenture dated April 28, 2015 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on April 28, 2015 (File No. 000-29187-87)).
†4.18	—	Seventeenth Supplemental Indenture dated May 20, 2015 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 22, 2015 (File No. 000-29187-87)).
†4.19	—	Eighteenth Supplemental Indenture dated May 20, 2015 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on May 22, 2015 (File No. 000-29187-87)).
†4.20	—	Nineteenth Supplemental Indenture dated May 20, 2015 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on May 22, 2015 (File No. 000-29187-87)).
†4.21	—	Twentieth Supplemental Indenture dated July 14, 2017 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on July 14, 2017 (File No. 000-29187-87)).

67

†4.22	—	Officers’ Certificate of Carrizo Oil & Gas, Inc. dated as of November 17, 2011 (incorporated herein by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed on November 17, 2011 (File No. 000-29187-87)).
†4.23	—	Officers’ Certificate of Carrizo Oil & Gas, Inc. dated as of February 23, 2015 (incorporated herein by reference to Exhibit 4.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 000-29187-87)).
†4.24	—	Warrant Agreement, dated as of August 10, 2017, between Carrizo Oil & Gas, Inc. and Wells Fargo Bank, N.A., as warrant agent (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on August 11, 2017 (File No. 000-29187087)).
*†10.1	—	Amended and Restated Incentive Plan of Carrizo Oil & Gas, Inc. effective as of May 15, 2014 (the “2014 Incentive Plan”) (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 16, 2014 (File No. 000-29187-87)).
*†10.2	—	2017 Incentive Plan of Carrizo Oil & Gas, Inc. effective as of May 16, 2017 (the “2017 Incentive Plan”) (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 16, 2017 (File No. 000-29187087)).
*†10.3	—	Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (incorporated herein by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K filed on June 9, 2009 (File No. 000-29187-87)).
*†10.4	—	Form of Employment Agreement between Carrizo Oil & Gas, Inc. and future executive officers as of May 1, 2015 (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly report on Form 10-Q for the quarter ended March 31, 2015 (File No. 000-29187-87)).
*†10.5	—	Form of Employment Agreement between Carrizo Oil & Gas, Inc. and future non-executive officers as of May 1, 2015 (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly report on Form 10-Q for the quarter ended March 31, 2015 (File No. 000-29187-87)).
*†10.6	—	Amended and Restated Employment Agreement between the Company and S.P. Johnson IV (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 9, 2009 (File No. 000-29187-87)).
*†10.7	—	Amended and Restated Employment Agreement between the Company and J. Bradley Fisher (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on June 9, 2009 (File No. 000-29187-87)).
*†10.8	—	Amended and Restated Employment Agreement between the Company and Richard H. Smith (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on June 9, 2009 (File No. 000-29187-87)).
*†10.9	—	Employment Agreement between the Company and David L. Pitts (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 20, 2010 (File No. 000-29187-87)).
*†10.10	—	Employment Agreement between the Company and Gregory F. Conaway (incorporated herein by reference to Exhibit 10.10 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 100-29187-87)).
*†10.11	—	Employment Agreement between the Company and Gerald A. Morton (incorporated herein by reference to Exhibit 10.11 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 (File No. 100-29187-87)).
*†10.12	—	Form of Employee Restricted Stock Award Agreement (Officer) under the 2014 Incentive Plan (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 17, 2013 (File No. 000-29187-87)).
*†10.13	—	Form of Employee Restricted Stock Unit Award Agreement (Officer) under the 2014 Incentive Plan (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on June 17, 2013 (File No. 000-29187-87)).
*†10.14	—	Form of Employee Performance Share Award Agreement under the 2014 Incentive Plan (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 (File No. 000-29187-87)).
*†10.15	—	Form of Employee Stock Appreciation Rights Agreement (Officer) under the 2014 Incentive Plan (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on June 17, 2013 (File No. 000-29187-87)).

68

*†10.16	—	Form of Employee Stock Appreciation Rights Agreement (Officer) under the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on June 17, 2013 (File No. 000-29187-87)).
*†10.17	—	Form of Director Restricted Stock Unit Agreement under the 2017 Incentive Plan (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 16, 2017 (File No. 000-29187-87)).
*†10.18	—	Form of Employee Restricted Stock Unit Agreement under the 2017 Incentive Plan (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on May 16, 2017 (File No. 000-29187-87)).
*10.19	—	Form of Employee Restricted Stock Agreement under the 2017 Incentive Plan.
*10.20	—	Form of Employee Performance Share Award Agreement (Officer) under the 2017 Incentive Plan.
*10.21	—	Form of Employee Stock Appreciation Rights Agreement (Officer) under the 2017 Incentive Plan.
*10.22	—	Form of Employee Stock Appreciation Rights Agreement (Officer) under the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan.
†10.23	—	Credit Agreement dated as of January 27, 2011 among Carrizo Oil & Gas, Inc., as Borrower, BNP Paribas, as Administrative Agent, Credit Agricole Corporate and Investment Bank and Royal Bank of Canada, as Co-Syndication Agents, Capital One, N.A. and Compass Bank, as Co-Documentation Agents, BNP Paribas Securities Corp. as Sole Lead Arranger and Sole Bookrunner, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 2, 2011 (File No. 000-29187-87)).
†10.24	—	First Amendment, dated as of March 26, 2012, to Credit Agreement dated as of January 27, 2011, among Carrizo Oil & Gas, Inc., BNP Paribas as administrative agent, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 (File No. 000-29187-87)).
†10.25	—	Second Amendment to Credit Agreement, dated as of September 4, 2012, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 5, 2012 (File No. 000-29187-87)).
†10.26	—	Third Amendment to Credit Agreement, dated as of September 27, 2012, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
†10.27	—	Fourth Amendment to Credit Agreement, dated as of October 9, 2013, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 11, 2013 (File No. 000-29187-87)).
†10.28	—	Fifth Amendment to Credit Agreement, dated as of October 7, 2014, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 9, 2014 (File No. 000-29187-87)).
†10.29	—	Sixth Amendment to Credit Agreement, dated as of May 5, 2015, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 (File No. 000-29187-87)).
†10.30	—	Seventh Amendment to Credit Agreement, dated as of October 30, 2015, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 (File No. 000-29187-87)).
†10.31	—	Eighth Amendment to Credit Agreement, dated as of May 3, 2016, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 4, 2016 (File No. 000-29187-87)).

69

†10.32	—	Ninth Amendment to Credit Agreement, dated as of May 4, 2017, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 10-Q filed on May 9, 2017 (File No. 000-29187-87)).
†10.33	—	Tenth Amendment to Credit Agreement, dated as of June 28, 2017, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 28, 2017 (File No. 000-29187087)).
†10.34	—	Eleventh Amendment to Credit Agreement, dated as of November 3, 2017, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 10-Q filed on November 9, 2017 (File No. 000-29187087)).
†10.35	—	Form of Indemnification Agreement between the Company and each of its directors and executive officers (incorporated herein by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-29187-87)).
†10.36	—	Form of Amendment to Director Indemnification Agreement (incorporated herein by reference to Exhibit 99.8 to the Company’s Current Report a Form 8-K filed February 27, 2002 (File No. 000-29187-87)).
†10.37	—	Preferred Stock Purchase Agreement dated as of June 28, 2017 between Carrizo Oil & Gas, Inc. and the purchasers named therein (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 28, 2017 (File No. 000-29187087)).
†10.38	—	Registration Rights Agreement dated as of August 10, 2017 between Carrizo Oil & Gas, Inc. and the GSO Funds party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 11, 2017 (File No. 000-29187087)).
†10.39	—	Standstill and Voting Agreement dated as of August 10, 2017 between Carrizo Oil & Gas, Inc. and the GSO Funds party thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 11, 2017 (File No. 000-29187087)).
21.1	—	Subsidiaries of the Company.
23.1	—	Consent of Ernst & Young LLP.
23.2	—	Consent of KPMG LLP.
23.3	—	Consent of Ryder Scott Company, L.P.
31.1	—	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	—	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	—	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	—	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	—	Summary of Reserve Report and Report of Ryder Scott Company, L.P. as of December 31, 2017.
101	—	Interactive Data Files.

†    Incorporated by reference as indicated.

*    Management contract or compensatory plan or arrangement.

+ Schedules to this exhibit have been omitted pursuant to Item 601(b) of Regulation S-K; a copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.

70

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	PAGE
Reports of Independent Registered Public Accounting Firms	F-2
Consolidated Balance Sheets as of December 31, 2017 and 2016	F-5
Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015	F-6
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2017, 2016 and 2015	F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015	F-8
Notes to Consolidated Financial Statements	F-9

F-1

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Carrizo Oil & Gas, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Carrizo Oil & Gas, Inc. (the Company) as of December 31, 2017, and the related consolidated statements of operations, shareholders’ equity and cash flows for the year then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017, and the results of its operations and its cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 28, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2017.

Houston, Texas

February 28, 2018

F-2

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Carrizo Oil & Gas, Inc.

Opinion on Internal Control over Financial Reporting

We have audited Carrizo Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Carrizo Oil & Gas, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet as of December 31, 2017, and the related consolidated statements of operations, shareholders’ equity and cash flows for the year then ended, and the related notes and our report dated February 28, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2018

F-3

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Carrizo Oil & Gas, Inc.:

We have audited the accompanying consolidated balance sheet of Carrizo Oil & Gas, Inc. and subsidiaries (the Company) as of December 31, 2016, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the two‑year period ended December 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Carrizo Oil & Gas, Inc. and subsidiaries as of December 31, 2016, and the results of their operations and their cash flows for each of the years in the two‑year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

February 27, 2017

F-4

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

	December 31,
	2017			2016
Assets
Current assets
Cash and cash equivalents		$9,540			$4,194
Accounts receivable, net	107,441			64,208
Other current assets	5,897			4,586
Total current assets	122,878			72,988
Property and equipment
Oil and gas properties, full cost method
Proved properties, net	1,965,347			1,294,667
Unproved properties, not being amortized	660,287			240,961
Other property and equipment, net	10,176			10,132
Total property and equipment, net	2,635,810			1,545,760
Other assets	19,616			7,579
Total Assets		$2,778,304			$1,626,327
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable		$74,558			$55,631
Revenues and royalties payable	52,154			38,107
Accrued capital expenditures	119,452			36,594
Accrued interest	28,362			22,016
Accrued lease operating expense	18,223			12,377
Derivative liabilities	57,121			22,601
Other current liabilities	22,952			24,633
Total current liabilities	372,822			211,959
Long-term debt	1,629,209			1,325,418
Asset retirement obligations	23,497			20,848
Derivative liabilities	112,332			27,528
Deferred income taxes	3,635			—
Other liabilities	51,650			17,116
Total liabilities	2,193,145			1,602,869
Commitments and contingencies
Preferred Stock
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	214,262			—
Shareholders’ equity
Common stock, $0.01 par value, 180,000,000 shares authorized; 81,454,621 issued and outstanding as of December 31, 2017 and 90,000,000 shares authorized; 65,132,499 issued and outstanding as of December 31, 2016	815			651
Additional paid-in capital	1,926,056			1,665,891
Accumulated deficit	(1,555,974		)	(1,643,084		)
Total shareholders’ equity	370,897			23,458
Total Liabilities and Shareholders’ Equity		$2,778,304			$1,626,327

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

F-5

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

	Years Ended December 31,
	2017			2016			2015
Revenues
Crude oil		$633,233			$378,073			$376,094
Natural gas liquids	47,405			22,428			15,608
Natural gas	65,250			43,093			37,501
Total revenues	745,888			443,594			429,203
Costs and Expenses
Lease operating	139,854			98,717			90,052
Production taxes	32,509			19,046			17,683
Ad valorem taxes	7,267			5,559			9,255
Depreciation, depletion and amortization	262,589			213,962			300,035
General and administrative, net	66,229			74,972			67,224
(Gain) loss on derivatives, net	59,103			49,073			(99,261		)
Interest expense, net	80,870			79,403			69,195
Impairment of proved oil and gas properties	—			576,540			1,224,367
Loss on extinguishment of debt	4,170			—			38,137
Other expense, net	2,157			1,796			11,276
Total costs and expenses	654,748			1,119,068			1,727,963
Income (Loss) From Continuing Operations Before Income Taxes	91,140			(675,474		)	(1,298,760		)
Income tax (expense) benefit	(4,030		)	—			140,875
Income (Loss) From Continuing Operations		$87,110			($675,474	)		($1,157,885	)
Income From Discontinued Operations, Net of Income Taxes	—			—			2,731
Net Income (Loss)		$87,110			($675,474	)		($1,155,154	)
Dividends on preferred stock	(7,781		)	—			—
Accretion on preferred stock	(862		)	—			—
Net Income (Loss) Attributable to Common Shareholders		$78,467			($675,474	)		($1,155,154	)
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$1.07			($11.27	)		($22.45	)
Diluted		$1.06			($11.27	)		($22.45	)
Weighted Average Common Shares Outstanding
Basic	73,421			59,932			51,457
Diluted	73,993			59,932			51,457

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

F-6

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands, except share amounts)

	Common Stock			Additional Paid-in Capital			Accumulated Deficit			Total Shareholders’ Equity
	Shares	Amount
Balance as of January 1, 2015	46,127,924		$461		$915,436			$187,544			$1,103,441
Stock options exercised for cash	2,433	—		46			—			46
Stock-based compensation expense	—	—		25,707			—			25,707
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units	630,723	6		(150		)	—			(144		)
Sale of common stock, net of offering costs	11,500,000	115		470,043			—			470,158
Other	71,913	1		(1		)	—			—
Net loss	—	—		—			(1,155,154		)	(1,155,154		)
Balance as of December 31, 2015	58,332,993		$583		$1,411,081			($967,610	)		$444,054
Stock-based compensation expense	—	—		31,194			—			31,194
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units	799,506	8		(63		)	—			(55		)
Sale of common stock, net of offering costs	6,000,000	60		223,679			—			223,739
Net loss	—	—		—			(675,474		)	(675,474		)
Balance as of December 31, 2016	65,132,499		$651		$1,665,891			($1,643,084	)		$23,458
Stock-based compensation expense	—	—		23,625			—			23,625
Issuance of common stock upon grants of restricted stock awards and vestings of restricted stock units and performance shares	722,122	8		(42		)	—			(34		)
Sale of common stock, net of offering costs	15,600,000	156		222,222			—			222,378
Issuance of warrants	—	—		23,003			—			23,003
Dividends on preferred stock	—	—		(7,781		)	—			(7,781		)
Accretion on preferred stock	—	—		(862		)	—			(862		)
Net income	—	—		—			87,110			87,110
Balance as of December 31, 2017	81,454,621		$815		$1,926,056			($1,555,974	)		$370,897

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

F-7

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2017			2016			2015
Cash Flows From Operating Activities
Net income (loss)		$87,110			($675,474	)		($1,155,154	)
Income from discontinued operations, net of income taxes	—			—			(2,731		)
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities from continuing operations
Depreciation, depletion and amortization	262,589			213,962			300,035
Impairment of proved oil and gas properties	—			576,540			1,224,367
(Gain) loss on derivatives, net	59,103			49,073			(99,261		)
Cash received for derivative settlements, net	7,773			119,369			194,296
Loss on extinguishment of debt	4,170			—			38,137
Stock-based compensation expense, net	14,309			36,086			14,729
Deferred income taxes	3,635			—			(140,875		)
Non-cash interest expense, net	3,657			4,172			4,289
Other, net	2,337			3,753			5,709
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(41,630		)	(12,836		)	29,781
Accounts payable	11,822			(30,130		)	(12,617		)
Accrued liabilities	11,512			(7,938		)	(17,517		)
Other assets and liabilities, net	(3,406		)	(3,809		)	(4,453		)
Net cash provided by operating activities from continuing operations	422,981			272,768			378,735
Net cash used in operating activities from discontinued operations	—			—			(1,368		)
Net cash provided by operating activities	422,981			272,768			377,367
Cash Flows From Investing Activities
Capital expenditures	(654,711		)	(480,929		)	(675,952		)
Acquisitions of oil and gas properties	(695,774		)	(153,521		)	(1,817		)
Net proceeds from divestitures of oil and gas properties	197,564			15,564			8,047
Other, net	(6,531		)	(946		)	(3,654		)
Net cash used in investing activities from continuing operations	(1,159,452		)	(619,832		)	(673,376		)
Net cash used in investing activities from discontinued operations	—			—			(2,678		)
Net cash used in investing activities	(1,159,452		)	(619,832		)	(676,054		)
Cash Flows From Financing Activities
Issuance of senior notes	250,000			—			650,000
Tender and redemptions of senior notes	(152,813		)	—			(626,681		)
Payment of deferred purchase payment	—			—			(150,000		)
Borrowings under credit agreement	1,992,523			770,291			1,126,860
Repayments of borrowings under credit agreement	(1,788,223		)	(683,291		)	(1,126,860		)
Payments of debt issuance costs and credit facility amendment fees	(9,051		)	(1,330		)	(12,420		)
Sale of common stock, net of offering costs	222,378			223,739			470,158
Sale of preferred stock, net of offering costs	236,404			—			—
Payment of dividends on preferred stock	(7,781		)	—			—
Proceeds from stock options exercised	—			—			46
Other, net	(1,620		)	(1,069		)	(336		)
Net cash provided by financing activities from continuing operations	741,817			308,340			330,767
Net cash provided by financing activities from discontinued operations	—			—			—
Net cash provided by financing activities	741,817			308,340			330,767
Net Increase (Decrease) in Cash and Cash Equivalents	5,346			(38,724		)	32,080
Cash and Cash Equivalents, Beginning of Year	4,194			42,918			10,838
Cash and Cash Equivalents, End of Year		$9,540			$4,194			$42,918

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

F-8

CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations

Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, the “Company”), is actively engaged in the exploration, development, and production of crude oil, NGLs, and gas from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas and the Permian Basin in West Texas.

2. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. The Company evaluates subsequent events through the date the financial statements are issued.

Significant estimates include volumes of proved oil and gas reserves, which are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated costs and timing of cash outflows underlying asset retirement obligations. Oil and gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title and drilling requirements. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil and gas reserves, oil and gas prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in the Company’s estimates. Other significant estimates are involved in determining acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of derivative assets and liabilities, fair values of contingent consideration, preferred stock fair value upon issuance, grant date fair value of stock-based awards, and evaluating disputed claims, interpreting contractual arrangements and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling and completion, testing and production as well as subsequent changes in oil and gas prices, interest rates and the market value and volatility of the Company’s common stock.

Cash and Cash Equivalents

Cash equivalents include highly liquid investments with original maturities of three months or less. Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The outstanding checks written against these zero-balance accounts have been classified as a component of accounts payable in the consolidated balance sheets and totaled $62.6 million and $34.3 million as of December 31, 2017 and 2016, respectively.

Accounts Receivable

As of December 31, 2017 payables due to related parties were less than $0.1 million and as of December 31, 2016, receivables due from related parties were $0.9 million. The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. As of December 31, 2017 and 2016, the Company’s allowance for doubtful accounts was $0.4 million and $0.8 million, respectively.

F-9

Concentration of Credit Risk

The Company’s accounts receivable consists primarily of receivables from oil and gas purchasers and joint interest owners in properties the Company operates. This concentration of accounts receivable from oil and gas purchasers and joint interest owners in the oil and gas industry may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company generally does not require collateral from its purchasers or joint interest owners. The Company generally has the right to withhold revenue distributions to recover past due receivables from joint interest owners.

Major Customers

Shell Trading (US) Company accounted for approximately 69%, 56%, and 65% of the Company’s total revenues in 2017, 2016, and 2015, respectively. Flint Hills Resources, LP, an indirect wholly owned subsidiary of Koch Industries, Inc. accounted for approximately 7%, 15% and 9% of the Company’s total revenues in 2017, 2016 and 2015, respectively.

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to cost centers established on a country-by-country basis. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either proved or unproved oil and gas properties based on the type of activity and totaled $14.8 million, $10.5 million and $15.8 million for the years ended December 31, 2017, 2016 and 2015, respectively. Internal costs related to production, general corporate overhead and similar activities are expensed as incurred.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to proved oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average DD&A per Boe of proved oil and gas properties was $13.09, $13.50 and $22.05 for the years ended December 31, 2017, 2016 and 2015, respectively.

Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Individually significant unevaluated leaseholds 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 reclassified to proved oil and gas properties. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling, completion, and infrastructure capital expenditure plans. Individually insignificant unevaluated leaseholds are grouped by major area and added to proved oil and gas properties based on the average primary lease term of the properties. Geological and geophysical costs not associated with specific prospects are recorded to proved oil and gas property costs as incurred. The Company capitalized interest costs to unproved properties totaling $28.3 million, $17.0 million and $32.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings.

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 average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment.

F-10

The Company did not recognize impairments of proved oil and gas properties for the year ended December 31, 2017. For the years ended December 31, 2016 and 2015, the Company recorded impairments of proved oil and gas properties of $576.5 million and $1,224.4 million, due primarily to declines in the 12-Month Average Realized Price of crude oil.

Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of proved oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For the years ended December 31, 2017, 2016 and 2015, the Company did not have any sales of oil and gas properties that significantly altered such relationship. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties.”

Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from three to ten years.

Debt Issuance Costs

Debt issuance costs associated with the revolving credit facility are amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are amortized to interest expense using the effective interest method over the terms of the related notes. Debt issuance costs associated with the revolving credit facility are classified in “Other assets” in the consolidated balance sheets while the debt issuance costs associated with the senior notes are classified as a reduction of the related long-term debt in the consolidated balance sheets.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration determined to be embedded derivatives and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s commodity derivative assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk adjustments. The fair values of the Company’s contingent consideration are determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate.

The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s senior notes and other long-term debt may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the senior notes and other long-term debt bear interest at fixed rates. See “Note 6. Long-Term Debt” and “Note 12. Fair Value Measurements.”

Asset Retirement Obligations

The Company’s asset retirement obligations represent the present value of the estimated future costs associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows are discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates consider historical experience, third party estimates, the requirements of oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations are recognized when the well is drilled or acquired or when the production equipment and facilities are installed or acquired with an associated increase in proved oil and gas property costs. Asset retirement obligations are accreted each period through DD&A to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. Cash paid to settle asset retirement obligations is included in net cash provided by operating activities from continuing operations in the consolidated statements of cash flows. On a quarterly basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. At least annually, the Company reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Revisions typically occur due to changes in estimated costs or well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells. See “Note 7. Asset Retirement Obligations.”

F-11

Commitments and Contingencies

Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable. See “Note 8. Commitments and Contingencies.”

Revenue Recognition

Crude oil, NGL and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. The Company follows the sales method of accounting whereby revenues from the production of natural gas from properties in which the Company has an interest with other producers are recognized for production sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved reserves. Sales volumes are not significantly different from the Company’s share of production and as of December 31, 2017 and 2016, the Company did not have any material production imbalances.

Derivative Instruments

The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling, completion, and infrastructure capital expenditure program. All derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As the Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from operating activities. The Company does not enter into derivative instruments for speculative or trading purposes.

The Company’s Board of Directors establishes risk management policies and, on a quarterly basis, reviews its commodity derivative instruments, including volumes, types of instruments and counterparties. These policies require that commodity derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. See “Note 11. Derivative Instruments” for further discussion of the Company’s commodity derivative instruments.

The Company has entered into agreements for acquisitions or divestitures of oil and gas properties that include obligations to pay the seller or rights to receive from the buyer, respectively, additional consideration if commodity prices exceed certain thresholds during certain specified periods in the future. These contingent consideration liabilities and assets are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheet, with subsequent changes in fair value recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. Cash payments made to settle contingent consideration liabilities are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 11. Derivative Instruments” for further discussion of the contingent consideration.

Preferred Stock and Warrants

The Company applies the accounting standards for distinguishing liabilities from equity when determining the classification and measurement of preferred stock. Preferred stock that is not mandatorily redeemable is excluded from liability classification and is evaluated for classification in shareholders’ equity or temporary equity. As the number of common shares that could be delivered upon the holders’ optional redemption is indeterminate, the Company cannot assert that it will be able to settle in shares of its common stock and, as a result, presents preferred stock as temporary equity. On a quarterly basis, the Company reassesses the presentation of preferred stock in the consolidated balance sheets.

When preferred stock is issued in conjunction with warrants, the warrants are evaluated separately as a freestanding financial instrument to determine whether they must be recorded as a derivative instrument. The Company further evaluates the warrants for equity classification and have determined the warrants qualify for equity classification and, therefore, are presented in additional paid-in capital in the consolidated balance sheets. The preferred stock and warrants are recorded based on the net proceeds received allocated to the two instrument’s relative fair values. The preferred stock is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The warrants do not require further adjustments from their relative fair value at the issuance date.

F-12

Dividends and accretion associated with preferred stock are presented in the consolidated statements of operations as reductions to net income, or increases of net loss, to derive net income (loss) attributable to common shareholders. Dividend payments are presented as a financing activity in the consolidated statement of cash flows.

See “Note 9. Preferred Stock and Warrants” for further details of the Company’s outstanding preferred stock and warrants.

Stock-Based Compensation

The Company recognized stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“SARs”) and performance share awards, which is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties. See “Note 10. Shareholders’ Equity and Stock Based Compensation” for further details of the awards discussed below.

Restricted Stock Awards and Units. Stock-based compensation expense is based on the price of the Company’s common stock on the grant date and recognized over the vesting period (generally one to three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method.

Stock Appreciation Rights. For SARs, stock-based compensation expense is initially based on the grant date fair value determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period and recognized over the vesting period (generally two or three years) using the graded vesting method. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at the end of each reporting period based on the intrinsic value of the SAR. The liability for SARs is classified as “Other current liabilities” for the portion of the fair value liability attributable to awards that are vested or are expected to vest within the next 12 months and have an exercise price in excess of the market price at the end of the reporting period, with the remainder classified as “Other liabilities” in the consolidated balance sheets. SARs typically expire between four and seven years after the date of grant. If SARs expire unexercised, the cumulative compensation costs associated with the unexercised SARs will be zero.

Performance Share Awards. For performance share awards, stock-based compensation expense is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over an approximate three year vesting period using the straight-line method. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of performance share awards granted based on the Company’s total shareholder return relative to a specified industry peer group over an approximate three year performance period. Compensation costs related to the performance share awards will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the market condition is not achieved.

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. See “Note 5. Income Taxes” for further discussion of the deferred tax assets valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense. The Company applies the tax law ordering approach to determine the sequence in which deferred tax assets and other tax attributes are utilized.

Net Income (Loss) Attributable to Common Shareholders Per Common Share

Basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted net income (loss) attributable to common shareholders per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include restricted stock awards and units, performance share awards, stock options and warrants. The Company includes the number of restricted stock awards and units, stock options and warrants in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s common stock for the period. The Company includes the number of performance share awards in the calculation of diluted weighted average common shares outstanding based on the number of shares, if any, that would be issuable as if the end of the period was the end of the

F-13

performance period. When a loss attributable to common shareholders exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding.

Supplemental net income (loss) attributable to common shareholders per common share information is provided below:

	Years Ended December 31,
	2017		2016			2015
	(In thousands, except per share amounts)
Net Income (Loss) Attributable to Common Shareholders		$78,467		($675,474	)		($1,155,154	)
Basic weighted average common shares outstanding	73,421		59,932			51,457
Effect of dilutive instruments	572		—			—
Diluted weighted average common shares outstanding	73,993		59,932			51,457
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$1.07		($11.27	)		($22.45	)
Diluted		$1.06		($11.27	)		($22.45	)

When the Company recognizes a net loss attributable to common shareholders, as was the case for the years ended December 31, 2016 and 2015, all potentially dilutive shares are anti-dilutive and excluded from the calculation of diluted weighted average common shares outstanding. The table below presents the weighted average dilutive and anti-dilutive shares outstanding for the periods presented:

	Years Ended December 31,
	2017	2016	2015
	(In thousands)
Dilutive	572	—	—
Anti-dilutive	52	669	649

Recently Adopted Accounting Pronouncement

Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures, minimum statutory tax withholdings, and prescribes certain disclosures to be made in the period of adoption.

Effective January, 1, 2017, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero. Effective January 1, 2017, all windfall tax benefits and tax shortfalls are recorded as income tax expense or benefit in the consolidated statements of operations, whereas prior to adoption, windfall tax benefits were recorded as an increase to additional paid-in capital. In addition, windfall tax benefits, along with tax shortfalls, are now required to be classified as an operating cash flow as opposed to a financing cash flow. Further, the Company has elected to account for forfeitures of share-based payment awards as they occur, which resulted in an immaterial cumulative-effect adjustment to retained earnings.

Recently Issued Accounting Pronouncements

Revenue From Contracts With Customers. In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.

The Company will adopt ASU 2014-09 effective January 1, 2018, using the modified retrospective approach, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company has performed an analysis of existing contracts and does not expect adoption to have a material impact on its consolidated financial statements, however, certain immaterial natural gas processing fees, which have historically been netted in revenue, will be recorded to lease operating expense. In addition, the Company has evaluated the expected changes to relevant business practices, accounting policies and control activities and does not expect to have a material change as a result of the adoption of ASU 2014-09.

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Business Combinations. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company will adopt ASU 2017-01 effective January 1, 2018 on a prospective basis.

Statement of Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The Company will adopt ASU 2016-15 effective January 1, 2018 using the full retrospective method, meaning the standard is applied to all periods presented. The Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows and related disclosures.

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. ASU 2016-02 requires companies to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach.

The Company is currently assessing the impact of ASU 2016-02 which includes an analysis of existing contracts, including drilling rig contracts, office leases, certain field equipment, vehicles, produced water disposal commitments, pipeline gathering, transportation and gas processing agreements and current accounting policies and disclosures that will change as a result of adopting ASU 2016-02. Appropriate systems, controls, and processes to support the recognition and disclosure requirements of the new standard are also being evaluated. The Company currently expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities, (ii) an increase in depreciation, depletion and amortization expense, (iii) an increase in interest expense, and (iv) additional disclosures. The Company plans to adopt the guidance effective January 1, 2019.

3. Acquisitions and Divestitures of Oil and Gas Properties

Acquisitions

ExL Acquisition. On June 28, 2017, the Company entered into a purchase and sale agreement with ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”) to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward Counties, Texas (the “ExL Properties”) for an agreed upon price of $648.0 million, with an effective date of May 1, 2017, subject to customary purchase price adjustments (the “ExL Acquisition”). The Company paid $75.0 million as a deposit on June 28, 2017, $601.0 million upon closing on August 10, 2017 and $3.8 million upon post-closing on December 8, 2017, for an aggregate cash consideration of $679.8 million, which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. Upon closing the ExL Acquisition, the Company became the operator of the ExL Properties with an approximate 70% average working interest.

The Company also agreed to pay an additional $50.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $50.00 for any of the years of 2018, 2019, 2020 and 2021, with such payments due on January 29, 2019, January 28, 2020, January 28, 2021 and January 28, 2022, respectively. This payment (the “Contingent ExL Consideration”) will be zero for the respective year if such EIA WTI average price of a barrel of oil is $50.00 or below for any of such years, and the Contingent ExL Consideration is capped at $125.0 million in the aggregate. The Company determined that the Contingent ExL Consideration is an embedded derivative and has reflected the liability at fair value in non-current “Derivative liabilities” in the consolidated balance sheets. The fair value of the Contingent ExL Consideration as of December 31, 2017 and August 10, 2017 was $85.6 million and $52.3 million, respectively. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further details.

The Company funded the ExL Acquisition with net proceeds from the sale of preferred stock on August 10, 2017, net proceeds from the common stock offering completed on July 3, 2017, and net proceeds from the senior notes offering completed on July 14, 2017. See “Note 9. Preferred Stock and Warrants” for details regarding the sale of Preferred Stock, “Note 10. Shareholders’ Equity and Stock-Based Compensation” for details regarding the common stock offering and “Note 6. Long-Term Debt” for details regarding the senior notes offering.

The ExL Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and

F-15

abandonment costs and a risk adjusted discount rate. The fair value of the Contingent ExL Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. See “Note 12. Fair Value Measurements” for further details.

The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$106
Oil and gas properties
Proved properties	294,754
Unproved properties	443,194
Total oil and gas properties		$737,948
Total assets acquired		$738,054
Liabilities
Revenues and royalties payable		$5,785
Asset retirement obligations	153
Contingent ExL Consideration	52,300
Total liabilities assumed		$58,238
Net Assets Acquired		$679,816

Included in the consolidated statements of operations for the year ended December 31,2017 are total revenues of $53.5 million and net income attributable to common shareholders of $44.3 million from the ExL Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction.

Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2017 and 2016, assuming the ExL Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the ExL Acquisition.

	Years Ended December 31,
	2017		2016
	(In thousands, except per share amounts)
Total revenues		$781,378		$454,913
Net Income (Loss) Attributable to Common Shareholders		$91,931		($688,180	)
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$1.25		($9.11	)
Diluted		$1.24		($9.11	)
Weighted Average Common Shares Outstanding
Basic	73,421		75,532
Diluted	73,993		75,532

F-16

Sanchez Acquisition. On October 24, 2016, the Company entered into a purchase and sale agreement with Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation to acquire oil and gas properties located in the Eagle Ford Shale (the “Sanchez Acquisition”) for an agreed upon price of $181.0 million, with an effective date of June 1, 2016, subject to customary purchase price adjustments. The Company paid $10.0 million as a deposit on October 24, 2016, $143.5 million upon the initial closing on December 14, 2016, and $7.0 million and $9.8 million on January 9, 2017 and April 13, 2017, respectively, for leases that were not conveyed to the Company at the time of the initial closing, for aggregate cash consideration of $170.3 million, which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. The Sanchez Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values based on then available information.

The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$477
Oil and gas properties
Proved properties	99,938
Unproved properties	74,536
Total oil and gas properties	174,474
Total assets acquired		$174,951
Liabilities
Revenues and royalties payable		$1,442
Other current liabilities	323
Asset retirement obligations	2,054
Other liabilities	1,078
Total liabilities assumed		$4,897
Net Assets Acquired		$170,054

Included in the consolidated statements of operations for the year ended December 31,2017 are total revenues of $37.8 million and net income attributable to common shareholders of $16.5 million from the Sanchez Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction.

Divestitures

Utica. On August 31, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Utica Shale, located primarily in Guernsey County, Ohio, for an agreed upon price of $62.0 million, with an effective date of April 1, 2017, subject to customary purchase price adjustments. On August 31, 2017, the Company received $6.2 million as a deposit, on November 15, 2017, the Company received $54.4 million at closing, subject to post-closing adjustments, and on December 28, 2017, the Company received $2.5 million, for aggregate net proceeds of $63.1 million, which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date.

The Company could also receive contingent consideration of $5.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $50.00, $53.00, and $56.00 for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Utica Consideration”). The Contingent Utica Consideration will be zero for the respective year if such EIA WTI average price of a barrel of oil is at or below the per barrel amounts listed above for any of such years. The Company determined that the Contingent Utica Consideration is an embedded derivative and has reflected the asset at fair value in non-current “Other assets” in the consolidated balance sheets. The fair value of the Contingent Utica Consideration as of December 31, 2017 and November 15, 2017 was $8.0 million and $6.1 million, respectively. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further details.

The aggregate net proceeds of $63.1 million were recognized as a reduction of proved oil and gas properties. The contingent consideration, if received, will be recognized as a reduction of the fair value asset in the consolidated balance sheets.

F-17

Marcellus. On October 5, 2017, the Company entered into a purchase and sale agreement with BKV Chelsea, LLC, a subsidiary of Kalnin Ventures LLC, to sell substantially all of its assets in the Marcellus Shale for an agreed upon price of $84.0 million, with an effective date of April 1, 2017, subject to customary purchase price adjustments. On October 5, 2017, the Company received $6.3 million into escrow as a deposit and on November 21, 2017, the Company received $67.6 million at closing, subject to post-closing adjustments, for aggregate net proceeds of $73.9 million, which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date.

The Company could also receive contingent consideration of $3.0 million per year if the average settlement prices of a 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. (the “CME HH average price”) is above $3.13, $3.18, and $3.30 for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Marcellus Consideration”). This conditional consideration will be zero for the respective year if such CME HH average price of a MMBtu of Henry Hub natural gas is at or below the per MMBtu amounts listed above for any of such years, and is capped at $7.5 million. The Company determined that the Contingent Marcellus Consideration is an embedded derivative and has reflected the asset at fair value in non-current “Other assets” in the consolidated balance sheets. The fair value of the Contingent Marcellus Consideration as of December 31, 2017 and November 21, 2017 was $2.2 million and $2.7 million, respectively. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further details.

The aggregate net proceeds of $73.9 million were recognized as a reduction of proved oil and gas properties. The contingent consideration, if received, will be recognized as a reduction of the fair value asset in the consolidated balance sheets.

Simultaneous with the signing of the Marcellus Shale transaction discussed above, the Company’s existing joint venture partner in the Marcellus Shale, Reliance Marcellus II, LLC (“Reliance”), a wholly owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited, entered into a purchase and sale agreement with BKV Chelsea, LLC to sell its interest in the same oil and gas properties. Simultaneous with the closing of these Marcellus Shale sale transactions, the agreements governing the Reliance joint venture were assigned to the buyer and, after giving effect to such transactions, the Reliance joint venture was terminated except for limited post-closing obligations.

Niobrara. On November 20, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Niobrara Formation for an agreed upon price of $140.0 million, with an effective date of October 1, 2017, subject to customary purchase price adjustments. On November 20, 2017, the Company received $14.0 million as a deposit, which is refundable only in specified circumstances if the transaction is not consummated and is classified as “Other liabilities” in the consolidated balance sheets and as “Net proceeds from divestitures of oil and gas properties” in the cash flows from investing activities section in the consolidated statements of cash flows. On January 19, 2018, the Company received $122.6 million at closing, subject to post-closing adjustments, for aggregate net proceeds of $136.6 million, which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date.

The Company could also receive contingent consideration of $5.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $55.00 for the years of 2018 and 2019 and above $60.00 for 2020, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Niobrara Consideration”). The Contingent Niobrara Consideration will be zero for the respective year if such EIA WTI average price of a barrel of oil is at or below the per barrel amounts listed above for any of such years.

Eagle Ford. On December 11, 2017, the Company entered into a purchase and sale agreement with EP Energy E&P Company, L.P. to sell a portion of its assets in the Eagle Ford Shale for an agreed upon price of $245.0 million, with an effective date of October 1, 2017, subject to adjustment and customary terms and conditions. On December 11, 2017, the Company received $24.5 million as a deposit, which is refundable only in specified circumstances if the transaction is not consummated and is classified as “Other liabilities” in the consolidated balance sheets and as “Net proceeds from divestitures of oil and gas properties” in the cash flows from investing activities section in the consolidated statements of cash flows. On January 31, 2018, the Company received $211.7 million at closing, subject to post-closing adjustments, and on February 16, 2018, the Company received $10.0 million for leases that were not conveyed at closing, for aggregate net proceeds of $246.2 million, which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date.

In the first quarter of 2018, the aggregate net proceeds that were received for the Niobrara and Eagle Ford divestitures will be recognized as reductions of proved oil and gas properties and the Contingent Niobrara Consideration will be recognized as an asset at fair value in the Company's consolidated balance sheet.

Other Assets. During the first quarter of 2017, the Company sold a small undeveloped acreage position in the Delaware Basin for net proceeds of $15.3 million. The proceeds from this sale were recognized as a reduction of proved oil and gas properties.

F-18

4. Property and Equipment, Net

As of December 31, 2017 and 2016, total property and equipment, net consisted of the following:

	December 31,
	2017			2016
Oil and gas properties, full cost method	(In thousands)
Proved properties		$5,615,153			$4,687,416
Accumulated DD&A and impairments	(3,649,806		)	(3,392,749		)
Proved properties, net	1,965,347			1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	612,589			211,067
Capitalized interest	47,698			29,894
Total unproved properties, not being amortized	660,287			240,961
Other property and equipment	25,625			23,127
Accumulated depreciation	(15,449		)	(12,995		)
Other property and equipment, net	10,176			10,132
Total property and equipment, net		$2,635,810			$1,545,760

Costs not subject to amortization totaling $660.3 million at December 31, 2017 were incurred in the following periods: $523.1 million in 2017, $106.8 million in 2016 and $24.0 million in 2015.

Impairments of Proved Oil and Gas Properties

The Company did not recognize impairments of proved oil and gas properties for the year ended December 31,2017. Primarily due to declines in the 12-Month Average Realized Price of crude oil, the Company recognized impairments of proved oil and gas properties of $576.5 million and $1,224.4 million for the years ended December 31, 2016 and 2015, respectively.

5. Income Taxes

The components of income tax (expense) benefit from continuing operations were as follows:

	Years Ended December 31,
	2017			2016		2015
	(In thousands)
Current income tax (expense) benefit
U.S. Federal		$—			$—		$—
State	(395		)	—		—
Total current income tax (expense) benefit	(395		)	—		—
Deferred income tax (expense) benefit
U.S. Federal	—			—		131,502
State	(3,635		)	—		9,373
Total deferred income tax (expense) benefit	(3,635		)	—		140,875
Total income tax (expense) benefit from continuing operations		($4,030	)		$—		$140,875

F-19

The Company’s income tax (expense) benefit from continuing operations differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) from continuing operations before income taxes as follows:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Income (loss) from continuing operations before income taxes		$91,140			($675,474	)		($1,298,760	)
Income tax (expense) benefit at the statutory rate	(31,899		)	236,416			454,566
State income tax (expense) benefit, net of U.S. Federal income taxes	(4,030		)	3,894			9,373
Tax shortfalls from stock-based compensation expense	(3,089		)	—			—
Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense	—			—			1,671
Provisional impact of Tax Cuts and Jobs Act	(211,724		)	—			—
Change in valuation allowance from provisional impact of Tax Cuts and Jobs Act	211,724			—			—
Change in valuation allowance from current year activity	35,376			(240,864		)	(323,586		)
Other	(388		)	554			(1,149		)
Income tax (expense) benefit		($4,030	)		$—			$140,875

Significant changes in the Company’s operations in 2017, including the ExL Acquisition in the Delaware Basin and divestitures of substantially all of the Company's assets in the Utica and Marcellus Shales, resulted in changes to the Company's anticipated future state apportionment for estimated state deferred tax liabilities. As a result of these changes, the Company recorded a $3.6 million state deferred tax expense primarily associated with future Texas deferred tax liabilities.

Deferred Income Taxes

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. As of December 31, 2017 and 2016, deferred tax assets and liabilities are comprised of the following:

	December 31,
	2017			2016
	(In thousands)
Deferred income tax assets
Net operating loss carryforward - U.S. Federal and State		$242,915			$221,063
Oil and gas properties	50,177			309,848
Asset retirement obligations	4,996			7,434
Stock-based compensation	—			5,238
Derivative liabilities	35,585			17,545
Other	1,496			3,739
Deferred income tax assets	335,169			564,867
Deferred tax asset valuation allowance	(333,029		)	(564,434		)
Net deferred income tax assets	2,140			433
Deferred income tax liabilities
Oil and gas properties	(3,635		)	—
Derivative assets	(2,140		)	(433		)
Net deferred income tax asset (liability)		($3,635	)		$—

Tax Cuts and Jobs Act

On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to U.S. federal income tax law, including lowering the federal statutory corporate income tax rate to 21% from 35% beginning January 1, 2018. The income tax effects of changes in tax laws are recognized in the period when enacted. While the Company continues to assess the impact of the tax reform legislation on its business and consolidated financial statements, the Company remeasured its deferred tax balances by applying the reduced rate and and recorded a provisional deferred tax expense of $211.7 million during the year ended December 31, 2017. This provisional deferred tax expense was fully offset by a $211.7 million deferred tax benefit as a result of the associated change in the valuation allowance against the net deferred tax assets. As reflected in the rate reconciliation above, the change in the deferred tax balances due to the rate reduction had no impact on the net deferred tax balances reported

F-20

in the consolidated balance sheets as of December 31, 2017 and no impact in the consolidated statements of operations for the year ended December 31, 2017.

Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin 118 (“SAB 118”) which allows the Company to provide a provisional estimate of the impacts of the Act in its earnings for the year ended December 31, 2017. The Company's estimate does not reflect changes in current interpretations of performance based executive compensation deduction limitations, effects of any state tax law changes and uncertainties regarding interpretations that may arise as a result of federal tax reform. The Company will continue to analyze the effects of the Act in its consolidated financial statements and operations. Additional impacts from the enactment of the Act will be recorded as they are identified during the one-year measurement period provided for in SAB 118. As of December 31, 2017, the Company has not completed its accounting for the tax effects of enactment of the Act; however, the Company has made a reasonable estimate of the effects on it existing deferred tax balances.

Deferred Tax Assets Valuation Allowance

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 deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluated possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies.

A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2017, driven primarily by the impairments of proved oil and gas properties recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016, which limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the third quarter of 2015 and continuing through the fourth quarter of 2017, the Company concluded that it was more likely than not the deferred tax assets will not be realized. As a result, the net deferred tax assets at the end of each quarter, including December 31, 2017 were reduced to zero.

Effective January 1, 2017, the Company adopted ASU 2016-09, and the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero and brought the valuation allowance to $580.1 million as of January 1, 2017.

For the year ended December 31,2017, the Company reduced the valuation allowance by $247.1 million. This was primarily due to the re-measurement of its deferred tax assets as a result of the Act as mentioned above as well as partial releases of $35.4 million, as a result of current year activity. After the impact of the re-measurement and the partial releases, the valuation allowance as of December 31, 2017 was $333.0 million, of which $12.7 million is a valuation allowance against state deferred tax assets.

The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes sufficient taxable income within the carryforward periods. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant federal deferred income tax expense or benefit. However, the Company currently expects to continue to have state deferred income tax expense or benefit as a result of change in state deferred tax liabilities as the Company's operations become more heavily weighted towards Texas.

Net Operating Loss Carryforwards and Other

Net Operating Loss Carryforwards. As of December 31, 2017, the Company had U.S. federal net operating loss carryforwards of approximately $1,096.2 million. If not utilized in earlier periods, the U.S. federal net operating loss will expire between 2026 and 2037.

F-21

The ability of the Company to utilize its U.S. 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 upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the Company multiplied by (ii) 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.

Due to the issuance of the Preferred Stock and the common stock offering associated with the ExL Acquisition, the Company’s calculated ownership change percentage increased, however, as of December 31, 2017, the Company does not believe it has a Section 382 limitation on the ability to utilize its U.S. loss carryforwards. Future equity transactions involving the Company or 5% shareholders of the Company (including, potentially, relatively small transactions and transactions beyond the Company’s control) could cause further ownership changes and therefore a limitation on the annual utilization of the U. S. loss carryforwards.

Other. The Company files income tax returns in the U.S. Federal jurisdiction and various states, each with varying statutes of limitations. The 1999 through 2017 tax years generally remain subject to examination by federal and state tax authorities. As of December 31, 2017, 2016 and 2015, the Company had no uncertain tax positions.

6. Long-Term Debt

Long-term debt consisted of the following as of December 31, 2017 and 2016:

	December 31,
	2017			2016
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$291,300			$87,000
7.50% Senior Notes due 2020	450,000			600,000
Unamortized premium for 7.50% Senior Notes	579			1,020
Unamortized debt issuance costs for 7.50% Senior Notes	(4,492		)	(7,573		)
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(8,208		)	(9,454		)
8.25% Senior Notes due 2025	250,000			—
Unamortized debt issuance costs for 8.25% Senior Notes	(4,395		)	—
Other long-term debt due 2028	4,425			4,425
Long-term debt		$1,629,209			$1,325,418

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of December 31, 2017, had a borrowing base of $900.0 million, with an elected commitment amount of $800.0 million, and $291.3 million of borrowings outstanding at a weighted average interest rate of 3.73%. As of December 31, 2017, the Company also had $0.4 million in letters of credit outstanding, which reduce the amounts available under the revolving credit facility. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced on or prior to such time), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

On May 4, 2017, the Company entered into a ninth amendment to the credit agreement governing the revolving credit facility to, among other things, (i) extend the maturity date of the revolving credit facility to May 4, 2022, subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced or redeemed on or prior to such time, (ii) increase the maximum credit amount under the revolving credit facility from $1.0 billion to $2.0 billion, (iii) increase the borrowing base from $600.0 million to $900.0 million, with an elected commitment amount of $800.0 million, until the next redetermination thereof and (iv) amend certain financial covenants including replacing the Total Secured Debt to EBITDA ratio covenant with a Total Debt to EBITDA ratio and removing the minimum EBITDA to Interest Expense ratio.

F-22

On June 28, 2017, the Company entered into a tenth amendment to its credit agreement governing the revolving credit facility to, among other things, (i) amend the calculation of certain financial covenants to provide that EBITDA will be calculated on an annualized basis as of the end of each of the first three fiscal quarters commencing with the quarter ending September 30, 2017 and (ii) amend the restricted payments covenant.

Upon issuance of the 8.25% Senior Notes (described below), in accordance with the credit agreement governing the revolving credit facility, the Company’s borrowing base was reduced by 25% of the aggregate principal amount of the 8.25% Senior Notes, reducing the Company’s borrowing base from $900.0 million to $837.5 million.

On November 3, 2017, the Company entered into an eleventh amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $900.0 million, with an elected commitment amount of $800.0 million, until the next determination thereof, (ii) increase the general basket available for restricted payments from $50.0 million to $75.0 million and (iii) amend certain other provisions, in each case as set forth therein.

The obligations of the Company under the credit agreement are guaranteed by the Company’s material domestic subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and gas properties having at least 90% of the total value of the oil and gas properties included in the Company’s reserve report used in its most recent redetermination.

Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set forth in the table below. The Company also incurs commitment fees at rates as set forth in the table below on the unused portion of lender commitments, which are included in interest expense, net in the consolidated statements of operations.

Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 25%	1.00%	2.00%	0.375%
Greater than or equal to 25% but less than 50%	1.25%	2.25%	0.375%
Greater than or equal to 50% but less than 75%	1.50%	2.50%	0.500%
Greater than or equal to 75% but less than 90%	1.75%	2.75%	0.500%
Greater than or equal to 90%	2.00%	3.00%	0.500%

The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt premiums and debt issuance costs and is net of cash and cash equivalents, EBITDA for the fiscal quarter ended December 31, 2017 is calculated based on an annualized average of the last two fiscal quarters, EBITDA for the fiscal quarter ending March 31, 2018, will be calculated based on an annualized average of the last three fiscal quarters, and EBITDA for fiscal quarters ending thereafter will be calculated based on the last four fiscal quarters, in each case after giving pro forma effect to EBITDA for material acquisitions and dispositions of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of December 31, 2017, the ratio of Total Debt to EBITDA was 2.59 to 1.00 and the Current Ratio was 1.98 to 1.00. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the level of borrowings outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and divestitures of oil and gas properties and securities offerings.

The credit agreement also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions and divestitures of oil and gas properties, mergers, transactions with affiliates, hedging transactions and other matters.

The credit agreement is subject to customary events of default, including in connection with a change in control. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).

Senior Notes

8.25% Senior Notes due 2025. On July 14, 2017, the Company closed a public offering of $250.0 million aggregate principal amount of 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”). The 8.25% Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from

F-23

106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. The Company used the net proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs, to fund a portion of the purchase price for 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.

7.50% Senior Notes due 2020. On November 28, 2017, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes due 2020 (the “7.50% Senior Notes”) to call for redemption on December 28, 2017, $150.0 million aggregate principal amount of the 7.50% Senior Notes then outstanding. On December 28, 2017, the Company paid an aggregate redemption price of $156.0 million, which included a redemption premium of $2.8 million as well as accrued and unpaid interest of $3.2 million from the last interest payment date up to, but not including, the redemption date. As a result of the redemption of $150.0 million of the 7.50% Senior Notes, the Company recorded a loss on extinguishment of debt of $4.2 million, which includes the redemption premium paid to redeem the notes and non-cash charges of $1.3 million attributable to the write-off of unamortized premium and debt issuance costs associated with the 7.50% Senior Notes. The Company delivered additional notices of redemption to the trustee for its 7.50% Senior Notes subsequent to December 31, 2017. See “Note 15. Subsequent Events (Unaudited)” for further details of these redemptions.

Since September 15, 2017, the Company has had the right to redeem all or a portion of the 7.50% Senior Notes at redemption prices decreasing from 101.875% to 100% of the principal amount on September 15, 2018, plus accrued and unpaid interest.

6.25% Senior Notes due 2023. Before April 15, 2018, the Company may, at its option, redeem all or a portion of the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 104.688% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest.

If a Change of Control (as defined in the indentures governing the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest.

The indentures governing the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes contain covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s common stock or other capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. Such indentures governing the Company’s senior notes are also subject to customary events of default, including those related to failure to comply with the terms of the notes and the indenture, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments. At December 31, 2017, the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes are guaranteed by the same subsidiaries that also guarantee the revolving credit facility.

7. Asset Retirement Obligations

The following table sets forth asset retirement obligations for the years ended December 31, 2017 and 2016:

	Years Ended December 31,
	2017			2016
	(In thousands)
Beginning of year asset retirement obligations		$21,240			$16,511
Liabilities incurred	3,920			2,137
Increase due to acquisition of oil and gas properties	153			2,037
Liabilities settled	(343		)	(599		)
Reduction due to divestitures of oil and gas properties	(2,671		)	—
Accretion expense	1,799			1,364
Revisions to estimated cash flows	(306		)	(210		)
End of year asset retirement obligations	23,792			21,240
Current asset retirement obligations (included in other current liabilities)	(295		)	(392		)
Non-current asset retirement obligations		$23,497			$20,848

F-24

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. 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 the financial position or results of operations of the Company.

The 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, 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 for the years ended December 31, 2017, 2016 and 2015 was $1.7 million, $2.0 million, and $2.2 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 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		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

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

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.

9. Preferred Stock and Warrants

On June 28, 2017, the Company entered into a Preferred Stock Purchase Agreement with certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”) to issue and sell in a private placement (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 GSO Funds $5.0 million as a commitment fee upon signing the Preferred Stock Purchase Agreement. 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 the Preferred Stock and the common stock that may be issued in respect of the Preferred Stock and that underlie the Warrants. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.

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

F-25

of the Preferred Stock dividends in shares of its common stock in decreasing percentages as follows with respect to any 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 remain outstanding; or

• Upon the occurrence of certain changes of 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 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.

F-26

The table below summarizes Preferred Stock activity for the year ended December 31, 2017:

	December 31, 2017
For the Year Ended December 31, 2017
Preferred Stock, beginning 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 and the 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 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.

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 of Common Stock

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 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 facility and 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 portion of the borrowings under the Company’s revolving credit facility and for general corporate purposes.

F-27

Stock-Based Compensation

At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”), which replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”). From the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. 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. 

As of December 31, 2017, there were 1,750,908 common shares remaining available for grant under the 2017 Incentive Plan. Each restricted stock award, restricted stock unit, or performance share granted under the 2017 Incentive Plan counts as 1.35 shares while a stock option or stock-settled stock appreciation right granted under the 2017 Incentive Plan counts as 1.00 share against the number of common shares 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.

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

	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
Granted	887,254			$27.80
Vested	(811,136	)		$36.32
Forfeited	(6,405	)		$34.46
Unvested restricted stock awards and units, end of period	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
Granted	1,020,465			$25.63
Vested	(635,965	)		$39.62
Forfeited	(13,555	)		$29.11
Unvested restricted stock awards and units, end of period	1,482,655			$28.07

The aggregate fair value of restricted stock awards and units that vested during the years ended December 31, 2017, 2016 and 2015 was $20.3 million, $26.3 million and $32.0 million, respectively.

Stock Appreciation Rights (“SARs”). SARs can be granted to employees and independent contractors under the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”) or the 2017 Incentive Plan. SARs granted under the 2017 Incentive Plan can be settled in shares of common stock or cash, at the option of the Company, while SARs granted under the Cash SAR Plan may only be settled in cash. All outstanding SARs have been granted under the Cash SAR Plan and therefore will be settled solely in cash. The grant date fair value of SARs is calculated using the Black-Scholes-Merton option pricing model. The liability for SARs as of December 31, 2017 was $4.4 million, all of which was classified as “Other liabilities” in the consolidated balance sheets. As of December 31, 2016, the liability for SARs was $11.5 million, of which $10.0 million was classified as “Other current liabilities,” with the remaining $1.5 million classified as “Other liabilities” in the consolidated balance sheets. Unrecognized compensation costs related to unvested SARs was $1.3 million as of December 31, 2017, and will be recognized over a weighted average period of 1.1 years.

F-28

The table below summarizes the activity for SARs for the years ended December 31, 2017, 2016 and 2015:

	Stock Appreciation Rights		Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)		Aggregate Intrinsic Value of Exercises (In millions)
For the Year Ended December 31, 2015
Outstanding, beginning of period	765,198			$22.49
Granted	—		—
Exercised	(64,745	)		$29.40					$1.5
Forfeited	—		—
Outstanding, end of period	700,453			$21.86
Vested, end of period	626,661			$21.05
Vested and exercisable, end of period	626,661			$21.05
For the Year Ended December 31, 2016
Outstanding, beginning of period	700,453			$21.86
Granted	376,260		27.30
Exercised	(354,075	)		$23.89					$5.2
Forfeited	—		—
Outstanding, end of period	722,638			$23.69
Vested, end of period	350,840			$19.87
Vested and exercisable, end of period	350,840			$19.87
For the Year Ended December 31, 2017
Outstanding, beginning of period	722,638			$23.69
Granted	342,440			$26.94
Exercised	(219,279	)		$17.28					$2.1
Forfeited	—		—
Expired	(131,561	)		$24.19
Outstanding, end of period	714,238			$27.12	3.7		$—
Vested, end of period	185,899			$27.30
Vested and exercisable, end of period	—			$27.30	3.2		$—

No SARs were granted during the year ended December 31, 2015. The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the years ended December 31, 2017 and 2016:

	Years Ended December 31,
	2017		2016
Expected term (in years)	4.24		3.93
Expected volatility	54.3	%	45.1	%
Risk-free interest rate	1.8	%	1.3	%
Dividend yield	—	%	—	%

Performance Shares. The Company can grant performance shares to employees and independent contractors, where each performance share represents the right to receive one share of common stock. The number of performance shares that will vest ranges from zero to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three year performance period, the last day of which is also the vesting date. The grant date fair value of the performance awards is calculated using a Monte Carlo simulation. As of December 31, 2017, unrecognized compensation costs related to unvested performance shares was $2.1 million and will be recognized over a weighted average period of 1.7 years.

F-29

The table below summarizes performance share activity for the years ended December 31, 2017, 2016 and 2015:

	Target Performance Shares (1)		Weighted Average Grant Date Fair Value
For the Year Ended December 31, 2015
Unvested performance shares, beginning of period	56,342			$68.15
Granted	56,517			$65.51
Vested	—		—
Forfeited	—		—
Unvested performance shares, end of period	112,859			$66.83
For the Year Ended December 31, 2016
Unvested performance shares, beginning of period	112,859			$66.83
Granted	41,651			$35.71
Vested	—		—
Forfeited	—		—
Unvested performance shares, end of period	154,510			$58.44
For the Year Ended December 31, 2017
Unvested performance shares, beginning of period	154,510			$58.44
Granted	46,787			$35.14
Vested	(56,342	)		$68.15
Forfeited	—		—
Unvested performance shares, end of period	144,955			$47.14

(1) The number of shares of common stock issued upon vesting may vary from the number of target performance shares depending on the Company’s final TSR ranking for the approximate three year performance period.

During the first quarter of 2017, the Company issued 92,200 shares of common stock for 56,342 target performance shares that vested during the first quarter of 2017 with a multiplier of 164% based on the Company’s final TSR ranking during the performance period.

The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the years ended December 31, 2017, 2016 and 2015:

	Years Ended December 31,
	2017		2016		2015
Number of simulations	500,000		500,000		500,000
Expected term (in years)	2.98		3.01		2.89
Expected volatility	59.2	%	55.3	%	45.3	%
Risk-free interest rate	1.5	%	1.2	%	0.9	%
Dividend yield	—	%	—	%	—	%

Stock-Based Compensation Expense, Net. Stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash and performance shares is reflected as general and administrative expense, net of amounts capitalized to oil and gas properties in the consolidated statements of operations.

The Company recognized the following stock-based compensation expense, net for the periods indicated:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Restricted stock awards and units		$21,372			$28,196			$23,668
Stock appreciation rights	(5,023		)	9,675			(6,326		)
Performance shares	2,442			2,806			1,961
	18,791			40,677			19,303
Less: amounts capitalized to oil and gas properties	(4,482		)	(4,591		)	(4,574		)
Total stock-based compensation expense, net		$14,309			$36,086			$14,729

F-30

11. Derivative Instruments

Commodity Derivative Instruments

The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling, completion, and infrastructure capital expenditure program. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s commodity derivative instruments consist of fixed price swaps, basis swaps, three-way collars and purchased and sold call options, which are described below.

Fixed Price Swaps: The Company receives a fixed price and pays a variable market price to the counterparties over specified periods for contracted volumes.

Basis Swaps: The 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 of options including a purchased put option (fixed floor price), a sold call option (fixed ceiling price) and a sold put option (fixed 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 between the fixed 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. If the market price is below the fixed sub-floor price, the Company receives the market price plus the difference between the fixed floor price and the fixed sub-floor price. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party. The Company has incurred premiums on certain of these contracts 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 of 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 the Company has entered into three-way collars which span multiple years, 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 derivative positions at weighted average contract prices as of December 31, 2017:

Crude Oil Fixed Price Swaps

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	)

F-31

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

The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company nets its derivative instrument fair values executed with the same counterparty, along with deferred premium obligations, to a single asset or liability pursuant to ISDA master agreements, 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 derivative instruments who are also lenders under the Company’s credit agreement allow the Company to satisfy any need for margin obligations associated with derivative instruments where the Company is in a net liability position with its counterparties with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties who are not lenders under the Company’s credit agreement can require derivative contracts to be novated to a lender if the net liability position exceeds the Company’s unsecured credit limit with that counterparty and therefore do not require the posting of cash collateral.

Because the counterparties have investment grade credit ratings, or the Company has obtained guarantees from the applicable counterparty’s investment grade parent company, 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 derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of its counterparties and its counterparty’s parent company, as applicable.

Contingent Consideration

As part of the ExL Acquisition, the Company agreed to the Contingent ExL Consideration that will require payment of $50.0 million per year for each 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.

F-32

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, the Company agreed to the Contingent Niobrara Consideration. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details.

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 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, recorded in the consolidated balance sheets as of December 31, 2017 and 2016 are summarized below:

	December 31, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$4,869			($4,869	)		$—
Deferred premium obligations	—			—			—
Other current assets		$4,869			($4,869	)		$—
Commodity derivative instruments	9,505			(9,505		)	—
Deferred premium obligations	—			—			—
Contingent consideration	10,190			—			10,190
Other assets-non current		$19,695			($9,505	)		$10,190
Commodity derivative instruments		($52,671	)		$4,869			($47,802	)
Deferred premium obligations	(9,319		)	—			(9,319		)
Derivative liabilities-current		($61,990	)		$4,869			($57,121	)
Commodity derivative instruments	(24,609		)	9,505			(15,104		)
Deferred premium obligations	(11,603		)	—			(11,603		)
Contingent consideration	(85,625		)	—			(85,625		)
Derivative liabilities-non current		($121,837	)		$9,505			($112,332	)

F-33

	December 31, 2016
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$7,990			($6,753	)		$1,237
Deferred premium obligations	—			—			—
Other current assets		$7,990			($6,753	)		$1,237
Commodity derivative instruments	3,882			(3,882		)	—
Deferred premium obligations	—			—			—
Contingent consideration	—			—			—
Other assets-non current		$3,882			($3,882	)		$—
Commodity derivative instruments		($27,346	)		$6,753			($20,593	)
Deferred premium obligations	(2,008		)	—			(2,008		)
Derivative liabilities-current		($29,354	)		$6,753			($22,601	)
Commodity derivative instruments	(28,841		)	3,882			(24,959		)
Deferred premium obligations	(2,569		)	—			(2,569		)
Contingent consideration	—			—			—
Derivative liabilities-non current		($31,410	)		$3,882			($27,528	)

See “Note 12. Fair Value Measurements” for additional details regarding the fair value of the Company’s derivative instruments.

(Gain) Loss on Derivatives, Net

The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of the Company’s commodity derivative instruments and contingent consideration are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. All deferred premium obligations associated with the Company’s commodity derivative instruments are recognized in (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the deferred premium obligations are incurred. The effect of derivative instruments and deferred premium obligations in the consolidated statements of operations for the years ended December 31, 2017, 2016, and 2015 is summarized below:

	Years Ended December 31,
	2017			2016		2015
	(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		$22,839			$23,609		($99,624	)
Natural gas liquids	1,322			—		—
Natural gas	(15,399		)	19,584		(4,063		)
Deferred premium obligations incurred	18,401			5,880		4,426
Contingent consideration	31,940			—		—
Total (Gain) Loss on Derivatives, Net		$59,103			$49,073		($99,261	)

F-34

Cash Received (Paid) for Derivative Settlements, Net

Cash flows are impacted to the extent that settlements under these contracts, including deferred premium obligations paid, result in payments to or receipts from the counterparty during the period and are presented as cash received (paid) for derivative settlements, net in the consolidated statements of cash flows. The effect of commodity derivative instruments and deferred premium obligations in the consolidated statements of cash flows for the years ended December 31, 2017, 2016, and 2015 is summarized below:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil		$9,883			$125,098			$176,511
Natural gas	(54		)	—			17,785
Deferred premium obligations paid	(2,056		)	(5,729		)	—
Total Cash Received (Paid) for Derivative Settlements, Net		$7,773			$119,369			$194,296

12. Fair Value Measurements

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016:

	December 31, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$—			$10,190
Derivative instrument liabilities		$—		($62,906	)		($85,625	)

	December 31, 2016
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$1,237			$—
Derivative instrument liabilities		$—		($45,552	)		$—

The derivative asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors.

Commodity derivative instruments. The fair value of the Company’s commodity derivative instruments is based on a third-party industry-standard pricing model which uses contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments including forward oil and gas price curves, discount rates and volatility factors and are therefore designated as Level 2 within the valuation hierarchy. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for derivative liabilities.

The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. Deferred premium obligations are netted with the fair value derivative asset and liability positions, which are all offset to a single asset or liability, at the end of each reporting period. The Company

F-35

nets the fair values of its derivative assets and liabilities associated with commodity derivative instruments executed with the same counterparty, along with deferred premium obligations, pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the years ended December 31, 2017 and 2016.

Contingent consideration. The fair values of the Contingent ExL Consideration, the Contingent Utica Consideration and the Contingent Marcellus Consideration were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. As some of these assumptions are not observable throughout the full term of the contingent consideration, the contingent consideration was designated as Level 3 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods.

The following tables present reconciliations of changes in the fair values of the financial assets and liabilities related to the Company’s contingent consideration, which were designated as Level 3 within the valuation hierarchy, for the year ended December 31,2017:

	Year Ended December 31,
	2017
	(In thousands)
Fair value assets, beginning of period		$—
Recognition of acquisition date fair value	8,805
Gain (loss) on changes in fair value(1)	1,385
Transfers into (out of) Level 3	—
Fair value assets, end of period		$10,190

	Year Ended December 31,
	2017
	(In thousands)
Fair value liability, beginning of period		$—
Recognition of acquisition date fair value	(52,300		)
Gain (loss) on changes in fair value(1)	(33,325		)
Transfers into (out of) Level 3	—
Fair value liability, end of period		($85,625	)

(1) Included in (gain) loss on derivatives, net in the consolidated statements of operations.

See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 11. Derivative Instruments” for further details regarding the contingent consideration.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The fair value measurements of assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured as of the acquisition date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore designated as Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimated volumes of oil and gas reserves, production rates, future commodity prices, timing of development, future operating and development costs and a risk adjusted discount rate. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the assets acquired and liabilities assumed as of the acquisition dates for the ExL Acquisition and Sanchez Acquisition.

The fair value measurements of asset retirement obligations are measured as of the date a well is drilled or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 inputs. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 7. Asset Retirement Obligations” for additional details regarding the Company’s asset retirement obligations for the years ended December 31, 2017 and 2016.

The fair value measurements of the Preferred Stock are measured as of the issuance date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 inputs.

F-36

Significant inputs to the valuation of the Preferred Stock include the per share cash purchase price, redemption premiums, liquidation preference, and redemption assumptions provided by the Company. See “Note 9. Preferred Stock and Warrants” for details regarding the allocation of the net proceeds based on the relative fair values of the Preferred Stock and Warrants.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt, which are designated as Level 1 under the fair value hierarchy. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The following table presents the carrying amounts of the Company’s senior notes and other long-term debt, net of unamortized premiums and debt issuance costs, with the fair values measured using quoted secondary market trading prices.

	December 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020 (1)		$446,087		$459,518		$593,447		$624,750
6.25% Senior Notes due 2023	641,792		674,375		640,546		672,750
8.25% Senior Notes due 2025	245,605		274,375		—		—
Other long-term debt due 2028	4,425		4,445		4,425		4,419

(1) The Company delivered additional notices of redemption to the trustee for its 7.50% Senior Notes subsequent to December 31, 2017.

13. Condensed Consolidating Financial Information

The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities.

F-37

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

	December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$3,441,633			$105,533			$—		($3,424,288	)		$122,878
Total property and equipment, net	5,953			2,630,707			3,028		(3,878		)	2,635,810
Investment in subsidiaries	(999,793		)	—			—		999,793			—
Other assets	9,270			10,346			—		—			19,616
Total Assets		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304
Liabilities and Shareholders’ Equity
Current liabilities		$165,701			$3,631,401			$3,028		($3,427,308	)		$372,822
Long-term liabilities	1,689,466			114,978			—		15,879			1,820,323
Preferred stock	214,262			—			—		—			214,262
Total shareholders’ equity	387,634			(999,793		)	—		983,056			370,897
Total Liabilities and Shareholders’ Equity		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304

	December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$2,735,830			$63,513			$—		($2,726,355	)		$72,988
Total property and equipment, net	42,181			1,503,695			3,800		(3,916		)	1,545,760
Investment in subsidiaries	(1,282,292		)	—			—		1,282,292			—
Other assets	7,423			156			—		—			7,579
Total Assets		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327
Liabilities and Shareholders’ Equity
Current liabilities		$114,805			$2,822,729			$3,800		($2,729,375	)		$211,959
Long-term liabilities	1,348,105			26,927			—		15,878			1,390,910
Preferred stock	—			—			—		—			—
Total shareholders’ equity	40,232			(1,282,292		)	—		1,265,518			23,458
Total Liabilities and Shareholders’ Equity		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327

F-38

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$302			$745,586			$—		$—			$745,888
Total costs and expenses	195,728			459,057			—		(37		)	654,748
Income (loss) from continuing operations before income taxes	(195,426		)	286,529			—		37			91,140
Income tax expense	—			(4,030		)	—		—			(4,030		)
Equity in income of subsidiaries	282,499			—			—		(282,499		)	—
Income from continuing operations		$87,073			$282,499			$—		($282,462	)		$87,110
Income from discontinued operations, net of income taxes	—			—			—		—			—
Net income		$87,073			$282,499			$—		($282,462	)		$87,110
Dividends on preferred stock	(7,781		)	—			—		—			(7,781		)
Accretion on preferred stock	(862		)	—			—		—			(862		)
Net income attributable to common shareholders		$78,430			$282,499			$—		($282,462	)		$78,467

	Year Ended December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$482			$443,112			$—		$—			$443,594
Total costs and expenses	208,054			910,522			—		492			1,119,068
Loss from continuing operations before income taxes	(207,572		)	(467,410		)	—		(492		)	(675,474		)
Income tax benefit	—			—			—		—			—
Equity in loss of subsidiaries	(467,410		)	—			—		467,410			—
Loss from continuing operations		($674,982	)		($467,410	)		$—		$466,918			($675,474	)
Income from discontinued operations, net of income taxes	—			—			—		—			—
Net loss		($674,982	)		($467,410	)		$—		$466,918			($675,474	)
Dividends on preferred stock	—			—			—		—			—
Accretion on preferred stock	—			—			—		—			—
Net loss attributable to common shareholders		($674,982	)		($467,410	)		$—		$466,918			($675,474	)

	Year Ended December 31, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$1,708			$427,495			$—		$—			$429,203
Total costs and expenses	95,464			1,603,515			—		28,984			1,727,963
Loss from continuing operations before income taxes	(93,756		)	(1,176,020		)	—		(28,984		)	(1,298,760		)
Income tax benefit	10,125			127,010			—		3,740			140,875
Equity in loss of subsidiaries	(1,049,010		)	—			—		1,049,010			—
Loss from continuing operations		($1,132,641	)		($1,049,010	)		$—		$1,023,766			($1,157,885	)
Income from discontinued operations, net of income taxes	2,731			—			—		—			2,731
Net loss		($1,129,910	)		($1,049,010	)		$—		$1,023,766			($1,155,154	)
Dividends on preferred stock	—			—			—		—			—
Accretion on preferred stock	—			—			—		—			—
Net loss attributable to common shareholders		($1,129,910	)		($1,049,010	)		$—		$1,023,766			($1,155,154	)

F-39

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($121,107	)		$544,088			$—		$—			$422,981
Net cash used in investing activities from continuing operations	(615,364		)	(1,155,340		)	—		611,252			(1,159,452		)
Net cash provided by financing activities from continuing operations	741,817			611,252			—		(611,252		)	741,817
Net cash used in discontinued operations	—			—			—		—			—
Net increase in cash and cash equivalents	5,346			—			—		—			5,346
Cash and cash equivalents, beginning of year	4,194			—			—		—			4,194
Cash and cash equivalents, end of year		$9,540			$—			$—		$—			$9,540

	Year Ended December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($34,773	)		$307,541			$—			$—			$272,768
Net cash used in investing activities from continuing operations	(312,291		)	(575,824		)	(740		)	269,023			(619,832		)
Net cash provided by financing activities from continuing operations	308,340			268,283			740			(269,023		)	308,340
Net cash used in discontinued operations	—			—			—			—			—
Net decrease in cash and cash equivalents	(38,724		)	—			—			—			(38,724		)
Cash and cash equivalents, beginning of year	42,918			—			—			—			42,918
Cash and cash equivalents, end of year		$4,194			$—			$—			$—			$4,194

	Year Ended December 31, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by operating activities from continuing operations		$2,655			$376,080			$—		$—			$378,735
Net cash used in investing activities from continuing operations	(447,296		)	(674,758		)	—		448,678			(673,376		)
Net cash provided by financing activities from continuing operations	480,767			298,678			—		(448,678		)	330,767
Net cash used in discontinued operations	(4,046		)	—			—		—			(4,046		)
Net increase in cash and cash equivalents	32,080			—			—		—			32,080
Cash and cash equivalents, beginning of year	10,838			—			—		—			10,838
Cash and cash equivalents, end of year		$42,918			$—			$—		$—			$42,918

F-40

14. Supplemental Cash Flow Information

Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$77,213			$75,231			$64,692
Cash paid for income taxes	—			—			—
Non-cash investing and financing activities:
Increase (decrease) in capital expenditure payables and accruals		$102,272			($21,492	)		($86,878	)
Contingent consideration related to acquisitions of oil and gas properties	52,300			—			—
Contingent consideration related to divestitures of oil and gas properties	(8,805		)	—			—
Liabilities assumed in connection with the Sanchez Acquisition	—			4,880			—
Stock-based compensation expense capitalized to oil and gas properties	4,482			4,591			4,574
Asset retirement obligations capitalized to oil and gas properties	3,726			1,927			4,853

15.Subsequent Events (Unaudited)

Divestitures

Niobrara.On January 19, 2018, the Company closed the sale of substantially all of its assets in the Niobrara Formation. The Company has received net cash proceeds of approximately $136.6 million, subject to post-closing adjustments, which includes a deposit received upon the execution of the purchase and sale agreement and amounts received at closing.

Eagle Ford. On January 31, 2018, the Company closed the sale of a portion of its assets in the Eagle Ford Shale to EP Energy E&P Company, L.P. The Company has received net cash proceeds of approximately $246.2 million, subject to post-closing adjustments, which includes a deposit received upon the execution of the purchase and sale agreement and amounts received at the initial closing as well as a subsequent closing for leases that were not conveyed at the initial closing.

See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details regarding these divestitures.

Redemptions of 7.50% Senior Notes due 2020

On January 19, 2018, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes to call for redemption on February 18, 2018, $100.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On February 20, 2018, the Company paid an aggregate redemption price of $105.1 million, which included a redemption premium of $1.9 million as well as accrued and unpaid interest of $3.2 million from the last interest payment date up to, but not including, the redemption date.

On January 31, 2018, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes to call for redemption on March 2, 2018, $220.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On the redemption date, the Company expects to pay an aggregate redemption price of $231.8 million, which includes a redemption premium of $4.1 million as well as accrued and unpaid interest of $7.7 million from the last interest payment date up to, but not including, the redemption date.

Redemption of Preferred Stock

On January 19, 2018, the Company provided a notice to be delivered to the holders of its Preferred Stock under which it called for redemption of 50,000 of the shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, on January 24, 2018. The Company paid $50.5 million on January 24, 2018 upon redemption, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends.

Senior Secured Revolving Credit Facility

On January 31, 2018, as a result of the divestiture in the Eagle Ford Shale discussed above, the Company’s borrowing base under the Senior Secured Revolving Credit Facility was reduced from $900.0 million to $830.0 million, however, the elected commitment amount remained unchanged at $800.0 million.

F-41

Hedging

In January 2018, the Company entered into the following natural gas derivative positions at the weighted average contract prices summarized below:

Natural Gas Fixed Price Swaps

Period	Volumes (MMBtu/d)	NYMEX Price ($/MMBtu)
March 2018 - December 2018	25,000		$3.01

16. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited)

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below:

	Years Ended December 31,
	2017		2016		2015
	(In thousands)
Property acquisition costs
Proved properties		$303,307		$90,661		$—
Unproved properties	525,061		113,535		63,446
Total property acquisition costs	828,368		204,196		63,446
Exploration costs	91,098		37,508		117,227
Development costs	569,982		374,134		389,396
Total costs incurred		$1,489,448		$615,838		$570,069

Costs incurred exclude capitalized interest on unproved properties of $28.3 million, $17.0 million, and $32.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. Included in exploration and development costs are non-cash additions related to the estimated future asset retirement obligations of the Company’s oil and gas properties of $3.5 million, $1.9 million and $4.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. Non-cash additions related to the estimated future asset retirement obligations associated with the ExL Acquisition of $0.1 million and for the Sanchez Acquisition of $2.0 million are included in acquisition costs of proved properties for the year ended December 31, 2017 and 2016, respectively. The internal cost of employee compensation and benefits, including stock-based compensation, capitalized to proved or unproved oil and gas properties of $14.8 million, $10.5 million and $15.8 million for the years ended December 31, 2017, 2016 and 2015, respectively, are included in exploration, development and unproved property acquisition costs.

Proved Oil and Gas Reserve Quantities

Proved oil and gas reserves are generally those quantities of crude oil, NGLs and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves include reserves that can be expected to be produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves include reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserve quantities at December 31, 2017, 2016, and 2015 and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company, L.P. Such estimates have been prepared in accordance with guidelines established by the SEC. All of the Company’s proved reserves are attributable to properties within the United States. 

F-42

The Company’s proved reserves and changes in proved reserves are as follows:

	Crude Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total Proved Reserves (MBoe)
Proved reserves:
January 1, 2015	100,704		13,513		221,017		151,053
Extensions and discoveries	26,358		5,292		33,925		37,304
Revisions of previous estimates	(9,059	)	2,768		11,808		(4,323	)
Production	(8,415	)	(1,352	)	(21,812	)	(13,402	)
December 31, 2015	109,588		20,221		244,938		170,632
Extensions and discoveries	40,074		8,612		59,318		58,572
Revisions of previous estimates	(16,731	)	(3,230	)	1,481		(19,713	)
Purchases of reserves in place	4,810		122		7,282		6,145
Production	(9,423	)	(1,788	)	(25,574	)	(15,473	)
December 31, 2016	128,318		23,937		287,445		200,163
Extensions and discoveries	50,476		13,781		98,980		80,754
Revisions of previous estimates	(19,838	)	(909	)	27,774		(16,118	)
Purchases of reserves in place	21,634		8,642		94,962		46,103
Sales of reserves in place	(650	)	(526	)	(170,219	)	(29,546	)
Production	(12,566	)	(2,327	)	(28,472	)	(19,639	)
December 31, 2017	167,374		42,598		310,470		261,717
Proved developed reserves:
December 31, 2014	35,238		5,294		149,697		65,482
December 31, 2015	42,311		7,933		154,725		76,032
December 31, 2016	51,062		9,387		187,054		91,625
December 31, 2017	69,632		17,447		131,355		108,972
Proved undeveloped reserves:
December 31, 2014	65,466		8,219		71,320		85,571
December 31, 2015	67,277		12,288		90,213		94,600
December 31, 2016	77,256		14,550		100,391		108,538
December 31, 2017	97,742		25,151		179,115		152,745

Extensions and discoveries

For the year ended December 31, 2017, the Company added 6,473 MBoe of proved developed reserves and 74,281 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 51% and 48%, respectively, of the total extensions and discoveries.

For the year ended December 31, 2016, the Company added 6,525 MBoe of proved developed reserves and 52,047 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 79% and 20%, respectively, of the total extensions and discoveries.

For the year ended December 31, 2015, the Company added 5,237 MBoe of proved developed reserves and 32,067 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford comprised 89% of the total extensions and discoveries.

F-43

Revisions of previous estimates

For the year ended December 31, 2017, revisions of previous estimates reduced the Company’s proved reserves by 16,118 MBoe. Included in revisions of previous estimates were:

• Positive revisions due to price of 2,684 MBoe.

• Negative revisions due to performance of 4,500 MBoe primarily in the Eagle Ford due to a downward shift of the type curve for certain PUD locations partially offset by positive revisions due to well performance in Marcellus which occurred prior to the sale in November 2017.

• Negative revisions in proved undeveloped reserves of 14,302 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the recent ExL Acquisition and the move to a more efficient development plan which includes drilling and completing larger pads.

For the year ended December 31, 2016, revisions of previous estimates reduced the Company’s proved reserves by 19,713 MBoe. Included in revisions of previous estimates were:

• Negative revisions due to price of 6,705 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 3,228 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 3,477 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations due to loss of tail reserves;

• Negative revisions due to performance of 6,083 MBoe primarily in Eagle Ford as the EURs for certain PUD locations were reduced as a result of tighter spacing and shorter lateral lengths partially offset by positive revisions in Marcellus;

• Negative revisions in proved undeveloped reserves of 6,925 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the move to a more efficient development plan which includes drilling and completing larger pads and the recent Sanchez Acquisition.

For the year ended December 31, 2015, revisions of previous estimates reduced the Company’s proved reserves by 4,323 MBoe. Included in revisions of previous estimates were:

• Negative revisions due to price of 15,846 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 6,208 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 9,638 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations resulting in shorter economic lives;

• Positive revisions due to performance of 11,523 MBoe are primarily in Eagle Ford and Marcellus.

Purchases of reserves in place

For the year ended December 31, 2017, purchases of reserves in place included 26,009 MBoe of proved developed reserves and 20,094 MBoe of proved undeveloped reserves associated with the ExL Acquisition.

For the year ended December 31, 2016, purchases of reserves in place included 4,978 MBoe of proved developed reserves and 1,167 MBoe of proved undeveloped reserves associated with the Sanchez Acquisition.

There were no purchases of reserves in place for the year ended December 31, 2015.

Sales of reserves in place

For the year ended December 31, 2017, sales of reserves in place included 22,249 MBoe of proved developed reserves and 7,297 MBoe of proved undeveloped reserves associated with the Marcellus Shale and Utica Shale divestitures.

There were no sales of reserves in place for the years ended December 31, 2016 and 2015.

F-44

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved reserves is as follows:

	December 31,
	2017			2016			2015
	(In thousands)
Future cash inflows		$10,109,752			$5,903,629			$5,878,348
Future production costs	(3,202,201		)	(2,241,928		)	(2,124,059		)
Future development costs	(1,699,909		)	(1,264,493		)	(1,178,773		)
Future income taxes (1)	(445,056		)	—			—
Future net cash flows	4,762,586			2,397,208			2,575,516
Less 10% annual discount to reflect timing of cash flows	(2,297,544		)	(1,093,779		)	(1,210,292		)
Standard measure of discounted future net cash flows		$2,465,042			$1,303,429			$1,365,224

(1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company’s proved oil and gas reserves as of December 31, 2016 and 2015.

Proved reserve estimates and future cash flows are based on the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the year. The average realized prices used for 2017, 2016 and 2015 were $49.87, $39.60, and $47.24 per Bbl, respectively, for crude oil, $19.78, $11.66 and $12.00 per Bbl, respectively, for NGLs, and $2.96, $1.89 and $1.87 per Mcf, respectively, for natural gas.

Future operating and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved reserves at the end of the year, based on current costs and assuming continuation of existing economic conditions. Future income taxes, which include the effects of the Tax Cuts and Jobs Act, are based on current statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in proved reserve estimates.

F-45

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows relating to proved reserves are summarized below:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Standardized measure at beginning of year		$1,303,429			$1,365,224			$2,555,082
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production		$710,773			($346,763	)		($2,547,213	)
Net change in estimated future development costs	(51,854		)	74,407			342,238
Net change due to revisions in quantity estimates	(42,214		)	(150,245		)	(157,271		)
Accretion of discount	130,343			136,522			326,074
Changes in production rates (timing) and other	(116,056		)	(111,137		)	(139,533		)
Total revisions to reserves proved in prior years	630,992			(397,216		)	(2,175,705		)
Net change due to extensions and discoveries, net of estimated future development and production costs	597,502			313,201			252,155
Net change due to purchases of reserves in place	452,932			43,426			—
Net change due to divestitures of reserves in place	(106,608		)	—			—
Sales of crude oil, NGLs and natural gas produced, net of production costs	(566,258		)	(320,272		)	(312,213		)
Previously estimated development costs incurred	326,383			299,066			340,247
Net change in income taxes	(173,330		)	—			705,658
Net change in standardized measure of discounted future net cash flows	1,161,613			(61,795		)	(1,189,858		)
Standardized measure at end of year		$2,465,042			$1,303,429			$1,365,224

F-46

17. Quarterly Financial Data (Unaudited)

The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2017 and 2016:

Year Ended December 31, 2017	First Quarter			Second Quarter			Third Quarter (2)		Fourth Quarter (3)
	(In thousands, except per share data)
Total revenues		$151,355			$166,483			$181,279		$246,771
Operating profit (1)		$57,953			$63,147			$69,364		$113,205
(Gain) loss on derivatives, net		($25,316	)		($26,065	)		$24,377		$86,107
Net income (loss)		$40,021			$56,306			$7,823		($17,040	)
Net income (loss) attributable to common shareholders		$40,021			$56,306			$5,574		($23,434	)
Net income (loss) attributable to common shareholders per common share (3)
Basic		$0.61			$0.86			$0.07		($0.29	)
Diluted		$0.61			$0.85			$0.07		($0.29	)

Year Ended December 31, 2016	First Quarter (4)			Second Quarter (4)			Third Quarter (4)			Fourth Quarter
	(In thousands, except per share data)
Total revenues		$81,262			$107,324			$111,177			$143,831
Operating profit (loss) (1)		($7,491	)		$27,167			$31,634			$55,000
Net loss		($311,395	)		($262,126	)		($101,174	)		($779	)
Net loss attributable to common shareholders		($311,395	)		($262,126	)		($101,174	)		($779	)
Net loss attributable to common shareholders per common share (3)
Basic		($5.34	)		($4.46	)		($1.72	)		($0.01	)
Diluted		($5.34	)		($4.46	)		($1.72	)		($0.01	)

(1) Total revenues less lease operating expense, production taxes, ad valorem taxes and DD&A.

(2) Third quarter of 2017 included the following:

a. $2.2 million of Preferred Stock dividends which reduced net income attributable to common shareholders.

(3) Fourth quarter of 2017 included the following:

a. $4.2 million loss on extinguishment of debt as a result of the redemption of $150.0 million aggregate principal amount of 7.50% Senior Notes.

b. $5.5 million of Preferred Stock dividends which increased net loss attributable to common shareholders.

(4) The sum of quarterly net income (loss) attributable to common shareholders per common share does not agree with the total year net income (loss) attributable to common shareholders per common share as each computation is based on the weighted average of common shares outstanding during the period.

(5) In the first quarter, second quarter, and third quarter of 2016, the Company recognized impairments of proved oil and gas properties of $274.4 million, $197.1 million, and $105.1 million, respectively.

F-47

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CARRIZO OIL & GAS, INC.
By:	/s/ David L. Pitts
	David L. Pitts
	Vice President and Chief Financial Officer

Date: February 28, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Capacity	Date
/s/ S.P. Johnson IV	President, Chief Executive Officer and Director	February 28, 2018
S. P. Johnson IV	(Principal Executive Officer)
/s/ David L. Pitts	Vice President and Chief Financial Officer	February 28, 2018
David L. Pitts	(Principal Financial Officer)
/s/ Gregory F. Conaway	Vice President and Chief Accounting Officer	February 28, 2018
Gregory F. Conaway	(Principal Accounting Officer)
/s/ Steven A. Webster	Chairman of the Board	February 28, 2018
Steven A. Webster
/s/ Thomas L. Carter, Jr.	Director	February 28, 2018
Thomas L. Carter, Jr.
/s/ Robert F. Fulton	Director	February 28, 2018
Robert F. Fulton
/s/ F. Gardner Parker	Director	February 28, 2018
F. Gardner Parker
/s/ Roger A. Ramsey	Director	February 28, 2018
Roger A. Ramsey
/s/ Frank A. Wojtek	Director	February 28, 2018
Frank A. Wojtek

S-1

EX-2.2

Exhibit 2.2

PURCHASE AND SALE AGREEMENT

between

CARRIZO OIL & GAS, INC.

and

CARRIZO (EAGLE FORD) LLC,

as Seller

and

EP ENERGY E&P Company, L.P.

as Buyer

dated

December 11, 2017

TABLE OF CONTENTS

Page

Article I DEFINITIONS AND INTERPRETATION 1

Section 1.1. Defined Terms    1

Section 1.2. Interpretations    1

Article II PURCHASE AND SALE 2

Section 2.1. Purchase and Sale    2

Section 2.2. Excluded Assets    4

Section 2.3. Revenues and Expenses    4

Article III PURCHASE PRICE 5

Section 3.1. Purchase Price; Deposit    5

Section 3.2. Adjustments to Purchase Price    5

Section 3.3. Adjustment Methodology    7

Section 3.4. Preliminary Settlement Statement    7

Section 3.5. Final Settlement Statement    7

Section 3.6. Disputes    8

Section 3.7. Allocation of Purchase Price for Tax Purposes    8

Section 3.8. Allocated Value    9

Article IV REPRESENTATIONS AND WARRANTIES OF SELLER 9

Section 4.1. Organization, Existence    9

Section 4.2. Authorization    9

Section 4.3. No Conflicts    9

Section 4.4. Consents    10

Section 4.5. Bankruptcy    10

Section 4.6. Litigation    10

Section 4.7. Material Contracts    10

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(continued)

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Section 4.8. No Violation of Laws    12

Section 4.9. Preferential Rights    12

Section 4.10. Personal Property    12

Section 4.11. Imbalances    12

Section 4.12. Current Commitments    12

Section 4.13. Contribution Requirements    12

Section 4.14. Non-Consent Elections    12

Section 4.15. Payout Balances    12

Section 4.16. Environmental    13

Section 4.17. Asset Taxes    13

Section 4.18. Tax Partnerships    14

Section 4.19. Brokers’ Fees    14

Section 4.20. Current Plugging Obligations    14

Section 4.21. Bonds and Guaranties    14

Section 4.22. Permits    14

Section 4.23. Leases; Payments    14

Article V BUYER’S REPRESENTATIONS AND WARRANTIES 15

Section 5.1. Organization; Existence    15

Section 5.2. Authorization    15

Section 5.3. No Conflicts    15

Section 5.4. Consents    15

Section 5.5. Bankruptcy    16

Section 5.6. Litigation    16

Section 5.7. Financing    16

Section 5.8. Independent Evaluation    16

Section 5.9. Brokers’ Fees    16

Section 5.10. Accredited Investor    16

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(continued)

Page

Section 5.11. Qualified Operator; Credit Support    17

Section 5.12. No Foreign Ownership or Control    17

Article VI CERTAIN AGREEMENTS 17

Section 6.1. Conduct of Business    17

Section 6.2. Notification of Breaches    19

Section 6.3. Successor Operator    19

Section 6.4. Governmental and Third Party Bonds    19

Section 6.5. Record Retention    19

Section 6.6. Like-Kind Exchange    20

Section 6.7. Marketing and Transportation Agreements    20

Section 6.8. Amendment to Schedules    20

Section 6.9. Tax Matters    21

Article VII CONDITIONS TO CLOSING 22

Section 7.1. Buyer’s Conditions to Closing    22

Section 7.2. Seller’s Conditions to Closing    22

Article VIII CLOSING 23

Section 8.1. Date of Closing    23

Section 8.2. Place of Closing    24

Section 8.3. Closing Obligations    24

Section 8.4. Records    26

Article IX ACCESS; CONFIDENTIALITY; USE; DISCLAIMERS 26

Section 9.1. Access    26

Section 9.2. Confidentiality; Use    28

Section 9.3. Disclaimers    29

Article X TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS 31

Section 10.1. Seller’s Title    31

Section 10.2. Notice of Title Defects; Defect Adjustments    32

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TABLE OF CONTENTS

(continued)

Page

Section 10.3. Casualty or Condemnation Loss    35

Section 10.4. Preferential Rights to Purchase and Consents to Assign    36

Article XI ENVIRONMENTAL MATTERS 39

Section 11.1. Environmental Conditions    39

Section 11.2. NORM, Wastes and Other Substances    43

Article XII ASSUMPTION; SURVIVAL; INDEMNIFICATION 43

Section 12.1. Assumption by Buyer    43

Section 12.2. Retained Obligations; Indemnities of Seller    44

Section 12.3. Indemnities of Buyer    44

Section 12.4. Limitation on Liability    45

Section 12.5. Express Negligence    46

Section 12.6. Exclusive Remedy    46

Section 12.7. Indemnification Procedures    46

Section 12.8. Survival    48

Section 12.9. Waiver of Right to Rescission    49

Section 12.10. Non-Compensatory Damages    49

Section 12.11. Disclaimer of Application of Anti-Indemnity Statutes    49

Section 12.12. Waiver of Trade Practices Act    50

Article XIII TERMINATION, DEFAULT AND REMEDIES 50

Section 13.1. Right of Termination    50

Section 13.2. Effect of Termination; Remedies    51

Section 13.3. Return of Documentation and Confidentiality    51

Article XIV MISCELLANEOUS 52

Section 14.1. Expenses and Taxes    52

Section 14.2. Assignment    53

Section 14.3. Publicity    53

Section 14.4. Notices    53

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TABLE OF CONTENTS

(continued)

Page

Section 14.5. Removal of Name    54

Section 14.6. Further Cooperation    54

Section 14.7. Filings and Certain Governmental Approvals    55

Section 14.8. Entire Agreement    55

Section 14.9. Parties in Interest    55

Section 14.10. Amendment    55

Section 14.11. Waiver; Rights Cumulative    55

Section 14.12. Governing Law; Dispute Resolution    56

Section 14.13. Severability    57

Section 14.14. Counterparts    57

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TABLE OF CONTENTS

(continued)

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LIST OF APPENDICES, EXHIBITS AND SCHEDULES

Appendices

Appendix 1    Definitions

Appendix 2    Permitted Encumbrances

Appendix 3        Illustrative List of Items that are not Title Defects

Exhibits

Exhibit A-1    Leases

Exhibit A-2    Fee Interests

Exhibit A-3    Wells

Exhibit B    Rights of Way

Exhibit C    Form of Assignment and Bill of Sale

Exhibit D    Form of Assignment and Assumption for certain Contracts

Exhibit E    Form of Deed

Schedules

Schedule 1    Excluded Assets

Schedule 3.2(a)(vi)    Certain Capital Expenditures

Schedule 3.8    Allocated Values

Schedule 4.3    Conflicts

Schedule 4.4(a)    Required Consents

Schedule 4.4(b)    Soft Consents

Schedule 4.6    Litigation

Schedule 4.7    Material Contracts

Schedule 4.8    Violation of Laws

Schedule 4.9    Preferential Rights

Schedule 4.10    Personal Property

Schedule 4.11    Imbalances

Schedule 4.12    Current Commitments

Schedule 4.13    Contribution Requirements

Schedule 4.14    Non-Consent Elections

Schedule 4.15    Payout Balances

Schedule 4.16    Environmental

Schedule 4.17    Asset Taxes

Schedule 4.18    Tax Partnerships

Schedule 4.20    Plugging Obligations

Schedule 4.21    Bonds, Letters of Credit and Guarantees

Schedule 4.22    Permits

Schedule 4.23    Leases; Payments

Schedule 4.23(a)    Suspense Funds

Schedule 6.1    Conduct of Business

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PURCHASE AND SALE AGREEMENT

This PURCHASE AND SALE AGREEMENT (as may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is executed as of December 11, 2017 (the “Execution Date”), and is between Carrizo Oil & Gas, Inc., a Texas corporation (“Carrizo”), and Carrizo (Eagle Ford) LLC, a Delaware limited liability company (“Carrizo Eagle Ford,” and together with Carrizo, “Seller”), and EP Energy E&P Company, L.P., a Delaware limited partnership (“Buyer”).

Recitals

A.    Seller desires to sell and convey, and Buyer desires to purchase and pay for, all of Seller’s right, title and interest in and to certain oil and gas properties targeting the Eagle Ford Formation in the State of Texas (in LaSalle, McMullen and Frio counties) effective as of the Effective Time (as hereinafter defined).

B.    Certain of the Properties (as hereinafter defined) are owned of record by Carrizo for the benefit of Carrizo Eagle Ford, a wholly owned subsidiary of Carrizo.

NOW, THEREFORE, for and in consideration of the mutual promises contained herein, the benefits to be derived by each party hereunder, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Seller and Buyer agree as follows:

ARTICLE I

DEFINITIONS AND INTERPRETATION

Section 1.1.Defined Terms. In addition to the terms defined in the preamble of this Agreement, for purposes hereof, the capitalized terms used herein and not otherwise defined shall have the meanings set forth in Appendix 1.

Section 1.2.Interpretations. In construing this Agreement: (a) no consideration shall be given to the captions of the articles, sections, subsections or clauses, which are inserted for convenience in locating the provisions of this Agreement and not as an aid to construction and shall not be interpreted to limit or otherwise affect the provisions of this Agreement or the rights and other legal relations of the parties hereto; (b) no consideration shall be given to the fact or presumption that either party had a greater or lesser hand in drafting this Agreement; (c) examples shall not be construed to limit, expressly or by implication, the matter they illustrate; (d) the word “includes” and its syntactic variants mean, unless otherwise specified, “includes, but is not limited to” and corresponding syntactic variant expressions; (e) words such as “herein,” “hereby,” “hereafter,” “hereof,” “hereto,” “hereabove,” “hereinabove,” “hereinbelow” and “hereunder” refer to this Agreement as a whole and not to any particular article, section or provision of this Agreement; (f) whenever the context requires, the plural shall be deemed to include the singular, and vice versa; (g) each gender shall be deemed to include the other gender, when such construction is appropriate; (h) all of the Appendices, Exhibits and Schedules referred to in this Agreement are part of this Agreement and each Appendix, Exhibit and Schedule is hereby incorporated herein as if set forth in full herein; (i) references to a Person are also to its permitted successors and permitted assigns;

(j) all references in this Agreement to Appendices, Exhibits, Schedules, Articles and Sections refer to the corresponding Appendices, Exhibits, Schedules, Articles and Sections of this Agreement unless expressly provided otherwise; (k) unless expressly stated otherwise, the word “or” is not exclusive; and (l) unless otherwise expressly provided herein, any agreement, instrument or Law defined or referred to herein means such agreement, instrument or Law as from time to time amended, modified or supplemented, including (in the case of agreements or instruments) by waiver or consent and (in the case of Laws) by succession of comparable successor Laws and reference to all attachments thereto and instruments incorporated therein. Each accounting term not defined herein will have the meaning given to it under generally accepted accounting principles, as interpreted as of the Execution Date.

ARTICLE II

PURCHASE AND SALE

Section 2.1.Purchase and Sale. Subject to the terms and conditions of this Agreement, Seller agrees to sell, and Buyer agrees to purchase and pay for, all of Seller’s right, title and interest in and to the following (less and except for the Excluded Assets, such right, title and interest, collectively, the “Assets”):

(a)the oil and gas leases, more particularly described in Exhibit A-1 (collectively, the “Leases”), together with any and all other rights, titles and interests of Seller in and to (i) the leasehold estates created thereby and (ii) the lands covered by the Leases or included in units with which the Leases may have been pooled or unitized (the “Lands”), including in each case, fee interests, royalty interests, overriding royalty interests, production payments, net profits interests, carried interests and obligations, reversionary interests and all other interests of any kind or character;

(b)the surface or oil and gas mineral fee interests more particularly described in Exhibit A-2 (collectively, the “Fee Interests”);

(c)all oil, gas, water, injection, monitoring, and other wells located on the Leases, Lands, or Fee Interests or on other leases or lands with which the Leases, Lands or Fee Interests may have been pooled or unitized (collectively, the “Wells”) including those described in Exhibit A-3, and all Hydrocarbons produced therefrom or allocated thereto (the Leases, the Lands, the Fee Interests, the Wells, and the units described in Section 2.1(d) being collectively referred to hereinafter as the “Properties”);

(d)all rights and interests in, under or derived from all unitization and pooling agreements in effect with respect to the Properties and the units created thereby which accrue or are attributable to the interests of Seller in the Properties;

(e)all Applicable Contracts, but only with respect to rights and obligations arising thereunder from and after the Effective Time, except for rights relating to the Assumed Obligations;

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(f)to the extent that they may be assigned (subject toSection 10.4(f)), all permits, licenses, servitudes, easements, rights-of-way and other surface agreements (including those set forth on Exhibit B) to the extent used or held for use in connection with the ownership or operation of the Properties, the Applicable Contracts or the Personal Property (the “Easements”);

(g)all equipment, machinery, fixtures, and other real, personal and mixed property, operational and nonoperational, known or unknown, located on the Properties or the other Assets described above or used or held for use in connection with the Properties or other Assets described above, including well equipment, casing, rods, tanks, boilers, buildings, tubing, pumps, motors, fixtures, machinery, compression equipment, flow lines, pipelines, gathering systems, processing and separation facilities, structures, materials and other items used or held for use in the operation or maintenance thereof (“Personal Property”);

(h)all Imbalances relating to the Properties or other Assets;

(i)all geophysical and other seismic and related technical data and information relating to the Assets, excluding any proprietary geologic and geophysical interpretations (collectively, the “Seismic Data and Information”), to the extent such data and information may be assigned without Third Party consent or expenditures beyond tape copying costs and expenses unless Buyer has paid such expenditures and entered into a license agreement with the Third Party licensor;

(j)all of the rights, titles and interests of Seller in and to all of the files, records, information and data, whether written or electronically stored, to the extent relating to the Assets, including: (i) land and title records (including abstracts of title, title opinions and title curative documents); (ii) contract files; (iii) correspondence; (iv) log books and Operating Data; and (v) facility and well records (“Records”), which Records will be provided to Buyer in electronic form if so maintained by Seller and otherwise in paper form; provided, however, that Seller shall have the right to retain copies of any or all such Records, and provided further, that Records shall not include any of the foregoing to the extent a transfer or disclosure would be restricted by obligations of confidentiality (provided, however, that Seller shall use commercially reasonable efforts to obtain a waiver of such restriction, provided, however, that Seller shall not be required to incur any out-of-pocket costs in seeking to obtain any such waiver) or to the extent that such information is privileged (excluding, however, title opinions and Applicable Contracts);

(k)any claims and causes of action arising under or with respect to any Asset and all proceeds arising from such claims and causes of action, including any settlements thereof, to the extent such claims, causes of action and proceeds are attributable to the period from or after the Effective Time or relate to an Assumed Obligation;

(l)all audit rights arising under any of the Applicable Contracts or otherwise with respect to any period from or after the Effective Time pertaining to any of the Assets or that relate to an Assumed Obligation (or any other obligation which is the responsibility of Buyer hereunder) and, in each case, to the extent not relating to any Retained Obligations; and

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(m)any amounts held in suspense by Seller or any Third Party on Seller’s behalf pertaining to any of the Assets and that relate to an Assumed Obligation.

Section 2.2.Excluded Assets. Seller shall reserve and retain all of the Excluded Assets.

Section 2.3.Revenues and Expenses.

(a)Subject to the provisions hereof, Seller shall remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) attributable to, and shall remain responsible for all Operating Expenses incurred with respect to, the Assets for the period of time prior to the Effective Time. Subject to the provisions hereof, and subject to the occurrence of the Closing, Buyer shall be entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) attributable to, and shall be responsible for all Operating Expenses incurred with respect to, the Assets for the period of time from and after the Effective Time. Subject to the provisions hereof, all Operating Expenses attributable to the Assets, in each case that are: (i) incurred prior to the Effective Time shall be paid by or allocated to Seller and (ii) incurred from or after the Effective Time shall be paid by or allocated to Buyer. “Operating Expenses” means all operating expenses (including obligations to pay working interests, Royalties or other interest owners’ revenues or proceeds attributable to sales of Hydrocarbons relating to the Properties and including costs of insurance) and capital expenditures incurred in the ownership and operation of the Assets in the ordinary course of business and, where applicable, in accordance with the relevant operating or unit agreement, if any, and overhead costs charged to the Assets by Buyer or its Affiliate under the relevant operating agreement or unit agreement, if any, but excluding other overhead, general and administrative, and similar costs (without limiting Section 3.2(a)(v)) and further excluding, in each case, costs incurred by Seller (w) to cure any Title Defect (excluding any ordinary course title curative undertaken in furtherance of the drilling or completion of any well on the Properties on or after the Effective Time) or to cure or remediate any Environmental Condition that exceeds the Individual Environmental Threshold, regardless of whether raised by Buyer under Article X and/or Article XI; (x) in respect of Retained Obligations; (y) in respect of Taxes and Transfer Taxes; or (z) in respect of any indemnification, defense, hold harmless, contribution, or reimbursement requirement under Section 12.2, regardless of Section 12.4. Determination of whether Operating Expenses are incurred before or after the Effective Time for purposes of this Section 2.3(a) is based on when services are rendered, when goods are delivered or when the work is performed. Operating Expenses that are paid periodically shall be prorated based on the number of days in the applicable period falling before, or on or after, the Effective Time, as applicable. Operating Expenses allocable to both the Assets and other assets and properties (including costs of insurance) shall be prorated between the Assets to which such Operating Expenses apply and such other assets and properties pursuant to Seller’s past accounting practices, consistently applied, or, if no such accounting practices exist, a methodology reasonably reflective of the costs of ownership of the applicable Assets and any other assets and properties, in any case, excluding the effects of this Agreement.

(b)For purposes of allocating production (and proceeds of production and other proceeds) under this Section 2.3, (i) liquid Hydrocarbons shall be deemed to be “from or attributable

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to” the Properties when they pass through the pipeline connecting into the storage facilities into which they are run and (ii) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Properties when they pass through the royalty measurement meters, delivery point sales meters or custody transfer meters on the gathering lines or pipelines through which they are transported (whichever meter is closest to the well). Seller shall utilize reasonable interpolative procedures to arrive at an allocation of production when exact meter readings or gauging and strapping data is not available.

(c)Notwithstanding anything in this Section 2.3 to the contrary and without limiting Buyer’s rights with respect to Section 4.23(b) and Section 12.2(c)(vii) (as such rights may be limited by Article XII), (i) the Final Settlement Statement shall be the final accounting for any and all Operating Expenses owing from Seller to Buyer, and there shall be no adjustment for, or obligation to pay, any Operating Expenses owing from Seller to Buyer following the final determination of the Final Settlement Statement, and (ii) all Operating Expenses attributable to the Assets and not otherwise accounted for in the Final Settlement Statement shall become an “Assumed Obligation” as and to the extent set forth in Article XII.

ARTICLE III

PURCHASE PRICE

Section 3.1.Purchase Price; Deposit.

(a)The purchase price for the Assets shall be Two Hundred and Forty-Five Million Dollars ($245,000,000) (the “Purchase Price”), payable in United States currency by wire transfer in same day funds as and when provided in this Agreement.

(b)Concurrently with the execution of this Agreement, Buyer has deposited by wire transfer in same day funds with Seller an amount equal to Twenty-Four Million Five Hundred Thousand Dollars ($24,500,000) (the “Deposit”), which amount represents ten percent (10%) of the Purchase Price. The Deposit (without interest) shall be applied towards the Adjusted Purchase Price at Closing in accordance with Section 8.3(a)(vii) or be distributed in accordance with the terms of Section 13.2, as applicable.

Section 3.2.Adjustments to Purchase Price. The Purchase Price shall be adjusted as follows, and the resulting amount shall be herein called the “Adjusted Purchase Price”:

(a)The Purchase Price shall be adjusted upward by the following amounts (without duplication):

(i)an amount equal to all proceeds received by Buyer following Closing, in each case attributable to the sale of Hydrocarbons produced from or attributable or allocable to the Assets prior to the Effective Time, net of any Asset Taxes not already taken into account under Section 3.2(b)(iii), incurred in connection therewith and not reimbursed to Buyer by a Third Party purchaser and net of all Royalties (provided that to the extent such a netting for Royalties is made, Buyer shall assume

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the obligation to pay the netted amounts to the Persons to whom such amounts are due);

(ii)an amount equal to all Operating Expenses paid by Seller and not reimbursed to Seller that are incurred with respect to, the Assets on or after the Effective Time, whether paid before or after the Effective Time;

(iii)the amount of all Asset Taxes prorated to Buyer pursuant to Section 14.1(b) but paid by Seller;

(iv)an amount equal to the value of all merchantable Hydrocarbons (excluding basic sediment and water and tank bottoms) produced from or attributable or allocable to the Assets that, at the Effective Time, are in storage or tanks, or above the load level connection or within processing plants, at $50.00 per barrel (with respect to non-gaseous Hydrocarbons) or $3.00 per MCF (with respect to gaseous Hydrocarbons);

(v)for the period of time from the Effective Time until Closing, monthly indirect overhead for producing and drilling/completing Wells included in the Seller Operated Properties that would normally be charged under the applicable joint operating agreement shall instead be calculated as a flat fee of Ninety Thousand Dollars ($90,000.00) per month, prorated for any partial month;

(vi)any capital expenditures incurred by Seller with respect to the Properties listed on Schedule 3.2(a)(vi) and attributable to periods before the Effective Time;

(vii)an amount equal to the value of any Imbalances by which Seller is underproduced or overdelivered priced at $3.00 per Mcf for gas Imbalances, existing as of the Effective Time; and

(viii)any other amount provided for elsewhere in this Agreement or otherwise agreed upon by Seller and Buyer.

(b)The Purchase Price shall be adjusted downward by the following amounts (without duplication):

(i)an amount equal to all proceeds received by or on behalf of Seller on or following the Effective Time, in each case attributable to the sale of Hydrocarbons produced from or attributable or allocable to the Assets from and after the Effective Time, net of any Asset Taxes not already taken into account under Section 3.2(a)(iii), incurred in connection therewith and not reimbursed to Seller by a Third Party purchaser and net of all Royalties (provided that to the extent such a netting for Royalties is made, Seller shall assume the obligation to pay the netted amounts to the Persons to whom such amounts are due);

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(ii)an amount equal to all other proceeds received by Seller (other than from the sale of Hydrocarbons produced from or attributable or allocable to the Assets before the Effective Time) to which Buyer is entitled pursuant to Section 2.3;

(iii)the amount of all Asset Taxes prorated to Seller pursuant to Section 14.1(b) but to be paid by Buyer;

(iv)an amount equal to the value of any Imbalances by which Seller is overproduced or underdelivered priced at $3.00 per Mcf for gas Imbalances, existing as of the Effective Time;

(v)the amount provided in Section 10.2 for Title Defects;

(vi)the amount provided in Section 11.1 for Environmental Conditions;

(vii)the amounts provided in Section 10.2(c), Section 11.1(b), Section 10.3(b) or Section 10.4 for any Properties and other Assets excluded from the Assets pursuant to such Section;

(viii)(A) the amount of any funds held in suspense as described in Section 2.1(m); and (B) Third Party cash call payments received by or on behalf of Seller and not yet applied but only to the extent attributable to Assumed Obligations; and

(ix)any other amount provided for elsewhere in this Agreement or otherwise agreed upon by Seller and Buyer.

Section 3.3.Adjustment Methodology. When available, actual figures will be used for the adjustments to the Purchase Price at the Closing. To the extent actual figures are not available, estimates will be used subject to final adjustments in accordance with Section 3.4.

Section 3.4.Preliminary Settlement Statement. Not less than two (2) business days prior to the Closing, Seller shall prepare and submit to Buyer for review a draft settlement statement (the “Preliminary Settlement Statement”) that shall set forth the Adjusted Purchase Price, reflecting each adjustment made in accordance with this Agreement as of the date of preparation of such Preliminary Settlement Statement and the calculation of the adjustments used to determine such amount, together with reasonable supporting documentation and the designation of Seller’s account for the wire transfers of funds as set forth in Section 8.3(a)(vii). Within twenty-four (24) hours after receipt of the Preliminary Settlement Statement, Buyer will deliver to Seller a written report containing all changes with the explanation therefor that Buyer proposes to be made to the Preliminary Settlement Statement. The Preliminary Settlement Statement, as agreed upon by the parties, will be used to adjust the Purchase Price at Closing. If the parties are unable to reach agreement on adjustments to the Purchase Price on the Preliminary Settlement Statement (excluding adjustments to the Purchase Price under Section 3.2(b)(v), Section 3.2(b)(vi) and Section 3.2(b)(vii)), the Preliminary Settlement Statement as prepared by Seller will be used to adjust the Purchase Price at Closing, absent manifest error.

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Section 3.5.Final Settlement Statement. On or before 120 days after the Closing, a final settlement statement (the “Final Settlement Statement”) will be prepared by Seller, based on actual income and expenses during the Interim Period and which takes into account all final adjustments made to the Purchase Price (excluding any unresolved disputed matters under Section 11.1(b), or Section 10.2(c)) and shows the resulting final Purchase Price (“Final Price”). The Final Settlement Statement shall set forth the actual proration of the amounts required by this Agreement (including Section 2.3). As soon as practicable, and in any event within 30 days, after receipt of the Final Settlement Statement, Buyer shall return a written report containing any proposed changes to the Final Settlement Statement and an explanation of any such changes and the reasons therefor (the “Settlement Statement Dispute Notice”). If the Final Price set forth in the Final Settlement Statement is mutually agreed upon by Seller and Buyer or if Buyer fails to timely deliver the Settlement Statement Dispute Notice, the Final Settlement Statement and the Final Price, shall be final and binding on the parties hereto (excluding any unresolved disputed matters under Section 11.1(b)(i) or Section 10.2(c) and without limiting the other express rights of the parties under this Agreement). Any difference in the Adjusted Purchase Price as paid at Closing pursuant to the Preliminary Settlement Statement and the Final Price shall be paid by the owing party within ten days to the owed party. All amounts paid pursuant to this Section 3.5 shall be delivered in United States currency by wire transfer of immediately available funds to the account specified in writing by the relevant party.

Section 3.6.Disputes. If Seller and Buyer are unable to resolve the matters addressed in a timely delivered Settlement Statement Dispute Notice, each of Buyer and Seller shall, within 14 business days after the delivery of such Settlement Statement Dispute Notice, summarize its position with regard to such dispute in a written document and submit such summaries to the Houston office of Grant Thornton LLP, or such other party as the parties may mutually select (the “Accounting Arbitrator”), together with the Settlement Statement Dispute Notice, the Final Settlement Statement and any other documentation such party may desire to submit. The Accounting Arbitrator shall calculate the Final Price based on the information submitted by the parties and in accordance with the adjustment methodology set forth in this Article III, and render its decision no later than 20 days after receiving the parties’ respective submissions. The Accounting Arbitrator shall act as an expert for the limited purpose of determining the specific disputed aspects of the adjustments to the Purchase Price under this Article III submitted by a party and may not award damages, interest or penalties to any party with respect to any matter. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Seller and Buyer and will be enforceable against any of the parties in any court of competent jurisdiction. The costs of such Accounting Arbitrator shall be borne one-half by Buyer and one-half by Seller. Any difference in the Adjusted Purchase Price as paid at Closing pursuant to the Preliminary Settlement Statement and the Final Price, as determined by the Accounting Arbitrator, shall be paid by the owing party within ten days to the owed party.

Section 3.7.Allocation of Purchase Price for Tax Purposes. For federal income Tax purposes, Buyer and Seller agree that the Final Price and any other items properly treated as consideration for federal income Tax purposes shall be allocated among the Assets transferred to Buyer by each of (i) Carrizo and (ii) Carrizo Eagle Ford in accordance with the principles of Section 1060 of the Code and the Treasury Regulations and in a manner reasonably consistent with the

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Allocated Values, and will be set forth in separate schedules proposed by Buyer and reasonably acceptable to Seller (the “Tax Allocations”). If Seller and Buyer are unable to agree upon the Tax Allocations within 15 days of delivery of proposed schedules by Buyer, the matter will be submitted to the Accounting Arbitrator for binding resolution in accordance with Section 3.6. Buyer and Seller shall each bear their own respective costs of obtaining such resolution, except that any fees and expenses related to the procurement of services from an Accounting Arbitrator shall be shared equally by Buyer and Seller. Buyer and Seller agree that (i) the Tax Allocations shall be used by Seller and Buyer as the basis for reporting asset values and other items for purposes of all federal, state and local Tax Returns, including Internal Revenue Service Form 8594 and (ii) neither they nor their Affiliates will take positions inconsistent with such Tax Allocations in notices to Governmental Authorities, in audit or other proceedings with respect to Taxes. Seller makes no representation or warranty as to the accuracy of any value determined hereunder.

Section 3.8.Allocated Value. The “Allocated Value” for any Asset equals the portion of the unadjusted Purchase Price allocated to such Asset on Schedule 3.8 and such Allocated Value shall be used in calculating adjustments to the Purchase Price as provided herein. Seller makes no representation or warranty as to the accuracy of any Allocated Value.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF SELLER

Except as otherwise provided below or in the disclosures schedules, Seller (jointly and severally) represents and warrants to Buyer the matters set out in this Article IV:

Section 4.1.Organization, Existence. Seller is a corporation (with respect to Carrizo) or limited liability company (with respect to Carrizo Eagle Ford) duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation. Seller has all requisite power and authority to own and operate its property (including its interests in the Assets) and to carry on its business as now conducted. Seller is duly licensed or qualified to do business as a foreign entity, and is in good standing in all jurisdictions in which such qualification is required by Law.

Section 4.2.Authorization. Seller has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery, and performance by Seller of this Agreement and the Transaction Documents to which Seller is a party have been duly and validly authorized and approved by all necessary corporate or limited liability company action on the part of Seller. This Agreement is, and the Transaction Documents to which Seller is a party when executed and delivered by Seller will be, the valid and binding obligation of Seller and enforceable against Seller in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 4.3.No Conflicts. Subject to the receipt of the consents set forth on Schedule 4.4(a), all matters disclosed on Schedule 4.3, the Soft Consents and the Customary Post-Closing Consents, the execution, delivery and performance by Seller of this Agreement and the

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consummation of the transactions contemplated herein will not (a) conflict with or result in a breach of any provisions of the organizational documents or other governing documents of Seller, (b) result in a default or the creation of any Encumbrance or give rise to any right of termination, cancellation, or acceleration under any of the terms, conditions or provisions of any Lease, operating agreement, note, bond, mortgage, indenture, license or other contract, or (c) violate any Law applicable to Seller or any of the Assets the violation of which could reasonably be expected to have a Material Adverse Effect.

Section 4.4.Consents. Except (a) as set forth in Schedule 4.4(a), (b) as set forth in Schedule 4.4(b), (c) Customary Post-Closing Consents, and (d) Preferential Rights to Purchase set forth in Schedule 4.9, there are no consents or other restrictions on assignment, including requirements for consents to any assignment (excluding consents required from Buyer or its Affiliates), in each case that are necessary in connection with the transfer of the Assets or the consummation of the transactions contemplated by this Agreement by Seller.

Section 4.5.Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Seller’s Knowledge, threatened in writing against Seller.

Section 4.6.Litigation. Except as set forth in Schedule 4.6, there is no suit, action, or litigation by any Person by or before any Governmental Authority, and no legal, administrative or arbitration proceedings pending or, to Seller’s Knowledge, threatened against the Assets, Seller or its Affiliates relating to or that may affect any of the Assets (and provided that, with respect to Properties that are not Seller Operated Properties, this Section 4.6 shall be deemed qualified to Seller’s Knowledge to the extent not already so qualified) or Seller’s ownership or operation thereof.

Section 4.7.Material Contracts.

(a)Except for Applicable Contracts to which Buyer (or one or more of its Affiliates) is a named party or (with respect to a Buyer-Operated Property) subject (and provided that, with respect to Properties that are not Seller Operated Properties, this Section 4.7 shall be deemed qualified to Seller’s Knowledge), Schedule 4.7 sets forth all Applicable Contracts of the type described below that relate to the Assets (collectively, the “Material Contracts”):

(i)any Applicable Contract that has resulted or can reasonably be expected to result in aggregate payments or revenues by or to Seller (or its Affiliates) of more than $250,000 for (y) Applicable Contracts that have been in effect for at least one year, during the last, current, or any subsequent calendar year (based solely on the terms thereof and realized volumes and without regard to any expected increase in volumes or revenues) or (z) Applicable Contracts that have been in effect for less than one year, during the current or any subsequent calendar year (based solely on the terms thereof and current volumes and without regard to any expected increase in volumes or revenues);

(ii)any Hydrocarbon purchase and sale, exchange, gathering, transportation, processing, storage, transportation or similar Applicable Contract that

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(A) is not terminable without penalty on 60 days’ or less notice; (B) provides for a commitment of any Asset; or (C) provides for minimum throughputs or volumes or the payment of capital reimbursement, demand charges, facilities access charges or other similar charges;

(iii)any Applicable Contract that constitutes a lease under which Seller (or its Affiliates) is the lessor or the lessee of real or personal property which lease (A) cannot be terminated by Seller without penalty or cost upon 60 days’ or less notice and (B) involves an annual base rental of more than $365,000;

(iv)any joint operating agreements, unit operating agreements, unit agreements or other similar arrangements governing Properties with an Allocated Value of more than $75,000;

(v)any indenture, mortgage, loan, credit or sale-leaseback or similar Applicable Contract which will be binding after Closing on any of the Assets or Buyer’s ownership thereof after Closing;

(vi)any farmout, farmin, participation, asset purchase or sale, exchange, or similar agreement relating to the Assets where the primary obligations (including the obligation to make any payment (other than a payment in respect of a surviving indemnity obligation) to acquire or transfer any asset) have not been performed;

(vii)any futures, hedge, swap, collar, put, call, floor, cap, option or other Applicable Contract that is intended to benefit from, relate to or reduce or eliminate the risk of fluctuations in the price of commodities, including Hydrocarbons, in all of such cases that is binding upon the Assets or would be binding upon Buyer following the Closing;

(viii)any Applicable Contract that constitutes a non-competition agreement, area of mutual interest agreement or any other agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, Buyer after the Closing will be able to conduct business, including area of mutual interest Applicable Contracts;

(ix)any Applicable Contract containing “tag along,” “drag along” or similar rights allowing a Third Party to participate in, or cause the occurrence of, future sales of any of the Assets or interests therein;

(x)any Applicable Contract related to Seismic Data and Information that is not an Excluded Asset;

(xi)any Applicable Contract with any Affiliate of Seller that will not be terminated prior to Closing; and

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(xii)any saltwater disposal contract and any compressor contract not otherwise listed in this Section 4.7 relating to the Assets.

(b)Except as set forth on Schedule 4.7, the Material Contracts are in full force and effect in all material respects and there exist no material defaults under the Material Contracts by Seller or, to Seller’s Knowledge, by any other Person that is a party to such Material Contracts, and no event has occurred that with notice or lapse of time, or both, would constitute a material default under any such Material Contract by Seller or, to Seller’s Knowledge, any other Person who is a party to such Material Contract. Seller has not given, or received any unresolved written notice of termination or default with regards to any Material Contract. Prior to the execution of this Agreement, Seller has made available to Buyer true and complete copies of each Material Contract and all material amendments thereto. To Seller’s Knowledge, no party to a Material Contract has given any notice of price redetermination, market out, curtailment or termination.

Section 4.8.No Violation of Laws. Except as set forth on Schedule 4.8, there is no pending or, to Seller’s Knowledge, threatened regulatory compliance or enforcement action related to the Assets (other than the Buyer Operated Properties) and Seller has not received, nor has any Knowledge of, written notice alleging any violation of any Law applicable to the Assets (other than the Buyer Operated Properties), in each case, the resolution of which is currently outstanding. Except where lack of compliance would not have a Material Adverse Effect, Seller’s ownership and operation of the Assets (other than the Buyer Operated Properties) is in compliance with all Laws. This Section 4.8 does not include any matters with respect to Environmental Laws, such matters being addressed exclusively in Section 4.16.

Section 4.9.Preferential Rights. Except as set forth in Schedule 4.9, there are no Preferential Rights to Purchase that are applicable to the transfer of the Assets in connection with the transactions contemplated hereby.

Section 4.10.Personal Property. To Seller’s Knowledge, except as set forth in Schedule 4.10, all Personal Property constituting a part of the Assets are in a state of reasonable repair (ordinary wear and tear excepted) so as to be suitable for the purposes of which such Personal Property was constructed, obtained or currently being used, except as would reasonably be expected to have a Material Adverse Effect.

Section 4.11.Imbalances. Schedule 4.11 sets forth all Imbalances associated with the Properties as of the Effective Time.

Section 4.12.Current Commitments. Schedule 4.12 sets forth, as of the date set forth in such Schedule, all authorities for expenditures (“AFEs”) relating to the Properties (other than the Buyer Operated Properties) which require expenditures by Seller and/or its Affiliates in excess of $250,000 and for which all of the activities anticipated in such AFEs or commitments have not been completed by the date of this Agreement.

Section 4.13.Contribution Requirements. Except as set forth on Schedule 4.13 and only with respect to Assets that are Seller Operated Properties, there are no material contribution requirements with respect to defaulting co-owners as to any of such Assets.

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Section 4.14.Non-Consent Elections. Except as set forth on Schedule 4.14, Seller has not elected nor been deemed to have elected as a non-consenting party with respect to any Well, proposal or other operations with respect to the Assets.

Section 4.15.Payout Balances. (a) Schedule 4.15 contains a list of the estimated status of any “payout” balance (gross), as of the dates shown in such Schedule, for each Seller Operated Property that is subject to a reversion or other adjustment at some level of cost recovery or payout, and, (b) to Seller’s Knowledge, Schedule 4.15 contains a list of the estimated status of any “payout” balance (gross), as of the dates shown in such Schedule, for each other Property that is subject to a reversion or other adjustment at some level of cost recovery or payout.

Section 4.16.Environmental.

(a)Except as set forth on Schedule 4.16, to Seller’s Knowledge, Seller’s ownership, use and operation of the Assets (other than the Buyer Operated Properties) is in compliance with all applicable Environmental Laws, except for such failures to comply as have not had, and would not reasonably be expected, individually or in the aggregate, to have a Material Adverse Effect.

(b)Except as set forth on Schedule 4.16, Seller has not received, nor, to Seller’s Knowledge, has any Third Party operator received, within the preceding two (2) years, any notice of violation of any Environmental Law relating to the Assets (other than the Buyer Operated Properties), in each case which remains unresolved and for which remaining outstanding Liabilities (or series of related Liabilities) resulting therefrom reasonably would be expected to exceed $100,000.

(c)Complete and accurate copies of all final written third parties reports of environmental site assessments and/or compliance audits that have been prepared by or on behalf of Seller in the two (2) years prior to the Execution Date and that identify or address any material unresolved Environmental Condition affecting the Assets (other than the Buyer Operated Properties) have been provided to Buyer prior to the Execution Date.

This Section 4.16 constitutes, with respect to this Section, Section 4.7, Section 4.8 and Section 4.22, Seller’s sole and exclusive representations and warranties regarding Environmental Laws (including Permits required or issued thereunder), Environmental Conditions, and Hazardous Substances, and shall be deemed to control over any conflicting representation or warranty made by Seller with respect to such Sections.

Section 4.17.Asset Taxes. Except as disclosed on Schedule 4.17 and with respect to Taxes which are being paid by Buyer (or its Affiliates) as operator of certain of the Properties, all Asset Taxes and assessments (including penalties and interest) relating to Seller’s ownership or operation of the Assets, the production of Hydrocarbons therefrom, or the receipt of proceeds therefrom that are or have become due and payable have been time paid in full, other than Asset Taxes which have been contested in good faith, and no such contests are ongoing. Except as disclosed on Schedule 4.17, all Tax Returns with respect to Asset Taxes that are required to be filed by Seller relating to Seller’s ownership or operation of the Assets, the production of Hydrocarbons therefrom,

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or the receipt of proceeds therefrom have been filed. There are no audits, investigations, litigation or other proceedings pending or, to the Knowledge of Seller, threatened against Seller before any Governmental Authority relating to the payment of any Asset Taxes imposed or based on Seller’s ownership or operation of the Assets. There are not currently in effect any extensions or waivers by Seller of any statute of limitations of any jurisdiction regarding the assessment or collection of any Asset Taxes related to the ownership or operation of the Assets. There are no liens for Taxes on any of the Assets except for Permitted Encumbrances. All withholding required to be paid or withheld under applicable Law with respect to the ownership or operation of the Assets has been paid or withheld.

Section 4.18.Tax Partnerships. Except as set forth on Schedule 4.18, no Asset is subject to any tax partnership agreement or provisions requiring a partnership income Tax Return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code or any similar state statute, and in the case of any Asset subject to a tax partnership agreement, the tax partnership has an election in effect under Section 754 of the Code.

Section 4.19.Brokers’ Fees. Seller has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Buyer or any Affiliate of Buyer shall have any responsibility or which would burden the Assets.

Section 4.20.Current Plugging Obligations. Except as set forth in Schedule 4.20, (a) Seller has not received any notices or demands from any Governmental Authority or, to Seller’s Knowledge, any other Person to plug any Wells (excluding Wells included within the Buyer Operated Properties) or perform any mechanical integrity tests on Wells (excluding Wells included within the Buyer Operated Properties); and (b) there are no Wells (excluding Wells included within the Buyer Operated Properties) that Seller is obligated by applicable Law or contract to currently plug or abandon, that are currently subject to exceptions to a requirement to plug or abandon issued by a Governmental Authority, or that have been plugged and abandoned other than in compliance with applicable Law.

Section 4.21.Bonds and Guaranties. Schedule 4.21 contains a complete and accurate list of all material bonds, letters of credit, guaranties, and other credit support instruments posted, provided, or entered into by Seller or any of its Affiliates in connection with the ownership or operation of the Assets.

Section 4.22.Permits. Except as set forth in Schedule 4.22, (a) with respect to Seller Operated Properties, Seller or its Affiliates (as applicable) have acquired all Permits from appropriate Governmental Authorities to conduct operations on such Seller Operated Properties in material compliance with all applicable Laws; (b) all such Permits are in full force and effect and no proceeding is pending or, to Seller’s Knowledge, threatened to suspend, revoke or terminate any such Permit or declare any such Permit invalid; and (c) Seller is in compliance in all material respects with such Permits.

Section 4.23.Leases; Payments. Except as set forth on Schedule 4.23(a), (a) all proceeds owing to Seller from the sale of Hydrocarbons produced from the Properties are being

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received by Seller in a timely manner and are not being held in suspense; (b) all bonuses, rentals, Royalties and other payments and burdens upon, measured by or payable out of production due and payable under the Leases have been duly and timely paid, except such amounts as are held in suspense pursuant to applicable Law or are being held in suspense by any applicable operator; (c) no material default by Seller exists under any Lease or any contract, agreement or instrument related to any Lease; and (d) Seller has not received, and, to Seller’s Knowledge, no party to any Lease has given or threatened to give, notice of any action to terminate, cancel, rescind or procure judicial reformation of any such Lease or any provision thereof. Schedule 4.23 sets forth all Leases which (x) are held by any means other than the primary term thereof or the production of Hydrocarbons in paying quantities, and (y) will expire, terminate or become impaired, in whole or in part, absent actions by or on behalf of Seller on or before a date that is 90 days after the Closing Date.

ARTICLE V

BUYER’S REPRESENTATIONS AND WARRANTIES

Except as otherwise provided below, Buyer hereby represents and warrants to Seller the matters set forth in this Article V.

Section 5.1.Organization; Existence. Buyer is a limited partnership duly organized, validly existing and in good standing under the laws of the state of its formation and has all requisite power and authority to own and operate its property and to carry on its business as now conducted. Buyer is duly licensed or qualified to do business as a foreign limited partnership and is in good standing in all jurisdictions in which such qualification is required by Law, except where the failure to qualify or be in good standing would not have a material adverse effect on Buyer’s ability to consummate the transactions contemplated in this Agreement.

Section 5.2.Authorization. Buyer has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by Buyer of this Agreement and each Transaction Document to which Buyer is a party have been duly and validly authorized and approved by all necessary company action on the part of Buyer. This Agreement is, and the Transaction Documents to which Buyer is a party when executed and delivered by Seller will be, the valid and binding obligation of Buyer and enforceable against Buyer in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 5.3.No Conflicts. The execution, delivery, and performance by Buyer of this Agreement and the consummation of the transactions contemplated herein will not (a) conflict with or result in a breach of any provisions of the organizational or other governing documents of Buyer, (b) result in a default or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license or other agreement to which Buyer is a party or by which Buyer or any of its property may be bound or (c) violate any Law applicable to Buyer or any of its property, except in the case of clauses (b) and (c) where such default, lien, encumbrance, termination,

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cancellation, acceleration or violation would not have a material adverse effect on Buyer’s ability to consummate the transactions contemplated in this Agreement.

Section 5.4.Consents. There are no consents or other restrictions on assignment, including requirements for consents from Third Parties to any assignment (in each case) that would be applicable in connection with the consummation of the transactions contemplated by this Agreement by Buyer.

Section 5.5.Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s knowledge, threatened in writing against Buyer.

Section 5.6.Litigation. There is no suit, action, investigation or inquiry by any Person or by or before any Governmental Authority, and no legal, administrative or arbitration proceedings pending, or, to Buyer’s knowledge, threatened against Buyer, or to which Buyer is a party, that could reasonably be expected to have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated in this Agreement.

Section 5.7.Financing. Buyer has on the date hereof and shall have on the Closing Date, sufficient immediately available cash funds and available lines of credit with which to pay the Purchase Price and consummate the transactions contemplated by this Agreement.

Section 5.8.Independent Evaluation. Buyer is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and to consummate the transaction contemplated herein, Buyer, except to the extent of Seller’s representations in Article IV (and the confirmation of such representations and warranties in the certificate delivered by Seller at Closing pursuant to Section 8.3(b)(i)), and the special warranty of title in the Assignment and the Deed, (a) has relied or shall rely solely on its own independent investigation and evaluation of the Assets and the advice of its own legal, tax, economic, environmental, engineering, geological and geophysical advisors and the express provisions of this Agreement and not on any comments, statements, projections or other materials made or given by any representatives, consultants or advisors engaged by Seller and (b) has undertaken such due diligence pertaining to the Properties and other Assets as Buyer deems adequate.

Section 5.9.Brokers’ Fees. Buyer has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Seller or any Affiliate of Seller shall have any responsibility.

Section 5.10.Accredited Investor.

(a)Buyer is aware that the sale of the Assets conveyed herein by Seller has not been registered under the Securities Act or under the securities Laws of any state. Buyer represents and warrants that (i) Buyer is an accredited investor as such term is defined in Regulation D of the Securities Act and (ii) Buyer is acquiring an interest in the Assets for its own account for use in Buyer’s trade or business and not with a view toward or for sale in connection with any distribution

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thereof, nor with any present intention of making a distribution thereof within the meaning of the Securities Act (including the rules and regulations thereunder). Buyer represents and warrants that if it sells, transfers or otherwise disposes of the Assets, it will do so in compliance with the Securities Act and any other applicable securities Laws (including state securities Laws).

(b)Buyer is aware that no federal or state agency has made any findings or determinations as to the fairness of purchasing the Assets conveyed herein or any recommendations or endorsement with respect thereto.

(c)Buyer recognizes that its representations and warranties in this Section 5.10 are material inducements to Seller’s acceptance of Buyer’s purchase of the Assets conveyed herein, and without such representations and warranties, Buyer’s purchase would not be accepted.

Section 5.11.Qualified Operator; Credit Support. Buyer will upon the Closing and thereafter shall continue to be qualified per applicable Law to own and assume operatorship of the Assets in all jurisdictions where the Assets are located, and the consummation of the transactions contemplated by this Agreement will not cause Buyer to be disqualified as such an owner or operator. To the extent required by any Laws, Buyer has maintained (or as of Closing shall maintain), and will hereafter continue to maintain, all bonds, letters of credit and guarantees as may be required by, and in accordance with, all Laws governing the ownership and operation of the Assets.

Section 5.12.No Foreign Ownership or Control. Buyer’s purchase of the Assets conveyed under the Transaction Documents will not result in foreign ownership, control or influence requiring pre-closing notifications to, review by or consent or approval of the Committee on Foreign Investment in the United States.

ARTICLE VI

CERTAIN AGREEMENTS

Section 6.1.Conduct of Business. Except (i) as set forth in Schedule 6.1, (ii) as required to be taken prior to February 28, 2018 to perpetuate any Lease, (iii) as expressly required to be taken prior to February 28, 2018 by any Lease, Applicable Contract, Law or Governmental Authority, including as contemplated by the AFEs and other capital commitments described in Section 4.12, (iv) as expressly contemplated by this Agreement, (v) for actions taken to respond to sudden emergencies constituting an immediate threat to health, safety or the environment, or (vi) as consented to in advance in writing by Buyer (which consent shall not be unreasonably withheld, conditioned or delayed), Seller shall, from and after the date hereof until Closing:

(a)maintain the Assets in the ordinary manner consistent with past practice;

(b)operate the Seller Operated Properties in the ordinary manner consistent with past practice;

(c)maintain the books of account and records relating to the Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of Seller and applicable Law;

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(d)maintain in full force and effect all material permits and authorizations granted by a Governmental Authority;

(e)(i) not propose or commit to any single operation, or series of related operations, reasonably anticipated to require capital expenditures by the owner of the Assets in excess of $250,000, (ii) make any capital expenditures with respect to any single operation, or series of related operations, in excess of $250,000 or (iii) propose or make capital expenditures subject to clauses (i) and (ii) in excess of $1,000,000 in the aggregate; provided, however, that Seller may consent to any AFEs from Buyer (or an Affiliate of Buyer) to drill, frac or complete wells unless Seller and Buyer mutually agree in writing that Seller shall not consent to such AFE;

(f)not enter into an Applicable Contract that, if entered into on or prior to the Execution Date, would be required to be listed in Schedule 4.7, or terminate (unless such Material Contract terminates pursuant to its stated terms and except with respect to any agreement set forth on Schedule 4.18) or materially amend or change the terms of any Material Contract;

(g)maintain insurance coverage on the Assets furnished as of the Execution Date by Third Parties in the amounts and of the types in place as of the Execution Date;

(h)not transfer, sell, mortgage, pledge or dispose of or otherwise encumber any of the Assets other than (i) Permitted Encumbrances, (ii) the sale or disposal of Hydrocarbons in the ordinary course of business and (iii) sales of equipment and other Assets that are no longer necessary or useful in the operation of the Assets or for which replacement equipment of equal or better quality has been obtained;

(i)not settle, waive, or compromise any claim or other proceeding through payments in excess of $200,000 in a manner that would adversely affect in any material respect the ownership, operation, or use of the Assets taken as a whole or for which Buyer would have liability;

(j)produce Hydrocarbons consistent with past practices, subject to the terms of the applicable Leases and Applicable Contracts, applicable Laws, and requirements of Governmental Authorities and interruptions resulting from force majeure, mechanical breakdown, and planned maintenance, and not incur any material Imbalance; and

(k)not commit or agree to take (or omit to take) any action that, if so taken or omitted, would result in a violation of this Section 6.1.

Buyer acknowledges that Seller owns undivided interests in certain of the Properties where Seller is not the operator, and Buyer agrees that the acts or omissions of the other working interest owners (including the operators) who are not Seller or an Affiliate of Seller shall not constitute a breach of the provisions of this Section 6.1, nor shall any action required by a vote of working interest owners constitute such a breach so long as Seller and its Affiliates have not proposed an action that would be in violation of this Section 6.1 and have voted their interest in a manner that complies with the provisions of this Section 6.1. Notwithstanding anything to the contrary in this Section 6.1, subsections (ii) and (iii) of the lead-in of this Section 6.1 shall only constitute exceptions to Sections 6.1(e), (i), and (j).

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Section 6.2.Notification of Breaches. Until the Closing:

(a)Buyer shall use good faith efforts to notify Seller promptly after Buyer obtains actual Knowledge that any representation or warranty of Seller contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Seller prior to or on the Closing Date has not been so performed or observed in any material respect.

(b)Seller shall use good faith efforts to notify Buyer promptly after Seller obtains actual knowledge that any representation or warranty of Buyer contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Buyer prior to or on the Closing Date has not been so performed or observed in any material respect.

Section 6.3.Successor Operator. While Buyer acknowledges that it desires to succeed Seller as operator of the Seller Operated Properties, Buyer acknowledges and agrees that Seller cannot and does not covenant or warrant that Buyer shall become successor operator of the same since the Seller Operated Properties or portions thereof may be subject to operating or other agreements that control the appointment of a successor operator. Seller agrees, however, that as to the Seller Operated Properties, to the extent permitted under any joint operating agreement, Seller shall vote its interests in favor of Buyer as successor operator and use its commercially reasonable efforts to support Buyer’s efforts to become successor operator (to the extent permitted under any joint operating agreement) effective as of the Closing and to designate or appoint, by assignment, to the extent legally possible, Buyer as successor operator effective as of Closing.

Section 6.4.Governmental and Third Party Bonds. Buyer acknowledges that no bonds, letters of credit and guarantees that have been posted by Seller or its Affiliates with Governmental Authorities and Third Parties and relating to the Assets are transferable to Buyer and any bonds, letter of credit and guarantees shall be cancelled by Seller at or after Closing. On or before the Closing Date, Buyer shall obtain, or cause to be obtained in the name of Buyer or its designee, replacements for those bonds, letters of credit and guarantees set forth on Schedule 4.21 to the extent required for Buyer to own the Assets.

Section 6.5.Record Retention. Buyer shall, for the longer of a period of seven years and as required by Law, following Closing, retain the Records and provide Seller, its Affiliates, and its and their officers, employees and representatives with reasonable access upon prior notice to the Records (to the extent that Seller has not retained the original or a copy) during normal business hours for review and copying at Seller’s expense; provided that Buyer may destroy Records from time to time and prior to the end of such period in accordance with its normal document retention policy as long as Buyer notifies Seller in advance and provides Seller with an opportunity to copy such Records at Seller’s expense. Buyer shall also provide Seller, its Affiliates and its and their officers, employees and representatives with reasonable access during normal business hours to Records relating to any indemnification claim made under this Agreement with respect to a Claim for review and copying at Seller’s expense.

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Section 6.6.Like-Kind Exchange. Seller and Buyer agree that either or both of Seller and Buyer may elect to treat the acquisition or sale of the Assets as an exchange of like-kind property under section 1031 of the Code or similar section of the Code and any corresponding state income tax provisions (a “Like-Kind Exchange”). Each such party shall cooperate fully, to the extent reasonably requested by the other party, in connection with accommodating a Like-Kind Exchange. Each party reserves the right, at or prior to Closing, to assign its rights under this Agreement to a qualified intermediary (as that term is defined in Treasury Regulation Section 1.1031(k)-1(g)(4)(iii)) or an exchange accommodation titleholder (as that term is defined in Internal Revenue Service Revenue Procedure 2000-37) to effect an Exchange to accomplish this transaction, in whole or in part, in a manner that will comply with the requirements of a Like-Kind Exchange. In connection with any such Like-Kind Exchange, any exchange accommodation title holder shall have taken all steps necessary to own the Assets under applicable Law. Each party hereby consents to the other party’s assignment of its rights in this Agreement; provided that the Closing shall not be delayed or affected by reason of the Like-Kind Exchange. Each party acknowledges and agrees that a whole or partial assignment of its rights under this Agreement shall not release such exchanging party from any of its respective liabilities and obligations to the other cooperating party or expand any liabilities or obligations of such cooperating party under this Agreement. The cooperating party shall not be obligated to pay any additional costs or incur any additional obligations if such costs are the result of the exchanging party’s Like-Kind Exchange, and the exchanging party shall indemnify the cooperating party, its Affiliates, and their respective former, current and future partners, members, shareholders, owners, officers, directors, managers, employees, agents and representatives against any Claims arising from such exchanging party’s Like-Kind Exchange. No representations are made that any particular tax treatment will be given to either party as a result of the Like-Kind Exchange.

Section 6.7.Marketing and Transportation Agreements. Seller shall use commercially reasonable efforts to obtain the consents necessary to assign any marketing and transportation agreements before Closing. However, if Seller is unable to obtain such consents prior to Closing, Seller shall, if permitted under the terms of such agreements and applicable Law, make available the benefits of such marketing and transportation agreements to Buyer by marketing and selling Buyer’s Hydrocarbons through such agreements on the same terms and conditions as they exist on the Closing Date or such amended terms and conditions as Seller shall approve; provided, that Seller shall not be obligated to extend the stated term of any marketing and transportation agreements, including pursuant to any available renewal option; provided further, that Buyer shall use commercially reasonable efforts to replace such agreements as soon as practicable. If Seller markets and sells Buyer’s Hydrocarbons pursuant to this Section 6.7, Buyer shall deliver such quantity of Hydrocarbons to Seller as is sufficient to allow Seller to meet the minimum quantity and quality commitments under such agreement at the delivery point set forth therein. Buyer shall also fully comply with all other terms and conditions of such marketing and transportation agreements as if it were a party thereto. Buyer shall indemnify, defend, hold harmless and release the Seller Indemnified Parties against any Claims arising from or related to Seller’s marketing and transportation of Buyer’s Hydrocarbons, except for any claims actually resulting from the gross negligence or willful misconduct of Seller.

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Section 6.8.Amendment to Schedules. Buyer agrees that, without limiting in any respect Buyer’s rights hereunder or under any other Transaction Document or giving rise to or constituting a claim, counter-claim or other cause or right of action by Seller or any Seller Indemnified Party, Seller shall have the continuing right until Closing to add, supplement or amend the Schedules to its representations and warranties with respect to any matter hereafter arising or discovered by Seller after Seller’s execution and delivery of this Agreement (including the addition of Schedules that are responsive to the representations and warranties contained herein but for which a Schedule is not contemplated as of the Execution Date). Any such amendment shall be for informational purposes only, shall not constitute a waiver of, or otherwise impair in any respect the rights of the parties under the other provisions of this Agreement or any other Transaction Document (including under Article XII); shall not be admissible in any proceeding between or among the parties or their Affiliates (or Buyer Indemnified Parties or Seller Indemnified Parties, as applicable), whether pursuant to a defense of any claim, a counter-claim, or otherwise, and, without limiting the foregoing, for purposes of determining whether the conditions set forth in Section 7.1 have been fulfilled and for purposes of determining whether Seller has breached any of its representations and warranties contained in this Agreement, the Schedules to Seller’s representations and warranties contained in this Agreement shall be deemed to include only that information contained therein on the Execution Date and shall be deemed to exclude all information contained in any addition, supplement or amendment thereto.

Section 6.9.Tax Matters.

(a)Subject to Section 6.6, for federal income Tax purposes, Buyer and Seller agree that the transaction contemplated by this Agreement shall be treated as a sale and exchange of assets pursuant to section 1001 of the Code. Seller and Buyer further agree that (i) they shall file all federal, state and local Tax Returns consistently with this Section 6.9(a) and (ii) neither they nor their Affiliates will take positions inconsistent with this Section 6.9(a) in notices to Governmental Authorities, in audit or other proceedings with respect to Taxes.

(b)As soon as practicable, Seller shall cause the Tax Partnership to terminate effective on December 31, 2017. Seller shall cause the Tax Partnership to timely file a final Internal Revenue Service Form 1065 U.S. Partnership Return of Income and Internal Revenue Service Schedule K-1 (or such successor form and schedule) for the tax year ending on December 31, 2017.

(c)As soon as practicable after Closing but no later than April 15, 2019, pursuant to Section 3.3 of the Tax Partnership Agreement of the Tax Partnership, Seller agrees to take any action after the Tax Partnership is terminated, as is necessary to validly elect out of the provisions of Subchapter K Chapter 1 of Subtitle A of the Code with respect to the Joint Interests (as defined in the PPA) for the taxable year that includes the Closing Date (such actions include the filing of any returns and information statements required under Treas. Reg. Section 1.761-2(b) as consented to by the parties thereto). Seller shall deliver to Buyer a copy of such election as soon as practicable after such election is filed with the Internal Revenue Service.

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ARTICLE VII

CONDITIONS TO CLOSING

Section 7.1.Buyer’s Conditions to Closing. The obligations of Buyer to consummate the transactions provided for herein are subject, at the option of Buyer, to the fulfillment by Seller or express written waiver by Buyer, on or prior to the Closing of each of the following conditions:

(a)Representations. The representations and warranties of Seller set forth in this Agreement shall be true and correct in all material respects (without giving effect to any limitation as to materiality, Material Adverse Effect or any similar language contained therein) on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than individual representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except in the case where the failure of such representations and warranties to be so true and correct (without giving effect to any limitation as to materiality, Material Adverse Effect or any similar limitation contained therein), individually or in the aggregate, would not reasonably be expected to have a Material Adverse Effect.

(b)Performance. Seller shall have performed or complied in all material respects with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Seller is required prior to or at the Closing Date.

(c)No Legal Proceedings. No material suit, action or other proceeding by a Third Party shall be pending before any Governmental Authority or arbitrator or threatened in writing against Buyer or its Affiliates seeking to restrain, prohibit, enjoin or declare illegal, or seeking substantial damages from Buyer or its Affiliates in connection with, the transactions contemplated by this Agreement.

(d)Title Defects and Environmental Conditions. The sum of (i) the amount by which the sum of (A) all Title Defect Amounts claimed in good faith by Buyer pursuant to Section 10.2(e) with respect to Title Defects submitted on or before the Title Claim Date and (B) all Remediation Amounts for Environmental Conditions claimed in good faith by Buyer pursuant to Section 11.1 with respect to Environmental Conditions Notices submitted on or before the Environmental Claim Date, exceeds the Aggregate Deductible, (ii) all Casualty Losses pursuant to Section 10.3(a), (iii) the Allocated Value of any Asset excluded at Closing pursuant to Section 10.3(b) or subject to a threatened or pending eminent domain or condemnation action pursuant to Section 10.3(c) (whether or not excluded from this Agreement), and (iv) the Allocated Value of any Asset excluded at Closing pursuant to Section 10.4(c) or Section 10.4(f), shall be less than 25% of the Purchase Price.

(e)Closing Deliverables. Seller shall have delivered (or be ready, willing and able to deliver at Closing) to Buyer the documents and other items required to be delivered by Seller pursuant to this Agreement.

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Section 7.2.Seller’s Conditions to Closing. The obligations of Seller to consummate the transactions provided for herein are subject, at the option of Seller, to the fulfillment by Buyer or express written waiver by Seller, on or prior to the Closing of each of the following conditions:

(a)Representations. The representations and warranties of Buyer set forth in this Agreement shall be true and correct in all material respects (without giving effect to any limitation as to materiality, Material Adverse Effect or any similar language contained therein) on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than individual representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except in the case where the failure of such representations and warranties to be so true and correct, individually or in the aggregate, would not reasonably be expected to materially and adversely affect Buyer’s ability to consummate the transactions contemplated hereby.

(b)Performance. Buyer shall have performed or complied in all material respects with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Buyer is required prior to or at the Closing Date.

(c)No Legal Proceedings. No material suit, action or other proceeding by a Third Party shall be pending before any Governmental Authority or arbitrator or threatened in writing against Seller or its Affiliates seeking to restrain, prohibit, enjoin or declare illegal, or seeking substantial damages from Seller or its Affiliates in connection with, the transactions contemplated by this Agreement.

(d)Title Defects and Environmental Conditions. The sum of (i) the amount by which the sum of (A) all Title Defect Amounts claimed by Buyer pursuant to Section 10.2(e) with respect to Title Defects submitted on or before the Title Claim Date and (B) all Remediation Amounts for Environmental Conditions claimed by Buyer pursuant to Section 11.1 with respect to Environmental Conditions Notices submitted on or before the Environmental Claim Date, exceeds the Aggregate Deductible, (ii) all Casualty Losses pursuant to Section 10.3(a), (iii) the Allocated Value of any Asset excluded at Closing pursuant to Section 10.3(b) or subject to a threatened or pending eminent domain or condemnation action pursuant to Section 10.3(c) (whether or not excluded from this Agreement), and (iv) the Allocated Value of any Asset excluded at Closing pursuant to Section 10.4(c) or Section 10.4(f), shall be less than 25% of the Purchase Price.

(e)Closing Deliverables. Buyer shall have delivered (or be ready, willing and able to deliver at Closing) to Seller the documents and other items required to be delivered by Buyer pursuant to this Agreement.

ARTICLE VIII

CLOSING

Section 8.1.Date of Closing. Subject to the conditions stated in this Agreement, the sale by Seller and the purchase by Buyer of the Assets pursuant to this Agreement (the “Closing”)

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shall occur on January 31, 2018, or if all of the conditions to be satisfied in Article VII prior to Closing have not yet been satisfied or waived, two business days after the satisfaction (or waiver) of all closing conditions set forth in Article VII, or such other date as Buyer and Seller may agree upon in writing. The date on which the Closing actually occurs is referred to herein as the “Closing Date”.

Section 8.2.Place of Closing. The Closing shall be held at Seller’s offices located at 500 Dallas Street, Suite 2300, Houston, TX 77002.

Section 8.3.Closing Obligations. At the Closing, the following documents shall be delivered and the following events shall occur, the execution of each document and the occurrence of each event being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a)Buyer shall deliver to Seller:

(i)a certificate duly executed by an authorized corporate officer of Buyer, dated as of the Closing, certifying on behalf of Buyer that the conditions set forth in Section 7.2(a) and Section 7.2(b) have been fulfilled;

(ii)a certificate duly executed by an authorized representative of Buyer, dated as of the Closing, (A) attaching and certifying on behalf of Buyer complete and correct copies of (1) the organization documents of Buyer, each as in effect as of the Closing and (2) evidence of Buyer’s authorization for the execution, delivery, and performance by Buyer of this Agreement and the transactions contemplated hereby and (B) certifying on behalf of Buyer the incumbency of each authorized representative of Buyer executing this Agreement or any document delivered in connection with the Closing;

(iii)the executed and acknowledged Assignments, in sufficient counterparts to facilitate recording in the applicable counties, covering the Assets;

(iv)the executed and acknowledged Deeds, in sufficient counterparts to facilitate recording in the applicable counties, covering the Fee Interests;

(v)the executed Assignment and Assumption;

(vi)subject to Section 3.3, the Preliminary Settlement Statement;

(vii)to the account designated in the Preliminary Settlement Statement, by direct bank or wire transfer in same day funds, the Adjusted Purchase Price less the Deposit and any amounts in excess of the Deposit amounts withheld pursuant to Section 10.2(g) or Section 11.1(g);

(viii)any conveyances on official forms and related documentation reasonably necessary to transfer the Properties, or the operatorship thereof, to Buyer in accordance with requirements of any Governmental Authority; and

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(ix)any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and delivered at the Closing.

(b)Seller shall deliver to Buyer:

(i)certificates duly executed by an authorized corporate officer of each Seller, dated as of the Closing, certifying on behalf of each Seller that the conditions set forth in Section 7.1(a) and Section 7.1(b) have been fulfilled;

(ii)a certificate duly executed by the authorized representative of each Seller, dated as of the Closing, (A) attaching and certifying on behalf of Seller complete and correct copies of (1) the certificate of incorporation or formation and the bylaws or operating agreement of Seller, each as in effect as of the Closing and (2) the resolutions of the Board of Directors of Seller authorizing the execution, delivery, and performance by such Seller of this Agreement and the transactions contemplated hereby and (B) certifying on behalf of Seller the incumbency of each authorized representative of such Seller executing this Agreement or any document delivered in connection with the Closing;

(iii)the executed and acknowledged Assignments, in sufficient counterparts to facilitate recording in the applicable counties covering the Assets;

(iv)the executed and acknowledged Deeds, in sufficient counterparts to facilitate recording in the applicable counties, covering the Fee Interests;

(v)the executed Assignment and Assumption;

(vi)subject to Section 3.3, the Preliminary Settlement Statement;

(vii)on forms supplied by Buyer and reasonably acceptable to Seller, transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Buyer of proceeds attributable to production from the Assets from and after the Effective Time, for delivery by Buyer to the purchasers of production;

(viii)any conveyances on official forms and related documentation necessary to transfer the Properties, or the operatorship thereof, to Buyer in accordance with requirements of any Governmental Authority;

(ix)an executed statement described in Treasury Regulation Section 1.1445-2(b)(2) certifying that Seller is not a foreign person or is a disregarded entity whose owner is not a foreign person within the meaning of Section 1445 of the Code;

(x)full, recordable, and duly executed and acknowledged releases, effective as of the Closing Date, of all Encumbrances encumbering or affecting any of the Assets that are created under, pursuant to, or evidenced by that certain Credit Agreement dated as of January 27, 2011, as the same has been amended through the

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Closing Date, among Carrizo, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lender parties named therein, which releases will be in form and substance legally sufficient to fully and finally release all such Encumbrances with respect to the Assets and will otherwise be customary in the industry; provided, however, that Buyer shall have the opportunity to review and comment on such releases; and

(xi)any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and delivered at the Closing.

Section 8.4.Records. In addition to the obligations set forth in Section 8.3 above, no later than 60 days following the Closing, Seller shall make available to Buyer the Records in its possession in their current form and format as maintained by Seller as of the Effective Time, for pickup from Seller’s offices during normal business hours; provided that Seller may retain written or electronic copies of such Records. Copying and transportation of the Records will be at Buyer’s sole cost. From and after the Execution Date, Seller shall coordinate with Buyer and provide such commercially reasonable information to Buyer as may be reasonably necessary to permit Buyer to operate the Assets from and after the Closing and until receipt of the Records.

ARTICLE IX

ACCESS; CONFIDENTIALITY; USE; DISCLAIMERS

Section 9.1.Access.

(a)From and after the date hereof and up to delivery of the Records to Buyer as provided in Section 8.4 (or earlier termination of this Agreement) but subject to the other provisions of this Section 9.1 and obtaining any required consents of Third Parties, including Third Party operators of the Assets (with respect to which consents Seller shall use commercially reasonable efforts to obtain), Seller shall afford to Buyer and its officers, employees, agents, accountants, attorneys, consultants and other authorized representatives (“Buyer’s Representatives”) reasonable access, during normal business hours, to the Seller Operated Properties and all Records in Seller’s or its Affiliates’ possession relating to the Assets. Seller shall also make available to Buyer and Buyer’s Representatives, upon reasonable notice during normal business hours, Seller’s and Seller’s Affiliates’ personnel knowledgeable with respect to the Assets so that Buyer may make such reasonable diligence investigation as Buyer considers reasonably necessary or appropriate. All investigations and due diligence conducted by Buyer or any Buyer’s Representative shall be conducted at Buyer’s sole cost and expense and any conclusions made from any examination done by Buyer or any Buyer’s Representative shall result from Buyer’s own independent review and judgment and shall be conducted so as not to interfere unreasonably with the operation of the business of Seller and shall not require Seller to waive any attorney-client privilege nor to violate any contractual obligation. In addition, Seller shall provide Buyer with access to any records and to Seller’s Representatives to the extent reasonably requested and necessary to respond to any tax audit or inquiry suggesting that Buyer is liable as successor, transferee or member of a group having joint and several liability for any Taxes payable by Buyer but allocated to Seller or its Affiliates under Section 14.1; provided, however, Seller shall not be required to take any action pursuant to this Section 9.1 which would result in a waiver of attorney-client privilege.

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(b)Buyer shall be entitled to conduct a Phase I environmental property assessment with respect to the Assets (excluding the Buyer Operated Properties). Seller or its designee shall have the right to accompany Buyer and Buyer’s Representatives whenever they are on site on such Assets and also to collect split test samples if any are collected; provided, however, subject to Buyer providing Seller at least 2 business days’ prior written notice of Buyer’s proposed site access particulars (including, without limitation, an arrival schedule and list of persons to be present), Buyer’s rights under this Section 9.1 shall apply regardless of whether Seller or such designee elects or is able to so accompany Buyer or Buyer’s Representative, and neither Buyer nor Buyer’s Representative shall be required to accommodate the schedules of Seller or its designee. Notwithstanding anything herein to the contrary, Buyer shall not have access to, and shall not be permitted to conduct any environmental due diligence (including any Phase I environmental property assessments) with respect to any Assets where Seller does not have the authority to grant access for such due diligence (provided, however, Seller shall use its commercially reasonable efforts to obtain permission from any Third Party to allow Buyer and Buyer’s Representatives such access). In the event that Buyer’s Phase I environmental property assessments with respect to the Assets (excluding the Buyer Operated Properties) identify actual or potential “recognized environmental conditions,” then Buyer may request Seller’s permission to conduct additional Phase II environmental property assessments with respect to such Assets (excluding the Buyer Operated Properties) to further assess such conditions. Any sampling, boring, drilling or other invasive investigation activities shall be considered “Phase II” activities. The additional Phase II environmental property assessment procedures relating to any additional investigation shall be submitted to Seller in a Phase II environmental property assessment plan, which shall include a written description of the proposed scope of the Phase II assessment, including a description of the activities to be conducted, and a description of the approximate location and expected timing of such activities. Seller may, in its sole discretion, approve said Phase II environmental property assessment plan, in whole or in part, and Buyer shall not have the right to conduct any activities set forth in such plan until such time that Seller has approved such plan in writing. Any such approved Phase II environmental property assessment plan shall be conducted by a reputable environmental consulting or engineering firm, approved in advance by Seller (such approval not to be unreasonably withheld or delayed) and, once approved, such environmental consulting or engineering firm shall be deemed to be a “Buyer’s Representative,” and any such assessment shall be performed in accordance with this Section 9.1 and in compliance with all Governmental Requirements.

(c)Subject to Buyer providing Seller at least 2 business days’ prior written notice of Buyer’s proposed site access particulars (including, without limitation, an arrival schedule and list of persons to be present), Buyer shall coordinate any environmental property assessments and physical inspections of the Seller Operated Properties with Seller to minimize any inconvenience to or interruption of the conduct of business by Seller. Buyer shall abide by Seller’s safety rules, regulations and operating policies while conducting its due diligence evaluation of the Assets, including any environmental or other inspection or assessment of the Seller Operated Properties. Buyer hereby defends, indemnifies and holds harmless each of the operators of the Assets and Seller Indemnified Parties from and against any and all personal injury or property damage actually resulting from the access permitted pursuant to this Section 9.1 and the related due diligence activity conducted by Buyer or any Buyer’s Representative with respect to the Assets, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, SOLELY OR IN PART, THE SOLE,

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ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY A MEMBER OF SELLER INDEMNIFIED PARTIES, EXCEPTING ONLY LIABILITIES ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES.

(d)Buyer will promptly provide a copy of any final environmental report prepared by any Third Party environmental consultant to Seller. Seller shall not be deemed by its receipt of said documents or otherwise as a result of Buyer’s environmental assessment process to have made any representation or warranty, expressed, implied or statutory, as to the condition of the Assets or to the accuracy of said documents or the information contained therein, it being understood that Seller’s only representations or warranties with respect to environmental matters shall be those set forth in Section 4.16 of this Agreement.

(e)Upon completion of Buyer’s due diligence, Buyer shall at its sole cost and expense and without any cost or expense to Seller or its Affiliates, (i) repair all damage done to the Assets in connection with Buyer’s due diligence in a manner that restores the Assets to the approximate same or better condition existing prior to commencement of Buyer’s due diligence and (ii) remove all equipment, tools or other property brought onto the Assets in connection with Buyer’s due diligence. Any damage to the Assets (including the leasehold associated therewith) resulting from Buyer’s due diligence will be promptly corrected by Buyer.

(f)As a condition to its entry onto any of the Seller Operated Properties the environmental consultant shall obtain insurance coverage for general liability in an amount not less than $3,000,000 per occurrence and hold professional liability insurance. If the environmental consultant or Buyer fails to provide Seller with evidence of such insurance, Seller may deny the environmental consultant the right to enter upon the Seller Operated Properties. The parties acknowledge and agree that, for purposes of this Section 9.1(f), as of the Execution Date, Terracon Consultants, Inc. meets the foregoing requirements.

Section 9.2.Confidentiality; Use.

(a)Buyer acknowledges that, pursuant to its right of access to the Records or the Assets, Buyer will become privy to confidential and other information of Seller and that such confidential information shall be held confidential by Buyer and Buyer’s Representatives in accordance with the terms of the Confidentiality Agreement. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including the Confidentiality Agreement, shall terminate (except as to the Excluded Assets).

(b)If the Closing should occur, from and after the Closing and except as otherwise provided in this Agreement, Seller shall not, and shall cause its Affiliates and their respective officers, directors, employees, agents, consultants and other representatives (“Seller’s Representatives”) not to, disclose, use or copy any trade secrets and or proprietary or confidential information relating to the Assets, except for (i) disclosures and uses required by Law or stock exchange rules or information that is in the public domain or that after the Closing becomes part of the public domain through no fault of Seller or Seller’s Representatives after the Closing,

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(ii) disclosures to Affiliates, and (iii) any trade secrets, proprietary or confidential information which becomes available to Seller, any of its Affiliates or any of their representatives on a non-confidential basis from a source that did not acquire such information from Seller or Buyer or any of their Affiliates on a confidential basis. Notwithstanding any of the foregoing and anything to the contrary in this Agreement, Seller shall have the non-exclusive right to use in the ordinary course of business any information about the Assets, including copies (retained by Seller) of (A) any geophysical and other seismic and related technical data and information relating to the Assets (including copies of any geologic and geophysical interpretations retained pursuant to Section 2.1(i)) and (B) any reserve studies and evaluations, logs, Records or other data and information being transferred as part of the Assets; provided, however, that, except as required by Law, Seller shall, and shall cause Seller’s Representatives and each of their respective Affiliates to (i) keep such data and information confidential in accordance with the terms hereof, (ii) require any Third Party consultant or advisor to keep such information confidential in accordance with the terms hereof and (iii) continue to comply with the obligations under any Third Party confidentiality agreements with respect to such data or information or the Assets pursuant to the terms of such Third Party confidentiality agreements.

Section 9.3.Disclaimers.

(a)Except as and to the extent expressly set forth in Article IV, the affirmations thereof in the certificate delivered at Closing pursuant to Section 8.3(b)(i), or the special warranties of title contained in the Assignment and the Deed, (i) Seller makes no representations or warranties, express, statutory or implied, and (ii) Seller expressly disclaims all liability and responsibility for any representation, warranty, statement or information made or communicated (orally or in writing) to Buyer or any of its Affiliates, employees, agents, consultants or representatives (including any opinion, information, projection or advice that may have been provided to Buyer by any of Seller’s representatives and including with respect to the Seismic Data and Information).

(b)EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE IV OF THIS AGREEMENT, THE AFFIRMATIONS THEREOF IN THE CERTIFICATE DELIVERED AT CLOSING PURSUANT TO SECTION 8.3(B)(I), OR THE SPECIAL WARRANTIES OF TITLE CONTAINED IN THE ASSIGNMENT AND THE DEED, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS (AND BUYER EXPRESSLY WAIVES) ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO, OR LIENS OR ENCUMBRANCES UPON, ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, INCLUDING THE SEISMIC DATA AND INFORMATION, RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS

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OR STATEMENTS (INCLUDING FINANCIAL STATEMENTS) PREPARED BY SELLER OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT.

(c)EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE IV OF THIS AGREEMENT, THE AFFIRMATIONS THEREOF IN THE CERTIFICATE DELIVERED AT CLOSING PURSUANT TO SECTION 8.3(B)(i), OR THE SPECIAL WARRANTIES OF TITLE CONTAINED IN THE ASSIGNMENT AND THE DEED, SELLER DISCLAIMS (AND BUYER WAIVES) ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT, EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE IV, THE AFFIRMATIONS THEREOF IN THE CERTIFICATE DELIVERED AT CLOSING PURSUANT TO SECTION 8.3(B)(I), OR THE SPECIAL WARRANTIES OF TITLE CONTAINED IN THE ASSIGNMENT AND THE DEED, BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS, INCLUDING THE SEISMIC DATA AND INFORMATION, IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS OF THE ASSETS, INCLUDING THE SEISMIC DATA AND INFORMATION, AS BUYER DEEMS APPROPRIATE.

(d)OTHER THAN THOSE REPRESENTATIONS SET FORTH IN ARTICLE IV (OR THE CERTIFICATE TO BE DELIVERED AT CLOSING PURSUANT TO SECTION 8.3(B)(I)), SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CHARACTERISTICS OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND SUBJECT TO BUYER’S RIGHTS UNDER SECTION 12.2, BUYER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CHARACTERISTICS AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE. THE INCLUSION OF ANY INFORMATION ON THE DISCLOSURE SCHEDULE SHALL NOT BE DEEMED TO BE AN ADMISSION OR ACKNOWLEDGMENT, IN AND OF ITSELF, THAT SUCH

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INFORMATION IS REQUIRED BY THE TERMS HEREOF TO BE DISCLOSED, IS MATERIAL TO SELLER, IS OUTSIDE THE ORDINARY COURSE OF BUSINESS CONSISTENT WITH PAST PRACTICE, OR IS OTHERWISE REQUIRED TO BE INCLUDED ON SUCH SCHEDULE.

SELLER AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 9.3 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY APPLICABLE LAW.

ARTICLE X

TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS

Section 10.1.Seller’s Title.

(a)General Disclaimer of Title Warranties and Representations. Except for the special warranty of title set forth in the Assignment and the Deed and without limiting the express representations and warranties set forth in Article IV (or the certificate to be delivered at Closing pursuant to Section 8.3(b)(i)) or Buyer’s remedies for Title Defects set forth in this Article X, Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets, and Buyer hereby acknowledges and agrees that Buyer’s sole remedy for any defect of title, including any Title Defect, with respect to any of the Assets (i) before Closing, shall be as set forth in Section 10.2 and (ii) after the Closing, shall be pursuant to the special warranty of title set forth in the Assignment and the Deed.

(b)Special Warranty of Title. If the Closing occurs, then Seller, pursuant to the Assignment and the Deed, will warrant Defensible Title, without duplication, to the Properties unto Buyer against every Person whomsoever lawfully claiming or to claim the same or any part thereof by, through and under Seller or its Affiliates, subject, however, to the Permitted Encumbrances. If Buyer provides written notice of a breach of the special warranty of title in the Assignment or the Deed to Seller, Seller shall have a reasonable opportunity to cure such breach to the reasonable satisfaction of Buyer, and in any event, the value of any losses with respect to such breach shall not exceed the Allocated Value of the affected Properties. Disputes regarding the existence of a breach of the special warranty of title contained in the Assignment or the Deed or the cure thereof shall be resolved subject to and in accordance with Section 10.2(g) of this Agreement.

(c)Beneficial Ownership by Carrizo Eagle Ford. Buyer acknowledges that as of the Execution Date and the Closing Date, Carrizo holds record title as to certain of the Properties for the benefit of Carrizo Eagle Ford with Carrizo Eagle Ford owning all of the beneficial interest in such Properties. At the Closing, Carrizo Eagle Ford shall cause Carrizo to convey to Buyer record title to those Properties as to which Carrizo holds record title on behalf of Seller.

Section 10.2.Notice of Title Defects; Defect Adjustments.

(a)Title Defect Notices. In order to assert a claim under this Section 10.2, no later than January 18, 2018 (the “Title ClaimDate”), Buyer must deliver claim notices to Seller

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meeting the requirements of this Section 10.2(a) (collectively the “Title Defect Notices” and individually a “Title Defect Notice”) setting forth any matters which, in Buyer’s reasonable opinion, constitute Title Defects and which Buyer intends to assert as a Title Defect pursuant to this Article X. For all purposes of this Agreement and notwithstanding anything herein to the contrary, but subject in all cases to Buyer’s rights pursuant to the special warranty of title in the Assignment and the Deed, Buyer shall be deemed to have waived, and Seller shall have no liability for, any Title Defect which Buyer fails to assert as a Title Defect by a Title Defect Notice received by Seller on or before the Title Claim Date. Each Title Defect Notice shall be in writing, and shall include (i) a description of the alleged Title Defects, (ii) the Wells and/or Undeveloped Wells (or portion thereof) affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property and (iv) the amount, which estimate is non-binding, by which Buyer reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defects. To give Seller an opportunity to commence reviewing and curing Title Defects, Buyer agrees to use reasonable efforts to give Seller written notice (which shall not constitute a Title Defect Notice) of all Title Defects discovered by Buyer on a weekly basis, which notice may be preliminary in nature and supplemented prior to the Title Claim Date and which notice, or the failure by Buyer to give such notice, will not prejudice in any way Buyer’s ability to assert a Title Defect, serve to reduce any relevant Title Defect Amount, give rise to, or serve as the basis of a claim or counter-claim by or on behalf of Seller, or otherwise be taken into account (or be admissible in any proceeding under Section 10.2(h)) in determining whether a Title Defect exists or the Title Defect Amount with respect thereto. Buyer shall have the burden of proof in proving the existence of each alleged Title Defect and Title Defect Amount with respect thereto.

(b)Seller’s Right to Cure. If Buyer provides written notice of a Title Defect, Seller shall have the right, but not the obligation, by giving Buyer written notice thereof on or before the Closing Date, to attempt, at its sole cost and expense, to cure at any time prior to 110 days after the Closing Date (the “Cure Period”), to the reasonable satisfaction of Buyer, any Title Defects of which it has been advised by Buyer.

(c)Remedies for Title Defects. Subject to the rights of the parties pursuant toSection 13.1, and subject to Seller’s right to dispute the existence of a Title Defect and the Title Defect Amount asserted by Buyer, in the event that any Title Defect timely asserted by Buyer in accordance with Section 10.2(a) is not waived in writing by Buyer or cured on or before the last day of the Cure Period to Buyer’s reasonable satisfaction, the parties shall mutually agree to elect one of the following remedies:

(i)subject to the Individual Title Defect Threshold and the Aggregate Deductible (except as set forth in Section 10.2(f)), a reduction in the Purchase Price by the Title Defect Amount;

(ii)indemnification of Buyer by Seller against all Liability resulting from such Title Defect pursuant to a mutually acceptable indemnity agreement in which case the Purchase Price shall not be reduced by the Title Defect Amount or Allocated Value with respect to such Title Defect Property; or

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(iii)retention by Seller of the entirety of the Title Defect Property that is subject to such Title Defect, together with all associated Assets, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Title Defect Property and such associated Assets.

If the parties are unable to agree on whether subsection (i), (ii) or (iii) above will apply, then the parties shall be deemed to have elected option (i).

(d)Exclusive Remedy. Except for Seller’s special warranty of title under the Assignment and the Deed, and without limiting the express representations and warranties set forth in Article IV (or the certificate to be delivered at Closing pursuant to Section 8.3(b)(i)), Section 10.2(c) shall be the exclusive right and remedy of Buyer with respect to Seller’s failure to have Defensible Title or any other title matter or liens and Encumbrances with respect to any Property or Properties.

(e)Title Defect Amount. The “Title Defect Amount” resulting from a Title Defect that is not waived in writing by Buyer shall be the amount by which the Allocated Value of the affected Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following methodology, terms and conditions:

(i)if Buyer and Seller agree on the Title Defect Amount, then that amount shall be the Title Defect Amount;

(ii)if the Title Defect is an Encumbrance (other than a Permitted Encumbrance) that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from all relevant Title Defect Properties;

(iii)if the Title Defect represents a discrepancy between (i) the actual Net Revenue Interest with respect to the Target Formation for any Title Defect Property and (ii) the Net Revenue Interest with respect to the Target Formation as stated on Schedule 3.8, and Seller’s Working Interest is correspondingly and proportionately reduced as a result of such Title Defect over the entire life of the Title Defect Property, then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property and a fraction, the numerator of which is the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest with respect to the Target Formation stated in Schedule 3.8;

(iv)if the Title Defect represents an obligation or Encumbrance (other than a Permitted Encumbrance) upon or other defect in title to the Title Defect Property of a type not described above, the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Buyer and Seller and such other reasonable factors as are necessary to make a proper evaluation;

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(v)the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder; and

(vi)notwithstanding anything to the contrary in this Agreement, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

(f)Title Deductibles. Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any individual Title Defect for which the Title Defect Amount does not exceed $75,000 (the “Individual Title Defect Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any Title Defect for which the Title Defect Amount exceeds the Individual Title Defect Threshold unless (A) the amount of the sum of (x) the Title Defect Amounts of all uncured Title Defects that exceed the Individual Title Defect Threshold, in the aggregate, excluding any Title Defect Amounts attributable to Title Defects cured by Seller, and (y) the Remediation Amounts of all Environmental Conditions, in the aggregate, excluding (1) any individual Environmental Condition for which the Remediation Amount does not exceed the Individual Environmental Threshold, (2) any Environmental Conditions Remediated by Seller and (3) any Remediation Amounts attributable to an Asset affected by an Environmental Condition retained by Seller, after offsetting all Title Benefits which individually exceed the Individual Title Benefit Threshold, exceeds (B) the Aggregate Deductible, after which point Buyer shall be entitled to adjustments to the Purchase Price or other remedies only with respect to such Title Defects in excess of such Aggregate Deductible. If Seller retains any Title Defect Property pursuant to Section 10.2(c)(iii), the Purchase Price shall be reduced by the Allocated Value of such Title Defect Property and the Title Defect Amount relating to such Title Defect Property will not be counted towards the Aggregate Deductible.

(g)Title Benefits. If in the course of Buyer’s due diligence review of the Wells and/or Undeveloped Wells Buyer discovers a Title Benefit (such Well and/or Undeveloped Well, a “Title Benefit Property”), Buyer shall promptly notify Seller in writing of the existence of such Title Benefit and the associated Title Benefit Amount. Seller may also notify Buyer in writing of the existence of a Title Benefit and the associated Title Benefit Amount if Seller discovers a Title Benefit (such notice by Buyer or Seller, a “Title Benefit Notice”). A Title Benefit Notice must be delivered by the Title Claim Date and shall be in the form and contain the information required of a Title Defect Notice, mutatis mutandis. Each Title Benefit Amount in excess of the Individual Title Benefit Threshold shall be an offset to any Title Defect Amounts.

(h)Title Dispute Resolution. Seller and Buyer shall attempt to agree on all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts prior to the end of the Cure Period. If Seller and Buyer are unable to agree by the Closing Date, then (i) Seller’s estimate thereof shall control for the purposes of Closing, (ii) the relevant Title Defect Property shall be assigned to Buyer at Closing, (iii) the Purchase Price shall not be adjusted at Closing with respect to the relevant Title Defect or Title Defect Amount, and (iv) the existence of the Title Defect, Title Defect Amount,

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Title Benefit, or Title Benefit Amount, as applicable, shall be exclusively and finally resolved pursuant to this Section 10.2(h). There shall be a single arbitrator, who shall be a title attorney with at least ten years of experience in oil and gas titles involving properties in Texas, as selected by mutual agreement of Buyer and Seller within 15 days after the end of the Cure Period, and absent such agreement, by the Houston, Texas office of the American Arbitration Association (the “Title Arbitrator”). The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section 10.2. The Title Arbitrator’s determination shall be made within 20 days after submission of the matters in dispute and shall be final and binding upon both parties without right of appeal. In making his determination, the Title Arbitrator shall be bound by the rules set forth in this Article X and, subject to the foregoing, may consider such other matters as in the opinion of the Title Arbitrator are necessary to make a proper determination. The Title Arbitrator, however, may not award Buyer or Seller a greater Title Defect Amount or Title Benefit Amount, as applicable, than the Title Defect Amount or Title Benefit Amount claimed by Buyer or Seller in its applicable Title Defect Notice or Title Benefit Notice, and notwithstanding anything herein to the contrary, the Title Arbitrator’s awards are subject to the limitation on liabilities provisions set forth in Section 10.2(f). The Title Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts submitted by either party and may not award damages, interest or penalties to either party with respect to any matter. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Title Arbitrator. Following the determination of the Title Arbitrator, the parties shall make an election pursuant to Section 10.2(c) with respect to the Title Defect Property, to the extent determined to be subject to a Title Defect. To the extent that the award of the Title Arbitrator with respect to any Title Defect Amount or Title Benefit Amount is not taken into account as an adjustment to the Purchase Price pursuant to Section 3.4 or Section 3.5, then within ten days after the Title Arbitrator delivers written notice to Buyer and Seller of his award with respect to a Title Defect Amount or Title Benefit Amount, Seller shall pay to Buyer, the amount, if any, so awarded by the Title Arbitrator to Buyer. Subject to the parties’ rights pursuant to Section 13.1, the Closing shall not be delayed on account of any arbitration hereunder.

Section 10.3.Casualty or Condemnation Loss.

(a)Seller shall promptly notify Buyer of any material casualty to the Assets (other than the Buyer Operated Properties) or any portion thereof that occurs, or any condemnation proceeding commenced, after the Execution Date and prior to the Closing Date. If prior to the Closing Date any portion of the Assets is destroyed by Casualty Loss, then, if the Closing occurs, Seller, at Seller’s sole discretion, shall select one of the following options which shall apply to the Casualty Losses:

(i)Seller shall cause the Assets affected by such Casualty Losses to be repaired or restored to at least their condition prior to such Casualty Losses, at Seller’s sole cost, risk and expense, as promptly as reasonably practicable (which work may extend after the Closing Date); provided, however, that, in such circumstance, Seller shall indemnify, defend, and hold harmless Buyer Indemnified Parties from and

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against any Liability arising out of, or relating to, such attempt on the terms set forth in Section 12.5; or

(ii)Seller shall, at Closing, pay to Buyer all sums paid to Seller or its Affiliates by Third Parties by reason of such Casualty Losses and shall assign to Buyer all of Seller’s or its Affiliates’ right, title and interest (if any) in insurance claims, unpaid awards and other rights against Third Parties arising out of the casualty.

(b)If after the date of this Agreement but prior to the Closing Date, any portion of the Assets is taken in condemnation or under right of eminent domain by any Governmental Authority, the Assets or portion thereof shall be excluded from the Assets to be conveyed to Buyer at Closing to the extent of the interest affected by the condemnation or right of eminent domain and the Purchase Price will be reduced by the Allocated Value of such interest.

(c)If any action for condemnation or taking under right of eminent domain is pending or threatened with respect to any Asset or portion thereof after the Execution Date, but no taking of such Asset or portion thereof occurs prior to the Closing Date, the transaction contemplated by this Agreement shall nevertheless close and Seller, at Closing, shall assign, transfer and set over to Buyer or subrogate Buyer to all of Seller’s or its Affiliates’ right, title and interest (if any) in such taking, including any insurance claims, unpaid awards and other rights against Third Parties arising out of the taking, insofar as they are attributable to the Assets threatened to be taken.

(d)Notwithstanding anything herein to the contrary, from and after the Effective Time, if Closing occurs, Buyer shall assume all risk of loss with respect to production of Hydrocarbons through normal depletion or otherwise (including watering out of any Well, collapsed casing or sand infiltration of any Well) and the depreciation of Personal Property due to ordinary wear and tear, in each case, with respect to the Assets.

Section 10.4.Preferential Rights to Purchase and Consents to Assign.

(a)With respect to each Preferential Right to Purchase pertaining to an Asset and the transactions contemplated hereby, promptly (but in any event within 5 days) following the date hereof shall send to the holder of each such right a notice, in compliance with the contractual provisions applicable to such right and otherwise in form and substance reasonably satisfactory to Buyer. In addition, promptly (but in any event within 5 days) following the date hereof, Seller shall send to each holder of a right to consent applicable to the transactions contemplated hereby or otherwise as set forth on Schedule 4.4(a) (excepting the holder of a right to a Customary Post-Closing Consent) a notice seeking such party’s consent to the transactions contemplated hereby, which notice shall be in compliance with the contractual provisions applicable to such right and otherwise in form and substance reasonably satisfactory to Buyer.

(b)If, prior to the Closing, any holder of a Preferential Right to Purchase notifies Seller or an Affiliate of Seller that it elects to purchase of the Asset to which its Preferential Right to Purchase applies, that Asset shall be excluded from the Assets to be conveyed to Buyer to the extent of the interest affected by the Preferential Right to Purchase, and the Purchase Price shall be

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reduced by the Allocated Value of the relevant Asset (or portion thereof) allocable to such interest. Seller shall be entitled to all proceeds paid by a party exercising a Preferential Right to Purchase prior to the Closing. If such holder of such Preferential Right to Purchase thereafter fails to consummate the purchase of the Asset covered by such right on or before 60 days following the later of the Closing Date or the expiration of the time for exercising such Preferential Right to Purchase, no suit or other proceeding by such Person with respect to the Preferential Right to Purchase is pending or threatened, such Person has not disputed the Preferential Right to Purchase in any respect (including the Allocated Value of the Asset subject thereto), and the conditions set forth in Section 7.1 are otherwise satisfied with respect to such Asset, then Seller shall so notify Buyer, and Buyer shall purchase, on or before ten days following receipt of such notice, such Asset from Seller, under the terms of this Agreement for a price equal to the Allocated Value (or portion thereof) previously allocated to it (adjusted as set forth in this Agreement) and Seller shall assign to Buyer the Asset (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment.

(c)If a Preferential Right to Purchase burdening any Asset is not exercised and the time for exercising such Preferential Right to Purchase has not expired prior to the Closing Date, then such Asset shall be excluded from the Assets to be conveyed at Closing and the Purchase Price shall be reduced by the Allocated Value of the relevant Asset. If the holder of such Preferential Right to Purchase thereafter fails to exercise or consummate the purchase of the Asset covered by such right on or before 60 days following the later of the Closing Date or the date that such Preferential Right to Purchase expires without being exercised, no suit or other proceeding by such Person with respect to the Preferential Right to Purchase is pending or threatened, such Person has not disputed the Preferential Right to Purchase in any respect (including the Allocated Value of the Asset subject thereto), and the conditions set forth in Section 7.1 are otherwise satisfied with respect to such Asset, then Seller shall so notify Buyer, and Buyer shall purchase, on or before ten days following receipt of such notice, such Asset from Seller, under the terms of this Agreement for a price equal to the Allocated Value (or portion thereof) previously allocated to it (adjusted as set forth in this Agreement) and Seller shall assign to Buyer the Asset (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment.

(d)All Assets for which Preferential Rights to Purchase have been waived, or as to which the period to exercise such right has expired prior to the Closing, shall, if no dispute, suit or other proceeding with respect to such Preferential Right to Purchase is pending or threatened, be sold to Buyer at the Closing pursuant to the provisions of this Agreement.

(e)Promptly following the date hereof, and, in any event, prior to the Closing, Seller shall use its commercially reasonable efforts to obtain all consents with respect to the Assets, including those listed on Schedule 4.4(a), Schedule 4.4(b), Required Consents and Soft Consents (other than Customary Post-Closing Consents that cannot be acquired until after Closing), that are required to permit the assignment of the Assets by Seller to Buyer and the consummation by Seller of the transactions contemplated hereby; provided, however, neither party shall be required to incur any Liability or pay any money in order to be in compliance with the foregoing covenant.

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(f)If Seller fails to obtain a Required Consent affecting a Property (or portion thereof) that has an Allocated Value prior to the Closing, then the Property (or portion thereof) subject to such failed consent shall be excluded from the Assets to be conveyed to Buyer, and the Purchase Price shall be reduced by an amount equal to what the reduction to the Purchase Price would have been under Section 10.2(c)(i) had the relevant Property (or portion thereof) been subject to a Title Defect, except that Section 10.2(f) shall not apply and, notwithstanding anything herein to the contrary, in the event that the parties cannot agree on the amount of such adjustment, Buyer’s reasonable and good faith estimate thereof (to the extent that the relevant Property is included in a unit, not to exceed a number (calculated on a unit-by-unit basis) equal to the total number of net mineral acres contributed to the applicable unit by the relevant Property divided by the total number of net mineral acres included in the applicable unit multiplied by the aggregate Allocated Value for the entirety of such unit) shall control for purposes of closing and resolution of such dispute shall be resolved pursuant to Section 10.2(h), mutatis mutandis. If Seller fails to obtain a Required Consent affecting an Asset other than a Property with an Allocated Value and Buyer is assigned the Property or Properties to which such Asset relates, such Asset shall be excluded from the Assets conveyed to Buyer at Closing, and, at Buyer’s election, and if permitted by applicable Law and contract, such Asset shall be held by Seller for the benefit of Buyer and Buyer shall be responsible for the performance of any obligations under or with respect to such Asset to the extent Buyer has been transferred the other Assets that are necessary for such performance. Buyer shall indemnify, defend, hold harmless and release the Seller Indemnified Parties against any Claims arising from or related to Seller’s holding such Asset for the benefit of Buyer, except for any Claims actually resulting from the gross negligence or willful misconduct of Seller and except to the extent any such Claim would otherwise be the responsibility of Seller hereunder (including under Article XII, Section 2.3, or Section 14.1). For a period of 110 days following Closing, Seller and Buyer shall use their commercially reasonable efforts to attempt to obtain any Required Consent which was not obtained prior to Closing. If any such Required Consent is obtained within such period, or if Buyer otherwise so elects (in which case Buyer shall indemnify, defend, hold harmless and release the Seller Indemnified Parties against any Claims arising from or related to such conveyance of the applicable Asset without having obtained the Required Consent), then Seller shall convey to Buyer the Asset (or portion thereof) which was excluded from the Assets, and Buyer shall pay to Seller the amount by which the Purchase Price was reduced at Closing pursuant to this Section 10.4(f) (with appropriate adjustments pursuant to Section 3.2. If any such Required Consent is not obtained at the end of such 110 day period and Buyer does not elect to receive an assignment thereof, the relevant Asset shall constitute an Excluded Asset and shall no longer be subject to this Section 10.4(f), and, if the Asset is a Lease that is not already governed by an operating agreement to which Buyer and Seller are both parties, Buyer and Seller shall enter into an operating agreement substantially in the form of the Maltsberger B Unit operating agreement, naming Buyer as operator of such Asset. For the avoidance of doubt, although Seller will use its commercially reasonable best efforts to obtain any Soft Consent, Seller shall have no liability to Buyer if it fails to obtain such Soft Consent, and Buyer shall take assignment of such Lease without any adjustment to the Purchase Price under this Section 10.4(f) or any other provision of this Agreement.

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ARTICLE XI

ENVIRONMENTAL MATTERS

Section 11.1.Environmental Conditions.

(a)Assertions of Environmental Conditions. In order to assert a claim under this Section 11.1, Buyer must deliver claim notices to Seller meeting the requirements of this Section 11.1(a) (collectively the “Environmental Condition Notices” and individually an “Environmental Condition Notice”) no later than the Environmental Claim Date, setting forth any matters which, in Buyer’s reasonable opinion, constitute Environmental Conditions and which Buyer intends to assert as Environmental Conditions pursuant to this Section 11.1. For the avoidance of doubt, Buyer may only assert an Environmental Condition Notice, and claim an Environmental Condition with respect to Assets other than Buyer Operated Properties and Assets located thereon, and Buyer shall not be entitled to assert an Environmental Condition with respect to any Property or Asset that is operated by Buyer or any of its Affiliates. For all purposes of this Agreement but subject to Buyer’s remedy for a breach of Seller’s representation contained in Article IV (or the certificate to be delivered at Closing pursuant to Section 8.3(b)(i)), Seller’s indemnity obligation in Section 12.2(c)(ii) and (c)(v), Buyer shall be deemed to have waived any Environmental Condition which Buyer fails to assert as an Environmental Condition by an Environmental Condition Notice received by Seller on or before the Environmental Claim Date, as well as any Environmental Condition located on a Property that is a Buyer Operated Property, regardless of when such Environmental Condition arose, whether before or after the Effective Time. Each Environmental Condition Notice shall be in writing and shall include (i) a reasonably detailed description, including, where available, supporting documentation in Buyer’s possession or control, of the matter constituting the alleged Environmental Condition, (ii) a description of each Asset (or portion thereof) that is affected by the alleged Environmental Condition, (iii) Buyer’s assertion of the Allocated Value of the portion of the Assets affected by the alleged Environmental Condition, and (iv) an estimate, which is non-binding, of the Remediation Amount that Buyer asserts is attributable to such alleged Environmental Condition. Buyer’s calculation of the Remediation Amount included in the Environmental Condition Notice should describe in reasonable detail the Remediation proposed for the Environmental Condition that gives rise to the asserted Environmental Condition and the primary assumptions used in calculating the Remediation Amount, including, any standards that Buyer asserts must be met to comply with Environmental Laws. Seller shall have the right, but not the obligation, to Remediate any claimed Environmental Condition on or before the Closing Date (the “Environmental Condition Cure Period”). Seller may select and employ at its sole discretion any generally accepted remedial technology or approach to Remediate an identified Environmental Condition. Any Remediation attempt shall be at Seller’s sole cost, risk and expense, and Seller shall indemnify, defend, and hold harmless Buyer Indemnified Parties from and against any Liabilities arising out of, or relating to, such attempt on the terms set forth in Section 12.5.

(b)Remedies for Environmental Conditions. Subject to the parties’ rights pursuant to Section 13.1, in the event that any Environmental Condition timely asserted by Buyer in accordance with Section 11.1(a) is not waived in writing by Buyer or Remediated on or before Closing, then the parties shall mutually agree to elect one of the following remedies:

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(i)subject to the Individual Environmental Threshold and the Aggregate Deductible, a reduction of the Purchase Price by the Remediation Amount agreed upon by Seller and Buyer or determined in accordance with Section 11.1(g) and assumption by Buyer of responsibility for Remediation of the Environmental Condition;

(ii)assumption of responsibility by Seller for the Remediation of such Environmental Condition and mutually agreeable indemnification of Buyer Indemnified Parties by Seller therefor under a mutually acceptable access agreement; or

(iii)retention by Seller of the entirety of the Asset that is subject to such Environmental Condition, together with all associated Assets, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Asset and such associated Assets.

In the event the parties cannot agree to either Section 11.1(b)(i), (ii) or (iii), then Section 11.1(b)(i) shall be the remedy for an Environmental Condition unless the Allocated Value of such Asset is equal to or less than the Remediation Amount asserted by Buyer, in which event, at the election of either party, Section 11.1(b)(iii) shall be the remedy for an Environmental Condition.

(c)If clause (i) of Section 11.1(b) above is applicable or the default remedy, Buyer shall be deemed to have assumed responsibility for Remediation of such Environmental Condition and such Environmental Condition and all Liabilities with respect thereto shall be deemed to constitute Assumed Obligations. If clause (ii) of Section 11.1(b) above is applicable, then (A) Seller shall use commercially reasonable efforts to implement such Remediation in a manner which is consistent with the requirements of Environmental Laws, taking into consideration Buyer’s use and operation of the Assets, in a timely fashion for the type of Remediation Seller elects to undertake and, upon reasonable advance written notice, Buyer hereby grants Seller access to the affected Assets after the Closing Date to implement and complete such Remediation in accordance with an access agreement proposed by Buyer and reasonably acceptable to Seller, and (B) there shall be no reduction to the Purchase Price due to the relevant Environmental Condition pending implementation of such Remediation. Any Remediation shall be subject to the consent of Buyer, which consent shall not be unreasonably withheld. To the extent such Remediation is not completed to Buyer’s reasonable satisfaction within 110 days after the Closing Date, and neither party has elected to exclude the relevant Asset pursuant to Section 11.1(b)(iii), within five business days of the end of such period (or such longer period as is required by Section 11.1(g)), Seller shall pay to Buyer the amounts still required to Remediate such Environmental Condition (not to exceed the Allocated Value of the relevant Asset), and thereafter Buyer shall assume and discharge all responsibility for Remediation of the relevant Environmental Condition and all Liabilities with respect thereto shall be deemed to constitute Assumed Obligations. Any dispute regarding the Remediation Amount or whether, or to what extent, and Environmental Condition has been remediated shall be resolved pursuant to Section 11.1(g). Except as provided above in this Section 11.1(c), upon completion of Remediation under clause (ii) of Section 11.1(b) above, Seller shall at its sole cost and expense and without any cost or expense to Buyer or its Affiliates, (1) close all

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bore holes from its Remediation in accordance with recognized industry standards, (2) repair all damage done to the Assets in connection with the Remediation, and (3) remove all equipment, tools or other property brought onto the Assets in connection with the Remediation. The party performing Remediation shall keep the other party reasonably informed regarding any Remediation. In completing the Remediation, the party performing the Remediation shall provide the other party with draft copies of all documents to be submitted to any Governmental Authorities regarding the Remediation and shall reasonably cooperate with the other party to incorporate comments provided by it to the party performing the Remediation regarding such documents. In addition, the party performing the Remediation shall promptly provide the other party with copies of any correspondence with any Governmental Authority regarding the Remediation and shall provide the other party with the opportunity to participate in any meetings with any Governmental Authority regarding the Remediation. The party performing the Remediation shall be solely responsible for obtaining any permits or other authorizations from any Governmental Authority associated with the Remediation. The party performing the Remediation shall promptly remove any waste material generated during the Remediation from the Assets. The party performing the Remediation shall require any contractors or subcontractors entering the Assets in connection with the Remediation to provide the other party with certificates of insurance demonstrating coverage under Commercial General Liability, Contractors Pollution Liability, and Errors and Omissions Liability insurance policies in a form reasonably acceptable to the other party and naming the other party as an additional insured.

(d)With respect to any provision of this Article XI that refers to any Remediation completed by Seller, whether before or after the Closing, Seller will be deemed to have adequately completed the Remediation (A) upon receipt of a certificate of approval or completion or its equivalent from the applicable Governmental Authority that the Remediation has been implemented to the extent necessary to comply with existing Laws or (B) if no certificate or approval is available under Environmental Law or upon express written consent of Buyer, upon mutual agreement of the parties, upon receipt of a certificate from an independent, licensed professional engineer that the Remediation has been implemented to the extent necessary to comply with Environmental Laws; provided, if the parties cannot agree, the issue of whether the Remediation is completed may be resolved by the dispute resolution procedures set forth in Section 11.1(g).

(e)Exclusive Remedy. Without limiting the express representations and warranties set forth in Article IV (or the certificate to be delivered at Closing pursuant to Section 8.3(b)(i)), and except for Buyer’s remedy for a breach of Seller’s representation contained in Section 4.16, Seller’s indemnification obligation in Section 12.2(c)(ii) and Section 12.2(c)(v), and Buyer’s rights to terminate this Agreement pursuant to Section 13.1, the provisions set forth in Section 11.1(b) shall be the exclusive right and remedy of Buyer with respect to any Environmental Condition or other environmental matter with respect to any Asset. The parties acknowledge and agree that Environmental Conditions for which Buyer submits or, with Knowledge of the same, elects not to submit an Environmental Condition Notice pursuant to Section 11.1(a) shall not form the basis for a claim for a breach of representation or warranty pursuant to Section 4.16.

(f)Environmental Deductibles. Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller

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for any individual Environmental Condition under this Article XI for which the Remediation Amount does not exceed $75,000 (“Individual Environmental Threshold”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any Environmental Condition for which the Remediation Amount exceeds the Individual Environmental Threshold unless (A) the sum of (1) the Remediation Amounts of all such Environmental Conditions that exceed the Individual Environmental Threshold, in the aggregate, excluding (x) any Environmental Conditions Remediated by Seller and (y) the Remediation Amounts attributable to an Asset retained by Seller under Section 11.1(b)(iii), and (2) the Title Defect Amounts of all Title Defects, in the aggregate, excluding (x) any individual Title Defect for which the Title Defect Amount does not exceed the Individual Title Defect Threshold, (y) any Title Defects cured by Seller, and (z) any Title Defect Properties retained by Seller hereunder, (B) exceeds the Aggregate Deductible, after which point Buyer shall be entitled to adjustments to the Purchase Price or other remedies only with respect to the portion of the Remediation Amounts in excess of such Aggregate Deductible.

(g)Environmental Dispute Resolution. Seller and Buyer shall attempt to agree on all Environmental Conditions and Remediation Amounts prior to the Closing Date. If Seller and Buyer are unable to agree on the existence of an Environmental Condition or a Remediation Amount by the Closing Date, the entirety of the Asset that is subject to such Environmental Condition, together with all associated Assets, shall not be assigned by Seller at Closing, (ii) the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Asset and such associated Assets and (iii) the existence of the Environmental Condition or the Remediation Amount, as applicable, shall be exclusively and finally resolved by arbitration pursuant to this Section 11.1(g). There shall be a single arbitrator, who shall be an environmental attorney or environmental expert with at least ten years’ experience in environmental matters involving oil and gas producing properties in Texas, as selected by mutual agreement of Buyer and Seller within 15 days after the Closing Date, and absent such agreement within such time period, then each party will nominate a candidate to select the Environmental Arbitrator, and such candidates so nominated by Buyer and Seller shall together determine the Environmental Arbitrator within 15 days after the last candidate is nominated and absent such determination within such time period, the Environmental Arbitrator shall be selected by the Houston, Texas office of the American Arbitration Association (the “Environmental Arbitrator”). The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Article. The Environmental Arbitrator’s determination shall be made within 20 days after submission of the matters in dispute and shall be final and binding upon both parties, without right of appeal. In making his determination, the Environmental Arbitrator shall be bound by the rules set forth in this Section 11.1 and, subject to the foregoing, may consider such other matters as in the opinion of the Environmental Arbitrator are necessary or helpful to make a proper determination. The Environmental Arbitrator, however, may not award Buyer a greater Remediation Amount than the Remediation Amount claimed by Buyer in its applicable Environmental Condition Notice and notwithstanding anything herein to the contrary, the Environmental Arbitrator’s awards are subject to the limitations on liability set forth in Section 11.1(f). The Environmental Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Environmental Conditions or Remediation Amounts submitted by either party and may not award damages, interest or penalties to either party with respect to any

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matter. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Environmental Arbitrator. Following the determination of the Environmental Arbitrator, the parties shall make an election pursuant to Section 11.1(b) with respect to the affected Asset, to the extent determined to be subject to an Environmental Condition. To the extent that the award of the Environmental Arbitrator with respect to any Remediation Amount is not taken into account as an adjustment to the Purchase Price pursuant to Section 3.4 or Section 3.5, then within ten days after the Environmental Arbitrator delivers written notice to Buyer and Seller of his award with respect to a Remediation Amount if the relevant Asset and its associated Assets are to be conveyed to Buyer pursuant to Section 11.1(b), Buyer shall pay to Seller the Allocated Value of such Asset and its associated Assets (less any relevant Remediation Amount as determined pursuant to Section 11.1(b)(i) or 11.1(c), as applicable), and Seller shall convey such Asset and its associated Assets on a form of assignment substantially in the form attached to this Agreement as Exhibit C. Subject to the parties’ rights pursuant to Section 13.1, nothing herein shall operate to cause the Closing to be delayed on account of any arbitration hereunder.

Section 11.2.NORM, Wastes and Other Substances. Buyer acknowledges that the Assets have been used for exploration, development and production of oil and gas and that there may be Hydrocarbons, produced water, wastes, Hazardous Substances or other substances or materials located in, on or under the Assets or associated with the Assets. Equipment and sites included in the Assets may contain asbestos, NORM or other Hazardous Substances. NORM may affix or attach itself to the inside of wells, materials and equipment as scale, or in other forms. The wells, materials and equipment located on the Assets or included in the Assets may contain NORM and other wastes or Hazardous Substances. NORM containing material and other wastes or Hazardous Substances may have come in contact with various environmental media, including water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation or disposal of environmental media, wastes, asbestos, NORM and other Hazardous Substances from the Assets.

ARTICLE XII

ASSUMPTION; SURVIVAL; INDEMNIFICATION

Section 12.1.Assumption by Buyer. Except as otherwise provided herein (including in Section 14.1(b)) and subject to Buyer’s rights to indemnity under Section 12.2, from and after the Closing, Buyer assumes and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all obligations and Liabilities, known or unknown, with respect to the Assets, regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, including obligations and Liabilities relating in any manner to the ownership, operation or use of the Assets, including obligations (a) to furnish makeup gas or settle Imbalances according to the terms of applicable gas sales, processing, gathering or transportation Contracts, (b) to pay working interests, Royalties and owners’ revenues or proceeds attributable to the sale of Hydrocarbons produced from or attributable to the Assets after the Effective Time (including any such payments held in suspense that are transferred to Buyer pursuant to Section 2.1(m)), (c) to properly plug, re-plug and abandon any and all wells, wellbores, or previously plugged Wells on the Properties to the extent required or necessary, (d) to dismantle or decommission

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and remove any Personal Property and other property of whatever kind related to or associated with operations and activities conducted on the Properties or Assets, (e) to clean up, restore or remediate the premises covered by or related to the Assets in accordance with applicable agreements and Governmental Requirements, including Environmental Laws, (f) to perform all obligations applicable to or imposed on the lessee, owner or operator from and after the Effective Time under the Leases and the Applicable Contracts or as required by agreements and Governmental Requirements, (g) to pay any claims regarding the general method, manner or practice of calculating or making Royalty payments (or payments of overriding Royalties or similar burdens on production) with respect to the Properties, and (h) to dispose of or transport of any Hazardous Substances (all of said obligations and Liabilities herein being referred to as the “Assumed Obligations”). Notwithstanding the foregoing, Buyer does not assume, and shall not be responsible for, the Retained Obligations until such time as Seller’s indemnity obligations with respect thereto expire (if ever).

Section 12.2.Retained Obligations; Indemnities of Seller. If Closing occurs, subject to the limitations set forth in Section 12.4 and otherwise in this Article XII, Seller shall be responsible for, shall pay on a current basis, and hereby defends, indemnifies, holds harmless and forever releases Buyer and its Affiliates, and all of their respective stockholders, partners, members, directors, officers, managers, employees, agents and representatives (collectively, “Buyer Indemnified Parties”) from and against any and all Liabilities arising from, based upon, related to or associated with:

(a)any breach by Seller of its representations or warranties contained in Article IV (or the certificate to be delivered by Seller at Closing pursuant to Section 8.3(b)(i)), as of the Execution Date and as of the Closing, as though made at and as of the Closing;

(b)any breach by Seller of its covenants and agreements under this Agreement; and

(c)any obligations or liabilities of Seller or any of its Affiliates to the extent involving or relating to (i) the ownership, use or operation of the Excluded Assets, (ii) the transport or disposal prior to the Closing Date of any Hazardous Substances from the Assets (other than the Buyer Operated Properties) to any location not on the Assets prior to the Closing Date; (iii) any Seller Taxes; (iv) any Liability or obligation for compensation or reimbursement to any of Seller’s current or former employees for work performed, including any Liabilities or obligations to the extent related to or arising under any employee benefit plan, express or implied contract, wages, bonuses, commissions or severance benefits; (v) any fines, penalties and sanctions asserted, imposed or levied by any Governmental Authority resulting from any criminal investigation or proceedings to the extent arising out of or related to Seller’s ownership, use, maintenance or operation of the Seller Operated Properties; (vi) any death, physical injury, illness, or property damage (other than property damage constituting an Environmental Condition and/or property damage suffered by Third Parties that are not contractors or subcontractors of any tier of Seller or its Affiliates) related to or arising out of the Assets (other than the Buyer Operated Properties) and occurring prior to the Closing Date; (vii) the SOP Retained Operating Expenses; or (viii) litigation disclosed on Schedule 4.6 (collectively, the “Retained Obligations”).

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Section 12.3.Indemnities of Buyer. Effective as of the Closing, Buyer shall be responsible for, shall pay on a current basis, and hereby defends, indemnifies, holds harmless and forever releases Seller and its Affiliates, and all of their respective owners, stockholders, partners, members, directors, officers, managers, employees, agents and representatives (collectively, “Seller Indemnified Parties”) from and against any and all Liabilities arising from, based upon, related to or associated with any breach by Buyer of its representations or warranties contained in Article V (or the certificate to be delivered by Seller at Closing pursuant to Section 8.3(b)(i)), as of the Execution Date and as of the Closing, as though made at and as of the Closing;

(a)any breach by Buyer of its covenants and agreements under this Agreement; and

(b)the Assumed Obligations,

excluding, in each case above, matters against which Seller would be required to indemnify, defend, or hold harmless Buyer Indemnified Parties at the time that a Claim Notice or other notice of the matter indemnified against is presented to Buyer or a Buyer Indemnified Party.

Section 12.4.Limitation on Liability.

(a)Seller shall not have any liability for any indemnification under Section 12.2 for any individual Liability unless the indemnification amount owed by Seller to the Buyer Indemnified Parties with respect to such Liability exceeds the Post-Closing Threshold. Additionally, Seller shall not have any liability for any indemnification under Section 12.2 unless and until the amount of all Liabilities for which Claim Notices with respect thereto are delivered by Buyer exceeding the Post-Closing Threshold exceeds, in the aggregate, the Post-Closing Deductible, and then only to the extent such damages exceed the Post-Closing Deductible. Notwithstanding anything in this Section 12.4(a) to the contrary, the limitations on Seller’s Liability in this Section 12.4(a) shall not apply to (i) Seller’s Liability for breaches of its Fundamental Representations or the representations and warranties in Section 4.11, Section 4.17, or Section 4.18, (ii) Seller’s Liability for breaches of any covenant hereunder or (iii) Seller’s Liability under Section 12.2(c) (such Seller Liabilities in the immediately preceding clauses (i), (ii) and (iii), the “Specified Seller Indemnity Obligations”).

(b)Except with respect to the Specified Seller Indemnity Obligations, notwithstanding anything to the contrary in this Agreement, Seller shall not have any liability for any indemnification under Section 12.2, in the aggregate, in excess of 20% of the Final Price.

(c)Notwithstanding anything to the contrary in this Agreement, Seller’s aggregate Liabilities under and in connection with this Agreement shall not exceed 100% of the Final Price.

(d)Seller recognizes that the express terms of the Transaction Documents, including its representations and warranties in Article IV and its obligations under Section 12.2 are material inducements to Buyer’s decision to pursue the transactions contemplated by this Agreement, and without such provisions, Buyer would not have entered into this Agreement. It is

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the intent of the parties that such terms shall be enforceable as expressly set forth herein and regardless of the knowledge of any Buyer Indemnified Party, including of any matters that would constitute a breach of representation, warranty, covenant, or agreement or give rise to an obligation of indemnification under Section 12.2. For purposes of this Article XII (including for the purpose of determining whether or not a representation, warranty, covenant or agreement has been breached and except with respect to Section 4.16(a)), any representation, warranty, covenant or agreement qualified by Material Adverse Effect shall be deemed not to be so qualified.

Section 12.5.Express Negligence. THE DEFENSE, INDEMNIFICATION, HOLD HARMLESS, RELEASE, ASSUMED OBLIGATIONS AND RETAINED OBLIGATIONS PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE GROSS, SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY, BUT EXCLUDING THE WILLFUL MISCONDUCT OF ANY INDEMNIFIED PARTY. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS CONSPICUOUS.

Section 12.6.Exclusive Remedy. FROM AND AFTER THE CLOSING, EXCEPT WITH RESPECT TO SECTION 2.3, SECTION 3.5, SECTION 3.6, SECTION 3.7, SECTION 6.3, SECTION 6.5, SECTION 6.7, SECTION 6.9, SECTION 8.4, SECTION 9.1(d), SECTION 9.1(e), SECTION 9.2, SECTIONS 10.2(c) and (h), SECTION 10.3, SECTION 10.4, SECTIONS 11.1(b), (c), and (g), SECTION 14.1, SECTION 14.3, SECTION 14.5, SECTION 14.6, SECTION 14.7 AND SECTION 14.12 (FOR WHICH THE PARTIES SHALL BE ADDITIONALLY ENTITLED TO THE REMEDY OF SPECIFIC PERFORMANCE), THE SOLE AND EXCLUSIVE REMEDY OF ANY PARTY TO THIS AGREEMENT AND ITS AFFILIATES AND ANY INDEMNIFIED PARTY WITH RESPECT TO THIS AGREEMENT, THE ASSETS, THE EVENTS GIVING RISE TO THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT AND THE TRANSACTION DOCUMENTS SHALL BE LIMITED TO THE INDEMNIFICATION PROVISIONS AND REMEDIES SET FORTH IN SECTION 6.7 AND SECTION 10.4(F) AND ARTICLE IX, ARTICLE X, ARTICLE XI AND ARTICLE XII (WITH RESPECT TO THE MATTERS ADDRESSED THEREIN) AND SUCH PARTY’S RIGHTS UNDER ARTICLE XIII, AND, IN FURTHERANCE OF THE FOREGOING, EACH OF THE PARTIES, ON BEHALF OF ITSELF AND OF ITS AFFILIATES, HEREBY WAIVES, RELEASES AND DISCHARGES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE OTHER PARTIES TO THIS AGREEMENT AND THEIR RESPECTIVE AFFILIATES FROM ANY AND ALL LIABILITIES OF ANY KIND (WHETHER AT LAW OR IN EQUITY OR OTHERWISE, FORESEEN OR UNFORESEEN, MATURED OR UNMATURED, KNOWN OR UNKNOWN, ACCRUED OR NOT ACCRUED OR BASED ON ANY LAW OR RIGHT OF ACTION OR OTHERWISE) EXCEPT AS PROVIDED IN THIS AGREEMENT NOTWITHSTANDING THE STRICT LIABILITY OR NEGLIGENCE OF A RELEASED PARTY (WHETHER SOLE, JOINT OR CONCURRENT OR ACTIVE OR PASSIVE).

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Section 12.7.Indemnification Procedures. All claims for indemnification under Section 9.1(c), Section 12.2 and Section 12.3 shall be asserted and resolved as follows:

(a)For purposes of this Article XII, the term “Indemnifying Party”, when used in connection with particular Liabilities, shall mean the party or parties having an obligation to indemnify another party or parties with respect to such Liabilities pursuant to this Article XII, and the term “Indemnified Party”, when used in connection with particular Liabilities, shall mean the party or parties having the right to be indemnified with respect to such Liabilities by another party or parties pursuant to this Article XII.

(b)To make a claim for indemnification under Section 9.1(c), Section 12.2 or Section 12.3, a party shall notify the Indemnifying Party of the claim of an Indemnified Party under this Section 12.7, including the specific details of, and specific basis under this Agreement for, its claim (the “Claim Notice”). In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Party (a “Claim”), such party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Claim and shall enclose a copy of all papers (if any) served with respect to the Claim; provided that the failure of any Indemnified Party to give notice of a Claim as provided in this Section 12.7 shall not relieve the Indemnifying Party of its obligations under Section 9.1(c), Section 12.2 or Section 12.3 (as applicable) except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the claim. All claims by an Indemnified Party pursuant to this Article XII may only be brought by a party hereto, on its own behalf or on behalf of an Indemnified Party.

(c)In the case of a claim for indemnification based upon a Claim, the Indemnifying Party shall have 30 days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such 30 day period, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party.

(d)If the Indemnifying Party admits its liability, it shall have the right and obligation to diligently defend, at its sole cost and expense, the Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof subject to the remainder of this Section 12.7(d). If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in contesting any Claim which the Indemnifying Party elects to contest, including by making available all records (in any form) and furnishing management and employees as may be reasonable necessary for the preparation of any defense or settlement. The Indemnified Party may participate in, but not control, any defense or settlement of any Claim controlled by the Indemnifying Party pursuant to this Section 12.7(d). An Indemnifying Party shall not, without the prior written consent of the Indemnified Party, (i) settle any Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all liability in respect of such Claim or (ii) settle any Claim or consent to the entry of any judgment with respect thereto in any manner that may materially and

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adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(e)If the Indemnifying Party does not admit its liability within the 30 day period or admits its liability but fails to diligently defend or settle the Claim, then the Indemnified Party shall have the right to defend against the Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing; provided that the Indemnified Party shall not settle a Claim or consent to the entry of any judgment with respect thereto without the prior written consent of the Indemnifying Party, which consent shall not be unreasonably withheld, delayed or conditioned.

(f)In the case of a claim for indemnification not based upon a Claim, the Indemnifying Party shall have 90 days from its receipt of the Claim Notice to (i) cure, if curable, or Remediate, if applicable, the Liabilities complained of, (ii) admit its liability for such Liability or (iii) dispute the claim for such Liabilities.

(g)The amount of any Liabilities for which any of the Indemnified Parties is entitled to indemnification under this Agreement or in connection with the transactions contemplated by this Agreement shall be reduced by any corresponding insurance proceeds actually realized, net of any collection costs, and excluding the proceeds of any insurance underwritten by the Indemnified Parties; provided, however, that no Indemnified Party shall be required to seek or pursue such insurance proceeds as a condition of indemnification hereunder. If an Indemnified Party directly or indirectly receives an amount under insurance coverage with respect to Buyer Liabilities or Seller Liabilities, as applicable, at any time subsequent to any indemnification provided by Seller or Buyer, as applicable, pursuant to this Section 12.7, then such Indemnified Party shall promptly reimburse the Indemnifying Party for any payment made or expense incurred by the Indemnifying Party in connection with providing such indemnification up to such amount received by the Indemnified Party.

(h)Any liability for indemnification hereunder shall be determined without duplication of recovery by reason of the state of facts giving rise to such Liability constituting a breach of more than one representation, warranty, covenant or agreement herein. The Indemnifying Party shall not be liable for indemnification with respect to any of the Indemnified Party’s Liabilities, based on any set of facts to the extent the Purchase Price is being or has been adjusted by reason of the same set of facts. The determination of the dollar amount of any Liabilities shall be based solely on the actual dollar value thereof, on a dollar-for-dollar basis, and shall not take into account any multiplier valuations, including any multiple based on earnings or other financial condition.

Section 12.8.Survival.

(a)The representations and warranties of Seller in Article IV (other than Fundamental Representations and the representations and warranties in Section 4.17, Section 4.18, and Section 4.23(b)) and the covenants to be performed by Seller prior to Closing shall survive the Closing and for a period of 365 days thereafter. The representations and warranties of Seller in Section 4.23(b) shall survive Closing for a period of 15 months. The representations and warranties of Seller in Section 4.17 and Section 4.18 shall survive Closing for the applicable statute of

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limitations period plus 30 days. The covenants to be performed by Seller following Closing shall survive until fully performed. Subject to the foregoing and Section 12.8(b), the remainder of this Agreement shall survive the Closing without time limit. Representations, warranties, covenants and agreements shall be of no further force and effect after the date of their expiration and no claim may be brought in respect thereof after the date of such expiration; provided that there shall be no termination of any bona fide claim asserted pursuant to a Claim Notice under this Agreement with respect to such a representation, warranty, covenant or agreement prior to its expiration date. The parties intend to shorten the applicable statute of limitations as provided herein.

(b)The indemnities in this Article XII shall terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification, except in each case as to matters for which a Claim Notice has been delivered to the Indemnifying Party on or before such termination date. Seller’s obligations under Section 12.2(c) shall survive the Closing without time limit; provided, however, that, notwithstanding the foregoing, Seller’s obligations under (i) Section 12.2(c)(vii) shall only survive the Closing for a period of 15 months; and (ii) Section 12.2(c)(iii) shall only survive the Closing for the applicable statute of limitations period plus an additional 30 days, except, in each case as to matters for which a Claim Notice has been delivered to the Indemnifying Party on or before such termination date.

Section 12.9.Waiver of Right to Rescission. Seller and Buyer acknowledge that the payment of money, as limited by the terms of this Agreement, and Buyer’s remedy of specific performance, shall be adequate compensation and remedy for breach of any representation, warranty, covenant or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated in this Agreement. As the payment of money and Buyer’s remedy of specific performance shall be adequate compensation and remedy, Buyer and Seller waive any right to rescind this Agreement or any of the transactions contemplated hereby.

Section 12.10.Non-Compensatory Damages. None of the Buyer Indemnified Parties nor the Seller Indemnified Parties shall be entitled to recover from Seller or Buyer, or their respective Affiliates, any punitive, special, indirect, remote, speculative, exemplary or consequential damages of any kind arising under or in connection with this Agreement or the transactions contemplated hereby, except to the extent any such party suffers such damages (including costs of defense and reasonable attorney’s fees incurred in connection with defending of such damages) to a Third Party, which damages (including costs of defense and reasonable attorney’s fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder. SUBJECT TO THE PRECEDING SENTENCE, BUYER, ON BEHALF OF EACH OF THE BUYER INDEMNIFIED PARTIES, AND SELLER, ON BEHALF OF EACH OF SELLER INDEMNIFIED PARTIES, WAIVE ANY RIGHT TO RECOVER PUNITIVE, SPECIAL, INDIRECT, REMOTE, SPECULATIVE, EXEMPLARY AND CONSEQUENTIAL DAMAGES, ARISING IN CONNECTION WITH OR WITH RESPECT TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY. NOTWITHSTANDING THE FOREGOING, NOTHING HEREIN SHALL PREJUDICE BUYER’S RIGHTS TO PURSUE SPECIFIC PERFORMANCE IN ACCORDANCE WITH SECTION 13.2(c).

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Section 12.11.Disclaimer of Application of Anti-Indemnity Statutes. The parties acknowledge and agree that the provisions of any anti-indemnity statute relating to oilfield services and associated activities shall not be applicable to this Agreement and the transactions contemplated hereby.

Section 12.12.Waiver of Trade Practices Act.

(a)It is the intention of the parties that Buyer’s rights and remedies with respect to this transaction and with respect to all acts or practices of Seller, past, present or future, in connection with this transaction shall be governed by the legal principles other than the Texas Deceptive Trade Practices-Consumer Protection Act, Tex. Bus. & Com. Code Ann. § 17.41 et seq. (the “DTPA”). As such, Buyer hereby waives the applicability of the DTPA to this transaction and any and all duties, rights or remedies that might be imposed by the DTPA, whether such duties, rights and remedies are applied directly by the DTPA itself or indirectly in connection with other statutes. Buyer acknowledges, represents and warrants (i) that it is purchasing the goods and services covered by this Agreement for commercial or business use, (ii) that it or its controlling entity has assets of $25,000,000 or more according to its most recent financial statement prepared in accordance with generally accepted accounting principles, (iii) that it has knowledge and experience in financial and business matters that enable it to evaluate the merits and risks of a transaction such as this and (iv) that it is not in a significantly disparate bargaining position with Seller. In furtherance of the foregoing,

WAIVER OF CONSUMER RIGHTS

BUYER WAIVES ITS RIGHTS UNDER THE TEXAS DECEPTIVE TRADE PRACTICES-CONSUMER PROTECTION ACT, SECTION 17.41 ET SEQ., BUSINESS & COMMERCE CODE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS AND PROTECTIONS. AFTER CONSULTATION WITH AN ATTORNEY OF BUYER’S OWN SELECTION, BUYER VOLUNTARILY CONSENTS TO THIS WAIVER.

(b)Buyer expressly recognizes that the price for which Seller has agreed to perform its obligations under this Agreement has been predicated upon the inapplicability of the DTPA and this waiver of the DTPA. Buyer further recognizes that Seller, in determining to enter into this Agreement, has expressly relied on this waiver and the inapplicability of the DTPA.

ARTICLE XIII

TERMINATION, DEFAULT AND REMEDIES

Section 13.1.Right of Termination. This Agreement and the transactions contemplated herein may be terminated (a) at any time at or prior to Closing by mutual written agreement of the parties, (b) by Seller if (i) Seller is ready, willing and able to perform all of its agreements and covenants contained herein which are to be performed or observed by Seller at the Closing and (ii) the Closing shall not have occurred on or before February 14, 2018, or (c) by Buyer if (i) Buyer is ready, willing and able to perform all of its agreements and covenants contained herein which are to be performed or observed by such party at the Closing and (ii) the Closing shall

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not have occurred on or before February 14, 2018; provided, however, that no party shall have the right to terminate this Agreement to this Section 13.1 if such party or its Affiliates are at such time in material breach of any provision of this Agreement.

Section 13.2.Effect of Termination; Remedies.

(a)If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 13.1 hereof, then except for the provisions of Section 1.1, Section 9.1(e), Section 9.2(a), Section 12.10, this Article XIII, Article XIV (other than Section 14.1(b), Section 14.5, Section 14.6 and Section 14.7) and such of the defined terms in Appendix 1 as are referenced in such Sections and Articles, this Agreement shall forthwith become void, and the parties shall have no Liability or obligation hereunder.

(b)If Seller has the right to terminate this Agreement pursuant to Section 13.1 and Buyer is a Breaching Party, then Seller shall, as its sole and exclusive remedy, have the right to terminate this Agreement and retain the Deposit, as liquidated damages and not as a penalty for such termination, free and clear of any claims thereon by Buyer. THE PARTIES ACKNOWLEDGE AND AGREE THAT (A) SELLER’S ACTUAL DAMAGES RESULTING FROM A TERMINATION UNDER THIS SECTION 13.2(B) MAY BE DIFFICULT, IF NOT IMPOSSIBLE TO CALCULATE, (B) THE DEPOSIT IS A FAIR AND REASONABLE ESTIMATE OF SELLER’S LIQUIDATED DAMAGES IN LIGHT OF THE UNCERTAINTIES IN CALCULATING THE ACTUAL DAMAGES THAT WOULD BE SUFFERED BY SELLER UNDER THE CIRCUMSTANCES SET FORTH IN THIS SECTION 13.2(B) AND (C) SUCH LIQUIDATED DAMAGES ARE NOT A PENALTY.

(c)If Buyer has a right to terminate this Agreement pursuant to Section 13.1 and Seller is a Breaching Party, then Buyer shall, as its sole and exclusive remedy, have the right to, at its option, either (i) terminate this Agreement and receive a return of the Deposit; or (ii) seek specific performance by Seller of this Agreement. In connection with the foregoing, it is agreed and acknowledged by the parties that the Assets are unique and that Buyer shall be entitled to the remedies set forth in this Section 13.2(c)(ii), without the posting of a bond or other surety or proof of harm.

(d)In the event that this Agreement is terminated under Section 13.1 and Seller is not entitled to retain the Deposit under Section 13.2(b), then Seller shall, within five (5) business days of the date of such termination, return to Buyer the Deposit (without interest), free of any claims thereon by Seller.

(e)If a party resorts to legal proceedings to enforce this Agreement prior to Closing, the prevailing party in such proceedings shall be entitled to recover all costs incurred by such party from the party that is in breach or default, including reasonable attorneys’ fees, in addition to any other relief to which such party may be entitled.

Section 13.3.Return of Documentation and Confidentiality. Upon termination of this Agreement, Buyer shall promptly (a) return to Seller, or, if electronic, destroy, all title, engineering, geological and geophysical data, environmental assessments and reports, maps and other information furnished by Seller to Buyer or prepared by or on behalf of Buyer in connection

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with its due diligence investigation of the Assets and any documents, data, reports, assessments in paper, electronic, digital or any other form, to the extent derived from the matters described in this clause (a) or from any confidential information obtained under the Confidentiality Agreement, or (b) destroy any copies of such data, assessments and reports. An officer of Buyer shall certify same to Seller in writing. Notwithstanding the foregoing, nothing herein shall require Buyer to destroy or return data and information contained in Buyer’s computer back-up systems that will be deleted in accordance with Buyer’s document retention policies or data or information embedded within board or management presentations or minutes compiled by or on behalf of Buyer or that are otherwise retained for corporate governance purposes.

ARTICLE XIV

MISCELLANEOUS

Section 14.1.Expenses and Taxes.

(a)Except as otherwise specifically provided, all fees, costs and expenses incurred by Buyer or Seller in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the party incurring the same, including legal and accounting fees, costs and expenses.

(b)All required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to the Assets to Buyer shall be borne by Buyer. Buyer shall (i) file all necessary Tax Returns and other documentation with respect to all sales, use, transfer and similar taxes (“Transfer Taxes”) and fees arising out of or in connection with the transactions effected pursuant to this Agreement and (ii) be liable for and either promptly reimburse Seller for, or promptly pay, any such Transfer Taxes. Seller and Buyer shall cooperate in good faith to obtain an exemption from, or minimize, to the extent permissible under applicable Law, the amount of Transfer Taxes. Seller shall be responsible for, and shall bear and pay, all Asset Taxes assessed by any Governmental Authority for any period or the portion of the Straddle Period that ends prior to the Effective Time. Buyer shall be responsible for, and shall bear and pay, all Asset Taxes assessed by any Governmental Authority for any period, or the portion of the Straddle Period that begins on or after the Effective Time (including any “rollback” or similar ad valorem or property Tax resulting from a change in use of property by Buyer, regardless of the period with respect to which such rollback or similar Tax is calculated). For purposes of this Agreement, (i) production, severance, and similar Asset Taxes (including any applicable interest or penalties) that are attributable to the severance or production of Hydrocarbons shall be allocated to the period during which the relevant production or severance occurred, (ii) ad valorem, property and similar Asset Taxes (including any applicable interest or penalties) shall be prorated at the Closing based on the ratio of the number of days in the Straddle Period prior to (for Seller) and on and after (for Buyer) the Effective Time to the total number of days in the Straddle Period as applied to the amount of such Asset Taxes for the most recent year for which the amount of such Asset Taxes can be finally determined at the Closing, and (iii) all other Asset Taxes shall be allocated to the period in which the transaction giving rise to such taxes occurred. Seller shall pay to Buyer within 30 days of Buyer’s written demand Seller’s portion of all Asset Taxes prorated to Seller under this Section 14.1(b) but paid by Buyer to the extent not

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taken into account under Section 3.2(b)(iii). Buyer shall pay to Seller within 30 days of Seller’s written demand Buyer’s portion of all Asset Taxes prorated to Buyer under this Section 14.1(b) but paid by Seller to the extent not taken into account under Section 3.2(a)(iii).

(c)If Buyer receives a refund of any Taxes that Seller is responsible for hereunder, or if Seller receive a refund of any Taxes that Buyer is responsible for hereunder, and such refund was not taken into account for purposes of determining the Final Price under Section 3.1(b), the party receiving such refund shall, within 30 days after receipt of such refund, remit it to the party who has responsibility for such Taxes hereunder.

Section 14.2.Assignment. Except as otherwise set forth in Section 6.8, this Agreement may not be assigned by either party without prior written consent of the other, which consent shall not be unreasonably withheld, conditioned, or delayed; provided, however, Buyer shall have the right to assign this Agreement, in whole or in part, to an Affiliate of Buyer. No assignment of any rights hereunder by a party shall relieve such party of any obligations and responsibilities hereunder. Any assignment or other transfer by Buyer or its successors and assigns of any of the Assets shall not relieve Buyer or its successors or assigns of any of their obligations (including indemnity obligations) hereunder, as to the Assets so assigned or transferred.

Section 14.3.Publicity. Except as otherwise set forth in this Section 14.3, Seller and Buyer shall consult with each other with regard to all press releases or other public or private announcements issued or made prior to the Closing concerning this Agreement or the transactions contemplated herein, and, except as the disclosing party may reasonably consider necessary in order to satisfy its or its Affiliates’ obligations under Laws or the applicable rules and regulations of any Governmental Authority or stock exchange, neither Buyer nor Seller shall issue any such press release prior to the Closing, without the prior written consent of the other party, which shall not be unreasonably withheld; provided that a party shall have no obligation under this Section 14.3 with respect to information the substance of which has previously been publicly disclosed by a party other than themselves in breach of this Agreement and providedfurther that any information concerning this Agreement or the transactions contemplated herein once in the public domain may be discussed with the media, in investor presentations and conference calls, one on ones and other investor related activities without the consent of the other party.

Section 14.4.Notices. All notices and communications required or permitted to be given hereunder shall be in writing and shall be (a) delivered personally, (b) sent by bonded overnight courier, (c) mailed by U.S. Express Mail or by certified or registered United States Mail with all postage fully prepaid or (d) by delivery of a PDF copy by electronic mail, read receipt requested, in each case addressed to the appropriate party at the address for such party shown below or at such other address as such party shall have theretofore designated by written notice delivered to the party giving such notice:

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If to Seller:

Carrizo Oil & Gas, Inc.
Carrizo (Eagle Ford) LLC
500 Dallas, Suite 2300Houston, TX 77002
Attention: Andrew R. Agosto
Email: Andy.Agosto@carrizo.com

With a copy to:

Carrizo Oil & Gas, Inc.
Carrizo (Eagle Ford) LLC
500 Dallas, Suite 2300
Houston, TX 77002
Attention: Law Department
Email: Marcus.Bolinder@carrizo.com

If to Buyer:

EP Energy E&P Company, L.P.
P.O. Box 4660
Houston, TX 77210-4660
Attention: Jace Dalton Locke
Email: Jace.Locke@epenergy.com

Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier during normal business hours, or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or deposited in the United States Mail, or upon written confirmation of receipt if given by electronic mail, as the case may be. The parties hereto may change the address, telephone numbers, and email addresses to which such communications are to be addressed by giving written notice to the other parties in the manner provided in this Section 14.4.

Section 14.5.Removal of Name. As promptly as practicable, but in any case within 30 days after the Closing Date, Buyer shall eliminate the name “Carrizo” and “Carrizo Eagle Ford” and any variants thereof from the Assets acquired pursuant to this Agreement and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Seller or any of its Affiliates.

Section 14.6.Further Cooperation. After the Closing, Buyer and Seller shall execute and deliver, or shall cause to be executed and delivered from time to time, such further instruments of conveyance and transfer, and shall take such other actions as any party may reasonably request to convey and deliver the Assets to Buyer, to perfect Buyer’s title thereto and to accomplish the orderly transfer of the Assets to Buyer in the manner contemplated by this Agreement. If any party hereto receives monies belonging to the other, such amount shall immediately be paid over

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to the proper party. If an invoice or other evidence of an obligation is received by a party, which is partially an obligation of both Seller and Buyer, then the parties shall consult with each other, and each shall promptly pay its portion of such obligation to the obligee. At Seller’s sole cost and expense, Buyer agrees to use commercially reasonable efforts to cooperate with Seller in connection with Seller’s defense and other actions relating to or arising out of the litigation and claims that are Retained Obligations, including upon reasonable request by making its and its Affiliates’ employees engaged in the operation of the Assets available during normal business hours and upon reasonable notice for the purposes of providing testimony, depositions, information and other related activities relating to such litigation and claims. At Buyer’s sole cost and expense, Seller agrees to use commercially reasonable efforts to cooperate with Buyer in connection with Buyer’s defense and other actions relating to or arising out of any litigation and claims that are Assumed Obligations, including upon reasonable request by making its and its Affiliates’ employees that were engaged in the operation of the Assets prior to Closing available during normal business hours and upon reasonable notice for the purposes of providing testimony, depositions, information and other related activities relating to such litigation and claims.

Section 14.7.Filings and Certain Governmental Approvals. Promptly after Closing Buyer shall (a) record the Assignments of the Assets executed at the Closing in all applicable real property records and (b) actively pursue the approval of all applicable Governmental Authorities of the assignment of the Assets to Buyer and the designation of Buyer as the operator thereof, as applicable. Buyer shall be solely responsible for all filing fees associated therewith.

Section 14.8.Entire Agreement. This Agreement, the exhibits and schedules hereto, the Assignments, Assignment and Assumption, the Transaction Documents, and, only until Closing, the Confidentiality Agreement, collectively constitute the entire Agreement among Seller and Buyer pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the parties pertaining to the subject matter hereof.

Section 14.9.Parties in Interest. The terms and provisions of this Agreement shall be binding upon and inure to the benefit of Seller and Buyer and their respective legal representatives, successors and assigns. Except as expressly set forth in Section 12.2 or Section 12.3 (which rights must be enforced, if at all, by the applicable party to this Agreement), no other person shall have any right, benefit, priority, or interest hereunder or as a result hereof or have standing to require satisfaction of the provisions hereof in accordance with their terms.

Section 14.10.Amendment. This Agreement may be amended only by an instrument in writing executed by both parties.

Section 14.11.Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the party hereto waiving compliance. No course of dealing on the part of Seller or Buyer, or their respective officers, employees, agents or representatives, nor any failure by Seller or Buyer to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such party at a later time to enforce the performance of such provision. No waiver by any party of any condition, or any breach of any term, covenant,

55

representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation or warranty. The rights of Seller and Buyer under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

Section 14.12.Governing Law; Dispute Resolution.

(a)This Agreement and the legal relations among the parties shall be governed and construed in accordance with the laws of the State of Texas, excluding any conflicts of law rule or principle that might refer construction of such provisions to the laws of another jurisdiction.

(b)Any controversy, dispute or claim arising out of or relating to this Agreement or the Transaction Documents, or the transactions contemplated thereby (a “Dispute”) shall be resolved in accordance with this Section 14.12. Any party may give the other party written notice (a “Dispute Notice”) of any Dispute which has not been resolved in the normal course of business. Within 15 business days after delivery of the Dispute Notice, the receiving party shall submit to the other party a written response (the “Response”). The Dispute Notice and the Response shall each include (i) a statement setting forth the position of the party giving such notice, a summary of the arguments supporting such position and, if applicable, the relief sought and (ii) the name and title of a senior manager of such party who has authority to settle the Dispute and will be responsible for the negotiations related to the settlement of the Dispute (the “Senior Manager”).

(c)Within 10 days after the delivery of the Response provided for in Section 14.12(b), the Senior Managers of both parties shall meet or communicate by telephone at a mutually acceptable time and place, and thereafter as often as they reasonably deem necessary, and shall negotiate in good faith to attempt to resolve the Dispute that is the subject of such Dispute Notice. It is agreed between the parties that the content of any communications pursuant to this Section 14.12(c) will be and shall remain confidential. The parties, on behalf of themselves and their attorneys, hereby agree that they will not in any way reveal the content or terms of any such communications to any person, firm, corporation, or entity, with the exception that the disclosure shall not be a violation of this Section 14.12(c) where the same is required by Law or court Order, or any agency or authority having jurisdiction to require disclosure; provided, however, that the parties may disclose the content or terms of such communications to their attorneys, accountants, trustees, financial advisors or their tax related consultants, as may be necessary in their business affairs. If such Dispute has not been resolved within 30 days after delivery of the Dispute Notice, then the parties may proceed to arbitration pursuant to Section 14.12(d).

(d)Except as specifically otherwise provided in this Agreement, the parties agree that any and all Disputes arising from or related to this Agreement that cannot be amicably settled pursuant to Section 14.12(c) shall be determined solely and exclusively by arbitration in accordance with the Federal Arbitration Act and using the rules of the American Arbitration Association or any successor thereof when not in conflict with such act. Arbitration shall take place at an appointed time and place in Houston, Texas. Each party shall select one impartial arbitrator, and the two so designated shall select a third impartial arbitrator. If either party shall fail to designate an arbitrator within 14 days after arbitration is requested, or if the two arbitrators shall fail to select a third

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arbitrator within 30 days after arbitration is requested, then an arbitrator shall be selected by the Senior U.S. District Judge for the Southern District of Texas. Discovery shall be made pursuant to the Federal Rules of Civil Procedure and completed within 45 days of selection of the third arbitrator. Final hearing on the matter shall be had within 60 days of the selection of the third arbitrator and a final decision (which may include the award of reasonable attorney’s fees and costs) with a written opinion stating the reasons therefor shall be rendered within 75 days of said date and be final and binding, and the parties also waive irrevocably their right to any form of appeal, review or recourse to any state court or other judicial authority, insofar as such waiver may be validly made. Judgment upon an award of the majority of the arbitrators shall be binding. Judgment on the award may be entered and enforced by any court of competent jurisdiction. In no event may the arbitrators award damages that have been waived by the parties under Section 12.10. The arbitration process shall be kept confidential, and such conduct, statements, promises, offers, views and opinions shall not be discoverable or admissible in any legal proceeding for any purpose, except to the extent reasonably necessary to enforce the final decision of the arbitrators.

Section 14.13.Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect. Upon the determination that any term or provision is invalid, illegal or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

Section 14.14.Counterparts. This Agreement may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a party by electronic transmission shall be deemed an original signature hereto.

[THE NEXT SUCCEEDING PAGES ARE THE EXECUTION PAGES]

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IN WITNESS WHEREOF, Seller, Buyer and, for the limited purpose set forth herein, Buyer Parent have executed this Agreement on the date first above written.

SELLER:

CARRIZO OIL & GAS, INC.

By:    /s/ Andrew R. Agosto            Name:    Andrew R. Agosto
Title:    Vice President of Business Development

CARRIZO (EAGLE FORD) LLC

By:    /s/ Andrew R. Agosto            Name:    Andrew R. Agosto
Title:    Vice President of Business Development

Signature Page to Purchase and Sale Agreement

BUYER:

EP ENERGY E&P COMPANY, L.P.

By:    EP Energy Management, L.L.C.,

its general partner

By:    /s/ Kyle McCuen            Name:    Kyle McCuen
Title:    Interim Chief Financial Officer

Signature Page to Purchase and Sale Agreement

Appendix 1

Definitions

“Accounting Arbitrator” shall have the meaning set forth in Section 3.5.

“Additional Consideration” shall have the meaning set forth in Section 6.8.

“Adjusted Purchase Price” shall have the meaning set forth in Section 3.2.

“AFEs” shall have the meaning set forth in Section 4.12.

“Affiliate” shall mean any Person that, directly or indirectly, through one or more intermediaries, controls or is controlled by, or is under common control with, another Person. The term “control” and its derivatives with respect to any Person means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

“Aggregate Deductible” shall mean two percent (2%) of the Purchase Price.

“Agreement” shall have the meaning set forth in the preamble to this Agreement.

“Allocated Value,” with respect to any Asset, shall have the meaning set forth in Section 3.7.

“Applicable Contracts” shall mean all Contracts by which the Properties and other Assets are bound or that relate to the Properties or other Assets and (in each case) that will be binding on the Assets or Buyer after the Closing, including surface use agreements; farmin and farmout agreements; bottomhole agreements; crude oil, condensate and natural gas purchase and sale, gathering, transportation and marketing agreements; hydrocarbon storage agreements; acreage contribution agreements; operating agreements; balancing agreements; pooling declarations or agreements; unitization agreements; processing agreements; saltwater disposal agreements; water use and withdrawal agreements; facilities or equipment leases; crossing agreements; letters of no objection; production handling agreements; frac pond agreements; and other similar contracts and agreements, except for any master service agreements.

“Asset Taxes” shall mean ad valorem, property, excise, severance, production, sales, use, and similar Taxes based upon the operation or ownership of the Assets or the production of Hydrocarbons or receipt of proceeds therefrom, but excluding, for the avoidance of doubt, Income Taxes and Transfer Taxes.

“Assets” shall have the meaning set forth in Section 2.1.

“Assignment” shall mean the Assignment and Bill of Sale from Seller to Buyer, pertaining to certain of the Assets, substantially in the form attached to this Agreement as Exhibit C.

Appendix 1-1

“Assignment and Assumption” shall mean the Assignment and Assumption from Seller to Buyer, pertaining to certain of the Assets, substantially in the form attached to this Agreement as Exhibit D.

“Assumed Obligations” shall have the meaning set forth in Section 12.1.

“Breaching Party” means a party (a “Subject Party”) who, at the time in question, is in Willful Breach, if (but only if), at such time in question, all conditions precedent to the obligations of the Subject Party to close as set forth in Section 7.1 or Section 7.2, as applicable, (a) have been satisfied (or waived in writing by the Subject Party) other than those conditions that can only be satisfied at the Closing, but subject to the other party being ready, willing and able to satisfy such conditions at such time in question or (b) would have been fulfilled or satisfied except solely due to the Willful Breach by the Subject Party.

“Buyer” shall have the meaning set forth in the preamble to this Agreement.

“Buyer Indemnified Parties” shall have the meaning set forth in Section 12.2.

“Buyer Operated Properties” shall mean Properties operated by Buyer or its Affiliate.

“Buyer’s Representatives” shall have the meaning set forth in Section 9.1(a).

“Carrizo” shall have the meaning set forth in the preamble to this Agreement.

“Carrizo Eagle Ford” shall have the meaning set forth in the preamble to this Agreement.

“Casualty Loss” means any loss, damage or reduction in value of the Assets that occurs during the period between the Execution Date and Closing as a result of acts of God, fire, explosion, earthquake, windstorm or flood, but excluding any loss, damage or reduction in value as a result of depreciation, ordinary wear and tear and any change in condition of the Assets for production of Hydrocarbons through normal depletion (including the watering-out of any well, collapsed casing or sand infiltration of any well).

“Claim” shall have the meaning set forth in Section 12.7(b).

“Claim Notice” shall have the meaning set forth in Section 12.7(b).

“Closing” shall have the meaning set forth in Section 8.1.

“Closing Date” shall have the meaning set forth in Section 8.1.

“Code” shall mean the Internal Revenue Code of 1986, as amended.

“Confidentiality Agreement” shall mean that certain Confidentiality Agreement by and between Carrizo and Buyerdated as of November 2, 2017.

Appendix 1-2

“Contract” shall mean any written or oral contract, agreement, agreement regarding indebtedness, indenture, debenture, note, bond, loan, lease, mortgage, franchise, license agreement, purchase order, binding bid, commitment, letter of credit or any other legally binding arrangement, in each case together with all amendments, supplements and modifications thereto or thereof, excluding, however, any Lease, contract or agreement relating to Seismic Data and Information, or instrument creating or evidencing an interest in the Assets.

“Cure Period” shall have the meaning set forth in Section 10.2(b).

“Customary Post-Closing Consents” shall mean the consents and approvals from Governmental Authorities for the assignment of the Assets to Buyer, that are customarily obtained after the assignment of properties similar to the Assets.

“Deed” shall mean the Deed from Seller to Buyer, pertaining to certain of the Fee Interests, substantially in the form attached to this Agreement as Exhibit E.

“Defensible Title” shall mean, with respect to a given Property, ownership of record that is deducible from the applicable county, state and federal records so as to be sufficient against claims of bona fide purchasers for value without notice or other persons entitled to protection of applicable recording laws, and that, subject to and except for Permitted Encumbrances:

(a)with respect to each Well and/or Undeveloped Well listed on Schedule 3.8, entitles Seller to receive not less than the Net Revenue Interest with respect to the Target Formation shown for such Well and/or Undeveloped Well in Schedule 3.8 throughout the duration of the productive life of such Well and/or Undeveloped Well with respect to the Target Formation, except (i) for decreases in connection with those operations in which Seller may from and after the date of this Agreement be a non-consenting co-owner if permitted by the terms of this Agreement, (ii) for decreases resulting from the establishment or amendment from and after the date of this Agreement of pools or units if consented to by Buyer, (iii) for decreases required to allow other working interest owners to make up past underproduction or pipelines to make up past under deliveries, to the extent such underproduction or under deliveries are set forth on Schedule 4.11, and (iv) as otherwise expressly set forth in Schedule 3.8;

(b)with respect to each Well and/or Undeveloped Well listed on Schedule 3.8 obligates Seller to bear not more than the Working Interest with respect to the Target Formation shown in Schedule 3.8 for such Well and/or Undeveloped Well, unless any defect relating to such increase is accompanied by a proportionate increase in the Net Revenue Interest with respect to the Target Formation for such Well and/or Undeveloped Well; and

(c)is free and clear of all Encumbrances (except for the Permitted Encumbrances).

“Deposit” shall have the meaning set forth in Section 3.1(b).

“Dispute” shall have the meaning set forth in Section 14.12(b).

Appendix 1-3

“Dispute Notice” shall have the meaning set forth in Section 14.12(b).

“DTPA” shall have the meaning set forth in Section 12.12(a).

“Easements” shall have the meaning set forth in Section 2.1(f).

“Effective Time” shall mean 12:01 a.m. (Mountain Time) on October 1, 2017.

“Encumbrance” shall mean any lien, security interest, pledge, charge or similar encumbrance.

“Environmental Arbitrator” shall have the meaning set forth in Section 11.1(g).

“Environmental Claim Date” shall mean January 18, 2018.

“Environmental Condition” shall mean (a) a condition in, on, under or migrating from an Asset (excluding any Buyer Operated Property) (including the air, soil, subsurface, surface waters, ground waters and sediments) that causes such Asset (excluding any Buyer Operated Property) (or Seller with respect to such Asset) not to be in compliance with any Environmental Law or to be subject to Liability for Remediation under Environmental Laws with respect to such condition, (b) the existence with respect to an Asset (other than a Buyer Operated Property) or their operation of any environmental pollution, contamination, degradation, damage or injury for which remedial or corrective action is presently required (or if known, would be presently required) under Environmental Laws or (c) the failure of an Asset (other than a Buyer Operated Property) to be in compliance with any operational or permitting requirements imposed under Environmental Laws applicable to such Asset.

“Environmental Condition Cure Period” shall have the meaning set forth in Section 11.1(a).

“Environmental Condition Notice” shall have the meaning set forth in Section 11.1(a).

“Environmental Laws” shall mean all applicable federal, state and local laws, including common law, relating to the protection of the public health, welfare and the environment, including those laws relating to the storage, handling and use of chemicals and other Hazardous Substances, and those relating to the generation, processing, treatment, storage, transportation, disposal or other management thereof. The term “Environmental Laws” does not include good or desirable operating practices or standards that may be employed or adopted by other oil and gas well operators or recommended by a Governmental Authority that exceed the requirements of Environmental Laws.

“Excluded Assets” shall mean (a) all of Seller’s corporate minute books, financial and tax records and other business records that relate to Seller’s business generally other than those to the extent directly related to the ownership and operation of the Assets and Seller’s accounting records (other than Operating Data); (b) all trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to the Assets with respect to any period of time prior to the Effective Time, except to the extent relating to an Assumed Obligation; (c) all claims and causes of action of Seller arising under or with respect to any Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds), except to the extent relating to an

Appendix 1-4

Assumed Obligation; (d) all rights and interests of Seller (A) under any policy or agreement of insurance or indemnity, (B) under any bond or (C) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property prior to the Effective Time, in each case, except to the extent relating to an Assumed Obligation; (e) proceeds of all Hydrocarbons produced and sold from the Properties with respect to all periods prior to the Effective Time, except as described in Section 3.2(a)(iv); (f) all claims of Seller for refunds of or loss carry forwards with respect to (A) Seller Taxes for which Seller is responsible pursuant to Section 14.1(b), (B) Income Taxes or (C) any Taxes attributable to the Excluded Assets; (g) all of Seller’s proprietary computer software, patents, trade secrets, copyrights, names, trademarks and logos and all other intellectual property of any kind; (h) all documents and instruments of Seller that are protected by an attorney-client privilege or that are work product of Seller’s counsel (other than title opinions); (i) all data that cannot be disclosed to Buyer as a result of confidentiality arrangements under agreements with Third Parties; provided that (except with respect to all Seismic Data and Information) Seller shall use its commercially reasonable efforts to obtain a waiver of such restrictions in order to permit disclosure to Buyer; (j) all Seismic Data and Information relating to the Assets that requires Third Party consent for transfer to Buyer if such consent is not obtained or obtainable without the payment of any funds that have not been paid by Buyer, and all such Contracts relating to Seismic Data and Information as are set forth on Schedule 1; (k) all proprietary geologic and geophysical interpretations of Seismic Data and Information unless Buyer has a valid license to use such Seismic Data and Information and can provide evidence to Seller that the owner of such software and data has consented to Seller providing a non-exclusive copy of such Seismic Data and Information, including maps, seismic picks and interpretations; (l) maps, engineering data and reports, including lease maps, except to the extent such maps do not contain licensed information or information derived from licensed information for which Buyer does not have a license to use; (m) all audit rights arising under any of the Applicable Contracts or otherwise with respect to any period prior to the Effective Time or to any of the Excluded Assets, except for any Imbalances and except to the extent relating to an Assumed Obligation; (n) all other rights and obligations arising under the Applicable Contracts prior to the Effective Time (except to the extent relating to an Assumed Obligation); (o) documents prepared or received by Seller with respect to (A) lists of prospective purchasers for transactions compiled by Seller, (B) bids submitted by other prospective purchasers of the Assets, (C) analyses by Seller of any bids submitted by any prospective purchaser, (D) correspondence between or among Seller, its representatives and any prospective purchaser and (E) correspondence between Seller or any of its representatives with respect to any of the bids, the prospective purchasers or the transactions contemplated in this Agreement; (p) any offices, office leases or personal property not directly related to any one or more of the Assets (for example, trucks and computers); (q) all reserve estimates and economic estimates; (r) any Assets that are retained by Seller pursuant to Section 10.2(c), Section 10.3(b), Section 10.4 or Section 11.1(b); (s) copies of any of the foregoing that are retained by Seller; (t) copies (but not the originals) of any log books and other Operating Data; (u) any Assets which are excluded from the transaction contemplated by this Agreement by virtue of any provisions hereof; (v) Seller’s bonds, permits and licenses or other permits, licenses or authorizations; (w) all production, proceeds, income, receipts and credits to which Seller is entitled under Section 2.3, except to the extent relating to an Assumed Obligation; (x) originals of all Records that are not related to the Assets (subject to Buyer’s right to obtain a copy of such Records at its sole cost and expense; provided, however, that Buyer shall have no right to receive copies of (i) Tax Records

Appendix 1-5

unless such Tax Records are solely related to the Assets or (ii) any Records that are otherwise excluded herein); and (y) all assets set forth in Schedule 1.

“Execution Date” shall have the meaning set forth in the preamble to this Agreement.

“Final Price” shall have the meaning set forth in Section 3.5.

“Final Settlement Statement” shall have the meaning set forth in Section 3.5.

“Fundamental Representations” shall mean the representations and warranties set forth in Section 4.1, Section 4.2, Section 4.3(a), Section 4.3(b) (but excluding with respect to Leases, operating agreements or other contracts of a type not expressly listed), Section 4.5, Section 4.19, Section 5.1, Section 5.2, Section 5.3(a), Section 5.5 and Section 5.9.

“Gail” shall mean Gail Global (USA) Inc., a Texas corporation.

“Governmental Authority” shall mean any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, regulatory or taxing authority or power and any court or governmental tribunal, including any tribal authority having or asserting jurisdiction.

“Governmental Requirements” shall mean at any time (i) any Law, judgment, decree, injunction, writ, edict, award, authorization or other requirement of any Governmental Authority in effect at that time or (ii) any obligation included in any certificate, certification, franchise, permit or license issued by any Governmental Authority or resulting from binding arbitration, including any requirement under common law, at that time.

“Hazardous Substances” shall mean any pollutants, contaminants, toxic, hazardous or extremely hazardous substances, materials, wastes, constituents, compounds or chemicals including Hydrocarbons that are regulated by, or may form the basis of liability under, any Environmental Laws, including NORM and other substances referenced in Section 11.2.

“Hydrocarbons” shall mean oil and gas and other hydrocarbons produced or processed in association therewith.

“Imbalances” shall mean (a) any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well and allocable to the interests of Seller therein and the shares of production from the relevant Well to which Seller is entitled and (b) any marketing imbalance between the quantity of Hydrocarbons required to be delivered by Seller under any Contract relating to the purchase and sale, gathering, transportation, storage, processing or marketing of Hydrocarbons and the quantity of Hydrocarbons actually delivered by Seller pursuant to the relevant Contract, together with any appurtenant rights and obligations concerning future in-kind or cash balancing at the wellhead and production balancing at the delivery point into the relevant sale, gathering, transportation, storage or processing facility.

“Income Taxes shall mean any income, capital gains, franchise and similar Taxes.

Appendix 1-6

“Indemnified Party” shall have the meaning set forth in Section 12.7(a).

“Indemnifying Party” shall have the meaning set forth in Section 12.7(a).

“Individual Environmental Threshold” shall have the meaning set forth in Section 11.1(f).

“Individual Title Benefit Threshold” shall mean $75,000.

“Individual Title Defect Threshold” shall have the meaning set forth in Section 10.2(f).

“Interim Period” shall mean that period of time commencing at the Effective Time and ending at 12:01 a.m. (Central Time) on the Closing Date.

“Knowledge” or “knowledge” shall mean (a) with respect to Seller, the actual knowledge, without any obligation of inquiry or investigation, of any of the following Persons: Brad Fisher, Andrew R. Agosto, Rex Bigler, Scott Hudson, Jack Bayless, Max Seewann, and/or Richard Smith; and (b) with respect to Buyer, the actual knowledge, without any obligation of inquiry or investigation, of any of the following Persons: Gustavo Zapata, Peter Addison, Glenn Harper, Ray Ambrose, Chad Yelverton, Frank Olmstead, Chad England, and/or Lauren Sims.

“Lands” shall have the meaning set forth in Section 2.1(a).

“Law” shall mean any applicable statute, law, rule, regulation, ordinance, Order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Authority.

“Leases” shall have the meaning set forth in Section 2.1(a).

“Liabilities” shall mean any and all claims, causes of actions, proceedings, payments, charges, judgments, assessments, liabilities, losses, damages, penalties, fines, costs and expenses, including any attorneys’ fees, legal or other expenses incurred in connection therewith and including liabilities, costs, losses and damages for personal injury, death or property damage.

“Like-Kind Exchange” shall have the meaning set forth in Section 6.6.

“Material Adverse Effect” shall mean an event, effect or circumstance that, individually or in the aggregate, does or would reasonably be expected to have a material adverse effect on (a) the ownership, operations or condition of the Assets, taken as a whole, or (b) the ability of Seller to consummate the transactions contemplated by this Agreement; provided, however, that, for the purpose of clause (a) hereof, none of the following effects, events or circumstances relating to or resulting from the following shall be deemed to constitute a Material Adverse Effect: (i) changes in generally applicable market, economic, financial or political conditions (including changes in fuel supply or transportation markets, credit and equity markets, interest or rates) in Texas, the United States or worldwide, or any outbreak of hostilities, war or terrorist acts; (ii) changes in the prices of Hydrocarbons; (iii) acts or failures to act of Governmental Authorities or a change in Laws (or interpretations thereof) from and after the Execution Date to the extent not caused in whole or in part by Seller or any Affiliate thereof; (iv) changes generally applicable to the oil and gas industry or to the sector of the industry as to which the Assets relate, (v) entering into this Agreement or the

Appendix 1-7

announcement or proposed consummation of the transactions contemplated herein; (vi) acts of God, including storms, drought or meteorological events; (vii) reclassification or recalculation of reserves in the ordinary course of business; or (viii) declines in well performance due to natural causes; provided that subsections (i), (iii), (vi), and (viii) shall be taken into account in determining whether a Material Adverse Effect has occurred if such events or circumstances disproportionately affect the Assets.

“Material Contract” shall have the meaning set forth in Section 4.7.

“Net Revenue Interest” with respect to any Well and/or Undeveloped Well, shall mean the interest in and to all Hydrocarbons produced, saved, and sold from or allocated to such Well and/or Undeveloped Well, after giving effect to all Royalties.

“NORM” shall mean naturally occurring radioactive material.

“Operating Data” shall mean operations, environmental and production data, including division of interest decks, joint interest billings, payout statements, plant statements, lease operating statements and receipts or other records kept with respect to payment of invoices.

“Operating Expenses” shall have the meaning set forth in Section 2.3(a).

“Order” shall mean any award, decision, injunction, judgment, order, ruling, subpoena or verdict entered, issued, made or rendered by any court, administrative agency or other Governmental Authority or by any arbitrator.

“Permits” shall mean all environmental and other governmental (whether federal, state, local or tribal) certificates, consents, permits (including conditional use permits), licenses, Orders, authorizations, franchises and related instruments or rights granted by any Governmental Authority solely relating to the ownership, operation or use of the Assets.

“Permitted Encumbrances” shall have the meaning set forth on Appendix 2.

“Person” shall mean any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Authority or any other entity.

“Personal Property” shall have the meaning set forth in Section 2.1(g).

“Post-Closing Deductible” shall mean 2% of the Purchase Price.

“Post-Closing Threshold” shall mean $75,000.

“PPA” shall mean that certain Purchase and Participation Agreement dated September 28, 2011, by and among Seller and Gail, including the Exhibits thereto.

“Preferential Right to Purchase” shall mean any Third Party’s preferential right to purchase any of the Assets or any interest in any Asset or any portion of any Asset.

Appendix 1-8

“Preliminary Settlement Statement” shall have the meaning set forth in Section 3.4.

“Properties” shall have the meaning set forth in Section 2.1(c).

“Purchase Price” shall have the meaning set forth in Section 3.1.

“Records” shall have the meaning set forth in Section 2.1(j).

“Remediation” shall mean, with respect to an Environmental Condition, the implementation and completion of any and all investigatory, cleanup, monitoring, remedial, removal, response, construction, closure, disposal, treatment, containment, mitigation or other corrective actions required under Environmental Laws in effect on the Closing Date conducted after the identification of an Environmental Condition pursuant to Section 11.1 and to correct or remove such Environmental Condition to a degree sufficient to meet the requirements of Section 11.1.

“Remediation Amount” shall mean, with respect to an Environmental Condition, the cost (net to Seller’s interest) of the Remediation of such Environmental Condition, so as to allow all affected Assets to comply with Environmental Laws as such Assets are currently being used, by methods of Remediation that are consistent with customary industry practices in the State of Texas.

“Required Consents” shall mean any consent required from any person to the assignment of any Asset or otherwise in connection with the transactions contemplated by this Agreement (a) that are set forth on Schedule 4.4(a) or (b) that, if not obtained or waived (i) would cause the relevant Lease or other Asset (or Seller’s interest therein) to terminate or the assignment of such Lease or other Asset to Buyer hereunder to be void pursuant to the express terms of such Lease or other Asset; or (ii) regardless of whether such consent or waiver may be unreasonably withheld, delayed, or conditioned, would constitute breach of, or default under, such Lease which breach, with the passage of time, the giving of notice, or both, would give rise to the ability of a Third Person to terminate such Lease or other instrument pursuant to the express terms thereof; provided, that subsection (b)(ii) above shall only apply with respect to Leases or Fee Interests where Seller’s interest is greater than one hundred net mineral acres, with “net mineral acre” in such context meaning the gross number of acres covered by, or included in, such Lease or Fee Interest multiplied by the undivided portion of the oil, gas, or other minerals underlying such lands covered by such Lease or Fee Interest (provided that, if such Lease or Fee Interest includes different interests in the oil, gas, or minerals underlying different geographic areas covered by such Lease or Fee Interest, a different calculation shall be made for each such area) multiplied by Seller’s Working Interest in such Lease or Fee Interest.

“Response” shall have the meaning set forth in Section 14.12(b).

“Retained Obligations” shall have the meaning set forth in Section 12.2(c).

“Royalties” shall mean royalties, overriding royalties, production payments, carried interests, net profits interests, reversionary interests and other burdens upon, measured by or payable out of production therefrom.

Appendix 1-9

“Securities Act” shall mean the Securities Act of 1933, as amended.

“Seismic Data and Information” shall have the meaning set forth in Section 2.1(i).

“Seller” shall have the meaning set forth in the preamble to this Agreement.

“Seller Indemnified Parties” shall have the meaning set forth in Section 12.3.

“Seller Operated Properties” shall mean Properties operated by Seller (or its Affiliate) as of the Execution Date.

“Seller Taxes” shall mean, without duplication, (a) all Income Taxes imposed by any applicable laws on Seller, (b) Asset Taxes allocable to Seller pursuant to Section 14.1(b), (c) any Taxes imposed on or with respect to the ownership or operation of the Excluded Assets and (d) any and all Taxes (other than as provided in clauses (a), (b) or (c) of this definition) imposed on or with respect to the ownership or operation of the Assets or the production of Hydrocarbons or the receipts of proceeds therefrom for any Tax period (or portion thereof) ending before the Effective Time; provided, however, that Seller Taxes shall not include any such Taxes for which a Purchase Price adjustment is made pursuant to Section 3.2.

“Senior Manager” shall have the meaning set forth in Section 14.12(b).

“Settlement Statement Dispute Notice” shall have the meaning set forth in Section 3.5.

“Soft Consent” shall mean the consents of lessors under any Lease that specifies that the lessor’s consent will not be unreasonably withheld (or words of a similar import), and which lessors’ consents are set forth on Schedule 4.4(b), provided, however, that the term “Soft Consent” shall not include any consent or other requirement included in the definition of Required Consent.

“SOP Retained Operating Expenses” shall mean Operating Expenses attributable to the Properties other than the Buyer Operated Properties for the period of time prior to the Effective Time.

“Specified Seller Indemnity Obligations” shall have the meaning set forth in Section 12.4(a).

“Target Formation” shall mean the stratigraphic equivalent of that geologic formation found in the Mumme 1H Pilot Well, API # 42-283-3281 located in LaSalle County, Texas, as seen on “Array Induction – Gamma Ray Compensated Neutron/Lithodensity Platform Express 150” log with a top at 9763’ MD and a base at 9892’ MD, recognizing that the depth of such formation will vary across the area in which the Properties are located.

“Tax Allocations” shall have the meaning set forth in Section 3.7.

“Tax Partnership” shall mean the tax partnership created pursuant to the PPA between Seller and Gail.

Appendix 1-10

“Tax Return” shall mean any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto and any amendment thereof.

“Taxes” shall mean any taxes, assessments, fees and governmental charges imposed by any Governmental Authority, including without limitation income, profits, franchise, withholding, employment, social security, disability, occupation, ad valorem, property, severance, production, gross receipts, net proceeds, alternative or add-on minimum, environmental, stamp, leasing, user, duty, transfer, registration, social security, unemployment, disability, payroll, employment, fuel, excess profit, occupational, and excise taxes, together with any interest, penalties or additions thereto.

“Third Party” shall mean any Person other than a party to this Agreement or an Affiliate of a party to this Agreement.

“Title Arbitrator” shall have the meaning set forth in Section 10.2(h).

“Title Benefit” shall mean any right, circumstance or condition that entitles Seller to a larger Net Revenue Interest with respect to the Target Formation or a smaller Working Interest with respect to the Target Formation (without a decrease in the Net Revenue Interest with respect to the Target Formation that is either proportionate or proportionately greater than such decrease in the Working Interest with respect to the Target Formation) than that shown on Schedule 3.8.

“Title Benefit Amount” shall mean:

(i)if Seller and Buyer agree on the Title Benefit Amount, then that amount will be the Title Benefit Amount;

(ii)if the Title Benefit represents a discrepancy between (A) the Net Revenue Interest with respect to the Target Formation for any Title Benefit Property and (B) the Net Revenue Interest with respect to the Target Formation described in Schedule 3.8 for such Title Benefit Property, and such discrepancy is not accompanied by a greater than proportionate increase in Working Interest then the Title Benefit Amount will be the product of the Allocated Value of the affected Title Benefit Property multiplied by a fraction, the numerator of which is the Net Revenue Interest increase for such Title Benefit Property and the denominator of which is the Net Revenue Interest with respect to the Target Formation of such Title Benefit Property described in Schedule 3.8 for such Title Benefit Property; provided that if the increased Net Revenue Interest with respect to the Target Formation does not affect the Title Benefit Property throughout the entire life of the Title Benefit Property with respect to the Target Formation, then the Title Benefit Amount will be reduced to take into account the applicable time period only and provided further, that if the Title Benefit is an increase in Working interest or Net Revenue Interest that relates to a before payout calculation with respect to the fifteen Wells listed on Exhibit A-3 (not including the two with an asterisk) having an APO Working Interest or APO Net Revenue Interest that is different from such Wells’ BPO Working Interest or

Appendix 1-11

BPO Net Revenue Interest, as applicable, then the Title Benefit Amount shall only be any Title Benefit in excess of the amounts shown in the BPO Working Interest and/or BPO Net Revenue Interest column, as applicable; and

(iii)if the Title Benefit represents a benefit to title to the Title Benefit Property of a type not described in clause (i) or (ii) above, the Title Benefit Amount will be determined by taking into account the Allocated Value of the Title Benefit Property, the portion of the Title Benefit Property benefited by the Title Benefit, the legal effect of the Title Benefit, the potential economic effect of the Title Benefit over the life of the Title Benefit Property, the values placed upon the Title Benefit by Buyer and Seller and such other factors as are necessary to make a proper evaluation.

“Title Benefit Notice” shall have the meaning set forth in Section 10.2(g).

“Title Benefit Property” shall have the meaning set forth in Section 10.2(g).

“Title Claim Date” shall have the meaning set forth in Section 10.2(a).

“Title Defect” shall mean any Encumbrance (other than a Permitted Encumbrance), defect or other matter that causes Seller not to have Defensible Title in and to a Lease or Fee Interest as of the Closing Date; provided that the items set forth on Appendix 3 shall not be considered Title Defects.

“Title Defect Amount” shall have the meaning set forth in Section 10.2(e).

“Title Defect Notice” shall have the meaning set forth in Section 10.2(a).

“Title Defect Property” shall have the meaning set forth in Section 10.2(a).

“Transaction Documents” shall mean those documents executed pursuant to or in connection with this Agreement.

“Transfer Taxes” shall have the meaning set forth in Section 14.1(b).

“Treasury Regulations” shall mean the regulations promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of succeeding, similar, substitute, proposed or final Treasury Regulations.

“Undeveloped Well” means an undeveloped well location identified as “4PUD” on Schedule 3.8.

“Wells” shall have the meaning set forth in Section 2.1(c).

“Willful Breach” shall mean, with respect to a party, (a) such party’s willful or deliberate act or a willful or deliberate failure to act by such party, which act or failure to act (i) constitutes in

Appendix 1-12

and of itself a breach of any covenant set forth in this Agreement and (ii) which was undertaken with the actual knowledge of such party that such act or failure to act would be, or would reasonably be expected to cause, a material breach of this Agreement or (b) the failure by such party to consummate the transactions contemplated by this Agreement after all conditions to such party’s obligations in Section 7.1 or Section 7.2, as applicable, have been satisfied or waived in accordance with the terms of this Agreement (other than those conditions which by their terms can only be satisfied simultaneously with the Closing but which would be capable of being satisfied at Closing if Closing were to occur).

“Working Interest” with respect to any Well and/or Undeveloped Well, shall mean the interest in and to such Well and/or Undeveloped Well that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such Well and/or Undeveloped Well, but without regard to the effect of any royalties, overriding royalties, production payments, net profits interests and other similar burdens upon, measured by or payable out of production therefrom.

Appendix 1-13

Appendix 2

Permitted Encumbrances

Permitted Encumbrances shall mean:

(a)lessor’s royalties, non-participating royalties, overriding royalties, reversionary interests and similar burdens upon, measured by or payable out of production, if the net cumulative effect of such burdens does not (i) operate to reduce the Net Revenue Interest with respect to the Target Formation of Seller in any Well and/or Undeveloped Well to an amount less than the Net Revenue Interest with respect to the Target Formation set forth on Schedule 3.8 for such Well and/or Undeveloped Well; or (ii) obligate Seller to bear a Working Interest with respect to the Target Formation for such Well and/or Undeveloped Well in any amount greater than the Working Interest with respect to the Target Formation set forth on Schedule 3.8 for such Well and/or Undeveloped Well (unless the Net Revenue Interest with respect to the Target Formation for such Well and/or Undeveloped Well is greater than the Net Revenue Interest with respect to the Target Formation set forth on Schedule 3.8 in the same proportion as any increase in such Working Interest with respect to the Target Formation);

(b)liens for Taxes or assessments not yet due or delinquent or if due that are being contested in good faith in the normal course of business and liens for Taxes on the sale of Hydrocarbons relating to the Assets and payable to owners of working interests, Royalties and other similar interests that, in each case, are held by Seller in suspense as of the Effective Time and do not affect the Working Interest or Net Revenue Interest of Seller in any Property;

(c)Customary Post-Closing Consents and Soft Consents;

(d)Preferential Rights to Purchase as set forth on Schedule 4.9 and Third Party consents as set forth on Schedule 4.4(a), whether or not exercised or unwaived;

(e)such Title Defects as Buyer may have waived in writing;

(f)all rights reserved to or vested in any Governmental Authority (i) to control or regulate any Asset in any manner; and (ii) to enforce any obligations or duties affecting the Assets to any Governmental Authority, with respect to any franchise, grant, license, or permit;

(g)easements, servitudes, permits, rights-of-way, surface leases and other rights in respect of surface operations on the Assets which do not individually or in the aggregate materially impair the use of the Assets as currently owned and operated;

(h)vendor’s, carrier’s, warehousemen’s, repairmen’s, mechanic’s, workmen’s, materialmen’s, contractor’s, construction or other similar liens arising by operation of Law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations which are not yet due or if due that are being contested in good faith in the ordinary course of business;

Appendix 2-1

(i)liens created under Leases or an Applicable Contract or by operation of Law in respect of obligations that are not yet due;

(j)the terms and conditions of this Agreement or any other Transaction Document;

(k)the terms and conditions of any Lease or Contract (including any Applicable Contract) which individually and in the aggregate as of the Closing Date do not (i) reduce the Net Revenue Interest with respect to the Target Formation of Seller in any Well and/or Undeveloped Well to an amount less than the Net Revenue Interest with respect to the Target Formation set forth on Schedule 3.8 for such Well and/or Undeveloped Well; or (ii) obligate Seller to bear a Working Interest with respect to the Target Formation for such Well and/or Undeveloped Well in any amount greater than the Working Interest with respect to the Target Formation set forth on Schedule 3.8 for such Well and/or Undeveloped Well (unless the Net Revenue Interest with respect to the Target Formation for such Well and/or Undeveloped Well is greater than the Net Revenue Interest with respect to the Target Formation set forth on Schedule 3.8 in the same proportion as any increase in such Working Interest with respect to the Target Formation);

(l)the terms and conditions of (i) that certain Lease by and between Burlington Resources Oil & Gas Company, as Lessor, and Carrizo (Eagle Ford) LLC, as Lessee, dated January 10, 2014 (Lease Number TX2088001002-020 on Exhibit A-1) and (ii) that certain Lease by and between Donaldson Brown LaSalle Holdings LP, as Lessor, and Carrizo (Eagle Ford) LLC, as Lessee, dated January 3, 2014 (Lease Number TX2088001002-021 on Exhibit A-1), including any terms and conditions which could increase or decrease the Working Interest and/or the Net Revenue Interest with respect to the Target Formation of Seller in any Well and/or Undeveloped Well to amounts different than the Working Interest and/or the Net Revenue Interest with respect to the Target Formation set forth on Schedule 3.8 for such Well and/or Undeveloped Well;

(m)any Encumbrance affecting the Assets that is discharged by Seller at or prior to Closing;

(n)mortgages and deeds of trust or similar instruments entered into by a lessor or its predecessor under a Lease granting a lien, charge or security interest in and to the lessor’s interests in the lands covered thereby, or in and to the lessor’s interests in the oil and gas or mineral estate associated therewith, but only to the extent that the exercise of rights under any instrument would not terminate the relevant Lease or interest;

(o)rights of reassignment arising upon final intention to abandon or release any of the Assets;

(p)Imbalances set forth on Schedule 4.11;

(q)all other liens, charges, encumbrances, defects or irregularities which do not, individually or in the aggregate, materially detract from the value of or materially interfere with the use or ownership of the Property subject thereto or affected thereby (as currently used or owned), which would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties, and which do not, individually or in the aggregate (i) reduce the

Appendix 2-2

Net Revenue Interest with respect to the Target Formation of Seller in any Property below the Net Revenue Interest with respect to the Target Formation set forth on Schedule 3.8 for such Property; or (ii) increase the Working Interest with respect to the Target Formation of Seller in any Property above the Working Interest with respect to the Target Formation set forth on Schedule 3.8 for such Property without a corresponding increase in Net Revenue Interest with respect to the Target Formation;

(r)rights of a common owner of any interest in rights of way or easements currently held by Seller and such common owner as tenants in common or through common ownership, provided that no such matter could reasonably be expected to materially interfere with the ownership, use, or operation by horizontal pad drilling of any affected Property; and

(s)zoning and planning ordinances and municipal regulations that could not reasonably be expected to materially interfere with the ownership, use, or operation by horizontal pad drilling of any affected Property (including the drilling of any planned well, or portion thereof).

Appendix 2-3

Appendix 3

Illustrative List of Items that are not Title Defects

For the avoidance of doubt, the existence of any of the following with respect to any Asset shall not be a “Title Defect”:

(a)defects in the chain of title or in the applicable Lease or Fee Interest in the same unit covering the applicable Well and/or Undeveloped Well consisting of the failure to recite marital status in a document or omissions of successions of heirship or estate proceedings, unless Buyer provides affirmative evidence that such failure or omission has resulted in another Person’s superior claim of title to the relevant Asset;

(b)defects arising out of lack of survey or lack of metes and bounds descriptions, provided the leased premises are described by other means that would constitute a legally sufficient description of the relevant leased premises as between the parties and their predecessors in interest;

(c)defects arising out of lack of corporate or other entity authorization unless Buyer provides affirmative evidence that such corporate or other entity action was not authorized and such lack of authorization results in another Person’s superior claim to title of the applicable Lease or Fee Interest located in the same unit as the applicable Well and/or Undeveloped Well;

(d)defects based on a gap in Seller’s chain of title in the applicable county records, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain and such gap is less than 75 years old;

(e)the fact that Carrizo Eagle Ford is the beneficial owner and Carrizo is the record owner of certain Properties;

(f)any Encumbrance or loss of title resulting from Seller’s conduct of business after the Effective Time in accordance with this Agreement which has been consented to in advance by Buyer or which is an action taken by Buyer on a Buyer operated Property;

(g)defects arising from any change in applicable Governmental Requirement after the Effective Time, including changes that would raise the minimum landowner royalty;

(h)defect or irregularities resulting from or related to probate proceedings or the lack thereof, which defect or irregularities have been outstanding for seven and a half years or more;

(i)defects arising from prior oil and gas leases relating to the Leases located in the same unit as the applicable Well and/or Undeveloped Well that are terminated, expired or invalid but not surrendered of record, if the date of such Lease is more than 10 years prior to the Execution Date, and, in any case, absent evidence that such lease continues in force and effect;

(j)any Property subject to executed and recorded landowner consents for surface mining on such Property, to the extent the same could not reasonably be expected to materially interfere with or impair the ownership, use, or operation by horizontal pad drilling of the affected Property;

Appendix 3-1

(k)any preferential purchase right attached to a Lease or Fee Interest covering the applicable Well and/or Undeveloped Well that (in connection with the transactions contemplated by this Agreement) either has been waived in writing or for which the time period during which such preferential purchase right must be exercised has expired (without the exercise of such preferential purchase right);

(l)any lessor consent under a Lease covering the applicable Well and/or Undeveloped Well that (in connection with the transactions contemplated by this Agreement) has been granted in writing;

(m)in the case of any wells to be drilled in the future, any permits, easements (other than subsurface easements), rights-of-way, unit designations or production and drilling units or consents to the location or operation of such wells, in each case, not yet required to be obtained, formed or created, in each case, to the extent any such permits, easements, rights-of-way, unit designations or units would be obtained in the ordinary course of business, excluding, however, any matters which would be contrary to applicable Law or contract, for which consent could be withheld by any applicable counterparty or Governmental Authority in its discretion, or which would require an exception or exemption under applicable Law;

(n)any defect that affects only which person has the right to receive royalty payments (rather than the amount of such royalty) and that does not affect the validity of the underlying Lease or Fee Interest that is included in the unit that includes the applicable Well and/or Undeveloped Well; and to the extent the same does not (i) reduce the Net Revenue Interest with respect to the Target Formation of Seller in the applicable Well and/or Undeveloped Well below the Net Revenue Interest with respect to the Target Formation set forth on Schedule 3.8 for such Well and/or Undeveloped Well (unless the Working Interest with respect to the Target Formation for such Well and/or Undeveloped Well is less than the Working Interest with respect to the Target Formation set forth on Schedule 3.8 in the same proportion as any increase in such Net Revenue Interest with respect to the Target Formation); or (ii) obligate Seller to bear a Working Interest with respect to the Target Formation for any Well and/or Undeveloped Well that is greater than the Working Interest with respect to the Target Formation set forth on Schedule 3.8 for such Well and/or Undeveloped Well (unless the Net Revenue Interest with respect to the Target Formation for such Well and/or Undeveloped Well is greater than the Net Revenue Interest with respect to the Target Formation set forth on Schedule 3.8 in the same proportion as any increase in such Working Interest with respect to the Target Formation);

(o)defects based solely on any of the following: (i) lack of information in Seller’s files or similar records (or the absence of such activities or records; (ii) references to an unrecorded document(s) to which neither Seller nor any Affiliate are a party, if such document is dated earlier than January 1, 2000, and is not in Seller’s files; or (iii) Tax assessment, Tax payment or similar records; and

(p)defects pertaining to, or affecting, any formation other than the Target Formation and that do not pertain to, or affect, the Target Formation in any respect.

(q)

Appendix 3-2

CLOSING AGREEMENT AND AMENDMENT TO PURCHASE AND SALE AGREEMENT

This Closing Agreement and Amendment to Purchase and Sale Agreement (this “Amendment”), dated as of January 31, 2018, is made and entered into between Carrizo Oil & Gas, Inc. and Carrizo (Eagle Ford) LLC (collectively, “Seller”) and EP Energy E&P Company, L.P. (“Buyer”). Seller and Buyer are each referred to as a “Party” and collectively referred to as the “Parties.” Capitalized terms used but not defined in this Amendment shall have the meanings given to such terms in the PSA (as hereinafter defined).

WHEREAS, Seller and Buyer have entered into, and desire to amend as set forth below, that certain Purchase and Sale Agreement dated as of December 11, 2017 (as further amended, restated or supplemented from time to time, the “PSA”); and

WHEREAS, the Parties desire to amend certain Exhibits and Schedules to the PSA, as more specifically set forth in this Amendment and agree on certain other matters for the purposes of Closing.

NOW, THEREFORE, in consideration of the Closing of the transaction contemplated under the PSA, the mutual promises and covenants set forth herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1.    Amendments to the PSA. Notwithstanding anything to the contrary in the PSA, the Parties agree that the following amendments to the PSA are made effective as of the Execution Date:

(a)    Exhibit A-1 to the PSA is hereby deleted and replaced in its entirety with Annex 1 attached hereto;

(b)    Exhibit A-3 to the PSA is hereby deleted and replaced in its entirety with Annex 2 attached hereto; and

(c)    Schedule 4.7 to the PSA is hereby deleted and replaced in its entirety with Annex 3 attached hereto.

2.    Pipe Permits. Notwithstanding Section 2.1(f) of the PSA, certain permits relating to pipelines, rights of way, and related assets included in the Assets (the “Affected Pipelines”) may not be transferred to Buyer at Closing. The Parties shall cooperate to cause the transfer of such permits to Buyer (or its Affiliate) or the removal of the Affected Pipelines from Seller’s existing permits and the addition of the Affected Pipelines to Buyer’s permits.

3.    Frio LaSalle Contract. Reference is made to that certain Gas Gathering and Processing Agreement dated April 1, 2014 by and between Frio LaSalle Pipeline, LP and Carrizo (Eagle Ford) LLC (as amended, the “Gathering Agreement”). The Gathering Agreement covers and affects certain of the Assets and certain other properties and assets not included in the Assets

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under the PSA. The Parties shall cooperate reasonably to affect a partial assignment, novation, or similar arrangement with respect to the Gathering Agreement to Buyer such (a) that the Gathering Contract applies separately to the Assets and such other properties and assets and (b) the actions or omissions of one Party shall not affect the other Party with respect to the Gathering Agreement. Without limiting the foregoing, unless and until such partial assignment, novation, or similar arrangement occurs, each Party shall be liable and responsible for performance under the Gathering Agreement only with respect to its assets and properties held by such Party, and, with respect to Seller and its assets and properties that are not included in the Assets and transferred to Buyer under the PSA, the Gathering Agreement shall be considered to be an Excluded Asset. Notwithstanding the foregoing or anything to the contrary in the PSA, Buyer shall be responsible for a proportionate share of the Capital Recovery Fee under Section V.1 of the Gathering Agreement as determined under the final grammatical sentence of Section 2.3(a) of the PSA, not to exceed the amount of any Capital Recovery Fee attributable to throughput at the Carrizo Seigele Delivery Point, as described in Exhibit B of the Gathering Agreement.

4.    Mellenbruch Family Partnership Required Consent. As of the Closing Date, Seller has not obtained the Required Consent identified as TX2069001031-001 MELLENBRUCH FAMILY PARTNERSHIP LP CARRIZO (EAGLE FORD) LLC on Schedule 4.4(a) of the PSA (the “Mellenbruch Consent”), and the Properties (or portions thereof) affected thereby have been excluded from the Assets conveyed to Buyer at Closing. In accordance with Section 10.4(f) of the PSA, the Parties shall use their commercially reasonable efforts to attempt to obtain the Mellenbruch Consent, provided that, notwithstanding anything to the contrary in Section 10.4(f) of the PSA, (i) the period of time after Closing for which the Parties shall attempt to obtain the Mellenbruch Consent shall be ninety (90) days; (ii) if the Mellenbruch Consent is obtained within such period, or if Buyer otherwise so elects in writing, the Parties shall promptly close on the Properties that were excluded at Closing in respect of the Mellenbruch Consent in accordance with Section 10.4(f) of the PSA; (iii) if, after such ninety (90) day period, the Parties have not obtained the Mellenbruch Consent, and party holding such consent right has not affirmatively objected in writing to the assignment with a reasonable basis for such objection, the Parties shall promptly close on the Properties that were excluded at Closing in respect of the Mellenbruch Consent in accordance with Section 10.4(f) of the PSA; and (iv) if, on or before the end of such ninety (90) day period, the party or parties holding such consent right have affirmatively objected in writing to the assignment with a reasonable basis for such objection, and Buyer does not elect to close notwithstanding such objection, the Properties excluded at Closing in respect of the Mellenbruch Consent shall become Excluded Assets in accordance with the terms of the PSA, and the Parties shall enter into an operating agreement substantially in the form of the Maltsberger B Unit operating agreement, naming Seller as operator of such Asset, and such operating agreement shall prohibit the proposal of drilling operations with respect to a well by a non-operator that would, taking into account any non-consents by third parties in such well, hold less than a 25% Working Interest in such well.

5.    Confirmation. Except as otherwise provided herein, the provisions of the PSA shall remain in full force and effect in accordance with their respective terms following the execution of this Amendment.

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6.    Conflicts. If any provision of this Amendment is construed to conflict with any provision of the PSA (except as otherwise expressly provided in this Amendment), the provisions of this Amendment shall be deemed controlling to the extent of that conflict.

7.    Entire Agreement. This Amendment, the PSA, the Appendices, Exhibits and Schedules to the PSA, the Transaction Documents and the Confidentiality Agreement collectively constitute the entire agreement between the Parties pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations, and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof or thereof except as specifically set forth herein or therein.

8.    Choice of Law. This Amendment and any claim, controversy or dispute arising under or related to this Amendment or the transactions contemplated hereby or the rights, duties and relationship of the parties hereto and thereto, shall be governed by and construed and enforced in accordance with the laws of the State of Texas, excluding any conflicts of law, rule or principle that might refer construction of provisions to the Laws of another jurisdiction.

9.    Amendment. This Amendment may be amended, restated, supplemented or otherwise modified only by an instrument in writing executed by all Parties specifically referring to the terms to be amended, restated, supplemented and/or modified and expressly identified as an amendment, restatement, supplement or modification.

10.    Counterparts. This Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile or other electronic transmission shall be deemed an original signature hereto.

[SIGNATURE PAGE FOLLOWS]

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IN WITNESS WHEREOF, the Parties have executed and delivered this Amendment as of the date first written above.

SELLER:

CARRIZO OIL & GAS, INC.

By:    /s/ Andrew R. Agosto            Name:    Andrew R. Agosto
Title:    Vice President of Business Development

CARRIZO (EAGLE FORD) LLC

By:    /s/ Andrew R. Agosto            Name:    Andrew R. Agosto
Title:    Vice President of Business Development

Signature Page to Closing Agreement and Amendment to Purchase and Sale Agreement

BUYER:

EP ENERGY E&P COMPANY, L.P.

By:    EP Energy Management, L.L.C.,

its general partner

By: /s/ Peter D. Addison            

Name: Peter D. Addison

Title: Vice President, Land & Land Administration

Signature Page to Closing Agreement and Amendment to Purchase and Sale Agreement

EX-10.19

Exhibit 10.19

2017 INCENTIVE PLAN
OF
CARRIZO OIL & GAS, INC.

EMPLOYEE RESTRICTED STOCK AWARD AGREEMENT

THIS AGREEMENT (“Agreement”) is effective as of ______ ___, 20__ (the “Grant Date”), by and between Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), and _____________ (the “Grantee”).

The Company has adopted the 2017 Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 16, 2017 (as amended, modified or supplemented from time to time, the “Plan”), by this reference made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the restricted stock provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of Restricted Stock. Subject to the terms and conditions herein, effective as of the Grant Date, the Company hereby awards to the Grantee, pursuant to the Plan, ____ shares of Common Stock of the Company, par value $.01 per share (the “Restricted Stock”). The Company will (i) register the shares of Restricted Stock in a book entry account in the stock register of the Company maintained by the Company’s transfer agent (the “Account”) in the name of the Grantee or (ii) issue to the Grantee stock certificates evidencing the shares of Restricted Stock, which certificates will be registered in the name of the Grantee and will bear an appropriate legend referring to the terms, conditions, and restrictions applicable to the Restricted Stock.

Any certificates issued that evidence the shares of Restricted Stock shall be held in custody by the Company or, if specified by the Committee, by a third party custodian or trustee, until the restrictions on such shares shall have lapsed, and, as a condition of this award of Restricted Stock, the Company may require that the Grantee deliver a stock power, duly endorsed in blank, relating to the shares of Restricted Stock.

2.Restrictions; Vesting Schedule.

[Subject to the provisions of paragraph 3 hereof, the restrictions on the shares of Restricted Stock shall lapse and such shares shall vest in one-third increments (rounded up to the nearest whole

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number) on each of ____________, 20___, ____________, 20___ and ____________, 20___ (each, a “Vesting Date”); provided that (i) the Grantee remains in continuous employment with the Company or any Subsidiary (or the successor of any such company) through each Vesting Date and (ii) the Committee has certified that [Describe Performance Condition](the “Performance Condition”) as of such Vesting Date. If the Committee does not certify that the Performance Condition was achieved, all Restricted Stock awarded under this Agreement shall be forfeited.]

[Subject to the provisions of paragraph 3 hereof, the restrictions on the shares of Restricted Stock shall lapse and such shares shall vest on the date (the “Vesting Date”) that the Committee certifies that [Describe Performance Condition] (the “Performance Condition”); provided that the Grantee remains in continuous employment with the Company or any Subsidiary (or the successor of any such company) through the Vesting Date. If the Committee does not certify that the Performance Condition was achieved, all Restricted Stock awarded under this Agreement shall be forfeited.]

[Subject to the provisions of paragraph 3 hereof, the restrictions on the shares of Restricted Stock shall lapse and such shares shall vest in one-third increments (rounded up to the nearest whole number) on each of ____________, 20___, ____________, 20___ and ____________, 20___ (each, a “Vesting Date”); provided that the Grantee remains in continuous employment with the Company or any Subsidiary (or the successor of any such company) through each Vesting Date.]

[Subject to the provisions of paragraph 3 hereof, the restrictions on the shares of Restricted Stock shall lapse and such shares shall vest with respect to all of such shares awarded hereunder on  ____________, 20___ (the “Vesting Date”); provided that the Grantee remains in continuous employment with the Company or any Subsidiary (or the successor of any such company) through the Vesting Date.]

Notwithstanding the foregoing, subject to the provisions of any applicable written employment agreement between the Grantee and the Company or any Subsidiary (the “Employment Agreement”), upon a Change in Control while the Grantee remains in continuous employment of the Company or any Subsidiary, the restrictions on all unvested Restricted Stock shall immediately lapse and such occurrence shall be deemed a Vesting Date for purposes of this Agreement.

As soon as practicable but in no event later than thirty (30) days following the occurrence of a Vesting Date as to any portion of the Restricted Stock, the Company will cause to be removed from the Account the restrictions or cause a new certificate evidencing such number of shares of Common Stock to be delivered to the Grantee, free of the legend regarding transferability; provided that the Company shall not be obligated to issue any fractional shares of Common Stock.

3.Termination of Employment; Forfeiture. Upon termination of the Grantee’s employment with the Company or any Subsidiary (or the successor of any such company) as a result of the death of the Grantee, the restrictions on the shares of Restricted Stock shall lapse and such shares shall vest. Upon termination of the Grantee’s employment with the Company or any Subsidiary (or the successor of any such company) for any reason other than death, all shares of Restricted Stock as to which the restrictions thereon have not previously lapsed shall be immediately forfeited to the Company;subject, however, to the provisions of any Employment Agreement.

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[Notwithstanding the provisions of any Employment Agreement, if (a) a Change in Control has not occurred and (b) the Grantee (i) is terminated without Cause (as may be defined in such Employment Agreement) or (ii) resigns for Good Reason (as may be defined in such Employment Agreement) prior to the satisfaction of the Performance Condition, then the restrictions on the Restricted Stock shall not lapse unless and until the Performance Condition is satisfied].

4.Voting and Dividend Rights. During the period in which the restrictions provided herein are applicable to the Restricted Stock, the Grantee shall have the right to vote the shares of Restricted Stock. Subject to the forfeiture condition described below, Grantee shall be entitled to receive any cash dividends paid with respect to the Restricted Stock during the Restriction Period, but such dividends shall be held by the Company and paid, without interest, within 10 days following the occurrence of the applicable Vesting Date with respect to the underlying shares of Restricted Stock. In the event shares of Restricted Stock are forfeited, cash dividends paid with respect to such shares during the Restriction Period shall also be forfeited. Any dividend or distribution payable with respect to shares of Restricted Stock that shall be paid or distributed in shares of Common Stock shall be subject to the same restrictions provided for herein, and the shares so paid or distributed shall be deemed Restricted Stock subject to all terms and conditions herein. Any dividend or distribution (other than cash or Common Stock) payable or distributable on shares of Restricted Stock, unless otherwise determined by the Committee, shall be subject to the terms and conditions of this Agreement to the same extent and in the same manner as the Restricted Stock is subject; provided that the Committee may make such modifications and additions to the terms and conditions (including restrictions on transfer and the conditions to the timing and degree of lapse of such restrictions) that shall become applicable to such dividend or distribution as the Committee may provide in its absolute discretion.

5.Mandatory Withholding ofTaxes. Grantee acknowledges and agrees that the Company shall deduct from the shares of Common Stock and dividends otherwise payable or deliverable an amount of cash and/or number of shares of Common Stock (valued at their Fair Market Value) on the applicable date that is equal to the amount of all federal, state and local taxes required to be withheld by the Company, as determined by the Committee. In the event the Company, in its sole discretion, determines that the Grantee’s tax obligations will not be satisfied under the methods otherwise expressly described above and the Grantee does not provide payment to the Company in the form of cash or shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then the Grantee, subject to compliance with the Company’s insider trading policies, authorizes the Company or the Company’s Stock Plan Administrator, currently UBS Financial Services Inc., to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the Award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The shares of Common Stock may be sold as part of a block trade with other Participants such that all Participants receive an average price. [With the consent of the Committee, the Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock or cash that would otherwise be payable or deliverable an amount of cash and/or number of shares of Common Stock (valued at their Fair Market Value) equal to the product of the maximum federal marginal rate that could be applicable to the Grantee

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and the Fair Market Value of the shares of Common Stock or cash otherwise payable or deliverable, as applicable.]

6.Restrictions Imposed by Law. Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such exercise or delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.

7.Assignability. Except as expressly provided herein, the shares of Restricted Stock are not transferable (voluntarily or involuntarily) other than by will or the laws of descent and distribution or pursuant to a qualified domestic relations order as defined by the Internal Revenue Code of 1986, as amended (the “Code”) or Title I of the Employee Retirement Income Security Act, or the rules thereunder (a “QDRO”), and may not otherwise be assigned, pledged, hypothecated or otherwise disposed of and shall not be subject to execution, attachment or similar process. Upon any attempt to effect any such disposition, or upon the levy of any such process, the award provided for herein shall immediately become null and void, and the shares of Restricted Stock shall be immediately forfeited.

Notwithstanding the foregoing, the shares of Restricted Stock are transferable by the Grantee to (i) the spouse, children or grandchildren of the Grantee (“Immediate Family Members”), (ii) a trust or trusts for the exclusive benefit of such Immediate Family Members (“Immediate Family Member Trusts”), or (iii) a partnership or partnerships in which such Immediate Family Members have at least ninety‑nine percent (99%) of the equity, profit and loss interests (“Immediate Family Member Partnerships”). Subsequent transfers of a transferred shares of Restricted Stock shall be prohibited except by will or the laws of descent and distribution or pursuant to a QDRO, unless such transfers are made to the original Grantee or a person to whom the original Grantee could have made a transfer in the manner described herein. No transfer shall be effective unless and until written notice of such transfer is provided to the Committee, in the form and manner prescribed by the Committee. Following transfer, the shares of Restricted Stock shall continue to be subject to the same terms and conditions as were applicable immediately prior to transfer, and, except as otherwise provided herein, the term “Grantee” shall be deemed to refer to the transferee. The consequences of termination of employment shall continue to be applied with respect to the original Grantee.

8.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

Carrizo Oil & Gas, Inc.

500 Dallas Street, Suite 2300

Houston, Texas 77002

Attention: Human Resources

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with a copy to:

Carrizo Oil & Gas, Inc.

500 Dallas Street, Suite 2300

Houston, Texas 77002

Attention: Law Department

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or shall be sent to the Grantee’s e‑mail address specified in the Company’s records.

9.Grantee Employment. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or any of its Subsidiaries or interfere in any way with the right of the Company or any employing Subsidiary to terminate the Grantee’s employment at any time, with or without cause; subject, however, to the provisions of any Employment Agreement.

10.Governing Law. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Texas. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

11.Construction. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the paragraphs of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

12.Duplicate Originals. The Company and the Grantee may execute any number of copies of this Agreement. Each executed copy shall be an original, but all of them together represent the same agreement.

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13.Rules by Committee. The rights of the Grantee and obligations of the Company hereunder shall be subject to such reasonable rules and regulations as the Committee may adopt from time to time hereafter.

14.Entire Agreement. Subject to the provisions of any Employment Agreement, Grantee and the Company hereby declare and represent that no promise or agreement not herein expressed has been made and that this Agreement contains the entire agreement between the parties hereto with respect to the Restricted Stock and replaces and makes null and void any prior agreements, oral or written, between Grantee and the Company regarding the Restricted Stock. To the extent of any conflict between this Agreement and any Employment Agreement, the terms of such Employment Agreement shall control[; provided, however, that the parties acknowledge and agree that to the extent set forth in the last sentence of paragraph 3, the provisions of this Agreement modify and supersede the terms of such Employment Agreement with respect to the consequences to this award of Restricted Stock of a termination of employment without Cause or a resignation for Good Reason prior to a Change in Control].

15.Excise Taxes. Subject to the provisions of any Employment Agreement and notwithstanding anything to the contrary in this Agreement, if the Grantee is a “disqualified individual” (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a “parachute payment” (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee’s “base amount” (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee’s base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made. For the avoidance of doubt, if any Employment Agreement contains specific provisions relating to Code Section 280G and Code Section 4999, then this paragraph 15 shall not apply to the Restricted Stock.

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16.Grantee Acceptance. Grantee shall signify acceptance of the terms and conditions of this Agreement by executing this Agreement and returning an executed copy to the Company.

CARRIZO OIL & GAS, INC.

By:

S.P. Johnson, IV

President

ACCEPTED:

Grantee

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EX-10.20

Exhibit 10.20

2017 INCENTIVE PLAN
OF
CARRIZO OIL & GAS, INC.

PERFORMANCE SHARE AWARD AGREEMENT
(Officer)

THIS AGREEMENT (the “Agreement”) is effective as of _____ ___, 20__ (the “Grant Date”), by and between Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), and _____________ (the “Grantee”).

The Company has adopted the 2017 Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 16, 2017 (as amended, modified or supplemented from time to time, the “Plan”), by this reference made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the performance shares provided herein in order to provide Grantee with the potential to earn additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of Performance Shares.Pursuant to the Plan and subject further to the terms and conditions herein, the Company and Grantee enter into this Agreement pursuant to which the Grantee has a target of ________ performance shares (the “Target Award”) where each performance share represents the right to receive one share of Common Stock or the cash equivalent thereof (“Performance Shares”). The range of Performance Shares which may be earned by the Grantee is 0 to 200% of the Target Award. The Performance Shares will vest, if at all, based on the Total Shareholder Return Performance and the Production Performance Condition set forth in this Agreement (together, the “Performance Goals”); provided that the Grantee remains in continuous employment with the Company or any Subsidiary (or the successor of any such company) through the last day of the Performance Period (as defined below).

2.Total Shareholder Return Performance.Subject further to the Production Performance Condition set forth in paragraph 3 below, awards of Performance Shares will be paid to the Grantee, if at all, following the close of the _____ year period beginning on the Grant Date and ending on  ____________, 20___ (the “Performance Period”) based upon the TSR (as defined below) of the Company relative to the TSR of the Peer Companies for the Performance Period (the “Total Shareholder Return Performance”).

“Peer Companies” means the companies listed on Schedule A. Any of the Peer Companies that cease to be publicly traded on a recognized stock exchange during the Performance Period will be removed from the Peer Companies for the Performance Period. No companies may be added to the Peer Companies for the Performance Period.

Except as otherwise provided in paragraphs 4 and 5 below, total shareholder return (“TSR”) for a company, including the Company, will be the result of the average Fair Market Value (as defined in the Plan) for the [number of trading days] ending at the end of the Performance Period, minus the average Fair Market Value for the [number of trading days] ending on the Grant Date, plus dividends (cash or stock based on ex-dividend date) paid per share of common stock during the Performance Period, divided by the Fair Market Value on the Grant Date.

Following the close of the Performance Period, the Peer Companies and the Company shall be ranked together based on their TSR for the Performance Period from the highest TSR being number 1 to the lowest TSR being the number of Peer Companies, including the Company. Based on the Company’s relative TSR rank among the Peer Companies for the Performance Period, Grantee will have earned Performance Shares, subject to the Production Performance Condition set forth below, as determined by the Company’s rank as follows:

• If the Company is ranked number 1, 200% of the Target Award

• If the Company is ranked at the 75^th percentile of the Peer Companies, including the Company, 150% of the Target Award

• If the Company is ranked at the 50^th percentile or median of the Peer Companies, including the Company, 100% of the Target Award

• If the Company is ranked at the 25^th percentile of the Peer Companies, including the Company, 50% of the Target Award

• If the Company is ranked below the 25^th percentile of the Peer Companies, including the Company, 0% of the Target Award

If the Company is ranked between any of these payout levels, the percentage multiple of the Target Award will be linearly interpolated based on the actual percentile ranking of the Company in relation to the payout levels. Any partial shares will be rounded up to the next whole number.

3.Production Performance Condition. Subject further to the Total Shareholder Return Performance set forth in paragraph 2 above, Awards of Performance Shares will be paid to the Grantee, if at all, following the close of the Performance Period, provided that the Committee has certified that [Describe Production Performance Goal](the “Production Performance Condition”).

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4.Payment of Performance Shares. Subject to the provisions of paragraph 5 below, Performance Shares will be earned and paid to the Grantee only following (i) the Committee’s certification of the level of Total Shareholder Return Performance and (ii) the Committee’s certification of the achievement of the Production Performance Condition. If the Committee does not certify that the Production Performance Condition was achieved or if the Total Shareholder Return Performance achieved results in 0% of the Target Award earned, all Performance Shares awarded under this Agreement shall be forfeited.

Notwithstanding the foregoing, subject to the provisions of paragraph 5 and any applicable written employment agreement between the Grantee and the Company or any Subsidiary (the “Employment Agreement”), no Performance Shares shall be payable unless the Grantee remains in continuous employment with the Company or any Subsidiary (or the successor of any such company) through the last day of the Performance Period.

In the event of a Change in Control, the Performance Shares payable to the Grantee shall be calculated as follows: if (A) less than one-half of the Performance Period has elapsed, then one hundred percent (100%) of the Target Award for the Performance Period will be paid to the Grantee, (B) one-half or more of the Performance Period has elapsed, then the greater of (i) one hundred percent (100%) of the Target Award or (ii) the percentage corresponding to the actual performance level achieved as of the date of the Change in Control, with the TSR calculated based upon the average Fair Market Value for the fifteen (15) trading days ending on the date of the Change in Control.

As soon as practicable but in no event later than thirty (30) days following the last day of the Performance Period, or, in the event of a death that occurs during the first two (2) years of the Performance Period, no later than thirty (30) days following the date of death or, in the event of a Change in Control, no later than thirty (30) days following the date of the Change in Control, the Company shall deliver to the Grantee (i) certificates representing the applicable number shares of Common Stock or cause the applicable number of shares of Common Stock to be evidenced in book-entry form in the Grantee’s name in the stock register of the Company maintained by the Company’s transfer agent, (ii) cash equal to the Fair Market Value of the applicable number of shares of Common Stock on the applicable date, or (iii) any combination of (i) or (ii).

5.Termination of Employment; Forfeiture. Upon termination of the Grantee’s employment with the Company or any Subsidiary (or the successor of any such company) for any reason other than death prior to the end of the Performance Period, all Performance Shares shall be immediately forfeited to the Company; subject, however, to the provisions of any Employment Agreement. Notwithstanding the foregoing, in the event of the death of the Grantee during the Performance Period, which occurs before a Change in Control, the Grantee’s estate will receive a pro-rata payment (based on the number of completed months during the Performance Period prior to the Grantee’s death compared to the total number of months in the Performance Period) based on actual results at the end of the Performance Period. Notwithstanding, in the event of a death that occurs during the first two (2) years of the Performance Period, such pro-rata payment will be based on actual results through the date of death with the TSR calculated based upon the average Fair Market Value for the fifteen (15) trading days ending on the date of death.

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Notwithstanding the provisions of any Employment Agreement, if (a) a Change in Control has not occurred and (b) the Grantee (i) is terminated without Cause (as may be defined in such Employment Agreement) or (ii) resigns for Good Reason (as may be defined in such Employment Agreement) prior to the satisfaction of the Performance Goals, (A) no Performance Shares will be payable unless and until the Performance Goals have been satisfied and (B) any such payment will be made in accordance with paragraph 4 following the end of the relevant Performance Period.

6.No Ownership Rights Prior to Issuance of Shares of Common Stock; No Dividend Equivalents. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Performance Shares, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock, unless and until and after such shares of Common Stock have been delivered to the Grantee as described in the last subparagraph of paragraph 4.

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7.Mandatory Withholding of Taxes. Grantee acknowledges and agrees that the Company shall deduct from the shares of Common Stock or cash otherwise payable or deliverable an amount of cash or number of shares of Common Stock (valued at their Fair Market Value), as applicable, on the applicable date that is equal to the amount of all federal, state and local taxes required to be withheld by the Company, as determined by the Committee. In the event the Company, in its sole discretion, determines that the Grantee’s tax obligations will not be satisfied under the methods otherwise expressly described above and the Grantee does not provide payment to the Company in the form of cash or shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then, the Grantee, subject to compliance with the Company’s insider trading policies, authorizes the Company or the Company’s Stock Plan Administrator, currently UBS Financial Services Inc., to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The shares of Common Stock may be sold as part of a block trade with other Participants such that all Participants receive an average price. [With the consent of the Committee, the Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock or cash that would otherwise be payable or deliverable an amount of cash or number of shares of Common Stock (valued at their Fair Market Value), or any combination thereof as determined by the Grantee in its sole discretion, equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the Fair Market Value of the shares of Common Stock or cash otherwise payable or deliverable, as applicable.]

8.Restrictions Imposed by Law.Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.

9.Assignability.Except as expressly provided herein, the Performance Shares are not transferable (voluntarily or involuntarily) other than by will or the laws of descent and distribution or pursuant to a qualified domestic relations order as defined by the Code or Title I of the Employee Retirement Income Security Act, or the rules thereunder (a “QDRO”), and may not otherwise be assigned, pledged, hypothecated or otherwise disposed of and shall not be subject to execution, attachment or similar process. Upon any attempt to effect any such disposition, or upon the levy of any such process, the award provided for herein shall immediately become null and void, and the Performance Shares shall be immediately forfeited.

Notwithstanding the foregoing, the Performance Shares are transferable by the Grantee to (i) the spouse, children or grandchildren of the Grantee (“Immediate Family Members”), (ii) a trust or trusts for the exclusive benefit of such Immediate Family Members, or (iii) a partnership or partnerships in which such Immediate Family Members have at least ninety‑nine percent (99%) of

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the equity, profit and loss interests. Subsequent transfers of Performance Shares shall be prohibited except by will or the laws of descent and distribution or pursuant to a QDRO, unless such transfers are made to the original Grantee or a person to whom the original Grantee could have made a transfer in the manner described herein. No transfer shall be effective unless and until written notice of such transfer is provided to the Committee, in the form and manner prescribed by the Committee. Following transfer, the Performance Shares shall continue to be subject to the same terms and conditions as were applicable immediately prior to transfer, and, except as otherwise provided herein, the term “Grantee” shall be deemed to refer to the transferee. The consequences of termination of employment shall continue to be applied with respect to the original Grantee.

10.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

Carrizo Oil & Gas, Inc.

500 Dallas Street, Suite 2300

Houston, Texas 77002

Attention: Human Resources

with a copy to:

Carrizo Oil & Gas, Inc.

500 Dallas Street, Suite 2300

Houston, Texas 77002

Attention: Law Department

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or shall be sent to the Grantee’s e‑mail address specified in the Company’s records.

11.Grantee Employment. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or any of its Subsidiaries or interfere in any way with the right of the Company or any employing Subsidiary to terminate the Grantee’s employment at any time, with or without cause; subject, however, to the provisions of any Employment Agreement.

12.Governing Law.This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Texas. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any

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objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

13.Construction. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the paragraphs of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

14.Duplicate Originals. The Company and the Grantee may execute any number of copies of this Agreement. Each executed copy shall be an original, but all of them together represent the same agreement.

15.Rules by Committee. The rights of the Grantee and obligations of the Company hereunder shall be subject to such reasonable rules and regulations as the Committee may adopt from time to time hereafter.

16.Entire Agreement. Subject to the provisions of any Employment Agreement, Grantee and the Company hereby declare and represent that no promise or agreement not herein expressed has been made and that this Agreement contains the entire agreement between the parties hereto with respect to the Performance Shares and replaces and makes null and void any prior agreements, oral or written, between Grantee and the Company regarding the Performance Shares. To the extent of any conflict between this Agreement and any Employment Agreement, the terms of such Employment Agreement shall control; provided, however, that the parties acknowledge and agree that to the extent set forth in the last sentence of paragraph 5, the provisions of this Agreement modify and supersede the terms of such Employment Agreement with respect to the consequences to this award of Performance Shares of a termination of employment without Cause or a resignation for Good Reason prior to a Change in Control.

17.Code Section 409A. Payments under this Agreement are designed to be made in a manner that is exempt from Code Section 409A as a “short-term deferral,” and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed).

18.Excise Taxes. Subject to the provisions of any Employment Agreement and notwithstanding anything to the contrary in this Agreement, if the Grantee is a “disqualified individual” (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a “parachute payment” (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced

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(but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee’s “base amount” (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee’s base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made. For the avoidance of doubt, if any Employment Agreement contains specific provisions relating to Code Section 280G and Code Section 4999, then this paragraph 18 shall not apply to the Performance Shares.

19.Grantee Acceptance. Grantee shall signify acceptance of the terms and conditions of this Agreement by executing this Agreement and returning an executed copy to the Company.

CARRIZO OIL & GAS, INC.

By:

                        S. P. Johnson, IV    

President

ACCEPTED:

Grantee            

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Schedule A to Performance Share Award Agreement dated as of ____________

SCHEDULE A

PEER COMPANIES

The following companies comprise the Peer Companies for the Performance Period:

[Describe Peer Companies]

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EX-10.21

Exhibit 10.21

2017 INCENTIVE PLAN
OF
CARRIZO OIL & GAS, INC.

EMPLOYEE STOCK APPRECIATION RIGHTS AGREEMENT
(Officer)

THIS AGREEMENT (“Agreement”) is effective as of _____ ___, 20___ (the “Grant Date”), by and between Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), and _____________ (the “Grantee”).

The Company has adopted the 2017 Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 16, 2017 (as amended, modified or supplemented from time to time, the “Plan”), by this reference made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the stock appreciation rights provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of SAR. Subject to the terms and conditions herein, the Company hereby awards to the Grantee, pursuant to the Plan, during the period commencing on the Grant Date and expiring at 5:00 p.m. Houston, Texas time (“Close of Business”) on _____ ___, 20___ (the “SAR Term”), subject to earlier termination pursuant to paragraph 5 below, a stock appreciation right with respect to the number of shares of Company Common Stock (“Common Stock”) set forth on Schedule 1 hereto (the “SAR Shares”) with an exercise price set forth on Schedule 1 (the “Exercise Price”). The Exercise Price and SAR Shares are subject to adjustment pursuant to the Plan. This stock appreciation right is hereinafter referred to as the “SAR.”

2.Vesting Schedule. The SAR is exercisable only in accordance with the conditions stated in this paragraph 2.

(a)Except as otherwise provided in this subparagraph (a), the SAR may only be exercised to the extent the SAR has become vested in accordance with the following schedule (each date, a “Vesting Date”), provided, however, that the SAR shall not become vested unless the Committee has certified that [Describe Performance Condition] (the “Performance Condition”). If the Committee does

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not certify that the Performance Condition was achieved, the SAR shall be forfeited in its entirety.

Vesting Date	Percentage of SAR Shares  (rounded up to nearest whole number)
_____ __, 20__	___%
_____ __, 20__	___%

Notwithstanding the foregoing, subject to the provisions of any applicable written employment agreement between the Grantee and the Company or any Subsidiary (the “Employment Agreement”), the SAR will not vest if Grantee has not remained in the continuous employment with the Company or any Subsidiary (or the successor of any such company) through each Vesting Date.

(b)To the extent the SAR becomes exercisable, the SAR may be exercised in whole or in part (at any time or from time to time, except as otherwise provided herein) until expiration of the SAR Term or earlier termination thereof.

3.Manner of Exercise. The SAR shall be considered exercised (as to the number of SAR Shares specified in the notice referred to in subparagraph (a) below) on the latest of (i) the date of exercise designated in the written notice referred to in subparagraph (a) below, (ii) if the date so designated is not a business day, the first business day following such date or (iii) the earliest business day by which the Company has received all of the following:

(a)Written notice, in such form as the Committee may require, designating, among other things, the date of exercise and the number of SAR Shares with respect to which the SAR is to be exercised; and

(b)Any other documentation that the Committee may reasonably require.

4.Payment by the Company. As soon as practicable after receipt of all items referred to in paragraph 3, and subject to the withholding referred to in paragraph 7, the Company shall deliver to the Grantee an amount, in cash or shares of Common Stock or any combination thereof as determined by the Committee in its sole discretion, equal to the product of (i) the number of SAR Shares with respect to which the SAR was exercised and (ii) the difference between (A) the Fair Market Value per share of Common Stock on the date of exercise and (B) the Exercise Price.

5.Termination of Employment. Unless otherwise determined by the Committee in its sole discretion, the SAR shall terminate, prior to the expiration of the SAR Term, at the time specified below:

(a)If Grantee’s employment with the Company and its Subsidiaries is terminated by death, by the Grantee voluntarily, or by the Company or a Subsidiary without cause (as determined by the Committee in its sole discretion) or, if Grantee

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is party to any Employment Agreement, without Cause (as defined in such Employment Agreement), then the SAR shall terminate at the Close of Business on the first business day following the expiration of the 90-day period which began on the date of termination of Grantee’s employment; or

(b)If Grantee’s employment with the Company and its Subsidiaries is terminated by the Company or a Subsidiary for cause (as determined by the Committee in its sole discretion) or, if Grantee is party to any Employment Agreement, for Cause (as defined in such Employment Agreement), then the SAR shall terminate immediately upon termination of Grantee’s employment.

In any event in which the SAR remains exercisable for a period of time following the date of termination of Grantee’s employment, the SAR may be exercised during such period of time only to the extent it is vested as provided in paragraph 2. Notwithstanding any period of time referenced in this paragraph 5 or any other provision of this paragraph 5 that may be construed to the contrary, the SAR shall in any event terminate upon the expiration of the SAR Term.

6.No Stockholder Rights. The Grantee shall not be deemed for any purpose to be, or to have any of the rights of, a stockholder of the Company with respect to any shares of Common Stock as to which this Agreement relates unless and until shares shall have been issued to Grantee by the Company pursuant to paragraph 4.

7.Mandatory Withholding for Taxes. Grantee acknowledges and agrees that the Company shall deduct from the cash or shares of Common Stock otherwise payable or deliverable upon exercise of the SAR an amount of cash or number of shares of Common Stock (valued at their Fair Market Value on the date of exercise) that is equal to the amount of all federal, state and local taxes required to be withheld by the Company upon such exercise, as determined by the Committee. In the event the Company, in its sole discretion, determines that the Grantee's tax obligations will not be satisfied under the methods otherwise expressly described above and the Grantee does not provide payment to the Company in the form of cash or shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then, the Grantee authorizes the Company or the Company's Stock Plan Administrator, currently UBS Financial Services Inc., to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the Award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The shares of Common Stock may be sold as part of a block trade with other Participants such that all Participants receive an average price. [With the consent of the Committee, the Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock or cash that would otherwise be payable or deliverable an amount of cash or number of shares of Common Stock (valued at their Fair Market Value), or any combination thereof as determined by the Grantee in its sole discretion, equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the Fair Market Value of the shares of Common Stock or cash otherwise payable or deliverable, as applicable.]

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8.Restrictions Imposed by Law. Without limiting the generality of Section 16 of the Plan, the Grantee agrees that Grantee will not exercise the SAR and that the Company will not be obligated to deliver any payment or shares of Common Stock, if counsel to the Company determines that such exercise, payment or delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the exercise of the SAR or the resulting payment or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.

9.Assignability. During Grantee’s lifetime, the SAR is not transferable (voluntarily or involuntarily) other than pursuant to a qualified domestic relations order as defined by the Code or Title I of the Employee Retirement Income Security Act, or the rules thereunder (a “QDRO”), and, except as otherwise required pursuant to a QDRO, is exercisable only by the Grantee or Grantee’s court appointed legal representative. The Grantee may designate a beneficiary or beneficiaries to whom the SAR shall pass upon Grantee’s death and may change such designation from time to time by filing a written designation of beneficiary or beneficiaries with the Committee on the form attached hereto as Exhibit A or such other form as may be prescribed by the Committee, provided that no such designation shall be effective unless so filed prior to the death of Grantee. If no such designation is made or if the designated beneficiary does not survive the Grantee’s death, the SAR shall pass by will or the laws of descent and distribution. Following Grantee’s death, the SAR, if otherwise exercisable, may be exercised by the person to whom such SAR passes according to the foregoing and such person shall be deemed the Grantee for purposes of any applicable provisions of this Agreement.

Notwithstanding the foregoing, the SAR is transferable by the Grantee to (i) the spouse, children or grandchildren of the Grantee (“Immediate Family Members”), (ii) a trust or trusts for the exclusive benefit of such Immediate Family Members (“Immediate Family Member Trusts”), or (iii) a partnership or partnerships in which such Immediate Family Members have at least ninety‑nine percent (99%) of the equity, profit and loss interests (“Immediate Family Member Partnerships”). Subsequent transfers of a transferred SAR shall be prohibited except by will or the laws of descent and distribution or pursuant to a QDRO, unless such transfers are made to the original Grantee or a person to whom the original Grantee could have made a transfer in the manner described herein. No transfer shall be effective unless and until written notice of such transfer is provided to the Committee, in the form and manner prescribed by the Committee. Following transfer, the SAR shall continue to be subject to the same terms and conditions as were applicable immediately prior to transfer, and, except as otherwise provided herein, the term “Grantee” shall be deemed to refer to the transferee. The consequences of termination of employment shall continue to be applied with respect to the original Grantee, following which the SAR shall be exercisable by the transferee only to the extent and for the periods specified in the Plan and this Agreement.

10.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

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Carrizo Oil & Gas, Inc.

500 Dallas Street, Suite 2300

Houston, Texas 77002

Attention: Human Resources

with a copy to:

Carrizo Oil & Gas, Inc.

500 Dallas Street, Suite 2300

Houston, Texas 77002

Attention: Law Department

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or shall be sent to the Grantee’s e‑mail address specified in the Company’s records.

11.Grantee Employment. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or any of its Subsidiaries or interfere in any way with the right of the Company or any employing Subsidiary to terminate the Grantee’s employment at any time, with or without cause; subject, however, to the provisions of any Employment Agreement.

12.Governing Law. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Texas. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

13.Construction. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the paragraphs of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

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14.Duplicate Originals. The Company and the Grantee may execute any number of copies of this Agreement. Each executed copy shall be an original, but all of them together represent the same agreement.

15.Rules by Committee. The rights of the Grantee and obligations of the Company hereunder shall be subject to such reasonable rules and regulations as the Committee may adopt from time to time hereafter.

16.Entire Agreement. Subject to the provisions of any Employment Agreement, Grantee and the Company hereby declare and represent that no promise or agreement not herein expressed has been made and that this Agreement contains the entire agreement between the parties hereto with respect to the SAR and replaces and makes null and void any prior agreements, oral or written, between Grantee and the Company regarding the SAR. To the extent of any conflict between this Agreement and any Employment Agreement, the terms of such Employment Agreement shall control.

17.Grantee Acceptance. Grantee shall signify acceptance of the terms and conditions of this Agreement by executing this Agreement and returning an executed copy to the Company.

CARRIZO OIL & GAS, INC.

By:

S.P. Johnson, IV

President

ACCEPTED:

Grantee

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Schedule 1 to Stock Appreciation Rights Agreement dated as of ___________

2017 Incentive Plan of Carrizo Oil & Gas, Inc.

Grantee:        [Employee Name]

Grant Date:        _______________

Exercise Price:    $________ per SAR Share

Number of SAR Shares: ______

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Exhibit A to Stock Appreciation Rights Agreement dated as of ___________

2017 Incentive Plan of Carrizo Oil & Gas, Inc.

Designation of Beneficiary

I, ___________________________________________ (the “Grantee”), hereby declare

that upon my death __________________________________________ (the “Beneficiary”) of

Name

_____________________________________________________________________________,

Street Address             City             State         Zip Code

who is my _________________________________________________, shall be entitled to the

Relationship to Grantee

SAR and all other rights accorded the Grantee by the above‑referenced agreement (the “Agreement”).

It is understood that this Designation of Beneficiary is made pursuant to the Agreement and is subject to the conditions stated herein, including the Beneficiary’s survival of the Grantee’s death. If any such condition is not satisfied, such rights shall devolve according to the Grantee’s will or the laws of descent and distribution.

It is further understood that all prior designations of beneficiary under the Agreement are hereby revoked and that this Designation of Beneficiary may only be revoked in writing, signed by the Grantee, and filed with the Company prior to the Grantee’s death.

Date                            Grantee

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EX-10.22

Exhibit 10.22

CARRIZO OIL & GAS, INC.

CASH-SETTLED STOCK APPRECIATION RIGHTS PLAN

EMPLOYEE STOCK APPRECIATION RIGHTS AGREEMENT
(Officer)

THIS AGREEMENT (“Agreement”) is effective as of _____ ___, 20___ (the “Grant Date”), by and between Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), and ____________ (the “Grantee”).

The Company has adopted the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (as amended, modified or supplemented from time to time, the “Plan”), by this reference made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the stock appreciation rights provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of SAR. Subject to the terms and conditions herein, the Company hereby awards to the Grantee, pursuant to the Plan, during the period commencing on the Grant Date and expiring at 5:00 p.m. Houston, Texas time (“Close of Business”) on ___________, 20___ (the “SAR Term”), subject to earlier termination pursuant to paragraph 5 below, a stock appreciation right with respect to the number of shares of Company Common Stock (“Common Stock”) set forth on Schedule 1 hereto (the “SAR Shares”) with an exercise price set forth on Schedule 1 (the “Exercise Price”). The Exercise Price and SAR Shares are subject to adjustment pursuant to the Plan. This stock appreciation right is hereinafter referred to as the “SAR.”

2.Vesting Schedule. The SAR is exercisable only in accordance with the conditions stated in this paragraph.

(a)Except as otherwise provided in this subparagraph (a), the SAR may only be exercised to the extent the SAR has become vested in accordance with the following schedule (each date, a “Vesting Date”), provided, however, that the SAR shall not become vested unless the Committee has certified that [Describe Performance Condition] (the “Performance Condition”). If the Committee does not certify that the Performance Condition was achieved, the SAR shall be forfeited in its entirety.

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Vesting Date	Percentage ofSAR Shares  (rounded up to nearest whole number)
_____ __, 20__	___%
_____ __, 20__	___%

Notwithstanding the foregoing, subject to the provisions of any applicable written employment agreement between the Grantee and the Company or any Subsidiary (the “Employment Agreement”), the SAR will not vest if Grantee has not remained in the continuous employment with the Company or any Subsidiary (or the successor of any such company) through each Vesting Date.

(b)To the extent the SAR becomes exercisable, the SAR may be exercised in whole or in part (at any time or from time to time, except as otherwise provided herein) until expiration of the SAR Term or earlier termination thereof.

3.Manner of Exercise. The SAR shall be considered exercised (as to the number of SAR Shares specified in the notice referred to in subparagraph (a) below) on the latest of (i) the date of exercise designated in the written notice referred to in subparagraph (a) below, (ii) if the date so designated is not a business day, the first business day following such date or (iii) the earliest business day by which the Company has received all of the following:

(a)Written notice, in such form as the Committee may require, designating, among other things, the date of exercise and the number of SAR Shares with respect to which the SAR is to be exercised; and

(b)Any other documentation that the Committee may reasonably require.

4.Payment by the Company. As soon as practicable after receipt of all items referred to in paragraph 3, and subject to the withholding referred to in paragraph 7, the Company shall deliver to the Grantee an amount, in cash, equal to the product of (i) the number of SAR Shares with respect to which the SAR was exercised and (ii) the difference between (A) the Fair Market Value per share of Common Stock on the date of exercise and (B) the Exercise Price.

5.Termination of Employment. Unless otherwise determined by the Committee in its sole discretion, the SAR shall terminate, prior to the expiration of the SAR Term, at the time specified below:

(a)If Grantee’s employment with the Company and its Subsidiaries is terminated by death, by the Grantee voluntarily, or by the Company or a Subsidiary without cause (as determined by the Committee in its sole discretion) or, if Grantee is party to any Employment Agreement, without Cause (as defined in such Employment Agreement), then the SAR shall terminate at the Close of Business on the first business day following the expiration of the 90-day period which began on the date of termination of Grantee’s employment; or

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(b)If Grantee’s employment with the Company and its Subsidiaries is terminated by the Company or a Subsidiary for cause (as determined by the Committee in its sole discretion) or, if Grantee is party to any Employment Agreement, for Cause (as defined in such Employment Agreement), then the SAR shall terminate immediately upon termination of Grantee’s employment.

In any event in which the SAR remains exercisable for a period of time following the date of termination of Grantee’s employment, the SAR may be exercised during such period of time only to the extent it is vested as provided in paragraph 2. Notwithstanding any period of time referenced in this paragraph 5 or any other provision of this paragraph 5 that may be construed to the contrary, the SAR shall in any event terminate upon the expiration of the SAR Term.

6.No Stockholder Rights. The Grantee shall not be deemed for any purpose to be, or to have any of the rights of, a stockholder of the Company with respect to any shares of Common Stock as to which this Agreement relates.

7.Mandatory Withholding for Taxes. Grantee acknowledges and agrees that the Company shall deduct from the cash otherwise payable or deliverable upon exercise of the SAR an amount of cash that is equal to the amount of all federal, state and local taxes required to be withheld by the Company upon such exercise, as determined by the Committee.

8.Restrictions Imposed by Law. Without limiting the generality of Section 13 of the Plan, the Grantee agrees that Grantee will not exercise the SAR and that the Company will not be obligated to deliver any payment, if counsel to the Company determines that such exercise or payment would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the exercise of the SAR or the resulting payment to comply with any such law, rule, regulation or agreement.

9.Assignability. During Grantee’s lifetime, the SAR is not transferable (voluntarily or involuntarily) other than pursuant to a qualified domestic relations order as defined by the Code or Title I of the Employee Retirement Income Security Act, or the rules thereunder (a “QDRO”), and, except as otherwise required pursuant to a QDRO, is exercisable only by the Grantee or Grantee’s court appointed legal representative. The Grantee may designate a beneficiary or beneficiaries to whom the SAR shall pass upon Grantee’s death and may change such designation from time to time by filing a written designation of beneficiary or beneficiaries with the Committee on the form attached hereto as Exhibit A or such other form as may be prescribed by the Committee, provided that no such designation shall be effective unless so filed prior to the death of Grantee. If no such designation is made or if the designated beneficiary does not survive the Grantee’s death, the SAR shall pass by will or the laws of descent and distribution. Following Grantee’s death, the SAR, if otherwise exercisable, may be exercised by the person to whom such SAR passes according to the foregoing and such person shall be deemed the Grantee for purposes of any applicable provisions of this Agreement.

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Notwithstanding the foregoing, the SAR is transferable by the Grantee to (i) the spouse, children or grandchildren of the Grantee (“Immediate Family Members”), (ii) a trust or trusts for the exclusive benefit of such Immediate Family Members (“Immediate Family Member Trusts”), or (iii) a partnership or partnerships in which such Immediate Family Members have at least ninety‑nine percent (99%) of the equity, profit and loss interests (“Immediate Family Member Partnerships”). Subsequent transfers of a transferred SAR shall be prohibited except by will or the laws of descent and distribution or pursuant to a QDRO, unless such transfers are made to the original Grantee or a person to whom the original Grantee could have made a transfer in the manner described herein. No transfer shall be effective unless and until written notice of such transfer is provided to the Committee, in the form and manner prescribed by the Committee. Following transfer, the SAR shall continue to be subject to the same terms and conditions as were applicable immediately prior to transfer, and, except as otherwise provided herein, the term “Grantee” shall be deemed to refer to the transferee. The consequences of termination of employment shall continue to be applied with respect to the original Grantee, following which the SAR shall be exercisable by the transferee only to the extent and for the periods specified in the Plan and this Agreement.

10.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

Carrizo Oil & Gas, Inc.

500 Dallas Street, Suite 2300

Houston, Texas 77002

Attention: Human Resources

with a copy to:

Carrizo Oil & Gas, Inc.

500 Dallas Street, Suite 2300

Houston, Texas 77002

Attention: Law Department

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or shall be sent to the Grantee’s e‑mail address specified in the Company’s records.

11.Grantee Employment. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or any of its Subsidiaries or interfere in any way with the right of the Company or any employing Subsidiary to terminate the Grantee’s employment at any time, with or without cause; subject, however, to the provisions of any Employment Agreement.

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12.Governing Law. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Texas. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

13.Construction. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the paragraphs of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

14.Duplicate Originals. The Company and the Grantee may execute any number of copies of this Agreement. Each executed copy shall be an original, but all of them together represent the same agreement.

15.Rules by Committee. The rights of the Grantee and obligations of the Company hereunder shall be subject to such reasonable rules and regulations as the Committee may adopt from time to time hereafter.

16.Entire Agreement. Subject to the provisions of any Employment Agreement, Grantee and the Company hereby declare and represent that no promise or agreement not herein expressed has been made and that this Agreement contains the entire agreement between the parties hereto with respect to the SAR and replaces and makes null and void any prior agreements, oral or written, between Grantee and the Company regarding the SAR. To the extent of any conflict between this Agreement and any Employment Agreement, the terms of such Employment Agreement shall control.

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17.Grantee Acceptance. Grantee shall signify acceptance of the terms and conditions of this Agreement by executing this Agreement and returning an executed copy to the Company.

CARRIZO OIL & GAS, INC.

By:

S. P. Johnson, IV    

President

ACCEPTED:

Grantee            

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Schedule 1 to Stock Appreciation Rights Agreement dated as of ____________

Carrizo Oil & Gas, Inc.
Cash-Settled Stock Appreciation Rights Plan

Grantee:        [Employee Name]

Grant Date:        ____________

Exercise Price:    $________ per SAR Share

Number of SAR Shares: ______

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Exhibit A to Stock Appreciation Rights Agreement dated as of ____________

Carrizo Oil & Gas, Inc.
Cash-Settled Stock Appreciation Rights Plan

Designation of Beneficiary

I, ___________________________________________ (the “Grantee”), hereby declare

that upon my death __________________________________________ (the “Beneficiary”) of

Name

_____________________________________________________________________________,

Street Address             City             State         Zip Code

who is my _________________________________________________, shall be entitled to the

Relationship to Grantee

SAR and all other rights accorded the Grantee by the above‑referenced agreement (the “Agreement”).

It is understood that this Designation of Beneficiary is made pursuant to the Agreement and is subject to the conditions stated herein, including the Beneficiary’s survival of the Grantee’s death. If any such condition is not satisfied, such rights shall devolve according to the Grantee’s will or the laws of descent and distribution.

It is further understood that all prior designations of beneficiary under the Agreement are hereby revoked and that this Designation of Beneficiary may only be revoked in writing, signed by the Grantee, and filed with the Company prior to the Grantee’s death.

Date                            Grantee

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EX-21.1

Exhibit 21.1

Subsidiaries of the Company

The following are wholly owned subsidiaries of Carrizo Oil & Gas, Inc.:

Bandelier Pipeline Holding, LLC

Carrizo (Eagle Ford) LLC

Carrizo (Marcellus) LLC

Carrizo (Marcellus) WV LLC

Carrizo (Niobrara) LLC

Carrizo (Permian) LLC

Carrizo (Utica) LLC

Carrizo Marcellus Holding Inc.

CLLR, Inc.

Hondo Pipeline, Inc.

Mescalero Pipeline, LLC

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statements (Form S-3 Nos. 333-221121, and 333-221122) of Carrizo Oil & Gas, Inc. and in the related Prospectuses,

(2) Registration Statement (Form S-8 No. 333-218036) pertaining to the 2017 Incentive Plan of Carrizo Oil & Gas, Inc., and

(3) Registration Statements (Form S-8 Nos. 333-196252, 333-181585, 333-162888, 333-137273, 333-116528, 333-55838, and 333-35245) pertaining to the Incentive Plan of Carrizo Oil & Gas, Inc.,

of our reports dated February 28, 2018, with respect to the consolidated financial statements of Carrizo Oil & Gas, Inc. and the effectiveness of internal control over financial reporting of Carrizo Oil & Gas, Inc. included in this Annual Report (Form 10-K) of Carrizo Oil & Gas, Inc. for the year ended December 31, 2017.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2018

EX-23.2

Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

The Board of Directors
Carrizo Oil & Gas, Inc.:

We consent to the incorporation by reference in the registration statements (No. 333‑221121 and No. 333-221122) on Form S-3 and registration statements (Nos. 333-218036, 333-196252, 333-181585, 333-162888, 333-137273, 333-116528, 333-55838, and 333-35245) on Form S-8 of Carrizo Oil & Gas, Inc. of our report dated February 28, 2017, with respect to the consolidated balance sheet of Carrizo Oil & Gas, Inc. as of December 31, 2016, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2016, which report appears in the December 31, 2017 annual report on Form 10‑K of Carrizo Oil & Gas, Inc.

/s/ KPMG LLP

Houston, Texas

February 28, 2018

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

We hereby consent to the incorporation by reference in the registration statements on Form S-8 (Registration Nos. 333-218036, 333-196252, 333-181585, 333-162888, 333-137273, 333-116528, 333-55838 and 333-35245) and the registration statements on Form S-3ASR (Registration Nos. 333-221121 and 333-221122) of Carrizo Oil & Gas, Inc. of our letter dated February 2, 2018, relating to estimates of proved reserves attributable to certain interests of Carrizo Oil & Gas, Inc. as of December 31, 2017.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 28, 2018

EX-31.1

Exhibit 31.1

CERTIFICATION

PRINCIPAL EXECUTIVE OFFICER

I, S.P. Johnson, IV, certify that:

1. I have reviewed this Annual Report on Form 10-K of Carrizo Oil & Gas, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 28, 2018	/s/ S.P. Johnson, IV
		S.P. Johnson, IV President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

PRINCIPAL FINANCIAL OFFICER

I, David L. Pitts, certify that:

1. I have reviewed this Annual Report on Form 10-K of Carrizo Oil & Gas, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	February 28, 2018	/s/ David L. Pitts
		David L. Pitts Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, S.P. Johnson, IV, President and Chief Executive Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

1. the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	February 28, 2018	/s/ S.P. Johnson, IV
		S.P. Johnson, IV President and Chief Executive Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, David L. Pitts, Vice President and Chief Financial Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

1. the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	February 28, 2018	/s/ David L. Pitts
		David L. Pitts Vice President and Chief Financial Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

Carrizo Oil & Gas, Inc.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2017

/s/ Michael F. Stell

Michael F. Stell, P.E.

TBPE License No. 56416

Advising Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

[Ryder Scott Company L.P. logo]

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

February 2, 2018

Carrizo Oil & Gas, Inc.

500 Dallas Street, Suite 2300

Houston, Texas 77002

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Carrizo Oil & Gas, Inc. (Carrizo) as of December 31, 2017. The subject properties are located in the states of Colorado and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 1, 2018 and presented herein, was prepared for public disclosure by Carrizo in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for all of Carrizo’s total net proved reserves as of December 31, 2017.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2017, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Carrizo Oil & Gas, Inc.

As of December 31, 2017

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate –MBarrels	68,456		1,176		97,742		167,374
Plant Products – MBarrels	17,016		431		25,151		42,598
Gas – MMCF	128,031		3,324		179,115		310,470
Income Data (M$)
Future Gross Revenue		$3,940,953		$71,795		$5,607,638		$9,620,386
Deductions	1,323,504		18,394		3,070,846		4,412,744
Future Net Income (FNI)		$2,617,449		$53,401		$2,536,792		$5,207,642
Discounted FNI @ 10%		$1,589,692		$31,303		$1,017,377		$2,638,372

Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Carrizo. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The “Other” deductions, as shown in the cash flow, include variable operating costs on a dollar per barrel and dollar per MCF basis plus compression fees. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 91 percent and gas reserves account for the remaining 9 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258

Carrizo Oil & Gas, Inc.

February 2, 2018

Page 2

	Discounted Future Net Income (M$)
	As of December 31, 2017
Discount Rate		Total
Percent		Proved
5		$3,534,470
15		$2,086,498
20		$1,714,226
25		$1,446,911

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Carrizo’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Carrizo Oil & Gas, Inc.

February 2, 2018

Page 3

much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Carrizo’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies, including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Carrizo owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Carrizo Oil & Gas, Inc.

February 2, 2018

Page 4

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods. All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. The performance methods, such as decline curve analysis, utilized extrapolations of historical production and pressure data available through December 2017 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Carrizo or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved developed non-producing and undeveloped reserves included herein were estimated by analogy. The analogs utilized data furnished to Ryder Scott by Carrizo or which we have obtained from public data sources that were available through December 2017.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Carrizo has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Carrizo with respect to property interests, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Carrizo. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Carrizo Oil & Gas, Inc.

February 2, 2018

Page 5

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Carrizo. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Carrizofurnished us with the above mentioned average prices in effect on December 31, 2017. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Carrizo. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Carrizo to determine these differentials.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Carrizo Oil & Gas, Inc.

February 2, 2018

Page 6

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
United States	Oil/Condensate	WTI Cushing	$51.34/Bbl	$49.87/Bbl
	NGLs	WTI Cushing	$51.34/Bbl*	$19.78/Bbl
	Gas	Henry Hub	$2.98/MMBTU	$2.96/MCF

*NGL Prices are calculated as a percentage of oil price.

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Carrizo and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Carrizo and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Carrizo were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Carrizo’s plans to develop these reserves as of December 31, 2017. The implementation of Carrizo’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Carrizo’s management. As the result of our inquiries during the course of preparing this report, Carrizo has informed us that the development activities included herein have been subjected to and received the internal approvals required by Carrizo’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Carrizo. Additionally, Carrizo has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2017, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Carrizo were held constant throughout the life of the properties.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Carrizo Oil & Gas, Inc.

February 2, 2018

Page 7

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Carrizo. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Carrizo.

Carrizo makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Carrizo has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Carrizo of the references to our name as well as to the references to our third party report for Carrizo, which appears in the December 31, 2017, annual report on Form 10-K of Carrizo. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Carrizo.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Carrizo Oil & Gas, Inc.

February 2, 2018

Page 8

We have provided Carrizo with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Carrizo and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Michael F. Stell

Michael F. Stell, P.E.

TBPE License No. 56416

Advising Senior Vice President

[SEAL]

MFS (DCR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Michael F. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.

Mr. Stell, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number of engineering positions with Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Stell fulfills. As part of his 2009 continuing education hours, Mr. Stell attended an internally presented 13hours of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Stell attended an additional 15 hours of formalized in-house training as well as an additional five hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr. Stell attended an internally presented sixhours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training. For each year starting 2011 through 2017, as of the date of this report, Mr. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.

Based on his educational background, professional training and over 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

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Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

Document And Entity Information - USD ($) $ / shares in Units, $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 23, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Entity Registrant Name	CARRIZO OIL & GAS INC
Entity Central Index Key	0001040593
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		81,469,593
Share Price			$ 17.42
Entity Public Float			$ 1.1
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

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Consolidated Balance Sheets - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 9,540,000	$ 4,194,000
Accounts receivable, net	107,441,000	64,208,000
Other current assets	5,897,000	4,586,000
Total current assets	122,878,000	72,988,000
Oil and gas properties, full cost method
Proved properties, net	1,965,347,000	1,294,667,000
Unproved properties, not being amortized	660,287,000	240,961,000
Other property and equipment, net	10,176,000	10,132,000
Total property and equipment, net	2,635,810,000	1,545,760,000
Other assets	19,616,000	7,579,000
Total Assets	2,778,304,000	1,626,327,000
Current liabilities
Accounts payable	74,558,000	55,631,000
Revenues and royalties payable	52,154,000	38,107,000
Accrued capital expenditures	119,452,000	36,594,000
Accrued interest	28,362,000	22,016,000
Accrued lease operating expense	18,223,000	12,377,000
Derivative liabilities	57,121,000	22,601,000
Other current liabilities	22,952,000	24,633,000
Total current liabilities	372,822,000	211,959,000
Long-term debt	1,629,209,000	1,325,418,000
Asset retirement obligations	23,497,000	20,848,000
Derivative liabilities	112,332,000	27,528,000
Deferred income taxes	3,635,000	0
Other liabilities	51,650,000	17,116,000
Liabilities	2,193,145,000	1,602,869,000
Commitments and contingencies
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	214,262,000	0
Shareholders’ equity
Common stock, $0.01 par value, 180,000,000 shares authorized; 81,454,621 issued and outstanding as of December 31, 2017 and 90,000,000 shares authorized; 65,132,499 issued and outstanding as of December 31, 2016	815,000	651,000
Additional paid-in capital	1,926,056,000	1,665,891,000
Accumulated deficit	(1,555,974,000)	(1,643,084,000)
Total shareholders’ equity	370,897,000	23,458,000
Total Liabilities and Shareholders’ Equity	$ 2,778,304,000	$ 1,626,327,000

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.00
Temporary Equity, Shares Authorized	10,000,000	0
Temporary Equity, Shares Issued	250,000	0
Temporary Equity, Shares Outstanding	250,000	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	180,000,000	90,000,000
Common stock, shares issued (in shares)	81,454,621	65,132,499
Common stock, shares outstanding (in shares)	81,454,621	65,132,499

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Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Crude oil revenue	$ 633,233	$ 378,073	$ 376,094
Natural gas liquids revenue	47,405	22,428	15,608
Natural gas revenue	65,250	43,093	37,501
Total revenues	745,888	443,594	429,203
Costs and Expenses
Lease operating	139,854	98,717	90,052
Production taxes	32,509	19,046	17,683
Ad valorem taxes	7,267	5,559	9,255
Depreciation, depletion and amortization	262,589	213,962	300,035
General and administrative, net	66,229	74,972	67,224
(Gain) loss on derivatives, net	59,103	49,073	(99,261)
Interest expense, net	80,870	79,403	69,195
Impairment of proved oil and gas properties	0	576,540	1,224,367
Loss on extinguishment of debt	4,170	0	38,137
Other expense, net	2,157	1,796	11,276
Total costs and expenses	654,748	1,119,068	1,727,963
OTHER INCOME AND EXPENSES
Income (Loss) From Continuing Operations Before Income Taxes	91,140	(675,474)	(1,298,760)
Income tax (expense) benefit	(4,030)	0	140,875
Income (Loss) From Continuing Operations	87,110	(675,474)	(1,157,885)
Income From Discontinued Operations, Net of Income Taxes	0	0	2,731
Net Income (Loss)	87,110	(675,474)	(1,155,154)
Dividends on preferred stock	(7,781)	0	0
Accretion on preferred stock	(862)	0	0
Net Income (Loss) Attributable to Common Shareholders	$ 78,467	$ (675,474)	$ (1,155,154)
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Net income (loss) per share, basic (in dollars per share)	$ 1.07	$ (11.27)	$ (22.45)
Net Income (Loss) Attributable to Common Shareholders Per Common Share - Diluted
Net income (loss) per share, diluted (in dollars per share)	$ 1.06	$ (11.27)	$ (22.45)
Weighted Average Common Shares Outstanding
Basic (in shares)	73,421	59,932	51,457
Diluted (in shares)	73,993	59,932	51,457

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Consolidated Statements Of Shareholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]
Total shareholders' equity at Dec. 31, 2014	$ 1,103,441	$ 461	$ 915,436	$ 187,544
Total shareholders' equity, shares at Dec. 31, 2014		46,127,924
Stock options exercised for cash	46	$ 0	46
Stock options exercised for cash, shares		2,433
Stock-based compensation expense	25,707		25,707
Issuance of common stock upon grants of employee stock awards or units	(144)	$ 6	(150)
Issuance of common stock upon grants of employee stock awards or units, shares		630,723
Sale of common stock, net of offering costs	470,158	$ 115	470,043
Sale of common stock, net of offering costs, shares		11,500,000
Dividends on preferred stock	0
Accretion on preferred stock	0
Other shareholders' equity	0	$ 1	(1)
Other shareholders' equity, shares		71,913
Net income (loss)	(1,155,154)			(1,155,154)
Total shareholders' equity at Dec. 31, 2015	444,054	$ 583	1,411,081	(967,610)
Total shareholders' equity, shares at Dec. 31, 2015		58,332,993
Stock-based compensation expense	31,194		31,194
Issuance of common stock upon grants of employee stock awards or units	(55)	$ 8	(63)
Issuance of common stock upon grants of employee stock awards or units, shares		799,506
Sale of common stock, net of offering costs	$ 223,739	$ 60	223,679
Sale of common stock, net of offering costs, shares	6,000,000	6,000,000
Dividends on preferred stock	$ 0
Accretion on preferred stock	0
Net income (loss)	(675,474)			(675,474)
Total shareholders' equity at Dec. 31, 2016	23,458	$ 651	1,665,891	(1,643,084)
Total shareholders' equity, shares at Dec. 31, 2016		65,132,499
Stock-based compensation expense	23,625		23,625
Issuance of common stock upon grants of employee stock awards or units	(34)	$ 8	(42)
Issuance of common stock upon grants of employee stock awards or units, shares		722,122
Sale of common stock, net of offering costs	$ 222,378	$ 156	222,222
Sale of common stock, net of offering costs, shares	15,600,000	15,600,000
Proceeds from Issuance of Warrants	$ 23,003		23,003
Dividends on preferred stock	(7,781)		(7,781)
Accretion on preferred stock	(862)		(862)
Net income (loss)	87,110			87,110
Total shareholders' equity at Dec. 31, 2017	$ 370,897	$ 815	$ 1,926,056	$ (1,555,974)
Total shareholders' equity, shares at Dec. 31, 2017		81,454,621

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Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flows From Operating Activities
Net income (loss)	$ 87,110	$ (675,474)	$ (1,155,154)
(Income) loss from discontinued operations, net of income taxes	0	0	(2,731)
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities from continuing operations
Depreciation, depletion and amortization	262,589	213,962	300,035
Impairment of proved oil and gas properties	0	576,540	1,224,367
(Gain) loss on derivatives, net	59,103	49,073	(99,261)
Cash received for derivative settlements, net	7,773	119,369	194,296
Loss on extinguishment of debt	4,170	0	38,137
Stock-based compensation expense, net	14,309	36,086	14,729
Deferred income taxes	3,635	0	(140,875)
Non-cash interest expense, net	3,657	4,172	4,289
Other, net	2,337	3,753	5,709
Changes in components of working capital and other assets and liabilities-
Accounts receivable	(41,630)	(12,836)	29,781
Accounts payable	11,822	(30,130)	(12,617)
Accrued liabilities	11,512	(7,938)	(17,517)
Other assets and liabilities, net	(3,406)	(3,809)	(4,453)
Net cash provided by operating activities from continuing operations	422,981	272,768	378,735
Net cash used in operating activities from discontinued operations	0	0	(1,368)
Net cash provided by operating activities	422,981	272,768	377,367
Cash Flows From Investing Activities
Capital expenditures	(654,711)	(480,929)	(675,952)
Acquisitions of oil and gas properties	(695,774)	(153,521)	(1,817)
Net proceeds from divestitures of oil and gas properties	197,564	15,564	8,047
Other, net	(6,531)	(946)	(3,654)
Net cash used in investing activities from continuing operations	(1,159,452)	(619,832)	(673,376)
Net cash used in investing activities from discontinued operations	0	0	(2,678)
Net cash used in investing activities	(1,159,452)	(619,832)	(676,054)
Cash Flows From Financing Activities
Issuance of senior notes	250,000	0	650,000
Tender and redemptions of senior notes	(152,813)	0	(626,681)
Payment of deferred purchase payment	0	0	(150,000)
Borrowings under credit agreement	1,992,523	770,291	1,126,860
Repayments of borrowings under credit agreement	(1,788,223)	(683,291)	(1,126,860)
Payments of debt issuance costs and credit facility amendment fees	(9,051)	(1,330)	(12,420)
Sale of common stock, net of offering costs	222,378	223,739	470,158
Sale of preferred stock, net of offering costs	236,404	0	0
Payment of dividends on preferred stock	(7,781)	0	0
Proceeds from stock options exercised	0	0	46
Other, net	(1,620)	(1,069)	(336)
Net cash provided by financing activities from continuing operations	741,817	308,340	330,767
Net cash provided by financing activities from discontinued operations	0	0	0
Net cash provided by financing activities	741,817	308,340	330,767
Net Increase (Decrease) in Cash and Cash Equivalents	5,346	(38,724)	32,080
Cash and Cash Equivalents, Beginning of Year	4,194	42,918	10,838
Cash and Cash Equivalents, End of Year	$ 9,540	$ 4,194	$ 42,918

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Nature Of Operations

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature Of Operations

1. Nature of Operations

Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively, the “Company”), is actively engaged in the exploration, development, and production of crude oil, NGLs, and gas from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas and the Permian Basin in West Texas.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

2. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. The Company evaluates subsequent events through the date the financial statements are issued.

Significant estimates include volumes of proved oil and gas reserves, which are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated costs and timing of cash outflows underlying asset retirement obligations. Oil and gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title and drilling requirements. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil and gas reserves, oil and gas prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in the Company’s estimates. Other significant estimates are involved in determining acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of derivative assets and liabilities, fair values of contingent consideration, preferred stock fair value upon issuance, grant date fair value of stock-based awards, and evaluating disputed claims, interpreting contractual arrangements and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling and completion, testing and production as well as subsequent changes in oil and gas prices, interest rates and the market value and volatility of the Company’s common stock.

Cash and Cash Equivalents

Cash equivalents include highly liquid investments with original maturities of three months or less. Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The outstanding checks written against these zero-balance accounts have been classified as a component of accounts payable in the consolidated balance sheets and totaled $62.6 million and $34.3 million as of December 31, 2017 and 2016, respectively.

Accounts Receivable

As of December 31, 2017 payables due to related parties were less than $0.1 million and as of December 31, 2016, receivables due from related parties were $0.9 million. The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. As of December 31, 2017 and 2016, the Company’s allowance for doubtful accounts was $0.4 million and $0.8 million, respectively.

Concentration of Credit Risk

The Company’s accounts receivable consists primarily of receivables from oil and gas purchasers and joint interest owners in properties the Company operates. This concentration of accounts receivable from oil and gas purchasers and joint interest owners in the oil and gas industry may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company generally does not require collateral from its purchasers or joint interest owners. The Company generally has the right to withhold revenue distributions to recover past due receivables from joint interest owners.

Major Customers

Shell Trading (US) Company accounted for approximately 69%, 56%, and 65% of the Company’s total revenues in 2017, 2016, and 2015, respectively. Flint Hills Resources, LP, an indirect wholly owned subsidiary of Koch Industries, Inc. accounted for approximately 7%, 15% and 9% of the Company’s total revenues in 2017, 2016 and 2015, respectively.

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to cost centers established on a country-by-country basis. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either proved or unproved oil and gas properties based on the type of activity and totaled $14.8 million, $10.5 million and $15.8 million for the years ended December 31, 2017, 2016 and 2015, respectively. Internal costs related to production, general corporate overhead and similar activities are expensed as incurred.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to proved oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average DD&A per Boe of proved oil and gas properties was $13.09, $13.50 and $22.05 for the years ended December 31, 2017, 2016 and 2015, respectively.

Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Individually significant unevaluated leaseholds 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 reclassified to proved oil and gas properties. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling, completion, and infrastructure capital expenditure plans. Individually insignificant unevaluated leaseholds are grouped by major area and added to proved oil and gas properties based on the average primary lease term of the properties. Geological and geophysical costs not associated with specific prospects are recorded to proved oil and gas property costs as incurred. The Company capitalized interest costs to unproved properties totaling $28.3 million, $17.0 million and $32.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings.

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 average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment.

The Company did not recognize impairments of proved oil and gas properties for the year ended December 31, 2017. For the years ended December 31, 2016 and 2015, the Company recorded impairments of proved oil and gas properties of $576.5 million and $1,224.4 million, due primarily to declines in the 12-Month Average Realized Price of crude oil.

Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of proved oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For the years ended December 31, 2017, 2016 and 2015, the Company did not have any sales of oil and gas properties that significantly altered such relationship. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties.”

Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from three to ten years.

Debt Issuance Costs

Debt issuance costs associated with the revolving credit facility are amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are amortized to interest expense using the effective interest method over the terms of the related notes. Debt issuance costs associated with the revolving credit facility are classified in “Other assets” in the consolidated balance sheets while the debt issuance costs associated with the senior notes are classified as a reduction of the related long-term debt in the consolidated balance sheets.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration determined to be embedded derivatives and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s commodity derivative assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk adjustments. The fair values of the Company’s contingent consideration are determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate.

The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s senior notes and other long-term debt may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the senior notes and other long-term debt bear interest at fixed rates. See “Note 6. Long-Term Debt” and “Note 12. Fair Value Measurements.”

Asset Retirement Obligations

The Company’s asset retirement obligations represent the present value of the estimated future costs associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows are discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates consider historical experience, third party estimates, the requirements of oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations are recognized when the well is drilled or acquired or when the production equipment and facilities are installed or acquired with an associated increase in proved oil and gas property costs. Asset retirement obligations are accreted each period through DD&A to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. Cash paid to settle asset retirement obligations is included in net cash provided by operating activities from continuing operations in the consolidated statements of cash flows. On a quarterly basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. At least annually, the Company reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Revisions typically occur due to changes in estimated costs or well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells. See “Note 7. Asset Retirement Obligations.”

Commitments and Contingencies

Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable. See “Note 8. Commitments and Contingencies.”

Revenue Recognition

Crude oil, NGL and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. The Company follows the sales method of accounting whereby revenues from the production of natural gas from properties in which the Company has an interest with other producers are recognized for production sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved reserves. Sales volumes are not significantly different from the Company’s share of production and as of December 31, 2017 and 2016, the Company did not have any material production imbalances.

Derivative Instruments

The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling, completion, and infrastructure capital expenditure program. All derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As the Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from operating activities. The Company does not enter into derivative instruments for speculative or trading purposes.

The Company’s Board of Directors establishes risk management policies and, on a quarterly basis, reviews its commodity derivative instruments, including volumes, types of instruments and counterparties. These policies require that commodity derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. See “Note 11. Derivative Instruments” for further discussion of the Company’s commodity derivative instruments.

The Company has entered into agreements for acquisitions or divestitures of oil and gas properties that include obligations to pay the seller or rights to receive from the buyer, respectively, additional consideration if commodity prices exceed certain thresholds during certain specified periods in the future. These contingent consideration liabilities and assets are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheet, with subsequent changes in fair value recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. Cash payments made to settle contingent consideration liabilities are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 11. Derivative Instruments” for further discussion of the contingent consideration.

Preferred Stock and Warrants

The Company applies the accounting standards for distinguishing liabilities from equity when determining the classification and measurement of preferred stock. Preferred stock that is not mandatorily redeemable is excluded from liability classification and is evaluated for classification in shareholders’ equity or temporary equity. As the number of common shares that could be delivered upon the holders’ optional redemption is indeterminate, the Company cannot assert that it will be able to settle in shares of its common stock and, as a result, presents preferred stock as temporary equity. On a quarterly basis, the Company reassesses the presentation of preferred stock in the consolidated balance sheets.

When preferred stock is issued in conjunction with warrants, the warrants are evaluated separately as a freestanding financial instrument to determine whether they must be recorded as a derivative instrument. The Company further evaluates the warrants for equity classification and have determined the warrants qualify for equity classification and, therefore, are presented in additional paid-in capital in the consolidated balance sheets. The preferred stock and warrants are recorded based on the net proceeds received allocated to the two instrument’s relative fair values. The preferred stock is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The warrants do not require further adjustments from their relative fair value at the issuance date.

Dividends and accretion associated with preferred stock are presented in the consolidated statements of operations as reductions to net income, or increases of net loss, to derive net income (loss) attributable to common shareholders. Dividend payments are presented as a financing activity in the consolidated statement of cash flows.

See “Note 9. Preferred Stock and Warrants” for further details of the Company’s outstanding preferred stock and warrants.

Stock-Based Compensation

The Company recognized stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“SARs”) and performance share awards, which is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties. See “Note 10. Shareholders’ Equity and Stock Based Compensation” for further details of the awards discussed below.

Restricted Stock Awards and Units. Stock-based compensation expense is based on the price of the Company’s common stock on the grant date and recognized over the vesting period (generally one to three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method.

Stock Appreciation Rights. For SARs, stock-based compensation expense is initially based on the grant date fair value determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period and recognized over the vesting period (generally two or three years) using the graded vesting method. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at the end of each reporting period based on the intrinsic value of the SAR. The liability for SARs is classified as “Other current liabilities” for the portion of the fair value liability attributable to awards that are vested or are expected to vest within the next 12 months and have an exercise price in excess of the market price at the end of the reporting period, with the remainder classified as “Other liabilities” in the consolidated balance sheets. SARs typically expire between four and seven years after the date of grant. If SARs expire unexercised, the cumulative compensation costs associated with the unexercised SARs will be zero.

Performance Share Awards. For performance share awards, stock-based compensation expense is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over an approximate three year vesting period using the straight-line method. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of performance share awards granted based on the Company’s total shareholder return relative to a specified industry peer group over an approximate three year performance period. Compensation costs related to the performance share awards will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the market condition is not achieved.

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. See “Note 5. Income Taxes” for further discussion of the deferred tax assets valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense. The Company applies the tax law ordering approach to determine the sequence in which deferred tax assets and other tax attributes are utilized.

Net Income (Loss) Attributable to Common Shareholders Per Common Share

Basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted net income (loss) attributable to common shareholders per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include restricted stock awards and units, performance share awards, stock options and warrants. The Company includes the number of restricted stock awards and units, stock options and warrants in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s common stock for the period. The Company includes the number of performance share awards in the calculation of diluted weighted average common shares outstanding based on the number of shares, if any, that would be issuable as if the end of the period was the end of the performance period. When a loss attributable to common shareholders exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding.

Supplemental net income (loss) attributable to common shareholders per common share information is provided below:

	Years Ended December 31,
	2017		2016			2015
	(In thousands, except per share amounts)
Net Income (Loss) Attributable to Common Shareholders		$78,467		($675,474	)		($1,155,154	)
Basic weighted average common shares outstanding	73,421		59,932			51,457
Effect of dilutive instruments	572		—			—
Diluted weighted average common shares outstanding	73,993		59,932			51,457
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$1.07		($11.27	)		($22.45	)
Diluted		$1.06		($11.27	)		($22.45	)

When the Company recognizes a net loss attributable to common shareholders, as was the case for the years ended December 31, 2016 and 2015, all potentially dilutive shares are anti-dilutive and excluded from the calculation of diluted weighted average common shares outstanding. The table below presents the weighted average dilutive and anti-dilutive shares outstanding for the periods presented:

	Years Ended December 31,
	2017	2016	2015
	(In thousands)
Dilutive	572	—	—
Anti-dilutive	52	669	649

Recently Adopted Accounting Pronouncement

Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures, minimum statutory tax withholdings, and prescribes certain disclosures to be made in the period of adoption.

Effective January, 1, 2017, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero. Effective January 1, 2017, all windfall tax benefits and tax shortfalls are recorded as income tax expense or benefit in the consolidated statements of operations, whereas prior to adoption, windfall tax benefits were recorded as an increase to additional paid-in capital. In addition, windfall tax benefits, along with tax shortfalls, are now required to be classified as an operating cash flow as opposed to a financing cash flow. Further, the Company has elected to account for forfeitures of share-based payment awards as they occur, which resulted in an immaterial cumulative-effect adjustment to retained earnings.

Recently Issued Accounting Pronouncements

Revenue From Contracts With Customers. In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.

The Company will adopt ASU 2014-09 effective January 1, 2018, using the modified retrospective approach, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company has performed an analysis of existing contracts and does not expect adoption to have a material impact on its consolidated financial statements, however, certain immaterial natural gas processing fees, which have historically been netted in revenue, will be recorded to lease operating expense. In addition, the Company has evaluated the expected changes to relevant business practices, accounting policies and control activities and does not expect to have a material change as a result of the adoption of ASU 2014-09.

Business Combinations. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company will adopt ASU 2017-01 effective January 1, 2018 on a prospective basis.

Statement of Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The Company will adopt ASU 2016-15 effective January 1, 2018 using the full retrospective method, meaning the standard is applied to all periods presented. The Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows and related disclosures.

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. ASU 2016-02 requires companies to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach.

The Company is currently assessing the impact of ASU 2016-02 which includes an analysis of existing contracts, including drilling rig contracts, office leases, certain field equipment, vehicles, produced water disposal commitments, pipeline gathering, transportation and gas processing agreements and current accounting policies and disclosures that will change as a result of adopting ASU 2016-02. Appropriate systems, controls, and processes to support the recognition and disclosure requirements of the new standard are also being evaluated. The Company currently expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities, (ii) an increase in depreciation, depletion and amortization expense, (iii) an increase in interest expense, and (iv) additional disclosures. The Company plans to adopt the guidance effective January 1, 2019.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2017

Acquisitions and Divestitures [Abstract]

Acquisitions and Divestitures Disclosures

3. Acquisitions and Divestitures of Oil and Gas Properties

Acquisitions

ExL Acquisition. On June 28, 2017, the Company entered into a purchase and sale agreement with ExL Petroleum Management, LLC and ExL Petroleum Operating Inc. (together “ExL”) to acquire oil and gas properties located in the Delaware Basin in Reeves and Ward Counties, Texas (the “ExL Properties”) for an agreed upon price of $648.0 million, with an effective date of May 1, 2017, subject to customary purchase price adjustments (the “ExL Acquisition”). The Company paid $75.0 million as a deposit on June 28, 2017, $601.0 million upon closing on August 10, 2017 and $3.8 million upon post-closing on December 8, 2017, for an aggregate cash consideration of $679.8 million, which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. Upon closing the ExL Acquisition, the Company became the operator of the ExL Properties with an approximate 70% average working interest.

The Company also agreed to pay an additional $50.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $50.00 for any of the years of 2018, 2019, 2020 and 2021, with such payments due on January 29, 2019, January 28, 2020, January 28, 2021 and January 28, 2022, respectively. This payment (the “Contingent ExL Consideration”) will be zero for the respective year if such EIA WTI average price of a barrel of oil is $50.00 or below for any of such years, and the Contingent ExL Consideration is capped at $125.0 million in the aggregate. The Company determined that the Contingent ExL Consideration is an embedded derivative and has reflected the liability at fair value in non-current “Derivative liabilities” in the consolidated balance sheets. The fair value of the Contingent ExL Consideration as of December 31, 2017 and August 10, 2017 was $85.6 million and $52.3 million, respectively. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further details.

The Company funded the ExL Acquisition with net proceeds from the sale of preferred stock on August 10, 2017, net proceeds from the common stock offering completed on July 3, 2017, and net proceeds from the senior notes offering completed on July 14, 2017. See “Note 9. Preferred Stock and Warrants” for details regarding the sale of Preferred Stock, “Note 10. Shareholders’ Equity and Stock-Based Compensation” for details regarding the common stock offering and “Note 6. Long-Term Debt” for details regarding the senior notes offering.

The ExL Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party valuation specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The fair value of the Contingent ExL Consideration was determined by a third-party valuation specialist using a Monte Carlo simulation. Significant inputs into the calculation included future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. See “Note 12. Fair Value Measurements” for further details.

The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$106
Oil and gas properties
Proved properties	294,754
Unproved properties	443,194
Total oil and gas properties		$737,948
Total assets acquired		$738,054
Liabilities
Revenues and royalties payable		$5,785
Asset retirement obligations	153
Contingent ExL Consideration	52,300
Total liabilities assumed		$58,238
Net Assets Acquired		$679,816

Included in the consolidated statements of operations for the year ended December 31,2017 are total revenues of $53.5 million and net income attributable to common shareholders of $44.3 million from the ExL Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction.

Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2017 and 2016, assuming the ExL Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the ExL Acquisition.

	Years Ended December 31,
	2017		2016
	(In thousands, except per share amounts)
Total revenues		$781,378		$454,913
Net Income (Loss) Attributable to Common Shareholders		$91,931		($688,180	)
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$1.25		($9.11	)
Diluted		$1.24		($9.11	)
Weighted Average Common Shares Outstanding
Basic	73,421		75,532
Diluted	73,993		75,532

Sanchez Acquisition. On October 24, 2016, the Company entered into a purchase and sale agreement with Sanchez Energy Corporation and SN Cotulla Assets, LLC, a subsidiary of Sanchez Energy Corporation to acquire oil and gas properties located in the Eagle Ford Shale (the “Sanchez Acquisition”) for an agreed upon price of $181.0 million, with an effective date of June 1, 2016, subject to customary purchase price adjustments. The Company paid $10.0 million as a deposit on October 24, 2016, $143.5 million upon the initial closing on December 14, 2016, and $7.0 million and $9.8 million on January 9, 2017 and April 13, 2017, respectively, for leases that were not conveyed to the Company at the time of the initial closing, for aggregate cash consideration of $170.3 million, which included purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. The Sanchez Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated acquisition date fair values based on then available information.

The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$477
Oil and gas properties
Proved properties	99,938
Unproved properties	74,536
Total oil and gas properties	174,474
Total assets acquired		$174,951
Liabilities
Revenues and royalties payable		$1,442
Other current liabilities	323
Asset retirement obligations	2,054
Other liabilities	1,078
Total liabilities assumed		$4,897
Net Assets Acquired		$170,054

Included in the consolidated statements of operations for the year ended December 31,2017 are total revenues of $37.8 million and net income attributable to common shareholders of $16.5 million from the Sanchez Acquisition, representing activity of the acquired properties subsequent to the closing of the transaction.

Divestitures

Utica. On August 31, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Utica Shale, located primarily in Guernsey County, Ohio, for an agreed upon price of $62.0 million, with an effective date of April 1, 2017, subject to customary purchase price adjustments. On August 31, 2017, the Company received $6.2 million as a deposit, on November 15, 2017, the Company received $54.4 million at closing, subject to post-closing adjustments, and on December 28, 2017, the Company received $2.5 million, for aggregate net proceeds of $63.1 million, which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date.

The Company could also receive contingent consideration of $5.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $50.00, $53.00, and $56.00 for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Utica Consideration”). The Contingent Utica Consideration will be zero for the respective year if such EIA WTI average price of a barrel of oil is at or below the per barrel amounts listed above for any of such years. The Company determined that the Contingent Utica Consideration is an embedded derivative and has reflected the asset at fair value in non-current “Other assets” in the consolidated balance sheets. The fair value of the Contingent Utica Consideration as of December 31, 2017 and November 15, 2017 was $8.0 million and $6.1 million, respectively. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further details.

The aggregate net proceeds of $63.1 million were recognized as a reduction of proved oil and gas properties. The contingent consideration, if received, will be recognized as a reduction of the fair value asset in the consolidated balance sheets.

Marcellus. On October 5, 2017, the Company entered into a purchase and sale agreement with BKV Chelsea, LLC, a subsidiary of Kalnin Ventures LLC, to sell substantially all of its assets in the Marcellus Shale for an agreed upon price of $84.0 million, with an effective date of April 1, 2017, subject to customary purchase price adjustments. On October 5, 2017, the Company received $6.3 million into escrow as a deposit and on November 21, 2017, the Company received $67.6 million at closing, subject to post-closing adjustments, for aggregate net proceeds of $73.9 million, which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date.

The Company could also receive contingent consideration of $3.0 million per year if the average settlement prices of a 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. (the “CME HH average price”) is above $3.13, $3.18, and $3.30 for the years of 2018, 2019, and 2020, respectively, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Marcellus Consideration”). This conditional consideration will be zero for the respective year if such CME HH average price of a MMBtu of Henry Hub natural gas is at or below the per MMBtu amounts listed above for any of such years, and is capped at $7.5 million. The Company determined that the Contingent Marcellus Consideration is an embedded derivative and has reflected the asset at fair value in non-current “Other assets” in the consolidated balance sheets. The fair value of the Contingent Marcellus Consideration as of December 31, 2017 and November 21, 2017 was $2.2 million and $2.7 million, respectively. See “Note 11. Derivative Instruments” and “Note 12. Fair Value Measurements” for further details.

The aggregate net proceeds of $73.9 million were recognized as a reduction of proved oil and gas properties. The contingent consideration, if received, will be recognized as a reduction of the fair value asset in the consolidated balance sheets.

Simultaneous with the signing of the Marcellus Shale transaction discussed above, the Company’s existing joint venture partner in the Marcellus Shale, Reliance Marcellus II, LLC (“Reliance”), a wholly owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited, entered into a purchase and sale agreement with BKV Chelsea, LLC to sell its interest in the same oil and gas properties. Simultaneous with the closing of these Marcellus Shale sale transactions, the agreements governing the Reliance joint venture were assigned to the buyer and, after giving effect to such transactions, the Reliance joint venture was terminated except for limited post-closing obligations.

Niobrara. On November 20, 2017, the Company entered into a purchase and sale agreement to sell substantially all of its assets in the Niobrara Formation for an agreed upon price of $140.0 million, with an effective date of October 1, 2017, subject to customary purchase price adjustments. On November 20, 2017, the Company received $14.0 million as a deposit, which is refundable only in specified circumstances if the transaction is not consummated and is classified as “Other liabilities” in the consolidated balance sheets and as “Net proceeds from divestitures of oil and gas properties” in the cash flows from investing activities section in the consolidated statements of cash flows. On January 19, 2018, the Company received $122.6 million at closing, subject to post-closing adjustments, for aggregate net proceeds of $136.6 million, which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date.

The Company could also receive contingent consideration of $5.0 million per year if the average daily closing spot price of a barrel of West Texas Intermediate crude oil as measured by the U.S. Energy Information Administration (the “EIA WTI average price”) is above $55.00 for the years of 2018 and 2019 and above $60.00 for 2020, with such receipts due on January 29, 2019, January 28, 2020, and January 28, 2021, respectively (the “Contingent Niobrara Consideration”). The Contingent Niobrara Consideration will be zero for the respective year if such EIA WTI average price of a barrel of oil is at or below the per barrel amounts listed above for any of such years.

Eagle Ford. On December 11, 2017, the Company entered into a purchase and sale agreement with EP Energy E&P Company, L.P. to sell a portion of its assets in the Eagle Ford Shale for an agreed upon price of $245.0 million, with an effective date of October 1, 2017, subject to adjustment and customary terms and conditions. On December 11, 2017, the Company received $24.5 million as a deposit, which is refundable only in specified circumstances if the transaction is not consummated and is classified as “Other liabilities” in the consolidated balance sheets and as “Net proceeds from divestitures of oil and gas properties” in the cash flows from investing activities section in the consolidated statements of cash flows. On January 31, 2018, the Company received $211.7 million at closing, subject to post-closing adjustments, and on February 16, 2018, the Company received $10.0 million for leases that were not conveyed at closing, for aggregate net proceeds of $246.2 million, which includes preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date.

In the first quarter of 2018, the aggregate net proceeds that were received for the Niobrara and Eagle Ford divestitures will be recognized as reductions of proved oil and gas properties and the Contingent Niobrara Consideration will be recognized as an asset at fair value in the Company's consolidated balance sheet.

Other Assets. During the first quarter of 2017, the Company sold a small undeveloped acreage position in the Delaware Basin for net proceeds of $15.3 million. The proceeds from this sale were recognized as a reduction of proved oil and gas properties.

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Property And Equipment, Net

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property And Equipment, Net

4. Property and Equipment, Net

As of December 31, 2017 and 2016, total property and equipment, net consisted of the following:

	December 31,
	2017			2016
Oil and gas properties, full cost method	(In thousands)
Proved properties		$5,615,153			$4,687,416
Accumulated DD&A and impairments	(3,649,806		)	(3,392,749		)
Proved properties, net	1,965,347			1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	612,589			211,067
Capitalized interest	47,698			29,894
Total unproved properties, not being amortized	660,287			240,961
Other property and equipment	25,625			23,127
Accumulated depreciation	(15,449		)	(12,995		)
Other property and equipment, net	10,176			10,132
Total property and equipment, net		$2,635,810			$1,545,760

Costs not subject to amortization totaling $660.3 million at December 31, 2017 were incurred in the following periods: $523.1 million in 2017, $106.8 million in 2016 and $24.0 million in 2015.

Impairments of Proved Oil and Gas Properties

The Company did not recognize impairments of proved oil and gas properties for the year ended December 31,2017. Primarily due to declines in the 12-Month Average Realized Price of crude oil, the Company recognized impairments of proved oil and gas properties of $576.5 million and $1,224.4 million for the years ended December 31, 2016 and 2015, respectively.

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

5. Income Taxes

The components of income tax (expense) benefit from continuing operations were as follows:

	Years Ended December 31,
	2017			2016		2015
	(In thousands)
Current income tax (expense) benefit
U.S. Federal		$—			$—		$—
State	(395		)	—		—
Total current income tax (expense) benefit	(395		)	—		—
Deferred income tax (expense) benefit
U.S. Federal	—			—		131,502
State	(3,635		)	—		9,373
Total deferred income tax (expense) benefit	(3,635		)	—		140,875
Total income tax (expense) benefit from continuing operations		($4,030	)		$—		$140,875

The Company’s income tax (expense) benefit from continuing operations differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) from continuing operations before income taxes as follows:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Income (loss) from continuing operations before income taxes		$91,140			($675,474	)		($1,298,760	)
Income tax (expense) benefit at the statutory rate	(31,899		)	236,416			454,566
State income tax (expense) benefit, net of U.S. Federal income taxes	(4,030		)	3,894			9,373
Tax shortfalls from stock-based compensation expense	(3,089		)	—			—
Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense	—			—			1,671
Provisional impact of Tax Cuts and Jobs Act	(211,724		)	—			—
Change in valuation allowance from provisional impact of Tax Cuts and Jobs Act	211,724			—			—
Change in valuation allowance from current year activity	35,376			(240,864		)	(323,586		)
Other	(388		)	554			(1,149		)
Income tax (expense) benefit		($4,030	)		$—			$140,875

Significant changes in the Company’s operations in 2017, including the ExL Acquisition in the Delaware Basin and divestitures of substantially all of the Company's assets in the Utica and Marcellus Shales, resulted in changes to the Company's anticipated future state apportionment for estimated state deferred tax liabilities. As a result of these changes, the Company recorded a $3.6 million state deferred tax expense primarily associated with future Texas deferred tax liabilities.

Deferred Income Taxes

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. As of December 31, 2017 and 2016, deferred tax assets and liabilities are comprised of the following:

	December 31,
	2017			2016
	(In thousands)
Deferred income tax assets
Net operating loss carryforward - U.S. Federal and State		$242,915			$221,063
Oil and gas properties	50,177			309,848
Asset retirement obligations	4,996			7,434
Stock-based compensation	—			5,238
Derivative liabilities	35,585			17,545
Other	1,496			3,739
Deferred income tax assets	335,169			564,867
Deferred tax asset valuation allowance	(333,029		)	(564,434		)
Net deferred income tax assets	2,140			433
Deferred income tax liabilities
Oil and gas properties	(3,635		)	—
Derivative assets	(2,140		)	(433		)
Net deferred income tax asset (liability)		($3,635	)		$—

Tax Cuts and Jobs Act

On December 22, 2017, the U.S. Congress enacted the Tax Cuts and Jobs Act (the “Act”) which made significant changes to U.S. federal income tax law, including lowering the federal statutory corporate income tax rate to 21% from 35% beginning January 1, 2018. The income tax effects of changes in tax laws are recognized in the period when enacted. While the Company continues to assess the impact of the tax reform legislation on its business and consolidated financial statements, the Company remeasured its deferred tax balances by applying the reduced rate and and recorded a provisional deferred tax expense of $211.7 million during the year ended December 31, 2017. This provisional deferred tax expense was fully offset by a $211.7 million deferred tax benefit as a result of the associated change in the valuation allowance against the net deferred tax assets. As reflected in the rate reconciliation above, the change in the deferred tax balances due to the rate reduction had no impact on the net deferred tax balances reported in the consolidated balance sheets as of December 31, 2017 and no impact in the consolidated statements of operations for the year ended December 31, 2017.

Due to the uncertainty or diversity in views about the application of ASC 740 in the period of enactment of the Act, the SEC issued Staff Accounting Bulletin 118 (“SAB 118”) which allows the Company to provide a provisional estimate of the impacts of the Act in its earnings for the year ended December 31, 2017. The Company's estimate does not reflect changes in current interpretations of performance based executive compensation deduction limitations, effects of any state tax law changes and uncertainties regarding interpretations that may arise as a result of federal tax reform. The Company will continue to analyze the effects of the Act in its consolidated financial statements and operations. Additional impacts from the enactment of the Act will be recorded as they are identified during the one-year measurement period provided for in SAB 118. As of December 31, 2017, the Company has not completed its accounting for the tax effects of enactment of the Act; however, the Company has made a reasonable estimate of the effects on it existing deferred tax balances.

Deferred Tax Assets Valuation Allowance

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 deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluated possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies.

A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2017, driven primarily by the impairments of proved oil and gas properties recognized beginning in the third quarter of 2015 and continuing through the third quarter of 2016, which limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the third quarter of 2015 and continuing through the fourth quarter of 2017, the Company concluded that it was more likely than not the deferred tax assets will not be realized. As a result, the net deferred tax assets at the end of each quarter, including December 31, 2017 were reduced to zero.

Effective January 1, 2017, the Company adopted ASU 2016-09, and the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero and brought the valuation allowance to $580.1 million as of January 1, 2017.

For the year ended December 31,2017, the Company reduced the valuation allowance by $247.1 million. This was primarily due to the re-measurement of its deferred tax assets as a result of the Act as mentioned above as well as partial releases of $35.4 million, as a result of current year activity. After the impact of the re-measurement and the partial releases, the valuation allowance as of December 31, 2017 was $333.0 million, of which $12.7 million is a valuation allowance against state deferred tax assets.

The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes sufficient taxable income within the carryforward periods. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant federal deferred income tax expense or benefit. However, the Company currently expects to continue to have state deferred income tax expense or benefit as a result of change in state deferred tax liabilities as the Company's operations become more heavily weighted towards Texas.

Net Operating Loss Carryforwards and Other

Net Operating Loss Carryforwards. As of December 31, 2017, the Company had U.S. federal net operating loss carryforwards of approximately $1,096.2 million. If not utilized in earlier periods, the U.S. federal net operating loss will expire between 2026 and 2037.

The ability of the Company to utilize its U.S. 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 upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the Company multiplied by (ii) 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.

Due to the issuance of the Preferred Stock and the common stock offering associated with the ExL Acquisition, the Company’s calculated ownership change percentage increased, however, as of December 31, 2017, the Company does not believe it has a Section 382 limitation on the ability to utilize its U.S. loss carryforwards. Future equity transactions involving the Company or 5% shareholders of the Company (including, potentially, relatively small transactions and transactions beyond the Company’s control) could cause further ownership changes and therefore a limitation on the annual utilization of the U. S. loss carryforwards.

Other. The Company files income tax returns in the U.S. Federal jurisdiction and various states, each with varying statutes of limitations. The 1999 through 2017 tax years generally remain subject to examination by federal and state tax authorities. As of December 31, 2017, 2016 and 2015, the Company had no uncertain tax positions.

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Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt

6. Long-Term Debt

Long-term debt consisted of the following as of December 31, 2017 and 2016:

	December 31,
	2017			2016
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$291,300			$87,000
7.50% Senior Notes due 2020	450,000			600,000
Unamortized premium for 7.50% Senior Notes	579			1,020
Unamortized debt issuance costs for 7.50% Senior Notes	(4,492		)	(7,573		)
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(8,208		)	(9,454		)
8.25% Senior Notes due 2025	250,000			—
Unamortized debt issuance costs for 8.25% Senior Notes	(4,395		)	—
Other long-term debt due 2028	4,425			4,425
Long-term debt		$1,629,209			$1,325,418

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility with a syndicate of banks that, as of December 31, 2017, had a borrowing base of $900.0 million, with an elected commitment amount of $800.0 million, and $291.3 million of borrowings outstanding at a weighted average interest rate of 3.73%. As of December 31, 2017, the Company also had $0.4 million in letters of credit outstanding, which reduce the amounts available under the revolving credit facility. The credit agreement governing the revolving credit facility provides for interest-only payments until May 4, 2022 (subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced on or prior to such time), when the credit agreement matures and any outstanding borrowings are due. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the credit agreement. The capitalized terms which are not defined in this description of the revolving credit facility, shall have the meaning given to such terms in the credit agreement.

On May 4, 2017, the Company entered into a ninth amendment to the credit agreement governing the revolving credit facility to, among other things, (i) extend the maturity date of the revolving credit facility to May 4, 2022, subject to a springing maturity date of June 15, 2020 if the 7.50% Senior Notes have not been refinanced or redeemed on or prior to such time, (ii) increase the maximum credit amount under the revolving credit facility from $1.0 billion to $2.0 billion, (iii) increase the borrowing base from $600.0 million to $900.0 million, with an elected commitment amount of $800.0 million, until the next redetermination thereof and (iv) amend certain financial covenants including replacing the Total Secured Debt to EBITDA ratio covenant with a Total Debt to EBITDA ratio and removing the minimum EBITDA to Interest Expense ratio.

On June 28, 2017, the Company entered into a tenth amendment to its credit agreement governing the revolving credit facility to, among other things, (i) amend the calculation of certain financial covenants to provide that EBITDA will be calculated on an annualized basis as of the end of each of the first three fiscal quarters commencing with the quarter ending September 30, 2017 and (ii) amend the restricted payments covenant.

Upon issuance of the 8.25% Senior Notes (described below), in accordance with the credit agreement governing the revolving credit facility, the Company’s borrowing base was reduced by 25% of the aggregate principal amount of the 8.25% Senior Notes, reducing the Company’s borrowing base from $900.0 million to $837.5 million.

On November 3, 2017, the Company entered into an eleventh amendment to its credit agreement governing the revolving credit facility to, among other things, (i) establish the borrowing base at $900.0 million, with an elected commitment amount of $800.0 million, until the next determination thereof, (ii) increase the general basket available for restricted payments from $50.0 million to $75.0 million and (iii) amend certain other provisions, in each case as set forth therein.

The obligations of the Company under the credit agreement are guaranteed by the Company’s material domestic subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and gas properties having at least 90% of the total value of the oil and gas properties included in the Company’s reserve report used in its most recent redetermination.

Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set forth in the table below. The Company also incurs commitment fees at rates as set forth in the table below on the unused portion of lender commitments, which are included in interest expense, net in the consolidated statements of operations.

Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 25%	1.00%	2.00%	0.375%
Greater than or equal to 25% but less than 50%	1.25%	2.25%	0.375%
Greater than or equal to 50% but less than 75%	1.50%	2.50%	0.500%
Greater than or equal to 75% but less than 90%	1.75%	2.75%	0.500%
Greater than or equal to 90%	2.00%	3.00%	0.500%

The Company is subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of Total Debt to EBITDA of not more than 4.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. As defined in the credit agreement, Total Debt excludes debt premiums and debt issuance costs and is net of cash and cash equivalents, EBITDA for the fiscal quarter ended December 31, 2017 is calculated based on an annualized average of the last two fiscal quarters, EBITDA for the fiscal quarter ending March 31, 2018, will be calculated based on an annualized average of the last three fiscal quarters, and EBITDA for fiscal quarters ending thereafter will be calculated based on the last four fiscal quarters, in each case after giving pro forma effect to EBITDA for material acquisitions and dispositions of oil and gas properties, and the Current Ratio includes an add back of the unused portion of lender commitments. As of December 31, 2017, the ratio of Total Debt to EBITDA was 2.59 to 1.00 and the Current Ratio was 1.98 to 1.00. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the level of borrowings outstanding under the credit agreement are impacted by the timing of cash flows from operations, capital expenditures, acquisitions and divestitures of oil and gas properties and securities offerings.

The credit agreement also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions and divestitures of oil and gas properties, mergers, transactions with affiliates, hedging transactions and other matters.

The credit agreement is subject to customary events of default, including in connection with a change in control. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).

Senior Notes

8.25% Senior Notes due 2025. On July 14, 2017, the Company closed a public offering of $250.0 million aggregate principal amount of 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”). The 8.25% Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. The Company used the net proceeds of $245.4 million, net of underwriting discounts and commissions and offering costs, to fund a portion of the purchase price for 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.

7.50% Senior Notes due 2020. On November 28, 2017, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes due 2020 (the “7.50% Senior Notes”) to call for redemption on December 28, 2017, $150.0 million aggregate principal amount of the 7.50% Senior Notes then outstanding. On December 28, 2017, the Company paid an aggregate redemption price of $156.0 million, which included a redemption premium of $2.8 million as well as accrued and unpaid interest of $3.2 million from the last interest payment date up to, but not including, the redemption date. As a result of the redemption of $150.0 million of the 7.50% Senior Notes, the Company recorded a loss on extinguishment of debt of $4.2 million, which includes the redemption premium paid to redeem the notes and non-cash charges of $1.3 million attributable to the write-off of unamortized premium and debt issuance costs associated with the 7.50% Senior Notes. The Company delivered additional notices of redemption to the trustee for its 7.50% Senior Notes subsequent to December 31, 2017. See “Note 15. Subsequent Events (Unaudited)” for further details of these redemptions.

Since September 15, 2017, the Company has had the right to redeem all or a portion of the 7.50% Senior Notes at redemption prices decreasing from 101.875% to 100% of the principal amount on September 15, 2018, plus accrued and unpaid interest.

6.25% Senior Notes due 2023. Before April 15, 2018, the Company may, at its option, redeem all or a portion of the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 104.688% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest.

If a Change of Control (as defined in the indentures governing the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest.

The indentures governing the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes contain covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s common stock or other capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. Such indentures governing the Company’s senior notes are also subject to customary events of default, including those related to failure to comply with the terms of the notes and the indenture, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments. At December 31, 2017, the 8.25% Senior Notes, the 7.50% Senior Notes and the 6.25% Senior Notes are guaranteed by the same subsidiaries that also guarantee the revolving credit facility.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

7. Asset Retirement Obligations

The following table sets forth asset retirement obligations for the years ended December 31, 2017 and 2016:

	Years Ended December 31,
	2017			2016
	(In thousands)
Beginning of year asset retirement obligations		$21,240			$16,511
Liabilities incurred	3,920			2,137
Increase due to acquisition of oil and gas properties	153			2,037
Liabilities settled	(343		)	(599		)
Reduction due to divestitures of oil and gas properties	(2,671		)	—
Accretion expense	1,799			1,364
Revisions to estimated cash flows	(306		)	(210		)
End of year asset retirement obligations	23,792			21,240
Current asset retirement obligations (included in other current liabilities)	(295		)	(392		)
Non-current asset retirement obligations		$23,497			$20,848

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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. 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 the financial position or results of operations of the Company.

The 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, 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 for the years ended December 31, 2017, 2016 and 2015 was $1.7 million, $2.0 million, and $2.2 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 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		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

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

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.

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Preferred Stock

12 Months Ended

Dec. 31, 2017

Preferred Stock [Abstract]

Preferred Stock

9. Preferred Stock and Warrants

On June 28, 2017, the Company entered into a Preferred Stock Purchase Agreement with certain funds managed or sub-advised by GSO Capital Partners LP and its affiliates (the “GSO Funds”) to issue and sell in a private placement (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 GSO Funds $5.0 million as a commitment fee upon signing the Preferred Stock Purchase Agreement. 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 the Preferred Stock and the common stock that may be issued in respect of the Preferred Stock and that underlie the Warrants. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the ExL Acquisition.

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 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 remain outstanding; or

• Upon the occurrence of certain changes of 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 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 Preferred Stock activity for the year ended December 31, 2017:

	December 31, 2017
For the Year Ended December 31, 2017
Preferred Stock, beginning 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 and the 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 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.

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Shareholders' Equity And Stock Incentive Plan

12 Months Ended

Dec. 31, 2017

Shareholders' Equity And Stock Incentive Plan [Abstract]

Shareholders' Equity And Stock Incentive Plan

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 of Common Stock

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 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 facility and 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 portion of the borrowings under the Company’s revolving credit facility and for general corporate purposes.

Stock-Based Compensation

At the Company’s annual meeting of shareholders on May 16, 2017, shareholders approved the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “2017 Incentive Plan”), which replaced the Incentive Plan of Carrizo Oil & Gas, Inc., as amended and restated effective May 15, 2014 (the “Prior Incentive Plan”). From the effective date of the 2017 Incentive Plan, no further awards may be granted under the Prior Incentive Plan, however, awards previously granted under the Prior Incentive Plan will remain outstanding in accordance with their terms. 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. 

As of December 31, 2017, there were 1,750,908 common shares remaining available for grant under the 2017 Incentive Plan. Each restricted stock award, restricted stock unit, or performance share granted under the 2017 Incentive Plan counts as 1.35 shares while a stock option or stock-settled stock appreciation right granted under the 2017 Incentive Plan counts as 1.00 share against the number of common shares 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.

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

	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
Granted	887,254			$27.80
Vested	(811,136	)		$36.32
Forfeited	(6,405	)		$34.46
Unvested restricted stock awards and units, end of period	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
Granted	1,020,465			$25.63
Vested	(635,965	)		$39.62
Forfeited	(13,555	)		$29.11
Unvested restricted stock awards and units, end of period	1,482,655			$28.07

The aggregate fair value of restricted stock awards and units that vested during the years ended December 31, 2017, 2016 and 2015 was $20.3 million, $26.3 million and $32.0 million, respectively.

Stock Appreciation Rights (“SARs”). SARs can be granted to employees and independent contractors under the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SAR Plan”) or the 2017 Incentive Plan. SARs granted under the 2017 Incentive Plan can be settled in shares of common stock or cash, at the option of the Company, while SARs granted under the Cash SAR Plan may only be settled in cash. All outstanding SARs have been granted under the Cash SAR Plan and therefore will be settled solely in cash. The grant date fair value of SARs is calculated using the Black-Scholes-Merton option pricing model. The liability for SARs as of December 31, 2017 was $4.4 million, all of which was classified as “Other liabilities” in the consolidated balance sheets. As of December 31, 2016, the liability for SARs was $11.5 million, of which $10.0 million was classified as “Other current liabilities,” with the remaining $1.5 million classified as “Other liabilities” in the consolidated balance sheets. Unrecognized compensation costs related to unvested SARs was $1.3 million as of December 31, 2017, and will be recognized over a weighted average period of 1.1 years.

The table below summarizes the activity for SARs for the years ended December 31, 2017, 2016 and 2015:

	Stock Appreciation Rights		Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)		Aggregate Intrinsic Value of Exercises (In millions)
For the Year Ended December 31, 2015
Outstanding, beginning of period	765,198			$22.49
Granted	—		—
Exercised	(64,745	)		$29.40					$1.5
Forfeited	—		—
Outstanding, end of period	700,453			$21.86
Vested, end of period	626,661			$21.05
Vested and exercisable, end of period	626,661			$21.05
For the Year Ended December 31, 2016
Outstanding, beginning of period	700,453			$21.86
Granted	376,260		27.30
Exercised	(354,075	)		$23.89					$5.2
Forfeited	—		—
Outstanding, end of period	722,638			$23.69
Vested, end of period	350,840			$19.87
Vested and exercisable, end of period	350,840			$19.87
For the Year Ended December 31, 2017
Outstanding, beginning of period	722,638			$23.69
Granted	342,440			$26.94
Exercised	(219,279	)		$17.28					$2.1
Forfeited	—		—
Expired	(131,561	)		$24.19
Outstanding, end of period	714,238			$27.12	3.7		$—
Vested, end of period	185,899			$27.30
Vested and exercisable, end of period	—			$27.30	3.2		$—

No SARs were granted during the year ended December 31, 2015. The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the years ended December 31, 2017 and 2016:

	Years Ended December 31,
	2017		2016
Expected term (in years)	4.24		3.93
Expected volatility	54.3	%	45.1	%
Risk-free interest rate	1.8	%	1.3	%
Dividend yield	—	%	—	%

Performance Shares. The Company can grant performance shares to employees and independent contractors, where each performance share represents the right to receive one share of common stock. The number of performance shares that will vest ranges from zero to 200% of the target performance shares granted based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR achieved by a specified industry peer group over an approximate three year performance period, the last day of which is also the vesting date. The grant date fair value of the performance awards is calculated using a Monte Carlo simulation. As of December 31, 2017, unrecognized compensation costs related to unvested performance shares was $2.1 million and will be recognized over a weighted average period of 1.7 years.

The table below summarizes performance share activity for the years ended December 31, 2017, 2016 and 2015:

	Target Performance Shares (1)		Weighted Average Grant Date Fair Value
For the Year Ended December 31, 2015
Unvested performance shares, beginning of period	56,342			$68.15
Granted	56,517			$65.51
Vested	—		—
Forfeited	—		—
Unvested performance shares, end of period	112,859			$66.83
For the Year Ended December 31, 2016
Unvested performance shares, beginning of period	112,859			$66.83
Granted	41,651			$35.71
Vested	—		—
Forfeited	—		—
Unvested performance shares, end of period	154,510			$58.44
For the Year Ended December 31, 2017
Unvested performance shares, beginning of period	154,510			$58.44
Granted	46,787			$35.14
Vested	(56,342	)		$68.15
Forfeited	—		—
Unvested performance shares, end of period	144,955			$47.14

(1) The number of shares of common stock issued upon vesting may vary from the number of target performance shares depending on the Company’s final TSR ranking for the approximate three year performance period.

During the first quarter of 2017, the Company issued 92,200 shares of common stock for 56,342 target performance shares that vested during the first quarter of 2017 with a multiplier of 164% based on the Company’s final TSR ranking during the performance period.

The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the years ended December 31, 2017, 2016 and 2015:

	Years Ended December 31,
	2017		2016		2015
Number of simulations	500,000		500,000		500,000
Expected term (in years)	2.98		3.01		2.89
Expected volatility	59.2	%	55.3	%	45.3	%
Risk-free interest rate	1.5	%	1.2	%	0.9	%
Dividend yield	—	%	—	%	—	%

Stock-Based Compensation Expense, Net. Stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash and performance shares is reflected as general and administrative expense, net of amounts capitalized to oil and gas properties in the consolidated statements of operations.

The Company recognized the following stock-based compensation expense, net for the periods indicated:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Restricted stock awards and units		$21,372			$28,196			$23,668
Stock appreciation rights	(5,023		)	9,675			(6,326		)
Performance shares	2,442			2,806			1,961
	18,791			40,677			19,303
Less: amounts capitalized to oil and gas properties	(4,482		)	(4,591		)	(4,574		)
Total stock-based compensation expense, net		$14,309			$36,086			$14,729

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Derivative Instruments

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

11. Derivative Instruments

Commodity Derivative Instruments

The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling, completion, and infrastructure capital expenditure program. The Company does not enter into derivative instruments for speculative or trading purposes. The Company’s commodity derivative instruments consist of fixed price swaps, basis swaps, three-way collars and purchased and sold call options, which are described below.

Fixed Price Swaps: The Company receives a fixed price and pays a variable market price to the counterparties over specified periods for contracted volumes.

Basis Swaps: The 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 of options including a purchased put option (fixed floor price), a sold call option (fixed ceiling price) and a sold put option (fixed 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 between the fixed 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. If the market price is below the fixed sub-floor price, the Company receives the market price plus the difference between the fixed floor price and the fixed sub-floor price. If the market price is between the fixed floor price and fixed ceiling price, no payments are due from either party. The Company has incurred premiums on certain of these contracts 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 of 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 the Company has entered into three-way collars which span multiple years, 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 derivative positions at weighted average contract prices as of December 31, 2017:

Crude Oil Fixed Price Swaps

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	)

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

The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company nets its derivative instrument fair values executed with the same counterparty, along with deferred premium obligations, to a single asset or liability pursuant to ISDA master agreements, 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 derivative instruments who are also lenders under the Company’s credit agreement allow the Company to satisfy any need for margin obligations associated with derivative instruments where the Company is in a net liability position with its counterparties with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting. Counterparties who are not lenders under the Company’s credit agreement can require derivative contracts to be novated to a lender if the net liability position exceeds the Company’s unsecured credit limit with that counterparty and therefore do not require the posting of cash collateral.

Because the counterparties have investment grade credit ratings, or the Company has obtained guarantees from the applicable counterparty’s investment grade parent company, 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 derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of its counterparties and its counterparty’s parent company, as applicable.

Contingent Consideration

As part of the ExL Acquisition, the Company agreed to the Contingent ExL Consideration that will require payment of $50.0 million per year for each 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, the Company agreed to the Contingent Niobrara Consideration. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details.

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 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, recorded in the consolidated balance sheets as of December 31, 2017 and 2016 are summarized below:

	December 31, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$4,869			($4,869	)		$—
Deferred premium obligations	—			—			—
Other current assets		$4,869			($4,869	)		$—
Commodity derivative instruments	9,505			(9,505		)	—
Deferred premium obligations	—			—			—
Contingent consideration	10,190			—			10,190
Other assets-non current		$19,695			($9,505	)		$10,190
Commodity derivative instruments		($52,671	)		$4,869			($47,802	)
Deferred premium obligations	(9,319		)	—			(9,319		)
Derivative liabilities-current		($61,990	)		$4,869			($57,121	)
Commodity derivative instruments	(24,609		)	9,505			(15,104		)
Deferred premium obligations	(11,603		)	—			(11,603		)
Contingent consideration	(85,625		)	—			(85,625		)
Derivative liabilities-non current		($121,837	)		$9,505			($112,332	)

	December 31, 2016
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$7,990			($6,753	)		$1,237
Deferred premium obligations	—			—			—
Other current assets		$7,990			($6,753	)		$1,237
Commodity derivative instruments	3,882			(3,882		)	—
Deferred premium obligations	—			—			—
Contingent consideration	—			—			—
Other assets-non current		$3,882			($3,882	)		$—
Commodity derivative instruments		($27,346	)		$6,753			($20,593	)
Deferred premium obligations	(2,008		)	—			(2,008		)
Derivative liabilities-current		($29,354	)		$6,753			($22,601	)
Commodity derivative instruments	(28,841		)	3,882			(24,959		)
Deferred premium obligations	(2,569		)	—			(2,569		)
Contingent consideration	—			—			—
Derivative liabilities-non current		($31,410	)		$3,882			($27,528	)

See “Note 12. Fair Value Measurements” for additional details regarding the fair value of the Company’s derivative instruments.

(Gain) Loss on Derivatives, Net

The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Therefore, all gains and losses as a result of changes in the fair value of the Company’s commodity derivative instruments and contingent consideration are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. All deferred premium obligations associated with the Company’s commodity derivative instruments are recognized in (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the deferred premium obligations are incurred. The effect of derivative instruments and deferred premium obligations in the consolidated statements of operations for the years ended December 31, 2017, 2016, and 2015 is summarized below:

	Years Ended December 31,
	2017			2016		2015
	(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		$22,839			$23,609		($99,624	)
Natural gas liquids	1,322			—		—
Natural gas	(15,399		)	19,584		(4,063		)
Deferred premium obligations incurred	18,401			5,880		4,426
Contingent consideration	31,940			—		—
Total (Gain) Loss on Derivatives, Net		$59,103			$49,073		($99,261	)

Cash Received (Paid) for Derivative Settlements, Net

Cash flows are impacted to the extent that settlements under these contracts, including deferred premium obligations paid, result in payments to or receipts from the counterparty during the period and are presented as cash received (paid) for derivative settlements, net in the consolidated statements of cash flows. The effect of commodity derivative instruments and deferred premium obligations in the consolidated statements of cash flows for the years ended December 31, 2017, 2016, and 2015 is summarized below:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil		$9,883			$125,098			$176,511
Natural gas	(54		)	—			17,785
Deferred premium obligations paid	(2,056		)	(5,729		)	—
Total Cash Received (Paid) for Derivative Settlements, Net		$7,773			$119,369			$194,296

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

12. Fair Value Measurements

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016:

	December 31, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$—			$10,190
Derivative instrument liabilities		$—		($62,906	)		($85,625	)

	December 31, 2016
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$1,237			$—
Derivative instrument liabilities		$—		($45,552	)		$—

The derivative asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors.

Commodity derivative instruments. The fair value of the Company’s commodity derivative instruments is based on a third-party industry-standard pricing model which uses contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments including forward oil and gas price curves, discount rates and volatility factors and are therefore designated as Level 2 within the valuation hierarchy. The fair values are also compared to the values provided by the counterparties for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for derivative liabilities.

The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. Deferred premium obligations are netted with the fair value derivative asset and liability positions, which are all offset to a single asset or liability, at the end of each reporting period. The Company nets the fair values of its derivative assets and liabilities associated with commodity derivative instruments executed with the same counterparty, along with deferred premium obligations, pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company had no transfers into Level 1 and no transfers into or out of Level 2 for the years ended December 31, 2017 and 2016.

Contingent consideration. The fair values of the Contingent ExL Consideration, the Contingent Utica Consideration and the Contingent Marcellus Consideration were determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate. As some of these assumptions are not observable throughout the full term of the contingent consideration, the contingent consideration was designated as Level 3 within the valuation hierarchy. The Company reviewed the valuations, including the related inputs, and analyzed changes in fair value measurements between periods.

The following tables present reconciliations of changes in the fair values of the financial assets and liabilities related to the Company’s contingent consideration, which were designated as Level 3 within the valuation hierarchy, for the year ended December 31,2017:

	Year Ended December 31,
	2017
	(In thousands)
Fair value assets, beginning of period		$—
Recognition of acquisition date fair value	8,805
Gain (loss) on changes in fair value(1)	1,385
Transfers into (out of) Level 3	—
Fair value assets, end of period		$10,190

	Year Ended December 31,
	2017
	(In thousands)
Fair value liability, beginning of period		$—
Recognition of acquisition date fair value	(52,300		)
Gain (loss) on changes in fair value(1)	(33,325		)
Transfers into (out of) Level 3	—
Fair value liability, end of period		($85,625	)

(1) Included in (gain) loss on derivatives, net in the consolidated statements of operations.

See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 11. Derivative Instruments” for further details regarding the contingent consideration.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The fair value measurements of assets acquired and liabilities assumed, other than contingent consideration which is discussed above, are measured as of the acquisition date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore designated as Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimated volumes of oil and gas reserves, production rates, future commodity prices, timing of development, future operating and development costs and a risk adjusted discount rate. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details of the assets acquired and liabilities assumed as of the acquisition dates for the ExL Acquisition and Sanchez Acquisition.

The fair value measurements of asset retirement obligations are measured as of the date a well is drilled or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 inputs. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 7. Asset Retirement Obligations” for additional details regarding the Company’s asset retirement obligations for the years ended December 31, 2017 and 2016.

The fair value measurements of the Preferred Stock are measured as of the issuance date by a third-party valuation specialist using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 inputs. Significant inputs to the valuation of the Preferred Stock include the per share cash purchase price, redemption premiums, liquidation preference, and redemption assumptions provided by the Company. See “Note 9. Preferred Stock and Warrants” for details regarding the allocation of the net proceeds based on the relative fair values of the Preferred Stock and Warrants.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables, and long-term debt, which are designated as Level 1 under the fair value hierarchy. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The following table presents the carrying amounts of the Company’s senior notes and other long-term debt, net of unamortized premiums and debt issuance costs, with the fair values measured using quoted secondary market trading prices.

	December 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020 (1)		$446,087		$459,518		$593,447		$624,750
6.25% Senior Notes due 2023	641,792		674,375		640,546		672,750
8.25% Senior Notes due 2025	245,605		274,375		—		—
Other long-term debt due 2028	4,425		4,445		4,425		4,419

(1) The Company delivered additional notices of redemption to the trustee for its 7.50% Senior Notes subsequent to December 31, 2017.

XML

Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2017

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

13. Condensed Consolidating Financial Information

The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities.

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

	December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$3,441,633			$105,533			$—		($3,424,288	)		$122,878
Total property and equipment, net	5,953			2,630,707			3,028		(3,878		)	2,635,810
Investment in subsidiaries	(999,793		)	—			—		999,793			—
Other assets	9,270			10,346			—		—			19,616
Total Assets		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304
Liabilities and Shareholders’ Equity
Current liabilities		$165,701			$3,631,401			$3,028		($3,427,308	)		$372,822
Long-term liabilities	1,689,466			114,978			—		15,879			1,820,323
Preferred stock	214,262			—			—		—			214,262
Total shareholders’ equity	387,634			(999,793		)	—		983,056			370,897
Total Liabilities and Shareholders’ Equity		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304

	December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$2,735,830			$63,513			$—		($2,726,355	)		$72,988
Total property and equipment, net	42,181			1,503,695			3,800		(3,916		)	1,545,760
Investment in subsidiaries	(1,282,292		)	—			—		1,282,292			—
Other assets	7,423			156			—		—			7,579
Total Assets		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327
Liabilities and Shareholders’ Equity
Current liabilities		$114,805			$2,822,729			$3,800		($2,729,375	)		$211,959
Long-term liabilities	1,348,105			26,927			—		15,878			1,390,910
Preferred stock	—			—			—		—			—
Total shareholders’ equity	40,232			(1,282,292		)	—		1,265,518			23,458
Total Liabilities and Shareholders’ Equity		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$302			$745,586			$—		$—			$745,888
Total costs and expenses	195,728			459,057			—		(37		)	654,748
Income (loss) from continuing operations before income taxes	(195,426		)	286,529			—		37			91,140
Income tax expense	—			(4,030		)	—		—			(4,030		)
Equity in income of subsidiaries	282,499			—			—		(282,499		)	—
Income from continuing operations		$87,073			$282,499			$—		($282,462	)		$87,110
Income from discontinued operations, net of income taxes	—			—			—		—			—
Net income		$87,073			$282,499			$—		($282,462	)		$87,110
Dividends on preferred stock	(7,781		)	—			—		—			(7,781		)
Accretion on preferred stock	(862		)	—			—		—			(862		)
Net income attributable to common shareholders		$78,430			$282,499			$—		($282,462	)		$78,467

	Year Ended December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$482			$443,112			$—		$—			$443,594
Total costs and expenses	208,054			910,522			—		492			1,119,068
Loss from continuing operations before income taxes	(207,572		)	(467,410		)	—		(492		)	(675,474		)
Income tax benefit	—			—			—		—			—
Equity in loss of subsidiaries	(467,410		)	—			—		467,410			—
Loss from continuing operations		($674,982	)		($467,410	)		$—		$466,918			($675,474	)
Income from discontinued operations, net of income taxes	—			—			—		—			—
Net loss		($674,982	)		($467,410	)		$—		$466,918			($675,474	)
Dividends on preferred stock	—			—			—		—			—
Accretion on preferred stock	—			—			—		—			—
Net loss attributable to common shareholders		($674,982	)		($467,410	)		$—		$466,918			($675,474	)

	Year Ended December 31, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$1,708			$427,495			$—		$—			$429,203
Total costs and expenses	95,464			1,603,515			—		28,984			1,727,963
Loss from continuing operations before income taxes	(93,756		)	(1,176,020		)	—		(28,984		)	(1,298,760		)
Income tax benefit	10,125			127,010			—		3,740			140,875
Equity in loss of subsidiaries	(1,049,010		)	—			—		1,049,010			—
Loss from continuing operations		($1,132,641	)		($1,049,010	)		$—		$1,023,766			($1,157,885	)
Income from discontinued operations, net of income taxes	2,731			—			—		—			2,731
Net loss		($1,129,910	)		($1,049,010	)		$—		$1,023,766			($1,155,154	)
Dividends on preferred stock	—			—			—		—			—
Accretion on preferred stock	—			—			—		—			—
Net loss attributable to common shareholders		($1,129,910	)		($1,049,010	)		$—		$1,023,766			($1,155,154	)

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($121,107	)		$544,088			$—		$—			$422,981
Net cash used in investing activities from continuing operations	(615,364		)	(1,155,340		)	—		611,252			(1,159,452		)
Net cash provided by financing activities from continuing operations	741,817			611,252			—		(611,252		)	741,817
Net cash used in discontinued operations	—			—			—		—			—
Net increase in cash and cash equivalents	5,346			—			—		—			5,346
Cash and cash equivalents, beginning of year	4,194			—			—		—			4,194
Cash and cash equivalents, end of year		$9,540			$—			$—		$—			$9,540

	Year Ended December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($34,773	)		$307,541			$—			$—			$272,768
Net cash used in investing activities from continuing operations	(312,291		)	(575,824		)	(740		)	269,023			(619,832		)
Net cash provided by financing activities from continuing operations	308,340			268,283			740			(269,023		)	308,340
Net cash used in discontinued operations	—			—			—			—			—
Net decrease in cash and cash equivalents	(38,724		)	—			—			—			(38,724		)
Cash and cash equivalents, beginning of year	42,918			—			—			—			42,918
Cash and cash equivalents, end of year		$4,194			$—			$—			$—			$4,194

	Year Ended December 31, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by operating activities from continuing operations		$2,655			$376,080			$—		$—			$378,735
Net cash used in investing activities from continuing operations	(447,296		)	(674,758		)	—		448,678			(673,376		)
Net cash provided by financing activities from continuing operations	480,767			298,678			—		(448,678		)	330,767
Net cash used in discontinued operations	(4,046		)	—			—		—			(4,046		)
Net increase in cash and cash equivalents	32,080			—			—		—			32,080
Cash and cash equivalents, beginning of year	10,838			—			—		—			10,838
Cash and cash equivalents, end of year		$42,918			$—			$—		$—			$42,918

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Disclosures

14. Supplemental Cash Flow Information

Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$77,213			$75,231			$64,692
Cash paid for income taxes	—			—			—
Non-cash investing and financing activities:
Increase (decrease) in capital expenditure payables and accruals		$102,272			($21,492	)		($86,878	)
Contingent consideration related to acquisitions of oil and gas properties	52,300			—			—
Contingent consideration related to divestitures of oil and gas properties	(8,805		)	—			—
Liabilities assumed in connection with the Sanchez Acquisition	—			4,880			—
Stock-based compensation expense capitalized to oil and gas properties	4,482			4,591			4,574
Asset retirement obligations capitalized to oil and gas properties	3,726			1,927			4,853

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Subsequent Events (Unaudited)

12 Months Ended

Dec. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

15.Subsequent Events (Unaudited)

Divestitures

Niobrara.On January 19, 2018, the Company closed the sale of substantially all of its assets in the Niobrara Formation. The Company has received net cash proceeds of approximately $136.6 million, subject to post-closing adjustments, which includes a deposit received upon the execution of the purchase and sale agreement and amounts received at closing.

Eagle Ford. On January 31, 2018, the Company closed the sale of a portion of its assets in the Eagle Ford Shale to EP Energy E&P Company, L.P. The Company has received net cash proceeds of approximately $246.2 million, subject to post-closing adjustments, which includes a deposit received upon the execution of the purchase and sale agreement and amounts received at the initial closing as well as a subsequent closing for leases that were not conveyed at the initial closing.

See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” for further details regarding these divestitures.

Redemptions of 7.50% Senior Notes due 2020

On January 19, 2018, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes to call for redemption on February 18, 2018, $100.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On February 20, 2018, the Company paid an aggregate redemption price of $105.1 million, which included a redemption premium of $1.9 million as well as accrued and unpaid interest of $3.2 million from the last interest payment date up to, but not including, the redemption date.

On January 31, 2018, the Company delivered a notice of redemption to the trustee for its 7.50% Senior Notes to call for redemption on March 2, 2018, $220.0 million aggregate principal amount of the outstanding 7.50% Senior Notes. On the redemption date, the Company expects to pay an aggregate redemption price of $231.8 million, which includes a redemption premium of $4.1 million as well as accrued and unpaid interest of $7.7 million from the last interest payment date up to, but not including, the redemption date.

Redemption of Preferred Stock

On January 19, 2018, the Company provided a notice to be delivered to the holders of its Preferred Stock under which it called for redemption of 50,000 of the shares of Preferred Stock, representing 20% of the issued and outstanding Preferred Stock, on January 24, 2018. The Company paid $50.5 million on January 24, 2018 upon redemption, which consisted of $1,000.00 per share of Preferred Stock redeemed, plus accrued and unpaid dividends.

Senior Secured Revolving Credit Facility

On January 31, 2018, as a result of the divestiture in the Eagle Ford Shale discussed above, the Company’s borrowing base under the Senior Secured Revolving Credit Facility was reduced from $900.0 million to $830.0 million, however, the elected commitment amount remained unchanged at $800.0 million.

Hedging

In January 2018, the Company entered into the following natural gas derivative positions at the weighted average contract prices summarized below:

Natural Gas Fixed Price Swaps

Period	Volumes (MMBtu/d)	NYMEX Price ($/MMBtu)
March 2018 - December 2018	25,000		$3.01

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Supplemental Disclosures About Oil And Gas Producing Activities

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Disclosures About Oil And Gas Producing Activities

16. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited)

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below:

	Years Ended December 31,
	2017		2016		2015
	(In thousands)
Property acquisition costs
Proved properties		$303,307		$90,661		$—
Unproved properties	525,061		113,535		63,446
Total property acquisition costs	828,368		204,196		63,446
Exploration costs	91,098		37,508		117,227
Development costs	569,982		374,134		389,396
Total costs incurred		$1,489,448		$615,838		$570,069

Costs incurred exclude capitalized interest on unproved properties of $28.3 million, $17.0 million, and $32.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. Included in exploration and development costs are non-cash additions related to the estimated future asset retirement obligations of the Company’s oil and gas properties of $3.5 million, $1.9 million and $4.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. Non-cash additions related to the estimated future asset retirement obligations associated with the ExL Acquisition of $0.1 million and for the Sanchez Acquisition of $2.0 million are included in acquisition costs of proved properties for the year ended December 31, 2017 and 2016, respectively. The internal cost of employee compensation and benefits, including stock-based compensation, capitalized to proved or unproved oil and gas properties of $14.8 million, $10.5 million and $15.8 million for the years ended December 31, 2017, 2016 and 2015, respectively, are included in exploration, development and unproved property acquisition costs.

Proved Oil and Gas Reserve Quantities

Proved oil and gas reserves are generally those quantities of crude oil, NGLs and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves include reserves that can be expected to be produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves include reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserve quantities at December 31, 2017, 2016, and 2015 and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company, L.P. Such estimates have been prepared in accordance with guidelines established by the SEC. All of the Company’s proved reserves are attributable to properties within the United States. 

The Company’s proved reserves and changes in proved reserves are as follows:

	Crude Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total Proved Reserves (MBoe)
Proved reserves:
January 1, 2015	100,704		13,513		221,017		151,053
Extensions and discoveries	26,358		5,292		33,925		37,304
Revisions of previous estimates	(9,059	)	2,768		11,808		(4,323	)
Production	(8,415	)	(1,352	)	(21,812	)	(13,402	)
December 31, 2015	109,588		20,221		244,938		170,632
Extensions and discoveries	40,074		8,612		59,318		58,572
Revisions of previous estimates	(16,731	)	(3,230	)	1,481		(19,713	)
Purchases of reserves in place	4,810		122		7,282		6,145
Production	(9,423	)	(1,788	)	(25,574	)	(15,473	)
December 31, 2016	128,318		23,937		287,445		200,163
Extensions and discoveries	50,476		13,781		98,980		80,754
Revisions of previous estimates	(19,838	)	(909	)	27,774		(16,118	)
Purchases of reserves in place	21,634		8,642		94,962		46,103
Sales of reserves in place	(650	)	(526	)	(170,219	)	(29,546	)
Production	(12,566	)	(2,327	)	(28,472	)	(19,639	)
December 31, 2017	167,374		42,598		310,470		261,717
Proved developed reserves:
December 31, 2014	35,238		5,294		149,697		65,482
December 31, 2015	42,311		7,933		154,725		76,032
December 31, 2016	51,062		9,387		187,054		91,625
December 31, 2017	69,632		17,447		131,355		108,972
Proved undeveloped reserves:
December 31, 2014	65,466		8,219		71,320		85,571
December 31, 2015	67,277		12,288		90,213		94,600
December 31, 2016	77,256		14,550		100,391		108,538
December 31, 2017	97,742		25,151		179,115		152,745

Extensions and discoveries

For the year ended December 31, 2017, the Company added 6,473 MBoe of proved developed reserves and 74,281 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 51% and 48%, respectively, of the total extensions and discoveries.

For the year ended December 31, 2016, the Company added 6,525 MBoe of proved developed reserves and 52,047 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 79% and 20%, respectively, of the total extensions and discoveries.

For the year ended December 31, 2015, the Company added 5,237 MBoe of proved developed reserves and 32,067 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford comprised 89% of the total extensions and discoveries.

Revisions of previous estimates

For the year ended December 31, 2017, revisions of previous estimates reduced the Company’s proved reserves by 16,118 MBoe. Included in revisions of previous estimates were:

• Positive revisions due to price of 2,684 MBoe.

• Negative revisions due to performance of 4,500 MBoe primarily in the Eagle Ford due to a downward shift of the type curve for certain PUD locations partially offset by positive revisions due to well performance in Marcellus which occurred prior to the sale in November 2017.

• Negative revisions in proved undeveloped reserves of 14,302 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the recent ExL Acquisition and the move to a more efficient development plan which includes drilling and completing larger pads.

For the year ended December 31, 2016, revisions of previous estimates reduced the Company’s proved reserves by 19,713 MBoe. Included in revisions of previous estimates were:

• Negative revisions due to price of 6,705 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 3,228 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 3,477 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations due to loss of tail reserves;

• Negative revisions due to performance of 6,083 MBoe primarily in Eagle Ford as the EURs for certain PUD locations were reduced as a result of tighter spacing and shorter lateral lengths partially offset by positive revisions in Marcellus;

• Negative revisions in proved undeveloped reserves of 6,925 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the move to a more efficient development plan which includes drilling and completing larger pads and the recent Sanchez Acquisition.

For the year ended December 31, 2015, revisions of previous estimates reduced the Company’s proved reserves by 4,323 MBoe. Included in revisions of previous estimates were:

• Negative revisions due to price of 15,846 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 6,208 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 9,638 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations resulting in shorter economic lives;

• Positive revisions due to performance of 11,523 MBoe are primarily in Eagle Ford and Marcellus.

Purchases of reserves in place

For the year ended December 31, 2017, purchases of reserves in place included 26,009 MBoe of proved developed reserves and 20,094 MBoe of proved undeveloped reserves associated with the ExL Acquisition.

For the year ended December 31, 2016, purchases of reserves in place included 4,978 MBoe of proved developed reserves and 1,167 MBoe of proved undeveloped reserves associated with the Sanchez Acquisition.

There were no purchases of reserves in place for the year ended December 31, 2015.

Sales of reserves in place

For the year ended December 31, 2017, sales of reserves in place included 22,249 MBoe of proved developed reserves and 7,297 MBoe of proved undeveloped reserves associated with the Marcellus Shale and Utica Shale divestitures.

There were no sales of reserves in place for the years ended December 31, 2016 and 2015.

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved reserves is as follows:

	December 31,
	2017			2016			2015
	(In thousands)
Future cash inflows		$10,109,752			$5,903,629			$5,878,348
Future production costs	(3,202,201		)	(2,241,928		)	(2,124,059		)
Future development costs	(1,699,909		)	(1,264,493		)	(1,178,773		)
Future income taxes (1)	(445,056		)	—			—
Future net cash flows	4,762,586			2,397,208			2,575,516
Less 10% annual discount to reflect timing of cash flows	(2,297,544		)	(1,093,779		)	(1,210,292		)
Standard measure of discounted future net cash flows		$2,465,042			$1,303,429			$1,365,224

(1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company’s proved oil and gas reserves as of December 31, 2016 and 2015.

Proved reserve estimates and future cash flows are based on the average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the year. The average realized prices used for 2017, 2016 and 2015 were $49.87, $39.60, and $47.24 per Bbl, respectively, for crude oil, $19.78, $11.66 and $12.00 per Bbl, respectively, for NGLs, and $2.96, $1.89 and $1.87 per Mcf, respectively, for natural gas.

Future operating and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved reserves at the end of the year, based on current costs and assuming continuation of existing economic conditions. Future income taxes, which include the effects of the Tax Cuts and Jobs Act, are based on current statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in proved reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows relating to proved reserves are summarized below:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Standardized measure at beginning of year		$1,303,429			$1,365,224			$2,555,082
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production		$710,773			($346,763	)		($2,547,213	)
Net change in estimated future development costs	(51,854		)	74,407			342,238
Net change due to revisions in quantity estimates	(42,214		)	(150,245		)	(157,271		)
Accretion of discount	130,343			136,522			326,074
Changes in production rates (timing) and other	(116,056		)	(111,137		)	(139,533		)
Total revisions to reserves proved in prior years	630,992			(397,216		)	(2,175,705		)
Net change due to extensions and discoveries, net of estimated future development and production costs	597,502			313,201			252,155
Net change due to purchases of reserves in place	452,932			43,426			—
Net change due to divestitures of reserves in place	(106,608		)	—			—
Sales of crude oil, NGLs and natural gas produced, net of production costs	(566,258		)	(320,272		)	(312,213		)
Previously estimated development costs incurred	326,383			299,066			340,247
Net change in income taxes	(173,330		)	—			705,658
Net change in standardized measure of discounted future net cash flows	1,161,613			(61,795		)	(1,189,858		)
Standardized measure at end of year		$2,465,042			$1,303,429			$1,365,224

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Selected Quarterly Financial Data

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data

17. Quarterly Financial Data (Unaudited)

The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2017 and 2016:

Year Ended December 31, 2017	First Quarter			Second Quarter			Third Quarter (2)		Fourth Quarter (3)
	(In thousands, except per share data)
Total revenues		$151,355			$166,483			$181,279		$246,771
Operating profit (1)		$57,953			$63,147			$69,364		$113,205
(Gain) loss on derivatives, net		($25,316	)		($26,065	)		$24,377		$86,107
Net income (loss)		$40,021			$56,306			$7,823		($17,040	)
Net income (loss) attributable to common shareholders		$40,021			$56,306			$5,574		($23,434	)
Net income (loss) attributable to common shareholders per common share (3)
Basic		$0.61			$0.86			$0.07		($0.29	)
Diluted		$0.61			$0.85			$0.07		($0.29	)

Year Ended December 31, 2016	First Quarter (4)			Second Quarter (4)			Third Quarter (4)			Fourth Quarter
	(In thousands, except per share data)
Total revenues		$81,262			$107,324			$111,177			$143,831
Operating profit (loss) (1)		($7,491	)		$27,167			$31,634			$55,000
Net loss		($311,395	)		($262,126	)		($101,174	)		($779	)
Net loss attributable to common shareholders		($311,395	)		($262,126	)		($101,174	)		($779	)
Net loss attributable to common shareholders per common share (3)
Basic		($5.34	)		($4.46	)		($1.72	)		($0.01	)
Diluted		($5.34	)		($4.46	)		($1.72	)		($0.01	)

(1) Total revenues less lease operating expense, production taxes, ad valorem taxes and DD&A.

(2) Third quarter of 2017 included the following:

a. $2.2 million of Preferred Stock dividends which reduced net income attributable to common shareholders.

(3) Fourth quarter of 2017 included the following:

a. $4.2 million loss on extinguishment of debt as a result of the redemption of $150.0 million aggregate principal amount of 7.50% Senior Notes.

b. $5.5 million of Preferred Stock dividends which increased net loss attributable to common shareholders.

(4) The sum of quarterly net income (loss) attributable to common shareholders per common share does not agree with the total year net income (loss) attributable to common shareholders per common share as each computation is based on the weighted average of common shares outstanding during the period.

(5) In the first quarter, second quarter, and third quarter of 2016, the Company recognized impairments of proved oil and gas properties of $274.4 million, $197.1 million, and $105.1 million, respectively.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation and Principles of Consolidation

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications had no material impact on prior period amounts.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. The Company evaluates subsequent events through the date the financial statements are issued.

Significant estimates include volumes of proved oil and gas reserves, which are used in calculating depreciation, depletion and amortization (“DD&A”) of proved oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated costs and timing of cash outflows underlying asset retirement obligations. Oil and gas reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title and drilling requirements. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil and gas reserves, oil and gas prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in the Company’s estimates. Other significant estimates are involved in determining acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of derivative assets and liabilities, fair values of contingent consideration, preferred stock fair value upon issuance, grant date fair value of stock-based awards, and evaluating disputed claims, interpreting contractual arrangements and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling and completion, testing and production as well as subsequent changes in oil and gas prices, interest rates and the market value and volatility of the Company’s common stock.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash equivalents include highly liquid investments with original maturities of three months or less. Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts that do not have the right of offset against the Company’s other cash balances. The outstanding checks written against these zero-balance accounts have been classified as a component of accounts payable in the consolidated balance sheets and totaled $62.6 million and $34.3 million as of December 31, 2017 and 2016, respectively.

Accounts Receivable

Accounts Receivable

As of December 31, 2017 payables due to related parties were less than $0.1 million and as of December 31, 2016, receivables due from related parties were $0.9 million. The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. As of December 31, 2017 and 2016, the Company’s allowance for doubtful accounts was $0.4 million and $0.8 million, respectively.

Concentration of Credit Risk

Concentration of Credit Risk

The Company’s accounts receivable consists primarily of receivables from oil and gas purchasers and joint interest owners in properties the Company operates. This concentration of accounts receivable from oil and gas purchasers and joint interest owners in the oil and gas industry may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company generally does not require collateral from its purchasers or joint interest owners. The Company generally has the right to withhold revenue distributions to recover past due receivables from joint interest owners.

Major Customers

Major Customers

Shell Trading (US) Company accounted for approximately 69%, 56%, and 65% of the Company’s total revenues in 2017, 2016, and 2015, respectively. Flint Hills Resources, LP, an indirect wholly owned subsidiary of Koch Industries, Inc. accounted for approximately 7%, 15% and 9% of the Company’s total revenues in 2017, 2016 and 2015, respectively.

Oil and Gas Properties

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to cost centers established on a country-by-country basis. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either proved or unproved oil and gas properties based on the type of activity and totaled $14.8 million, $10.5 million and $15.8 million for the years ended December 31, 2017, 2016 and 2015, respectively. Internal costs related to production, general corporate overhead and similar activities are expensed as incurred.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to proved oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average DD&A per Boe of proved oil and gas properties was $13.09, $13.50 and $22.05 for the years ended December 31, 2017, 2016 and 2015, respectively.

Unproved properties, not being amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Individually significant unevaluated leaseholds 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 reclassified to proved oil and gas properties. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling, completion, and infrastructure capital expenditure plans. Individually insignificant unevaluated leaseholds are grouped by major area and added to proved oil and gas properties based on the average primary lease term of the properties. Geological and geophysical costs not associated with specific prospects are recorded to proved oil and gas property costs as incurred. The Company capitalized interest costs to unproved properties totaling $28.3 million, $17.0 million and $32.1 million for the years ended December 31, 2017, 2016 and 2015, respectively. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings.

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 average realized prices for sales of crude oil, NGLs and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of derivative instruments as the Company elected not to meet the criteria to qualify derivative instruments for hedge accounting treatment.

The Company did not recognize impairments of proved oil and gas properties for the year ended December 31, 2017. For the years ended December 31, 2016 and 2015, the Company recorded impairments of proved oil and gas properties of $576.5 million and $1,224.4 million, due primarily to declines in the 12-Month Average Realized Price of crude oil.

Proceeds from the sale of proved and unproved oil and gas properties are recognized as a reduction of proved oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For the years ended December 31, 2017, 2016 and 2015, the Company did not have any sales of oil and gas properties that significantly altered such relationship. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties.”

Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from three to ten years.

Debt Issuance Costs

Debt Issuance Costs

Debt issuance costs associated with the revolving credit facility are amortized to interest expense on a straight-line basis over the term of the facility. Debt issuance costs associated with the senior notes are amortized to interest expense using the effective interest method over the terms of the related notes. Debt issuance costs associated with the revolving credit facility are classified in “Other assets” in the consolidated balance sheets while the debt issuance costs associated with the senior notes are classified as a reduction of the related long-term debt in the consolidated balance sheets.

Financial Instruments

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, commodity derivative assets and liabilities, contingent consideration determined to be embedded derivatives and long-term debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the Company’s commodity derivative assets and liabilities are based on a third-party industry-standard pricing model using contract terms and prices and assumptions and inputs that are substantially observable in active markets throughout the full term of the instruments, including forward oil and gas price curves, discount rates, volatility factors and credit risk adjustments. The fair values of the Company’s contingent consideration are determined by a third-party valuation specialist using Monte Carlo simulations including significant inputs such as future commodity prices, volatility factors for the future commodity prices and a risk adjusted discount rate.

The carrying amount of long-term debt associated with borrowings outstanding under the Company’s revolving credit facility approximates fair value as borrowings bear interest at variable rates. The carrying amounts of the Company’s senior notes and other long-term debt may not approximate fair value because carrying amounts are net of unamortized premiums and debt issuance costs, and the senior notes and other long-term debt bear interest at fixed rates. See “Note 6. Long-Term Debt” and “Note 12. Fair Value Measurements.”

Asset Retirement Obligations

Asset Retirement Obligations

The Company’s asset retirement obligations represent the present value of the estimated future costs associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows are discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates consider historical experience, third party estimates, the requirements of oil and gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations are recognized when the well is drilled or acquired or when the production equipment and facilities are installed or acquired with an associated increase in proved oil and gas property costs. Asset retirement obligations are accreted each period through DD&A to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. Cash paid to settle asset retirement obligations is included in net cash provided by operating activities from continuing operations in the consolidated statements of cash flows. On a quarterly basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. At least annually, the Company reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Revisions typically occur due to changes in estimated costs or well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and gas wells. See “Note 7. Asset Retirement Obligations.”

Commitments and Contingencies

Commitments and Contingencies

Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable. See “Note 8. Commitments and Contingencies.”

Revenue Recognition

Revenue Recognition

Crude oil, NGL and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. The Company follows the sales method of accounting whereby revenues from the production of natural gas from properties in which the Company has an interest with other producers are recognized for production sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved reserves. Sales volumes are not significantly different from the Company’s share of production and as of December 31, 2017 and 2016, the Company did not have any material production imbalances.

Derivative Instruments

Derivative Instruments

The Company uses commodity derivative instruments to reduce its exposure to commodity price volatility for a portion of its forecasted crude oil, NGL, and natural gas production and thereby achieve a more predictable level of cash flows to support the Company’s drilling, completion, and infrastructure capital expenditure program. All derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. As the Company has elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, gains and losses as a result of changes in the fair value of commodity derivative instruments are recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from operating activities. The Company does not enter into derivative instruments for speculative or trading purposes.

The Company’s Board of Directors establishes risk management policies and, on a quarterly basis, reviews its commodity derivative instruments, including volumes, types of instruments and counterparties. These policies require that commodity derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. See “Note 11. Derivative Instruments” for further discussion of the Company’s commodity derivative instruments.

The Company has entered into agreements for acquisitions or divestitures of oil and gas properties that include obligations to pay the seller or rights to receive from the buyer, respectively, additional consideration if commodity prices exceed certain thresholds during certain specified periods in the future. These contingent consideration liabilities and assets are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheet, with subsequent changes in fair value recognized as (gain) loss on derivatives, net in the consolidated statements of operations in the period in which the changes occur. Cash payments made to settle contingent consideration liabilities are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. See “Note 3. Acquisitions and Divestitures of Oil and Gas Properties” and “Note 11. Derivative Instruments” for further discussion of the contingent consideration.

Preferred Stock

Preferred Stock and Warrants

The Company applies the accounting standards for distinguishing liabilities from equity when determining the classification and measurement of preferred stock. Preferred stock that is not mandatorily redeemable is excluded from liability classification and is evaluated for classification in shareholders’ equity or temporary equity. As the number of common shares that could be delivered upon the holders’ optional redemption is indeterminate, the Company cannot assert that it will be able to settle in shares of its common stock and, as a result, presents preferred stock as temporary equity. On a quarterly basis, the Company reassesses the presentation of preferred stock in the consolidated balance sheets.

When preferred stock is issued in conjunction with warrants, the warrants are evaluated separately as a freestanding financial instrument to determine whether they must be recorded as a derivative instrument. The Company further evaluates the warrants for equity classification and have determined the warrants qualify for equity classification and, therefore, are presented in additional paid-in capital in the consolidated balance sheets. The preferred stock and warrants are recorded based on the net proceeds received allocated to the two instrument’s relative fair values. The preferred stock is subject to accretion from its relative fair value at the issuance date to the redemption value using the effective interest method. The warrants do not require further adjustments from their relative fair value at the issuance date.

Dividends and accretion associated with preferred stock are presented in the consolidated statements of operations as reductions to net income, or increases of net loss, to derive net income (loss) attributable to common shareholders. Dividend payments are presented as a financing activity in the consolidated statement of cash flows.

Warrants

See “Note 9. Preferred Stock and Warrants” for further details of the Company’s outstanding preferred stock and warrants.

Stock-Based Compensation

Stock-Based Compensation

The Company recognized stock-based compensation expense associated with restricted stock awards and units, stock appreciation rights to be settled in cash (“SARs”) and performance share awards, which is reflected as general and administrative expense in the consolidated statements of operations, net of amounts capitalized to oil and gas properties. See “Note 10. Shareholders’ Equity and Stock Based Compensation” for further details of the awards discussed below.

Restricted Stock Awards and Units. Stock-based compensation expense is based on the price of the Company’s common stock on the grant date and recognized over the vesting period (generally one to three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method, except for awards or units with performance conditions, in which case the Company uses the graded vesting method.

Stock Appreciation Rights. For SARs, stock-based compensation expense is initially based on the grant date fair value determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period and recognized over the vesting period (generally two or three years) using the graded vesting method. For periods subsequent to vesting and prior to exercise, stock-based compensation expense is based on the fair value liability remeasured at the end of each reporting period based on the intrinsic value of the SAR. The liability for SARs is classified as “Other current liabilities” for the portion of the fair value liability attributable to awards that are vested or are expected to vest within the next 12 months and have an exercise price in excess of the market price at the end of the reporting period, with the remainder classified as “Other liabilities” in the consolidated balance sheets. SARs typically expire between four and seven years after the date of grant. If SARs expire unexercised, the cumulative compensation costs associated with the unexercised SARs will be zero.

Performance Share Awards. For performance share awards, stock-based compensation expense is based on the grant date fair value determined using a Monte Carlo valuation model and recognized over an approximate three year vesting period using the straight-line method. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of performance share awards granted based on the Company’s total shareholder return relative to a specified industry peer group over an approximate three year performance period. Compensation costs related to the performance share awards will be recognized if the requisite service period is fulfilled and the performance condition is met, even if the market condition is not achieved.

Income Taxes

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) when determining whether a valuation allowance is required. In making this assessment, the Company evaluates possible sources of taxable income that may be available to realize the deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies. See “Note 5. Income Taxes” for further discussion of the deferred tax assets valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense. The Company applies the tax law ordering approach to determine the sequence in which deferred tax assets and other tax attributes are utilized.

Earnings Per Share

Income (Loss) Attributable to Common Shareholders Per Common Share

Basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding during the year. Diluted net income (loss) attributable to common shareholders per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include restricted stock awards and units, performance share awards, stock options and warrants. The Company includes the number of restricted stock awards and units, stock options and warrants in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s common stock for the period. The Company includes the number of performance share awards in the calculation of diluted weighted average common shares outstanding based on the number of shares, if any, that would be issuable as if the end of the period was the end of the performance period. When a loss attributable to common shareholders exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding.

Supplemental net income (loss) attributable to common shareholders per common share information is provided below:

	Years Ended December 31,
	2017		2016			2015
	(In thousands, except per share amounts)
Net Income (Loss) Attributable to Common Shareholders		$78,467		($675,474	)		($1,155,154	)
Basic weighted average common shares outstanding	73,421		59,932			51,457
Effect of dilutive instruments	572		—			—
Diluted weighted average common shares outstanding	73,993		59,932			51,457
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$1.07		($11.27	)		($22.45	)
Diluted		$1.06		($11.27	)		($22.45	)

When the Company recognizes a net loss attributable to common shareholders, as was the case for the years ended December 31, 2016 and 2015, all potentially dilutive shares are anti-dilutive and excluded from the calculation of diluted weighted average common shares outstanding. The table below presents the weighted average dilutive and anti-dilutive shares outstanding for the periods presented:

	Years Ended December 31,
	2017	2016	2015
	(In thousands)
Dilutive	572	—	—
Anti-dilutive	52	669	649

Recently Adopted Accounting Pronouncements

Recently Adopted Accounting Pronouncement

Stock Compensation. In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”), which amends certain aspects of accounting for share-based payment arrangements. ASU 2016-09 revises or provides alternative accounting for the tax impacts of share-based payment arrangements, forfeitures, minimum statutory tax withholdings, and prescribes certain disclosures to be made in the period of adoption.

Effective January, 1, 2017, the Company adopted ASU 2016-09. Using the modified retrospective approach as prescribed by ASU 2016-09, the Company recognized previously unrecognized windfall tax benefits which resulted in a cumulative-effect adjustment to retained earnings of approximately $15.7 million. This adjustment increased deferred tax assets, which in turn increased the valuation allowance by the same amount as of the beginning of 2017, resulting in a net cumulative-effect adjustment to retained earnings of zero. Effective January 1, 2017, all windfall tax benefits and tax shortfalls are recorded as income tax expense or benefit in the consolidated statements of operations, whereas prior to adoption, windfall tax benefits were recorded as an increase to additional paid-in capital. In addition, windfall tax benefits, along with tax shortfalls, are now required to be classified as an operating cash flow as opposed to a financing cash flow. Further, the Company has elected to account for forfeitures of share-based payment awards as they occur, which resulted in an immaterial cumulative-effect adjustment to retained earnings.

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements

Revenue From Contracts With Customers. In May 2014, the FASB issued ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.

The Company will adopt ASU 2014-09 effective January 1, 2018, using the modified retrospective approach, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. The Company has performed an analysis of existing contracts and does not expect adoption to have a material impact on its consolidated financial statements, however, certain immaterial natural gas processing fees, which have historically been netted in revenue, will be recorded to lease operating expense. In addition, the Company has evaluated the expected changes to relevant business practices, accounting policies and control activities and does not expect to have a material change as a result of the adoption of ASU 2014-09.

Business Combinations. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company will adopt ASU 2017-01 effective January 1, 2018 on a prospective basis.

Statement of Cash Flows. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The Company will adopt ASU 2016-15 effective January 1, 2018 using the full retrospective method, meaning the standard is applied to all periods presented. The Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows and related disclosures.

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which significantly changes accounting for leases by requiring that lessees recognize a right-of-use asset and a related lease liability representing the obligation to make lease payments, for virtually all lease transactions. Additional disclosures about an entity’s lease transactions will also be required. ASU 2016-02 defines a lease as “a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration.” ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018 with early adoption permitted. ASU 2016-02 requires companies to recognize and measure leases at the beginning of the earliest period presented in the financial statements using a modified retrospective approach.

The Company is currently assessing the impact of ASU 2016-02 which includes an analysis of existing contracts, including drilling rig contracts, office leases, certain field equipment, vehicles, produced water disposal commitments, pipeline gathering, transportation and gas processing agreements and current accounting policies and disclosures that will change as a result of adopting ASU 2016-02. Appropriate systems, controls, and processes to support the recognition and disclosure requirements of the new standard are also being evaluated. The Company currently expects the adoption of ASU 2016-02 will result in: (i) an increase in assets and liabilities, (ii) an increase in depreciation, depletion and amortization expense, (iii) an increase in interest expense, and (iv) additional disclosures. The Company plans to adopt the guidance effective January 1, 2019.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

Supplemental net income (loss) attributable to common shareholders per common share information is provided below:

	Years Ended December 31,
	2017		2016			2015
	(In thousands, except per share amounts)
Net Income (Loss) Attributable to Common Shareholders		$78,467		($675,474	)		($1,155,154	)
Basic weighted average common shares outstanding	73,421		59,932			51,457
Effect of dilutive instruments	572		—			—
Diluted weighted average common shares outstanding	73,993		59,932			51,457
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$1.07		($11.27	)		($22.45	)
Diluted		$1.06		($11.27	)		($22.45	)

When the Company recognizes a net loss attributable to common shareholders, as was the case for the years ended December 31, 2016 and 2015, all potentially dilutive shares are anti-dilutive and excluded from the calculation of diluted weighted average common shares outstanding. The table below presents the weighted average dilutive and anti-dilutive shares outstanding for the periods presented:

	Years Ended December 31,
	2017	2016	2015
	(In thousands)
Dilutive	572	—	—
Anti-dilutive	52	669	649

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

The table below presents the weighted average dilutive and anti-dilutive shares outstanding for the periods presented:

	Years Ended December 31,
	2017	2016	2015
	(In thousands)
Dilutive	572	—	—
Anti-dilutive	52	669	649

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Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2017

Business Acquisition [Line Items]

Business Acquisition, Pro Forma Information [Table Text Block]

Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2017 and 2016, assuming the ExL Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the ExL Acquisition.

	Years Ended December 31,
	2017		2016
	(In thousands, except per share amounts)
Total revenues		$781,378		$454,913
Net Income (Loss) Attributable to Common Shareholders		$91,931		($688,180	)
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Basic		$1.25		($9.11	)
Diluted		$1.24		($9.11	)
Weighted Average Common Shares Outstanding
Basic	73,421		75,532
Diluted	73,993		75,532

ExL Acquisition [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$106
Oil and gas properties
Proved properties	294,754
Unproved properties	443,194
Total oil and gas properties		$737,948
Total assets acquired		$738,054
Liabilities
Revenues and royalties payable		$5,785
Asset retirement obligations	153
Contingent ExL Consideration	52,300
Total liabilities assumed		$58,238
Net Assets Acquired		$679,816

The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$106
Oil and gas properties
Proved properties	294,754
Unproved properties	443,194
Total oil and gas properties		$737,948
Total assets acquired		$738,054
Liabilities
Revenues and royalties payable		$5,785
Asset retirement obligations	153
Contingent ExL Consideration	52,300
Total liabilities assumed		$58,238
Net Assets Acquired		$679,816

Sanchez Acquisition [Member]

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following presents the final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Other current assets		$477
Oil and gas properties
Proved properties	99,938
Unproved properties	74,536
Total oil and gas properties	174,474
Total assets acquired		$174,951
Liabilities
Revenues and royalties payable		$1,442
Other current liabilities	323
Asset retirement obligations	2,054
Other liabilities	1,078
Total liabilities assumed		$4,897
Net Assets Acquired		$170,054

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Property And Equipment, Net (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Schedule of Property and Equipment

As of December 31, 2017 and 2016, total property and equipment, net consisted of the following:

	December 31,
	2017			2016
Oil and gas properties, full cost method	(In thousands)
Proved properties		$5,615,153			$4,687,416
Accumulated DD&A and impairments	(3,649,806		)	(3,392,749		)
Proved properties, net	1,965,347			1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	612,589			211,067
Capitalized interest	47,698			29,894
Total unproved properties, not being amortized	660,287			240,961
Other property and equipment	25,625			23,127
Accumulated depreciation	(15,449		)	(12,995		)
Other property and equipment, net	10,176			10,132
Total property and equipment, net		$2,635,810			$1,545,760

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule Of Components Of Income Tax (Expense) Benefit

The components of income tax (expense) benefit from continuing operations were as follows:

	Years Ended December 31,
	2017			2016		2015
	(In thousands)
Current income tax (expense) benefit
U.S. Federal		$—			$—		$—
State	(395		)	—		—
Total current income tax (expense) benefit	(395		)	—		—
Deferred income tax (expense) benefit
U.S. Federal	—			—		131,502
State	(3,635		)	—		9,373
Total deferred income tax (expense) benefit	(3,635		)	—		140,875
Total income tax (expense) benefit from continuing operations		($4,030	)		$—		$140,875

Schedule Of Effective Income Tax Rate Reconciliation

The Company’s income tax (expense) benefit from continuing operations differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) from continuing operations before income taxes as follows:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Income (loss) from continuing operations before income taxes		$91,140			($675,474	)		($1,298,760	)
Income tax (expense) benefit at the statutory rate	(31,899		)	236,416			454,566
State income tax (expense) benefit, net of U.S. Federal income taxes	(4,030		)	3,894			9,373
Tax shortfalls from stock-based compensation expense	(3,089		)	—			—
Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense	—			—			1,671
Provisional impact of Tax Cuts and Jobs Act	(211,724		)	—			—
Change in valuation allowance from provisional impact of Tax Cuts and Jobs Act	211,724			—			—
Change in valuation allowance from current year activity	35,376			(240,864		)	(323,586		)
Other	(388		)	554			(1,149		)
Income tax (expense) benefit		($4,030	)		$—			$140,875

Schedule Of Deferred Tax Assets And Liabilities

As of December 31, 2017 and 2016, deferred tax assets and liabilities are comprised of the following:

	December 31,
	2017			2016
	(In thousands)
Deferred income tax assets
Net operating loss carryforward - U.S. Federal and State		$242,915			$221,063
Oil and gas properties	50,177			309,848
Asset retirement obligations	4,996			7,434
Stock-based compensation	—			5,238
Derivative liabilities	35,585			17,545
Other	1,496			3,739
Deferred income tax assets	335,169			564,867
Deferred tax asset valuation allowance	(333,029		)	(564,434		)
Net deferred income tax assets	2,140			433
Deferred income tax liabilities
Oil and gas properties	(3,635		)	—
Derivative assets	(2,140		)	(433		)
Net deferred income tax asset (liability)		($3,635	)		$—

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Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Schedule Of Debt

Long-term debt consisted of the following as of December 31, 2017 and 2016:

	December 31,
	2017			2016
	(In thousands)
Senior Secured Revolving Credit Facility due 2022		$291,300			$87,000
7.50% Senior Notes due 2020	450,000			600,000
Unamortized premium for 7.50% Senior Notes	579			1,020
Unamortized debt issuance costs for 7.50% Senior Notes	(4,492		)	(7,573		)
6.25% Senior Notes due 2023	650,000			650,000
Unamortized debt issuance costs for 6.25% Senior Notes	(8,208		)	(9,454		)
8.25% Senior Notes due 2025	250,000			—
Unamortized debt issuance costs for 8.25% Senior Notes	(4,395		)	—
Other long-term debt due 2028	4,425			4,425
Long-term debt		$1,629,209			$1,325,418

Interest and Commitment Fee Rates

Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus the margin set forth in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus the margin set forth in the table below. The Company also incurs commitment fees at rates as set forth in the table below on the unused portion of lender commitments, which are included in interest expense, net in the consolidated statements of operations.

Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments	Applicable Margin for Base Rate Loans	Applicable Margin for Eurodollar Loans	Commitment Fee
Less than 25%	1.00%	2.00%	0.375%
Greater than or equal to 25% but less than 50%	1.25%	2.25%	0.375%
Greater than or equal to 50% but less than 75%	1.50%	2.50%	0.500%
Greater than or equal to 75% but less than 90%	1.75%	2.75%	0.500%
Greater than or equal to 90%	2.00%	3.00%	0.500%

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Roll Forward Of Asset Retirement Obligations

The following table sets forth asset retirement obligations for the years ended December 31, 2017 and 2016:

	Years Ended December 31,
	2017			2016
	(In thousands)
Beginning of year asset retirement obligations		$21,240			$16,511
Liabilities incurred	3,920			2,137
Increase due to acquisition of oil and gas properties	153			2,037
Liabilities settled	(343		)	(599		)
Reduction due to divestitures of oil and gas properties	(2,671		)	—
Accretion expense	1,799			1,364
Revisions to estimated cash flows	(306		)	(210		)
End of year asset retirement obligations	23,792			21,240
Current asset retirement obligations (included in other current liabilities)	(295		)	(392		)
Non-current asset retirement obligations		$23,497			$20,848

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Total Minimum Commitments From Long-Term Non-Cancelable Operating Leases, Drilling Rig, Seismic And Pipeline Volume Commitments

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 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		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

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Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2017

Preferred Stock [Abstract]

Schedule of Preferred Stock Dividends Paid in Common Stock

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 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	%

Schedule of Preferred Stock Redemption Premiums

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	%

Preferred Stock

The table below summarizes Preferred Stock activity for the year ended December 31, 2017:

	December 31, 2017
For the Year Ended December 31, 2017
Preferred Stock, beginning 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

Warrants, Valuation Assumptions

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	—		%

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Shareholders' Equity And Stock Incentive Plan (Tables)

12 Months Ended

Dec. 31, 2017

Shareholders' Equity And Stock Incentive Plan [Abstract]

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity

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

	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
Granted	887,254			$27.80
Vested	(811,136	)		$36.32
Forfeited	(6,405	)		$34.46
Unvested restricted stock awards and units, end of period	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
Granted	1,020,465			$25.63
Vested	(635,965	)		$39.62
Forfeited	(13,555	)		$29.11
Unvested restricted stock awards and units, end of period	1,482,655			$28.07

Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity

The table below summarizes the activity for SARs for the years ended December 31, 2017, 2016 and 2015:

	Stock Appreciation Rights		Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)		Aggregate Intrinsic Value of Exercises (In millions)
For the Year Ended December 31, 2015
Outstanding, beginning of period	765,198			$22.49
Granted	—		—
Exercised	(64,745	)		$29.40					$1.5
Forfeited	—		—
Outstanding, end of period	700,453			$21.86
Vested, end of period	626,661			$21.05
Vested and exercisable, end of period	626,661			$21.05
For the Year Ended December 31, 2016
Outstanding, beginning of period	700,453			$21.86
Granted	376,260		27.30
Exercised	(354,075	)		$23.89					$5.2
Forfeited	—		—
Outstanding, end of period	722,638			$23.69
Vested, end of period	350,840			$19.87
Vested and exercisable, end of period	350,840			$19.87
For the Year Ended December 31, 2017
Outstanding, beginning of period	722,638			$23.69
Granted	342,440			$26.94
Exercised	(219,279	)		$17.28					$2.1
Forfeited	—		—
Expired	(131,561	)		$24.19
Outstanding, end of period	714,238			$27.12	3.7		$—
Vested, end of period	185,899			$27.30
Vested and exercisable, end of period	—			$27.30	3.2		$—

Schedule of Share-based Payment Award, Non-Options, Valuation Assumptions

The following table summarizes the assumptions used to calculate the grant date fair value of SARs granted during the years ended December 31, 2017 and 2016:

	Years Ended December 31,
	2017		2016
Expected term (in years)	4.24		3.93
Expected volatility	54.3	%	45.1	%
Risk-free interest rate	1.8	%	1.3	%
Dividend yield	—	%	—	%

Schedule of Share-based Compensation, Performance Shares Award Activity

The table below summarizes performance share activity for the years ended December 31, 2017, 2016 and 2015:

	Target Performance Shares (1)		Weighted Average Grant Date Fair Value
For the Year Ended December 31, 2015
Unvested performance shares, beginning of period	56,342			$68.15
Granted	56,517			$65.51
Vested	—		—
Forfeited	—		—
Unvested performance shares, end of period	112,859			$66.83
For the Year Ended December 31, 2016
Unvested performance shares, beginning of period	112,859			$66.83
Granted	41,651			$35.71
Vested	—		—
Forfeited	—		—
Unvested performance shares, end of period	154,510			$58.44
For the Year Ended December 31, 2017
Unvested performance shares, beginning of period	154,510			$58.44
Granted	46,787			$35.14
Vested	(56,342	)		$68.15
Forfeited	—		—
Unvested performance shares, end of period	144,955			$47.14

(1) The number of shares of common stock issued upon vesting may vary from the number of target performance shares depending on the Company’s final TSR ranking for the approximate three year performance period.

Schedule of Share-based Payment Award, Performance Share Award, Valuation Assumptions

The following table summarizes the assumptions used to calculate the grant date fair value of the performance shares granted during the years ended December 31, 2017, 2016 and 2015:

	Years Ended December 31,
	2017		2016		2015
Number of simulations	500,000		500,000		500,000
Expected term (in years)	2.98		3.01		2.89
Expected volatility	59.2	%	55.3	%	45.3	%
Risk-free interest rate	1.5	%	1.2	%	0.9	%
Dividend yield	—	%	—	%	—	%

Summary Of Stock Options Activity

Schedule of Compensation Cost, Allocation of Share-based Compensation Costs by Plan

The Company recognized the following stock-based compensation expense, net for the periods indicated:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Restricted stock awards and units		$21,372			$28,196			$23,668
Stock appreciation rights	(5,023		)	9,675			(6,326		)
Performance shares	2,442			2,806			1,961
	18,791			40,677			19,303
Less: amounts capitalized to oil and gas properties	(4,482		)	(4,591		)	(4,574		)
Total stock-based compensation expense, net		$14,309			$36,086			$14,729

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Derivative [Line Items]

Schedule of Contingent Consideration

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

Schedule of Derivative Instrument Fair Value Assets and Liabilities

The combined derivative instrument fair value assets and liabilities, including deferred premium obligations, recorded in the consolidated balance sheets as of December 31, 2017 and 2016 are summarized below:

	December 31, 2017
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$4,869			($4,869	)		$—
Deferred premium obligations	—			—			—
Other current assets		$4,869			($4,869	)		$—
Commodity derivative instruments	9,505			(9,505		)	—
Deferred premium obligations	—			—			—
Contingent consideration	10,190			—			10,190
Other assets-non current		$19,695			($9,505	)		$10,190
Commodity derivative instruments		($52,671	)		$4,869			($47,802	)
Deferred premium obligations	(9,319		)	—			(9,319		)
Derivative liabilities-current		($61,990	)		$4,869			($57,121	)
Commodity derivative instruments	(24,609		)	9,505			(15,104		)
Deferred premium obligations	(11,603		)	—			(11,603		)
Contingent consideration	(85,625		)	—			(85,625		)
Derivative liabilities-non current		($121,837	)		$9,505			($112,332	)

	December 31, 2016
	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
	(In thousands)
Commodity derivative instruments		$7,990			($6,753	)		$1,237
Deferred premium obligations	—			—			—
Other current assets		$7,990			($6,753	)		$1,237
Commodity derivative instruments	3,882			(3,882		)	—
Deferred premium obligations	—			—			—
Contingent consideration	—			—			—
Other assets-non current		$3,882			($3,882	)		$—
Commodity derivative instruments		($27,346	)		$6,753			($20,593	)
Deferred premium obligations	(2,008		)	—			(2,008		)
Derivative liabilities-current		($29,354	)		$6,753			($22,601	)
Commodity derivative instruments	(28,841		)	3,882			(24,959		)
Deferred premium obligations	(2,569		)	—			(2,569		)
Contingent consideration	—			—			—
Derivative liabilities-non current		($31,410	)		$3,882			($27,528	)

Derivative Instruments, (Gain) Loss

The effect of derivative instruments and deferred premium obligations in the consolidated statements of operations for the years ended December 31, 2017, 2016, and 2015 is summarized below:

	Years Ended December 31,
	2017			2016		2015
	(In thousands)
(Gain) Loss on Derivatives, Net
Crude oil		$22,839			$23,609		($99,624	)
Natural gas liquids	1,322			—		—
Natural gas	(15,399		)	19,584		(4,063		)
Deferred premium obligations incurred	18,401			5,880		4,426
Contingent consideration	31,940			—		—
Total (Gain) Loss on Derivatives, Net		$59,103			$49,073		($99,261	)

Schedule of Cash Received for Derivatives

The effect of commodity derivative instruments and deferred premium obligations in the consolidated statements of cash flows for the years ended December 31, 2017, 2016, and 2015 is summarized below:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Cash Received (Paid) for Derivative Settlements, Net
Crude oil		$9,883			$125,098			$176,511
Natural gas	(54		)	—			17,785
Deferred premium obligations paid	(2,056		)	(5,729		)	—
Total Cash Received (Paid) for Derivative Settlements, Net		$7,773			$119,369			$194,296

Crude Oil [Member] | Swap [Member]

Derivative [Line Items]

Schedule of Derivative Positions

Crude Oil Fixed Price Swaps

Period	Volumes (Bbls/d)	NYMEX Price ($/Bbl)
FY 2018	6,000		$49.55

Crude Oil [Member] | Basis Swap [Member]

Derivative [Line Items]

Schedule of Derivative Positions

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	)

Crude Oil [Member] | Three-way Collars [Member]

Derivative [Line Items]

Schedule of Derivative Positions

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 [Member] | Call Option [Member]

Derivative [Line Items]

Schedule of Derivative Positions

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

Natural Gas Liquids [Member] | Swap [Member]

Derivative [Line Items]

Schedule of Derivative Positions

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 [Member] | Swap [Member]

Derivative [Line Items]

Schedule of Derivative Positions

In January 2018, the Company entered into the following natural gas derivative positions at the weighted average contract prices summarized below:

Natural Gas Fixed Price Swaps

Period	Volumes (MMBtu/d)	NYMEX Price ($/MMBtu)
March 2018 - December 2018	25,000		$3.01

Natural Gas [Member] | Call Option [Member]

Derivative [Line Items]

Schedule of Derivative Positions

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

XML

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Assets And Liabilities Measured At Fair Value On A Recurring Basis

The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2017 and 2016:

	December 31, 2017
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$—			$10,190
Derivative instrument liabilities		$—		($62,906	)		($85,625	)

	December 31, 2016
	Level 1		Level 2			Level 3
	(In thousands)
Derivative instrument assets		$—		$1,237			$—
Derivative instrument liabilities		$—		($45,552	)		$—

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

	Year Ended December 31,
	2017
	(In thousands)
Fair value assets, beginning of period		$—
Recognition of acquisition date fair value	8,805
Gain (loss) on changes in fair value(1)	1,385
Transfers into (out of) Level 3	—
Fair value assets, end of period		$10,190

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

	Year Ended December 31,
	2017
	(In thousands)
Fair value liability, beginning of period		$—
Recognition of acquisition date fair value	(52,300		)
Gain (loss) on changes in fair value(1)	(33,325		)
Transfers into (out of) Level 3	—
Fair value liability, end of period		($85,625	)

Schedule of Fair Value of Debt Instruments

The following table presents the carrying amounts of the Company’s senior notes and other long-term debt, net of unamortized premiums and debt issuance costs, with the fair values measured using quoted secondary market trading prices.

	December 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
7.50% Senior Notes due 2020 (1)		$446,087		$459,518		$593,447		$624,750
6.25% Senior Notes due 2023	641,792		674,375		640,546		672,750
8.25% Senior Notes due 2025	245,605		274,375		—		—
Other long-term debt due 2028	4,425		4,445		4,425		4,419

(1) The Company delivered additional notices of redemption to the trustee for its 7.50% Senior Notes subsequent to December 31, 2017.

XML

Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2017

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

13. Condensed Consolidating Financial Information

The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities.

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

	December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$3,441,633			$105,533			$—		($3,424,288	)		$122,878
Total property and equipment, net	5,953			2,630,707			3,028		(3,878		)	2,635,810
Investment in subsidiaries	(999,793		)	—			—		999,793			—
Other assets	9,270			10,346			—		—			19,616
Total Assets		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304
Liabilities and Shareholders’ Equity
Current liabilities		$165,701			$3,631,401			$3,028		($3,427,308	)		$372,822
Long-term liabilities	1,689,466			114,978			—		15,879			1,820,323
Preferred stock	214,262			—			—		—			214,262
Total shareholders’ equity	387,634			(999,793		)	—		983,056			370,897
Total Liabilities and Shareholders’ Equity		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304

	December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$2,735,830			$63,513			$—		($2,726,355	)		$72,988
Total property and equipment, net	42,181			1,503,695			3,800		(3,916		)	1,545,760
Investment in subsidiaries	(1,282,292		)	—			—		1,282,292			—
Other assets	7,423			156			—		—			7,579
Total Assets		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327
Liabilities and Shareholders’ Equity
Current liabilities		$114,805			$2,822,729			$3,800		($2,729,375	)		$211,959
Long-term liabilities	1,348,105			26,927			—		15,878			1,390,910
Preferred stock	—			—			—		—			—
Total shareholders’ equity	40,232			(1,282,292		)	—		1,265,518			23,458
Total Liabilities and Shareholders’ Equity		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$302			$745,586			$—		$—			$745,888
Total costs and expenses	195,728			459,057			—		(37		)	654,748
Income (loss) from continuing operations before income taxes	(195,426		)	286,529			—		37			91,140
Income tax expense	—			(4,030		)	—		—			(4,030		)
Equity in income of subsidiaries	282,499			—			—		(282,499		)	—
Income from continuing operations		$87,073			$282,499			$—		($282,462	)		$87,110
Income from discontinued operations, net of income taxes	—			—			—		—			—
Net income		$87,073			$282,499			$—		($282,462	)		$87,110
Dividends on preferred stock	(7,781		)	—			—		—			(7,781		)
Accretion on preferred stock	(862		)	—			—		—			(862		)
Net income attributable to common shareholders		$78,430			$282,499			$—		($282,462	)		$78,467

	Year Ended December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$482			$443,112			$—		$—			$443,594
Total costs and expenses	208,054			910,522			—		492			1,119,068
Loss from continuing operations before income taxes	(207,572		)	(467,410		)	—		(492		)	(675,474		)
Income tax benefit	—			—			—		—			—
Equity in loss of subsidiaries	(467,410		)	—			—		467,410			—
Loss from continuing operations		($674,982	)		($467,410	)		$—		$466,918			($675,474	)
Income from discontinued operations, net of income taxes	—			—			—		—			—
Net loss		($674,982	)		($467,410	)		$—		$466,918			($675,474	)
Dividends on preferred stock	—			—			—		—			—
Accretion on preferred stock	—			—			—		—			—
Net loss attributable to common shareholders		($674,982	)		($467,410	)		$—		$466,918			($675,474	)

	Year Ended December 31, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$1,708			$427,495			$—		$—			$429,203
Total costs and expenses	95,464			1,603,515			—		28,984			1,727,963
Loss from continuing operations before income taxes	(93,756		)	(1,176,020		)	—		(28,984		)	(1,298,760		)
Income tax benefit	10,125			127,010			—		3,740			140,875
Equity in loss of subsidiaries	(1,049,010		)	—			—		1,049,010			—
Loss from continuing operations		($1,132,641	)		($1,049,010	)		$—		$1,023,766			($1,157,885	)
Income from discontinued operations, net of income taxes	2,731			—			—		—			2,731
Net loss		($1,129,910	)		($1,049,010	)		$—		$1,023,766			($1,155,154	)
Dividends on preferred stock	—			—			—		—			—
Accretion on preferred stock	—			—			—		—			—
Net loss attributable to common shareholders		($1,129,910	)		($1,049,010	)		$—		$1,023,766			($1,155,154	)

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($121,107	)		$544,088			$—		$—			$422,981
Net cash used in investing activities from continuing operations	(615,364		)	(1,155,340		)	—		611,252			(1,159,452		)
Net cash provided by financing activities from continuing operations	741,817			611,252			—		(611,252		)	741,817
Net cash used in discontinued operations	—			—			—		—			—
Net increase in cash and cash equivalents	5,346			—			—		—			5,346
Cash and cash equivalents, beginning of year	4,194			—			—		—			4,194
Cash and cash equivalents, end of year		$9,540			$—			$—		$—			$9,540

	Year Ended December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($34,773	)		$307,541			$—			$—			$272,768
Net cash used in investing activities from continuing operations	(312,291		)	(575,824		)	(740		)	269,023			(619,832		)
Net cash provided by financing activities from continuing operations	308,340			268,283			740			(269,023		)	308,340
Net cash used in discontinued operations	—			—			—			—			—
Net decrease in cash and cash equivalents	(38,724		)	—			—			—			(38,724		)
Cash and cash equivalents, beginning of year	42,918			—			—			—			42,918
Cash and cash equivalents, end of year		$4,194			$—			$—			$—			$4,194

	Year Ended December 31, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by operating activities from continuing operations		$2,655			$376,080			$—		$—			$378,735
Net cash used in investing activities from continuing operations	(447,296		)	(674,758		)	—		448,678			(673,376		)
Net cash provided by financing activities from continuing operations	480,767			298,678			—		(448,678		)	330,767
Net cash used in discontinued operations	(4,046		)	—			—		—			(4,046		)
Net increase in cash and cash equivalents	32,080			—			—		—			32,080
Cash and cash equivalents, beginning of year	10,838			—			—		—			10,838
Cash and cash equivalents, end of year		$42,918			$—			$—		$—			$42,918

Schedule Of Condensed Consolidating Balance Sheets

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In thousands)

	December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$3,441,633			$105,533			$—		($3,424,288	)		$122,878
Total property and equipment, net	5,953			2,630,707			3,028		(3,878		)	2,635,810
Investment in subsidiaries	(999,793		)	—			—		999,793			—
Other assets	9,270			10,346			—		—			19,616
Total Assets		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304
Liabilities and Shareholders’ Equity
Current liabilities		$165,701			$3,631,401			$3,028		($3,427,308	)		$372,822
Long-term liabilities	1,689,466			114,978			—		15,879			1,820,323
Preferred stock	214,262			—			—		—			214,262
Total shareholders’ equity	387,634			(999,793		)	—		983,056			370,897
Total Liabilities and Shareholders’ Equity		$2,457,063			$2,746,586			$3,028		($2,428,373	)		$2,778,304

	December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Total current assets		$2,735,830			$63,513			$—		($2,726,355	)		$72,988
Total property and equipment, net	42,181			1,503,695			3,800		(3,916		)	1,545,760
Investment in subsidiaries	(1,282,292		)	—			—		1,282,292			—
Other assets	7,423			156			—		—			7,579
Total Assets		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327
Liabilities and Shareholders’ Equity
Current liabilities		$114,805			$2,822,729			$3,800		($2,729,375	)		$211,959
Long-term liabilities	1,348,105			26,927			—		15,878			1,390,910
Preferred stock	—			—			—		—			—
Total shareholders’ equity	40,232			(1,282,292		)	—		1,265,518			23,458
Total Liabilities and Shareholders’ Equity		$1,503,142			$1,567,364			$3,800		($1,447,979	)		$1,626,327

Schedule Of Condensed Consolidating Statements Of Operations

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$302			$745,586			$—		$—			$745,888
Total costs and expenses	195,728			459,057			—		(37		)	654,748
Income (loss) from continuing operations before income taxes	(195,426		)	286,529			—		37			91,140
Income tax expense	—			(4,030		)	—		—			(4,030		)
Equity in income of subsidiaries	282,499			—			—		(282,499		)	—
Income from continuing operations		$87,073			$282,499			$—		($282,462	)		$87,110
Income from discontinued operations, net of income taxes	—			—			—		—			—
Net income		$87,073			$282,499			$—		($282,462	)		$87,110
Dividends on preferred stock	(7,781		)	—			—		—			(7,781		)
Accretion on preferred stock	(862		)	—			—		—			(862		)
Net income attributable to common shareholders		$78,430			$282,499			$—		($282,462	)		$78,467

	Year Ended December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$482			$443,112			$—		$—			$443,594
Total costs and expenses	208,054			910,522			—		492			1,119,068
Loss from continuing operations before income taxes	(207,572		)	(467,410		)	—		(492		)	(675,474		)
Income tax benefit	—			—			—		—			—
Equity in loss of subsidiaries	(467,410		)	—			—		467,410			—
Loss from continuing operations		($674,982	)		($467,410	)		$—		$466,918			($675,474	)
Income from discontinued operations, net of income taxes	—			—			—		—			—
Net loss		($674,982	)		($467,410	)		$—		$466,918			($675,474	)
Dividends on preferred stock	—			—			—		—			—
Accretion on preferred stock	—			—			—		—			—
Net loss attributable to common shareholders		($674,982	)		($467,410	)		$—		$466,918			($675,474	)

	Year Ended December 31, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Total revenues		$1,708			$427,495			$—		$—			$429,203
Total costs and expenses	95,464			1,603,515			—		28,984			1,727,963
Loss from continuing operations before income taxes	(93,756		)	(1,176,020		)	—		(28,984		)	(1,298,760		)
Income tax benefit	10,125			127,010			—		3,740			140,875
Equity in loss of subsidiaries	(1,049,010		)	—			—		1,049,010			—
Loss from continuing operations		($1,132,641	)		($1,049,010	)		$—		$1,023,766			($1,157,885	)
Income from discontinued operations, net of income taxes	2,731			—			—		—			2,731
Net loss		($1,129,910	)		($1,049,010	)		$—		$1,023,766			($1,155,154	)
Dividends on preferred stock	—			—			—		—			—
Accretion on preferred stock	—			—			—		—			—
Net loss attributable to common shareholders		($1,129,910	)		($1,049,010	)		$—		$1,023,766			($1,155,154	)

Schedule Of Condensed Consolidating Statements Of Cash Flows

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31, 2017
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($121,107	)		$544,088			$—		$—			$422,981
Net cash used in investing activities from continuing operations	(615,364		)	(1,155,340		)	—		611,252			(1,159,452		)
Net cash provided by financing activities from continuing operations	741,817			611,252			—		(611,252		)	741,817
Net cash used in discontinued operations	—			—			—		—			—
Net increase in cash and cash equivalents	5,346			—			—		—			5,346
Cash and cash equivalents, beginning of year	4,194			—			—		—			4,194
Cash and cash equivalents, end of year		$9,540			$—			$—		$—			$9,540

	Year Ended December 31, 2016
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities from continuing operations		($34,773	)		$307,541			$—			$—			$272,768
Net cash used in investing activities from continuing operations	(312,291		)	(575,824		)	(740		)	269,023			(619,832		)
Net cash provided by financing activities from continuing operations	308,340			268,283			740			(269,023		)	308,340
Net cash used in discontinued operations	—			—			—			—			—
Net decrease in cash and cash equivalents	(38,724		)	—			—			—			(38,724		)
Cash and cash equivalents, beginning of year	42,918			—			—			—			42,918
Cash and cash equivalents, end of year		$4,194			$—			$—			$—			$4,194

	Year Ended December 31, 2015
	Parent Company			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net cash provided by operating activities from continuing operations		$2,655			$376,080			$—		$—			$378,735
Net cash used in investing activities from continuing operations	(447,296		)	(674,758		)	—		448,678			(673,376		)
Net cash provided by financing activities from continuing operations	480,767			298,678			—		(448,678		)	330,767
Net cash used in discontinued operations	(4,046		)	—			—		—			(4,046		)
Net increase in cash and cash equivalents	32,080			—			—		—			32,080
Cash and cash equivalents, beginning of year	10,838			—			—		—			10,838
Cash and cash equivalents, end of year		$42,918			$—			$—		$—			$42,918

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2017

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized		$77,213			$75,231			$64,692
Cash paid for income taxes	—			—			—
Non-cash investing and financing activities:
Increase (decrease) in capital expenditure payables and accruals		$102,272			($21,492	)		($86,878	)
Contingent consideration related to acquisitions of oil and gas properties	52,300			—			—
Contingent consideration related to divestitures of oil and gas properties	(8,805		)	—			—
Liabilities assumed in connection with the Sanchez Acquisition	—			4,880			—
Stock-based compensation expense capitalized to oil and gas properties	4,482			4,591			4,574
Asset retirement obligations capitalized to oil and gas properties	3,726			1,927			4,853

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Subsequent Events (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Swap [Member] | Natural Gas [Member]

Derivative [Line Items]

Schedule of Derivative Positions

In January 2018, the Company entered into the following natural gas derivative positions at the weighted average contract prices summarized below:

Natural Gas Fixed Price Swaps

Period	Volumes (MMBtu/d)	NYMEX Price ($/MMBtu)
March 2018 - December 2018	25,000		$3.01

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Supplemental Disclosures About Oil And Gas Producing Activities (Tables)

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule Of Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities

Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below:

	Years Ended December 31,
	2017		2016		2015
	(In thousands)
Property acquisition costs
Proved properties		$303,307		$90,661		$—
Unproved properties	525,061		113,535		63,446
Total property acquisition costs	828,368		204,196		63,446
Exploration costs	91,098		37,508		117,227
Development costs	569,982		374,134		389,396
Total costs incurred		$1,489,448		$615,838		$570,069

Schedule Of Net Proved Oil And Gas Reserves And Changes In Net Proved Oil And Gas Reserves

The Company’s proved reserves and changes in proved reserves are as follows:

	Crude Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total Proved Reserves (MBoe)
Proved reserves:
January 1, 2015	100,704		13,513		221,017		151,053
Extensions and discoveries	26,358		5,292		33,925		37,304
Revisions of previous estimates	(9,059	)	2,768		11,808		(4,323	)
Production	(8,415	)	(1,352	)	(21,812	)	(13,402	)
December 31, 2015	109,588		20,221		244,938		170,632
Extensions and discoveries	40,074		8,612		59,318		58,572
Revisions of previous estimates	(16,731	)	(3,230	)	1,481		(19,713	)
Purchases of reserves in place	4,810		122		7,282		6,145
Production	(9,423	)	(1,788	)	(25,574	)	(15,473	)
December 31, 2016	128,318		23,937		287,445		200,163
Extensions and discoveries	50,476		13,781		98,980		80,754
Revisions of previous estimates	(19,838	)	(909	)	27,774		(16,118	)
Purchases of reserves in place	21,634		8,642		94,962		46,103
Sales of reserves in place	(650	)	(526	)	(170,219	)	(29,546	)
Production	(12,566	)	(2,327	)	(28,472	)	(19,639	)
December 31, 2017	167,374		42,598		310,470		261,717
Proved developed reserves:
December 31, 2014	35,238		5,294		149,697		65,482
December 31, 2015	42,311		7,933		154,725		76,032
December 31, 2016	51,062		9,387		187,054		91,625
December 31, 2017	69,632		17,447		131,355		108,972
Proved undeveloped reserves:
December 31, 2014	65,466		8,219		71,320		85,571
December 31, 2015	67,277		12,288		90,213		94,600
December 31, 2016	77,256		14,550		100,391		108,538
December 31, 2017	97,742		25,151		179,115		152,745

Extensions and discoveries

For the year ended December 31, 2017, the Company added 6,473 MBoe of proved developed reserves and 74,281 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 51% and 48%, respectively, of the total extensions and discoveries.

For the year ended December 31, 2016, the Company added 6,525 MBoe of proved developed reserves and 52,047 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford and Delaware Basin comprised 79% and 20%, respectively, of the total extensions and discoveries.

For the year ended December 31, 2015, the Company added 5,237 MBoe of proved developed reserves and 32,067 MBoe of proved undeveloped reserves through its drilling program and associated offset locations. Eagle Ford comprised 89% of the total extensions and discoveries.

Revisions of previous estimates

For the year ended December 31, 2017, revisions of previous estimates reduced the Company’s proved reserves by 16,118 MBoe. Included in revisions of previous estimates were:

• Positive revisions due to price of 2,684 MBoe.

• Negative revisions due to performance of 4,500 MBoe primarily in the Eagle Ford due to a downward shift of the type curve for certain PUD locations partially offset by positive revisions due to well performance in Marcellus which occurred prior to the sale in November 2017.

• Negative revisions in proved undeveloped reserves of 14,302 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the recent ExL Acquisition and the move to a more efficient development plan which includes drilling and completing larger pads.

For the year ended December 31, 2016, revisions of previous estimates reduced the Company’s proved reserves by 19,713 MBoe. Included in revisions of previous estimates were:

• Negative revisions due to price of 6,705 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 3,228 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 3,477 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations due to loss of tail reserves;

• Negative revisions due to performance of 6,083 MBoe primarily in Eagle Ford as the EURs for certain PUD locations were reduced as a result of tighter spacing and shorter lateral lengths partially offset by positive revisions in Marcellus;

• Negative revisions in proved undeveloped reserves of 6,925 MBoe in the Eagle Ford due to changes in the Company’s previously approved development plan which resulted in the timing of development for certain PUD locations to move beyond five years from initial booking. The drivers of the changes in the Company’s previously approved development plan were the move to a more efficient development plan which includes drilling and completing larger pads and the recent Sanchez Acquisition.

For the year ended December 31, 2015, revisions of previous estimates reduced the Company’s proved reserves by 4,323 MBoe. Included in revisions of previous estimates were:

• Negative revisions due to price of 15,846 MBoe primarily due to the decline in the 12-Month Average Realized price for crude oil, of which 6,208 MBoe related to proved developed and proved undeveloped locations that were no longer economic and 9,638 MBoe related to reductions in the level of economic reserves in proved developed and proved undeveloped reserve locations resulting in shorter economic lives;

• Positive revisions due to performance of 11,523 MBoe are primarily in Eagle Ford and Marcellus.

Purchases of reserves in place

For the year ended December 31, 2017, purchases of reserves in place included 26,009 MBoe of proved developed reserves and 20,094 MBoe of proved undeveloped reserves associated with the ExL Acquisition.

For the year ended December 31, 2016, purchases of reserves in place included 4,978 MBoe of proved developed reserves and 1,167 MBoe of proved undeveloped reserves associated with the Sanchez Acquisition.

There were no purchases of reserves in place for the year ended December 31, 2015.

Sales of reserves in place

For the year ended December 31, 2017, sales of reserves in place included 22,249 MBoe of proved developed reserves and 7,297 MBoe of proved undeveloped reserves associated with the Marcellus Shale and Utica Shale divestitures.

There were no sales of reserves in place for the years ended December 31, 2016 and 2015.

Schedule Of Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves

The standardized measure of discounted future net cash flows relating to proved reserves is as follows:

	December 31,
	2017			2016			2015
	(In thousands)
Future cash inflows		$10,109,752			$5,903,629			$5,878,348
Future production costs	(3,202,201		)	(2,241,928		)	(2,124,059		)
Future development costs	(1,699,909		)	(1,264,493		)	(1,178,773		)
Future income taxes (1)	(445,056		)	—			—
Future net cash flows	4,762,586			2,397,208			2,575,516
Less 10% annual discount to reflect timing of cash flows	(2,297,544		)	(1,093,779		)	(1,210,292		)
Standard measure of discounted future net cash flows		$2,465,042			$1,303,429			$1,365,224

(1) Future income taxes in the calculation of the standardized measure of discounted future net cash flows were zero as of December 31, 2016 and 2015, as the historical tax basis of proved oil and gas properties, net operating loss carryforwards, and future tax deductions exceeded the undiscounted future net cash flows before income taxes of the Company’s proved oil and gas reserves as of December 31, 2016 and 2015.

Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves

Changes in the standardized measure of discounted future net cash flows relating to proved reserves are summarized below:

	Years Ended December 31,
	2017			2016			2015
	(In thousands)
Standardized measure at beginning of year		$1,303,429			$1,365,224			$2,555,082
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production		$710,773			($346,763	)		($2,547,213	)
Net change in estimated future development costs	(51,854		)	74,407			342,238
Net change due to revisions in quantity estimates	(42,214		)	(150,245		)	(157,271		)
Accretion of discount	130,343			136,522			326,074
Changes in production rates (timing) and other	(116,056		)	(111,137		)	(139,533		)
Total revisions to reserves proved in prior years	630,992			(397,216		)	(2,175,705		)
Net change due to extensions and discoveries, net of estimated future development and production costs	597,502			313,201			252,155
Net change due to purchases of reserves in place	452,932			43,426			—
Net change due to divestitures of reserves in place	(106,608		)	—			—
Sales of crude oil, NGLs and natural gas produced, net of production costs	(566,258		)	(320,272		)	(312,213		)
Previously estimated development costs incurred	326,383			299,066			340,247
Net change in income taxes	(173,330		)	—			705,658
Net change in standardized measure of discounted future net cash flows	1,161,613			(61,795		)	(1,189,858		)
Standardized measure at end of year		$2,465,042			$1,303,429			$1,365,224

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Selected Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Schedule Of Quarterly Financial Information

The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2017 and 2016:

Year Ended December 31, 2017	First Quarter			Second Quarter			Third Quarter (2)		Fourth Quarter (3)
	(In thousands, except per share data)
Total revenues		$151,355			$166,483			$181,279		$246,771
Operating profit (1)		$57,953			$63,147			$69,364		$113,205
(Gain) loss on derivatives, net		($25,316	)		($26,065	)		$24,377		$86,107
Net income (loss)		$40,021			$56,306			$7,823		($17,040	)
Net income (loss) attributable to common shareholders		$40,021			$56,306			$5,574		($23,434	)
Net income (loss) attributable to common shareholders per common share (3)
Basic		$0.61			$0.86			$0.07		($0.29	)
Diluted		$0.61			$0.85			$0.07		($0.29	)

Year Ended December 31, 2016	First Quarter (4)			Second Quarter (4)			Third Quarter (4)			Fourth Quarter
	(In thousands, except per share data)
Total revenues		$81,262			$107,324			$111,177			$143,831
Operating profit (loss) (1)		($7,491	)		$27,167			$31,634			$55,000
Net loss		($311,395	)		($262,126	)		($101,174	)		($779	)
Net loss attributable to common shareholders		($311,395	)		($262,126	)		($101,174	)		($779	)
Net loss attributable to common shareholders per common share (3)
Basic		($5.34	)		($4.46	)		($1.72	)		($0.01	)
Diluted		($5.34	)		($4.46	)		($1.72	)		($0.01	)

(1) Total revenues less lease operating expense, production taxes, ad valorem taxes and DD&A.

(2) Third quarter of 2017 included the following:

a. $2.2 million of Preferred Stock dividends which reduced net income attributable to common shareholders.

(3) Fourth quarter of 2017 included the following:

a. $4.2 million loss on extinguishment of debt as a result of the redemption of $150.0 million aggregate principal amount of 7.50% Senior Notes.

b. $5.5 million of Preferred Stock dividends which increased net loss attributable to common shareholders.

(4) The sum of quarterly net income (loss) attributable to common shareholders per common share does not agree with the total year net income (loss) attributable to common shareholders per common share as each computation is based on the weighted average of common shares outstanding during the period.

(5) In the first quarter, second quarter, and third quarter of 2016, the Company recognized impairments of proved oil and gas properties of $274.4 million, $197.1 million, and $105.1 million, respectively.

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Summary of Significant Accounting Policies (Narrative) (Details) shares in Thousands	3 Months Ended			12 Months Ended
	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2017 USD ($) $ / Boe shares	Dec. 31, 2016 USD ($) $ / Boe shares	Dec. 31, 2015 USD ($) $ / Boe shares	Jan. 01, 2017 USD ($)
Summary Of Significant Accounting Policies [Line Items]
Due to Related Parties				$ 100,000
Other Accounts Payable and Accrued Liabilities				62,600,000	$ 34,300,000
Allowance for doubtful accounts receivable				400,000	800,000
Due from Related Parties, Current				100,000	900,000
Internal costs capitalized, oil and gas producing activities				$ 14,800,000	$ 10,500,000	$ 15,800,000
Average DD&A Per Boe (in USD per BOE) | $ / Boe				13.09	13.50	22.05
Capitalized interest				$ 28,300,000	$ 17,000,000	$ 32,100,000
Reserves discount factor				10.00%
Impairment of proved oil and gas properties	$ 105,100,000	$ 197,100,000	$ 274,400,000	$ 0	576,540,000	$ 1,224,367,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount				(247,100,000)
Deferred Tax Assets, Valuation Allowance				333,029,000	$ 564,434,000		$ 580,100,000
Deferred Tax Assets, Net				$ 0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares				52	669	649
Tax Adjustments, Settlements, and Unusual Provisions				$ 15,700,000
Tax Adjustments, Settlements, and Unusual Provisions, Retained Earnings Effect				$ 0.0
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life, minimum, years				3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life, minimum, years				10 years
Restricted Stock Awards And Units [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				1 year
Restricted Stock Awards And Units [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				3 years
Stock Appreciation Rights (SARs) [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				2 years
Expiration period, in years				4 years
Stock Appreciation Rights (SARs) [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				3 years
Expiration period, in years				7 years
Performance Shares [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				3 years
Performance Shares [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Range of Awards to Vest Based on Market Condition				0.00%
Performance Shares [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Range of Awards to Vest Based on Market Condition				200.00%
Customer One [Member]
Summary Of Significant Accounting Policies [Line Items]
Customer percentage of total revenue				69.00%	56.00%	65.00%
Customer Two [Member]
Summary Of Significant Accounting Policies [Line Items]
Customer percentage of total revenue				7.00%	15.00%	9.00%
Contractor [Member] | Restricted Stock Awards And Units [Member]
Summary Of Significant Accounting Policies [Line Items]
Vesting period, in years				3 years

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Summary of Significant Accounting Policies (Schedule of Earnings Per Share Reconciliation) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Attributable to Common Shareholders	$ (23,434)	$ 5,574	$ 56,306	$ 40,021	$ (779)	$ (101,174)	$ (262,126)	$ (311,395)	$ 78,467	$ (675,474)	$ (1,155,154)
Weighted Average Number of Shares Outstanding, Basic									73,421	59,932	51,457
Weighted Average Number Diluted Shares Outstanding Adjustment									572	0	0
Effect of dilutive instruments
Weighted Average Number of Shares Outstanding, Diluted									73,993	59,932	51,457
Net Income (Loss) Attributable to Common Shareholders Per Common Share
Net Income (Loss) Attributable to Common Shareholders, Per Basic Share	$ (0.29)	$ 0.07	$ 0.86	$ 0.61	$ (0.01)	$ (1.72)	$ (4.46)	$ (5.34)	$ 1.07	$ (11.27)	$ (22.45)
Net Income (Loss) Attributable to Common Shareholders, Per Diluted Share	$ (0.29)	$ 0.07	$ 0.85	$ 0.61	$ (0.01)	$ (1.72)	$ (4.46)	$ (5.34)	$ 1.06	$ (11.27)	$ (22.45)

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Summary of Significant Accounting Policies (Schedule of Antidilutive Shares Excluded from Earnings Per Share) (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Number Diluted Shares Outstanding Adjustment	572	0	0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	52	669	649

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Acquisitions and Divestitures (Narrative) (Details)	1 Months Ended		3 Months Ended					6 Months Ended	12 Months Ended			15 Months Ended
	Dec. 31, 2016 USD ($)	Oct. 31, 2016 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) $ / bbls $ / MMBTU	Sep. 30, 2017 USD ($) $ / bbls	Jun. 30, 2017 USD ($) $ / bbls	Mar. 31, 2017 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2017 USD ($)	Dec. 11, 2017 USD ($)	Nov. 20, 2017 USD ($)	Oct. 05, 2017 USD ($)	Aug. 31, 2017 USD ($)	Aug. 10, 2017 USD ($)	Jun. 28, 2017 USD ($)
Business Acquisition [Line Items]
Payments to Acquire Oil and Gas Property									$ 695,774,000	$ 153,521,000	$ 1,817,000
Business Combination, Contingent Consideration, Liability, Noncurrent				$ 85,625,000					85,625,000			$ 85,625,000
Net proceeds from divestitures of oil and gas properties									197,564,000	15,564,000	$ 8,047,000
Business Combination, Contingent Consideration, Liability																	$ 52,300,000
ExL Acquisition [Member]
Business Acquisition [Line Items]
Agreed Upon Purchase Price of Oil and Gas Property and Equipment				$ 648,000,000
Payments to Acquire Oil and Gas Property						$ 75,000,000			$ 679,800,000
Percentage of Working Interest Subsequent to Acquisition				70.00%					70.00%			70.00%
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Payments For Acquisition | $ / bbls						50.00
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High																		$ 125,000,000
Business Combination, Contingent Consideration, Liability, Noncurrent				$ 85,625,000					$ 85,625,000			$ 85,625,000					$ 52,300,000
Revenue of Acquiree since Acquisition Date, Actual									53,500,000
Earnings (Loss) of Acquiree since Acquisition Date, Actual									44,300,000
Sanchez Acquisition [Member]
Business Acquisition [Line Items]
Agreed Upon Purchase Price of Oil and Gas Property and Equipment										$ 181,000,000
Payments to Acquire Oil and Gas Property	$ 143,500,000	$ 10,000,000				$ 9,800,000	$ 7,000,000					$ 170,300,000
Revenue of Acquiree since Acquisition Date, Actual									37,800,000
Earnings (Loss) of Acquiree since Acquisition Date, Actual									16,500,000
Utica Shale Divestiture [Member]
Business Acquisition [Line Items]
Agreed Upon Sale Price of Oil and Gas Property and Equipment																$ 62,000,000
Net proceeds from divestitures of oil and gas properties									63,100,000
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture				5,000,000
Marcellus Shale Divestiture [Member]
Business Acquisition [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High															$ 7,500,000
Agreed Upon Sale Price of Oil and Gas Property and Equipment															$ 84,000,000
Net proceeds from divestitures of oil and gas properties				73,900,000
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture				3,000,000
Niobrara Divestiture [Member]
Business Acquisition [Line Items]
Agreed Upon Sale Price of Oil and Gas Property and Equipment														$ 140,000,000
Niobrara Divestiture [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties								$ 136,600,000
Eagle Ford Shale Divestiture [Member]
Business Acquisition [Line Items]
Agreed Upon Sale Price of Oil and Gas Property and Equipment													$ 245,000,000
Eagle Ford Shale Divestiture [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties								$ 246,200,000
Minimum [Member] | ExL Acquisition [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition						0
Minimum [Member] | Utica Shale Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture					$ 0
Minimum [Member] | Marcellus Shale Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture				0
Minimum [Member] | Niobrara Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture				$ 0
Maximum [Member] | ExL Acquisition [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition						$ 50,000,000
2018 [Member] | Utica Shale Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls					50.00
2018 [Member] | Marcellus Shale Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU				3.13
2019 [Member] | Utica Shale Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls					53.00
2019 [Member] | Marcellus Shale Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU				3.18
2020 [Member] | Utica Shale Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls					56.00
2020 [Member] | Marcellus Shale Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU				3.30
2020 [Member] | Niobrara Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls				60.00
Two Thousand Eighteen and Two Thousand Nineteen [Member] | Niobrara Divestiture [Member]
Business Acquisition [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls				55.00
Delaware Basin [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties							$ 15,300,000
Deposit Received Prior To Closing [Member] | Utica Shale Divestiture [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties					$ 6,200,000
Deposit Received Prior To Closing [Member] | Marcellus Shale Divestiture [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties				$ 6,300,000
Deposit Received Prior To Closing [Member] | Niobrara Divestiture [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties									$ 14,000,000
Deposit Received Prior To Closing [Member] | Eagle Ford Shale Divestiture [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties				24,500,000
Cash Received At Closing [Member] | Utica Shale Divestiture [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties				54,400,000
Cash Received At Closing [Member] | Marcellus Shale Divestiture [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties				67,600,000
Cash Received At Closing [Member] | Niobrara Divestiture [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties			$ 122,600,000
Cash Received At Closing [Member] | Eagle Ford Shale Divestiture [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties			211,700,000
Cash Received Post Closing [Member] | Utica Shale Divestiture [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties				2,500,000
Cash Received Post Closing [Member] | Eagle Ford Shale Divestiture [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Net proceeds from divestitures of oil and gas properties			$ 10,000,000
Cash Paid At Closing [Member] | ExL Acquisition [Member]
Business Acquisition [Line Items]
Payments to Acquire Oil and Gas Property					$ 601,000,000
Cash Paid Post Closing [Member] | ExL Acquisition [Member]
Business Acquisition [Line Items]
Payments to Acquire Oil and Gas Property				$ 3,800,000

XML

Acquisitions and Divestitures (Schedule of Consideration Paid for Assets Acquired and Liabilities Assumed) (Table) (Details) - USD ($) $ in Thousands	Aug. 10, 2017	Dec. 14, 2016
Acquisitions - Schedule of Consideration Paid for the Transactions of Assets Acquired and Liabilities Assumed [Abstract]
Business Combination, Current Assets	$ 106	$ 477
Business Combination, Oil and Gas Properties, Net	294,754	99,938
Business Combination, Recognized Assets Acquired and Liabilities Assumed, Unproved Oil and Gas Properties	443,194	74,536
Business Combination, Recognized Assets Acquired and Liabilities Assumed, Oil and Gas Properties	737,948	174,474
Business Combination, Total Assets	738,054	174,951
Business Combination, Current Liabilities	5,785	1,442
Business Combination, Other Liabilities		323
Business Combination, Noncurrent Liabilities	153	2,054
Business Combination, Contingent Consideration, Liability	52,300
Business Combination, Other Noncurrent Liabilities		1,078
Business Combination, Liabilities	58,238	4,897
Business Combination, Net	$ 679,816	$ 170,054

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Acquisitions and Divestitures (Schedule of Results of Operations) (Table) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Acquisitions - Results of Operations [Abstract]
Business Acquisition, Pro Forma Revenue	$ 781,378	$ 454,913
Business Acquisition, Pro Forma Net Income (Loss)	$ 91,931	$ (688,180)
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 1.25	$ (9.11)
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 1.24	$ (9.11)
Weighted Average Basic Shares Outstanding, Pro Forma	73,421	75,532
Pro Forma Weighted Average Shares Outstanding, Diluted	73,993	75,532

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Property And Equipment, Net (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Unproved properties, not being amortized				$ 660,287	$ 240,961
Capitalized costs of unproved properties				523,100	106,800	$ 24,000
Impairment of proved oil and gas properties	$ 105,100	$ 197,100	$ 274,400	$ 0	$ 576,540	$ 1,224,367

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Property And Equipment, Net (Schedule Of Property And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Proved properties, net	$ 5,615,153	$ 4,687,416
Accumulated DD&A and impairments	3,649,806	3,392,749
Proved properties, net	1,965,347	1,294,667
Unproved properties, not being amortized
Unevaluated leasehold and seismic costs	612,589	211,067
Capitalized interest	47,698	29,894
Total unproved properties, not being amortized	660,287	240,961
Other property and equipment	25,625	23,127
Accumulated depreciation	(15,449)	(12,995)
Other property and equipment, net	10,176	10,132
Total property and equipment, net	$ 2,635,810	$ 1,545,760

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Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 01, 2017
Income Taxes [Line Items]
U.S. federal statutory corporate pretax rate			35.00%
Deferred State and Local Income Tax Expense (Benefit)			$ 3,635,000	$ 0	$ (9,373,000)
Income Tax Rate Reconciliation, US Federal Rate Reduction			211,724,000	0	0
Valuation Allowance, Effect Of Tax Cuts And Jobs Act			211,724,000
Deferred Tax Assets, Net			0
Tax Adjustments, Settlements, and Unusual Provisions			15,700,000
Tax Adjustments, Settlements, and Unusual Provisions, Retained Earnings Effect			0.0
Deferred Tax Assets, Valuation Allowance			333,029,000	564,434,000		$ 580,100,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount			(247,100,000)
Partial Release Of Valuation Allowance			35,400,000
Deferred Tax Assets, Operating Loss Carryforwards, State and Local			$ 12,700,000
Ownership percentage change			5.00%
Change in beneficial ownership, percentage			50.00%
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount			$ (35,376,000)	240,864,000	323,586,000
Income Tax Expense (Benefit)			4,030,000	$ 0	$ (140,875,000)
United States Of America [Member]
Income Taxes [Line Items]
Operating loss carry forwards subject to expiration			1,096,200,000
Subsequent Event [Member]
Income Taxes [Line Items]
U.S. federal statutory corporate pretax rate		21.00%
Limitation Of Utilization Of NOL Carryforwards	80.00%
Texas [Member]
Income Taxes [Line Items]
Deferred State and Local Income Tax Expense (Benefit)			$ 3,600,000

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Income Taxes (Schedule Of Components Of Income Tax (Expense) Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current income tax (expense) benefit
U.S. Federal	$ 0	$ 0	$ 0
State	(395)	0	0
Total current income tax (expense) benefit	(395)	0	0
Deferred income tax (expense) benefit
U.S. Federal	0	0	131,502
State	(3,635)	0	9,373
Total deferred income tax (expense) benefit	(3,635)	0	140,875
Income tax (expense) benefit	$ (4,030)	$ 0	$ 140,875

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Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income (loss) from continuing operations before income taxes	$ 91,140	$ (675,474)	$ (1,298,760)
Income tax (expense) benefit at the statutory rate	31,899	(236,416)	(454,566)
State income tax (expense) benefit, net of U.S. Federal income taxes	(4,030)	3,894	9,373
Tax shortfalls from stock-based compensation expense	3,089	0	0
Texas Franchise Tax rate reduction, net of U.S. Federal income tax expense	0	0	1,671
Income tax (expense) benefit from U.S. Federal rate reduction	(211,724)	0	0
Change in valuation allowance from U.S. Federal rate reduction	(211,724)	0	0
Change in valuation allowance from current year activity	35,376	(240,864)	(323,586)
Other	(388)	554	(1,149)
Income tax (expense) benefit	$ (4,030)	$ 0	$ 140,875

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Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Jan. 01, 2017	Dec. 31, 2016
Deferred income tax assets
Net operating loss carryforward - U.S. Federal and State	$ 242,915		$ 221,063
Oil and gas properties	50,177		309,848
Asset retirement obligations	4,996		7,434
Stock-based compensation	0		5,238
Derivative liabilities	35,585		17,545
Other	1,496		3,739
Deferred income tax assets	335,169		564,867
Deferred tax asset valuation allowance	(333,029)	$ (580,100)	(564,434)
Net deferred income tax assets	2,140		433
Deferred income tax liabilities
Oil and gas properties	(3,635)		0
Derivative assets	(2,140)		(433)
Net deferred income tax asset (liability)	$ (3,635)		$ 0

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Debt (Narrative) (Details)	3 Months Ended	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2017 USD ($) Rate	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Nov. 03, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jul. 14, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Apr. 28, 2015
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	$ (4,170,000)	$ (4,170,000)	$ 0	$ (38,137,000)
Change of control repurchase price percentage	101.00%	101.00%
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility current borrowing base	$ 900,000,000	$ 900,000,000					$ 837,500,000	$ 900,000,000	$ 600,000,000
Line of Credit Facility, Elected Borrowing Capacity	800,000,000	800,000,000						800,000,000
Restricted Payments Basket					$ 75,000,000	$ 50,000,000
Line of credit facility amount outstanding	$ 291,300,000	$ 291,300,000	87,000,000
Debt, Weighted Average Interest Rate	3.73%	3.73%
Letters of credit outstanding amount	$ 415,000	$ 415,000
Line of credit facility, maximum borrowing capacity								$ 2,000,000,000	$ 1,000,000,000
Ratio of total debt to EBITDA		2.59
Pre-Tax SEC PV10 Reserve Value Percentage | Rate		90.00%
Federal funds rate plus percentage	0.50%	0.50%
Adjusted LIBO rate plus percentage	1.00%	1.00%
Reduction Of Borrowing Capacity Due To Issuance Of Senior Notes							25.00%
Current Ratio	1.98	1.98
Senior Secured Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Current Ratio	1.00	1.00
Senior Secured Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Ratio of total debt to EBITDA		4.00
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount							$ 250,000,000
Debt instrument interest rate							8.25%
Long-term Debt, Gross	$ 250,000,000	$ 250,000,000	0
Proceeds from Issuance of Debt	$ 245,400,000
7.50% Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument interest rate	7.50%	7.50%
Long-term Debt, Gross	$ 450,000,000	$ 450,000,000	600,000,000
Debt Instrument, Repurchased Face Amount	$ 150,000,000	150,000,000
Redemption Premium		2,800,000
Debt Instrument, Redemption, Cash Consideration		156,000,000
Accrued interest paid associated with redemption of debt		3,200,000
Gains (Losses) on Extinguishment of Debt		(4,170,000)
Write off of Deferred Debt Issuance Cost		$ 1,300,000
7.50% Senior Notes [Member] | On and after September 15, 2016 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount	100.00%	100.00%
7.50% Senior Notes [Member] | On and after September 15, 2016 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount	101.875%	101.875%
6.25% Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument interest rate										6.25%
Long-term Debt, Gross	$ 650,000,000	$ 650,000,000	650,000,000
6.25% Senior Notes [Member] | Prior to April 15, 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
6.25% Senior Notes [Member] | On and after April 15, 2018 [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
6.25% Senior Notes [Member] | On and after April 15, 2018 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	104.688%
Other Long Term Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 4,425,000	$ 4,425,000	$ 4,425,000
Prior to July 15, 2020 [Member] | 8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount							100.00%
On And After July 15, 2020 [Member] | 8.25% Senior Notes [Member] | Minimum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount							100.00%
On And After July 15, 2020 [Member] | 8.25% Senior Notes [Member] | Maximum [Member]
Debt Instrument [Line Items]
Redemption price, percentage of principal amount							106.188%

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Debt (Schedule Of Debt) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities	$ 1,629,209	$ 1,325,418
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility amount outstanding	291,300	87,000
8.25% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	250,000	0
Unamortized Debt Issuance Expense	4,395	0
7.50% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	450,000	600,000
Debt Instrument, Unamortized Premium	579	1,020
Unamortized Debt Issuance Expense	4,492	7,573
6.25% Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	650,000	650,000
Unamortized Debt Issuance Expense	8,208	9,454
Other Long Term Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 4,425	$ 4,425

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Debt (Interest and Commitment Fee Rates) (Details)	12 Months Ended
	Dec. 31, 2017
Less than 25 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.00%
Margin for eurodollar loans	2.00%
Line of Credit Facility, Commitment Fee Percentage	0.375%
Greater than or equal to 25 percent but less than 50 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.25%
Margin for eurodollar loans	2.25%
Line of Credit Facility, Commitment Fee Percentage	0.375%
Greater than or equal to 50 percent but less than 75 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.50%
Margin for eurodollar loans	2.50%
Line of Credit Facility, Commitment Fee Percentage	0.50%
Greater than or equal to 75 percent but less than 90 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	1.75%
Margin for eurodollar loans	2.75%
Line of Credit Facility, Commitment Fee Percentage	0.50%
Greater than or equal to 90 percent [Member]
Interest and Commitment Fee Rates [Line Items]
Margin for base rate loans	2.00%
Margin for eurodollar loans	3.00%
Line of Credit Facility, Commitment Fee Percentage	0.50%

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of year asset retirement obligations	$ 21,240	$ 16,511
Liabilities incurred	3,920	2,137
Liabilities settled	(343)	(599)
Reduction due to sales of oil and gas properties	2,671	0
Accretion expense	1,799	1,364
Revisions to estimated cash flows	(306)	(210)
End of year asset retirement obligations	23,792	21,240
Current asset retirement obligations (included in other current liabilities)	(295)	(392)
Non-current asset retirement obligations	23,497	20,848
ExL Acquisition [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities incurred	$ 153
Eagle Ford Shale Transaction [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities incurred		$ 2,037

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Commitments and Contingencies (Narrative) (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 28, 2017
Other Commitments [Line Items]
Other Commitment, Due 5 years and thereafter			$ 12,564,000
Rent expense			$ 1,700,000	$ 2,000,000	$ 2,200,000
Subsequent Event [Member] | Drilling Rig Contracts [Member]
Other Commitments [Line Items]
Contractual Obligation, Due in first and second year	$ 22,200,000
Subsequent Event [Member] | Delivery Commitments [Member]
Other Commitments [Line Items]
Other Commitment, Due 5 years and thereafter	$ 111,600,000
Subsequent Event [Member] | Minimum [Member] | Drilling Rig Contracts [Member]
Other Commitments [Line Items]
Commitments, Term in Years	1
Subsequent Event [Member] | Minimum [Member] | Delivery Commitments [Member]
Other Commitments [Line Items]
Commitments, Term in Years	5
Subsequent Event [Member] | Maximum [Member] | Drilling Rig Contracts [Member]
Other Commitments [Line Items]
Commitments, Term in Years	2
Subsequent Event [Member] | Maximum [Member] | Delivery Commitments [Member]
Other Commitments [Line Items]
Commitments, Term in Years	6
ExL Acquisition [Member]
Other Commitments [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High						$ 125,000,000
ExL Acquisition [Member] | Minimum [Member]
Other Commitments [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition		$ 0
ExL Acquisition [Member] | Maximum [Member]
Other Commitments [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition		$ 50,000,000

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Commitments and Contingencies (Schedule of Contractual Obligations) (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Operating leases
Less than 1 year	$ 5,038
Due in second year	4,895
Due in third year	4,637
Due in fourth year	4,450
Due in fifth year	1,854
More than 5 years	0
Total	20,874
Capital leases
Less than 1 year	1,823
Due in second year	1,800
Due in third year	1,050
Due in fourth year	0
Due in fifth year	0
More than 5 years	0
Total	4,673
Drilling rig contracts
Less than 1 year	23,885
Due in second year	8,881
Due in third year	0
Due in fourth year	0
Due in fifth year	0
More than 5 years	0
Total	32,766
Delivery commitments
Less than 1 year	3,657
Due in second year	3,676
Due in third year	2,757
Due in fourth year	2,438
Due in fifth year	10
More than 5 years	26
Total	12,564
Total
Less than 1 year	34,403
Due in second year	19,252
Due in third year	8,444
Due in fourth year	6,888
Due in fifth year	1,864
More than 5 years	26
Total	$ 70,877

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Preferred Stock (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 24, 2018
Preferred Stock Disclosure [Line Items]
Temporary Equity, Par Value		$ 250,000
Temporary Equity, Shares Issued		250,000	0
Preferred Stock, Dividend Rate, Percentage		8.875%
Preferred Stock, Par or Stated Value Per Share		$ 0.01	$ 0.00
Issuance of warrants to purchase common stock		2,750,000	0
Class of Warrant or Right Term		10 years
Class of Warrant or Right, Exercise Price of Warrants or Rights		$ 16.08
Cash Purchase Price Per Share of Preferred Stock		$ 970.00
Payment of Commitment Fees for Preferred Stock		$ (5,000)
Sale of preferred stock, net of offering costs		$ 236,404	$ 0	$ 0
Maximum Preferred Stock Shares Redeemable Within the First Year		50,000
Temporary Equity, Liquidation Preference Per Share		$ 1,000.00
Preferred Stock, Redemption Premium, Percentage		104.4375%
Preferred Stock, Percent of Ownership to be Able to Vote		50.00%
Preferred Stock, Prohibited Distributions		$ 15,000
Proceeds from Issuance of Preferred Stock and Preference Stock		213,400
Proceeds from Issuance of Warrants		23,003
Dividends on preferred stock		(7,781)	0	0
Accretion on preferred stock		$ (862)	$ 0	$ 0
On or before the seventh anniversary of the Preferred Stock Issuance Date [Domain]
Preferred Stock Disclosure [Line Items]
Preferred Stock, Dividend Rate, Percentage		12.00%
After August 10, 2024 [Domain]
Preferred Stock Disclosure [Line Items]
Preferred Stock, Dividend Rate, Percentage		12.00%
Libor Rate to Calculate Preferred Stock Dividend Rate		10.00%
Subsequent Event [Member]
Preferred Stock Disclosure [Line Items]
Temporary Equity, Liquidation Preference Per Share					$ 1,000.00
Preferred Stock Shares Redeemed					50,000
Payments for Repurchase of Redeemable Preferred Stock	$ 50,500

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Preferred Stock (Schedule of Dividends Paid in Common Stock) (Details)	Dec. 31, 2017 Rate
Preferred Stock Dividend Paid in Common Stock First Year [Member]
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items]
Percent of Dividend Payable in Common Stock	100.00%
Preferred Stock Dividend Paid in Common Stock Second Year [Member]
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items]
Percent of Dividend Payable in Common Stock	75.00%
Preferred Stock Dividend Paid in Common Stock Third Year [Member]
Schedule of Preferred Stock Dividend Paid in Common Stock [Line Items]
Percent of Dividend Payable in Common Stock	50.00%

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Preferred Stock (Schedule of Preferred Stock Redemption Premiums) (Details)	12 Months Ended
	Dec. 31, 2017
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	104.4375%
Preferred Stock Redemption Fourth Year [Member]
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	104.4375%
Preferred Stock Redemption Fifth Year [Member] [Member]
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	102.21875%
Preferred Stock Redemption Sixth Year [Member]
Schedule of Preferred Stock Redemption Premiums [Line Items]
Preferred Stock, Redemption Premium, Percentage	100.00%

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Preferred Stock (Warrants Valuation Assumptions) (Details)	12 Months Ended
	Dec. 31, 2017 $ / shares
Temporary Equity Disclosure [Abstract]
Class of Warrant or Right, Exercise Price of Warrants or Rights	$ 16.08
Fair Value Assumptions, Expected Term	10 years
Fair Value Assumptions, Expected Volatility Rate	62.90%
Fair Value Assumptions, Risk Free Interest Rate	2.20%
Fair Value Assumptions, Expected Dividend Rate	0.00%

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Preferred Stock (Schedule of Preferred Stock Activity) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Preferred Stock Activity [Abstract]
Proceeds from Issuance of Preferred Stock and Preference Stock	$ 213,400,000
Accretion on preferred stock	(862,000)	$ 0	$ 0
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	$ 214,262,000	$ 0

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Shareholders' Equity And Stock Incentive Plan (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended			12 Months Ended
	Mar. 31, 2017	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 03, 2017	Oct. 28, 2016	Oct. 21, 2015	Mar. 20, 2015	Dec. 31, 2014	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares authorized (in shares)				180,000,000	90,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Vested				$ 20,300	$ 26,300	$ 32,000
Sale of common stock, net of offering costs, shares		6,300,000	5,200,000	15,600,000	6,000,000
Sale of Stock, Price Per Share							$ 14.28	$ 37.32	$ 37.80	$ 44.75
Sale of common stock, net of offering costs		$ 238,800	$ 231,316	$ 222,378	$ 223,739	$ 470,158
Class of Warrant or Right, Outstanding												118,200
Issuance of warrants to purchase common stock				2,750,000	0
Investment warrants, exercise price						$ 22.09
Conversion of Stock, Shares Issued						71,913
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant				2,675,000
Ratio Of Stock Based Compensation Shares to Common Shares				1.35
Shares Granted, Options					0
Proceeds from stock options exercised				$ 0	$ 0	$ 46
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio Of Stock Based Compensation Shares to Common Shares				1.00
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation cost not yet recognized				$ 21,300
Compensation cost not yet recognized, period for recognition				1 year 10 months 24 days
Grants in Period, Performance Shares				1,020,465	887,254	401,421
Grant Date Fair Value, Performance Shares		$ 44.22		$ 28.07	$ 36.93	$ 44.22					$ 34.55
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period				635,965	811,136	671,417
Cash Settled Stock Appreciation Rights Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
SARs, Granted				342,440	376,260	0
Liability for cash stock appreciation rights				$ 4,400	$ 11,500
Liability for cash stock appreciation rights, classified as other accrued liabilities					10,000
Liability for cash stock appreciation rights remainder, classified as other long term liabilities					1,500
Cash paid at exercises, Stock Appreciation Rights				2,100	$ 5,200	$ 1,500
Compensation cost not yet recognized				$ 1,300
Compensation cost not yet recognized, period for recognition				1 year 1 month 5 days
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation cost not yet recognized				$ 2,100
Compensation cost not yet recognized, period for recognition				1 year 8 months 12 days
Grants in Period, Performance Shares				46,787	41,651	56,517
Grant Date Fair Value, Performance Shares		$ 66.83		$ 47.14	$ 58.44	$ 66.83					$ 68.15
Vesting period, in years				3 years
Performance Shares Vested Per TSR Ranking	92,200
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	56,342			56,342	0	0
Vesting Percentage Of Target Performance Shares Granted	164.00%
Minimum [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period, in years				1 year
Minimum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Awards to Vest Based on Market Condition				0.00%
Maximum [Member] | Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period, in years				3 years
Maximum [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Awards to Vest Based on Market Condition				200.00%
2017 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant				1,750,908

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Shareholders' Equity And Stock Incentive Plan (Summary Of Restricted Stock Award And Unit Activity) (Details) - Restricted Stock Awards And Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Awards and Units
Unvested Shares/Units, Beginning of Period	1,111,710	1,041,997	1,335,682
Granted Shares/Units	1,020,465	887,254	401,421
Vested Shares/Units	(635,965)	(811,136)	(671,417)
Forfeited Shares/Units	(13,555)	(6,405)	(23,689)
Unvested Shares/Units, End of Period	1,482,655	1,111,710	1,041,997
Weighted Average Grant Date Fair Value
Grant-date Fair Value, Beginning of Period (USD per share)	$ 36.93	$ 44.22	$ 34.55
Granted, Grant-date Fair Value (USD per share)	25.63	27.80	51.45
Vested, Grant-date Fair Value (USD per share)	39.62	36.32	32.96
Forfeited, Grant-date Fair Value (USD per share)	29.11	34.46	43.36
Grant-date Fair Value, End of Period (USD per share)	$ 28.07	$ 36.93	$ 44.22

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Shareholders' Equity And Stock Incentive Plan (Summary of SARs Activity) (Details) - Cash Settled Stock Appreciation Rights Plan [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
SARs, Outstanding, beginning of period	722,638	700,453	765,198
SARs, Granted	342,440	376,260	0
SARs, Exercised	(219,279)	(354,075)	(64,745)
SARs, Forfeitures	0	0	0
SARs, Expired	131,561
SARs, Outstanding, end of period	714,238	722,638	700,453
SARS, Vested, end of period	185,899	350,840	626,661
SARs, Exercisable, end of period	0	350,840	626,661
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Weighted Average Exercise Price [Roll Forward]
Weighted Average Exercise Prices, Outstanding, Beginning of Period	$ 23.69	$ 21.86	$ 22.49
Weighted Average Exercise Prices, Granted	26.94	27.30	0.00
Weighted Average Exercise Prices, Exercised	17.28	23.89	29.40
Weighted Average Exercise Prices, Forfeitures	0.00	0.00	0.00
Weighted Average Exercise Prices, Expired (USD per share)	24.19
Weighted Average Exercise Prices, Outstanding, End of Period	27.12	23.69	21.86
Weighted Average Exercise Prices, Vested, End of Period	27.30	19.87	21.05
Weighted Average Exercise Prices, Exercisable, End of Period	$ 27.30	$ 19.87	$ 21.05
Cash paid at exercises, Stock Appreciation Rights	$ 2.1	$ 5.2	$ 1.5
Weighted Average Remaining Life, Outstanding, End of Period	3 years 8 months 12 days
Weighted Average Remaining Life, Exercisable, End of Period	3 years 2 months 12 days
Aggregate Intrinsic Value, Outstanding, End of Period	$ 0.0
Aggregate Intrinsic Value, Exercisable, End of Period	$ 0.0

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Shareholders' Equity And Stock Incentive Plan (Summary of Stock Appreciation Rights Fair Value Assumptions) (Details) - Cash Settled Stock Appreciation Rights Plan [Member]	12 Months Ended
	Dec. 31, 2017 Rate	Dec. 31, 2016 Rate
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility	54.30%	45.10%
Dividend yield	0.00%	0.00%
Risk-free interest rate	1.80%	1.30%
Expected Term	4 years 2 months 26 days	3 years 11 months 5 days

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Shareholders' Equity And Stock Incentive Plan (Summary of Performance Share Award Activity) (Details) - Performance Shares [Member] - $ / shares	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Target Performance Shares (1)
Unvested Shares/Units, Beginning of Period	154,510	154,510	112,859	56,342
Granted Shares/Units		46,787	41,651	56,517
Vested Shares/Units	(56,342)	(56,342)	0	0
Forfeited Shares/Units		0	0	0
Unvested Shares/Units, End of Period		144,955	154,510	112,859
Weighted Average Grant Date Fair Value
Grant-date Fair Value, Beginning of Period (USD per share)	$ 58.44	$ 58.44	$ 66.83	$ 68.15
Granted, Grant-date Fair Value (USD per share)		35.14	35.71	65.51
Vested, Grant-date Fair Value (USD per share)		68.15	0.00	0.00
Forfeited, Grant-date Fair Value (USD per share)		0.00	0.00	0.00
Grant-date Fair Value, End of Period (USD per share)		$ 47.14	$ 58.44	$ 66.83

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Shareholders' Equity And Stock Incentive Plan (Summary of Performance Share Awards Fair Value Assumptions) (Details) - Performance Shares [Member]	12 Months Ended
	Dec. 31, 2017 Rate	Dec. 31, 2016 Rate	Dec. 31, 2015 Rate
Number of simulations	500,000	500,000	500,000
Expected Term	2 years 11 months 23 days	3 years 3 days	2 years 10 months 21 days
Expected volatility	59.20%	55.30%	45.30%
Risk-free interest rate	1.50%	1.20%	0.90%
Dividend yield	0.00%	0.00%	0.00%

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Shareholders' Equity And Stock Incentive Plan (Stock-Based Compensation Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	$ 18,791	$ 40,677	$ 19,303
Less: amounts capitalized	(4,482)	(4,591)	(4,574)
Total stock-based compensation expense	14,309	36,086	14,729
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	21,372	28,196	23,668
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	(5,023)	9,675	(6,326)
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Total stock-based compensation expense	$ 2,442	$ 2,806	$ 1,961

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Derivative Instruments (Narrative) (Details) $ in Thousands	3 Months Ended
	Dec. 31, 2017 USD ($) $ / MMBTU	Sep. 30, 2017 $ / bbls	Jun. 30, 2017 USD ($) $ / bbls	Nov. 21, 2017 USD ($)	Nov. 15, 2017 USD ($)	Oct. 05, 2017 USD ($)	Aug. 10, 2017 USD ($)	Jun. 28, 2017 USD ($)	Dec. 31, 2016 USD ($)
Derivative [Line Items]
Business Combination, Contingent Consideration, Liability, Noncurrent	$ 85,625
Business Combination, Contingent Consideration, Asset, Noncurrent	10,190								$ 0
ExL Acquisition [Member]
Derivative [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High								$ 125,000
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Payments For Acquisition | $ / bbls			50.00
Business Combination, Contingent Consideration, Liability, Noncurrent	85,625						$ 52,300
Utica Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture	5,000
Business Combination, Contingent Consideration, Asset, Noncurrent	7,985				$ 6,100
Marcellus Shale Divestiture [Member]
Derivative [Line Items]
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High						$ 7,500
Contingent Consideration Arrangement, Potential Additional Annual Proceeds From Divestiture	3,000
Business Combination, Contingent Consideration, Asset, Noncurrent	$ 2,205			$ 2,700
Maximum [Member] | ExL Acquisition [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Potential Additional Annual Payments for Acquisition			$ 50,000
2018 [Member] | Utica Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls		50.00
2018 [Member] | Marcellus Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU	3.13
2019 [Member] | Utica Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls		53.00
2019 [Member] | Marcellus Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU	3.18
2020 [Member] | Utica Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per Bbl For Additional Proceeds From Divestiture | $ / bbls		56.00
2020 [Member] | Marcellus Shale Divestiture [Member]
Derivative [Line Items]
Contingent Consideration Arrangement, Threshold Price Per MMBtu For Additional Payments From Divestiture | $ / MMBTU	3.30

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Derivative Instruments (Schedule of Crude Oil Derivative Positions) (Details) - Crude Oil [Member]	Dec. 31, 2017 bbl / d $ / bbls
Fixed Price Swaps [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	6,000
Weighted Average Fixed Price	(49.55)
Three-way Collars [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	24,000
Derivative Average Sub Floor Price	39.38
Weighted Average Floor Price ($/Bbl)	49.06
Weighted Average Ceiling Price ($/Bbl)	60.14
Three-way Collars [Member] | 2019 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	12,000
Derivative Average Sub Floor Price	40.00
Weighted Average Floor Price ($/Bbl)	48.40
Weighted Average Ceiling Price ($/Bbl)	60.29
Sold Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	3,388
Weighted Average Ceiling Price ($/Bbl)	71.33
Sold Call Options [Member] | 2019 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	3,875
Weighted Average Ceiling Price ($/Bbl)	73.66
Sold Call Options [Member] | 2020 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	4,575
Weighted Average Ceiling Price ($/Bbl)	75.98
LLS-NYMEX Price Differential [Member] | Basis Swap [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	6,000
Weighted Average Fixed Price	(2.91)
Midland-NYMEX Price Differential [Member] | Basis Swap [Member] | 2018 [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	6,000
Weighted Average Fixed Price	(0.10)

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Derivative Instruments (Schedule of NGL Derivative Positions) (Details) - 2018 [Member] - Natural Gas Liquids [Member] - Swap [Member]	Dec. 31, 2017 bbl / d $ / bbls
OPIS Purity Ethane Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	2,200
Weighted Average Fixed Price | $ / bbls	12.01
OPIS Propane Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	1,500
Weighted Average Fixed Price | $ / bbls	34.23
OPIS Normal Butane Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	200
Weighted Average Fixed Price | $ / bbls	38.85
OPIS Isobutane Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	600
Weighted Average Fixed Price | $ / bbls	38.98
OPIS Natural Gasoline Mont Belvieu Non-TET [Member]
Derivative [Line Items]
Derivative, Volumes | bbl / d	600
Weighted Average Fixed Price | $ / bbls	55.23

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Derivative Instruments (Schedule of Natural Gas Derivative Positions) (Details) - Natural Gas [Member] - Call Option [Member]	Dec. 31, 2017 MMBTU / d $ / MMBTU
2018 [Member]
Derivative [Line Items]
Derivative, Volumes | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.25
2019 [Member]
Derivative [Line Items]
Derivative, Volumes | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.25
2020 [Member]
Derivative [Line Items]
Derivative, Volumes | MMBTU / d	33,000
Weighted Average Ceiling Price ($/MMBtu) | $ / MMBTU	3.50

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Derivative Instruments (Schedule of Contingent Consideration) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Nov. 21, 2017	Nov. 15, 2017	Aug. 10, 2017
Embedded Derivative [Line Items]
Business Combination, Contingent Consideration, Asset, Noncurrent	$ 10,190	$ 0
Business Combination, Contingent Consideration, Liability, Noncurrent	(85,625)
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net	31,940	$ 0	$ 0
ExL Acquisition [Member]
Embedded Derivative [Line Items]
Business Combination, Contingent Consideration, Liability, Noncurrent	(85,625)					$ (52,300)
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net	33,325
Marcellus Shale Divestiture [Member]
Embedded Derivative [Line Items]
Business Combination, Contingent Consideration, Asset, Noncurrent	2,205			$ 2,700
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net	455
Utica Shale Divestiture [Member]
Embedded Derivative [Line Items]
Business Combination, Contingent Consideration, Asset, Noncurrent	7,985				$ 6,100
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net	$ (1,840)

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Derivative Instruments (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Business Combination, Contingent Consideration, Asset, Noncurrent	$ 10,190	$ 0
Derivative Liability, Current	57,121	22,601
Derivative Liability, Noncurrent	112,332	27,528
Other Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	4,869	7,990
Derivative Asset, Fair Value, Gross Liability	(4,869)	(6,753)
Derivative Assets (Liabilities), at Fair Value, Net	0	1,237
Derivative Asset, Current	0
Derivative Asset, Deferred Premiums, Gross Asset	0	0
Derivative Asset, Deferred Premiums, Gross Liability	0	0
Derivative Deferred Premium, Net	0	0
Derivative Asset, Gross Asset	4,869	7,990
Derivative Asset, Gross Liability	(4,869)	6,753
Other Noncurrent Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	9,505	3,882
Derivative Asset, Fair Value, Gross Liability	(9,505)	(3,882)
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Derivative Asset	10,190
Derivative Asset, Deferred Premiums, Gross Asset	0	0
Derivative Asset, Deferred Premiums, Gross Liability	0	0
Derivative Deferred Premium, Net	0	0
Business Combination, Contingent Consideration, Asset, Noncurrent	10,190
Derivative Asset, Gross Asset	19,695	3,882
Derivative Asset, Gross Liability	(9,505)	3,882
Other Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(47,802)	(20,593)
Derivative Liability, Fair Value, Gross Liability	(52,671)	(27,346)
Derivative Liability, Fair Value, Gross Asset	4,869	6,753
Derivative Deferred Premium, Net	(9,319)	(2,008)
Derivative Liability, Deferred Premiums, Gross Liability	9,319	2,008
Derivative Liability, Deferred Premiums, Gross Asset	0	0
Derivative Liability, Gross Liability	(61,990)	29,354
Derivative Liability, Gross Asset	4,869	6,753
Derivative Liability, Current	(57,121)
Other Noncurrent Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(15,104)	(24,959)
Derivative Liability, Fair Value, Gross Liability	(24,609)	(28,841)
Derivative Liability, Fair Value, Gross Asset	9,505	3,882
Derivative Deferred Premium, Net	(11,603)	(2,569)
Derivative Liability, Deferred Premiums, Gross Liability	11,603	2,569
Derivative Liability, Deferred Premiums, Gross Asset	0	0
Derivative Liability, Gross Liability	(121,837)	31,410
Derivative Liability, Gross Asset	9,505	3,882
Derivative Liability, Contingent Payment, Gross Liability	(85,625)	0
Derivative Liability, Contingent Payment, Gross Asset	0	0
Derivative Liability, Contingent Payment, Net	(85,625)	0
Derivative Liability, Noncurrent	(112,332)
Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	1,237
Derivative Liability	$ 62,906	45,552
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Current Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Current		1,237
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Noncurrent Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Noncurrent		0
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Current Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Current		(22,601)
Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Other Noncurrent Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Noncurrent		$ (27,528)

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Derivative Instruments (Schedule of (Gain) Loss on Derivative Instruments) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net	$ 86,107	$ 24,377	$ (26,065)	$ (25,316)	$ 59,103	$ 49,073	$ (99,261)
Embedded Derivative, Gain (Loss) on Embedded Derivative, Net					31,940	0	0
Crude Oil [Member]
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net					22,839	23,609	(99,624)
Natural Gas Liquids [Member]
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net					1,322	0	0
Natural Gas [Member]
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net					(15,399)	19,584	(4,063)
Deferred Premiums On Derivative Instruments [Member]
Derivative Instruments, (Gain) Loss, Commodity [Line Items]
(Gain) loss on derivatives, net					$ 18,401	$ 5,880	$ 4,426

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Derivative Instruments (Schedule of Cash Received for Derivative Settlements) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Cash Received For Derivatives [Line Items]
Net Cash Received Paid For Derivative Settlements	$ 7,773	$ 119,369	$ 194,296
Natural Gas [Member]
Schedule Of Cash Received For Derivatives [Line Items]
Net Cash Received Paid For Derivative Settlements	(54)	0	17,785
Crude Oil [Member]
Schedule Of Cash Received For Derivatives [Line Items]
Net Cash Received Paid For Derivative Settlements	9,883	125,098	176,511
Deferred Premiums On Derivative Instruments [Member]
Schedule Of Cash Received For Derivatives [Line Items]
Net Cash Received Paid For Derivative Settlements	$ (2,056)	$ (5,729)	$ 0

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Fair Value Measurements (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount	$ 0
Fair Value, Assets, Level 2 to Level 1 Transfers, Amount		$ 0
Fair value amount of transfers in or out of Levels 1 or 2		0
Fair Value, Assets, Level 3 Transfers		$ 0
Fair Value, Equity, Level 1 to Level 2 Transfers, Amount	$ 0

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Fair Value Measurements (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 0	$ 0
Derivative Liability	0	0
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	1,237
Derivative Liability	(62,906)	(45,552)
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	10,190	0
Derivative Liability	$ (85,625)	$ 0

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Fair Value Measurements (Schedule of Fair Value Assets, Unobservable Inputs Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$ 10,190	$ 0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances	8,805
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings	1,385
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	$ 0

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Fair Value Measurements (Schedule of Fair Value Liabilities, Unobservable Inputs Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (85,625)	$ 0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Issuances	(52,300)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings	(33,325)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	$ 0

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Fair Value Measurements (Schedule of Fair Value of Debt Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
7.50% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	$ 450,000	$ 600,000
8.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	250,000	0
Other Long Term Debt [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	4,425	4,425
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 7.50% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	446,087	593,447
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 6.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	641,792	640,546
Carrying (Reported) Amount, Fair Value Disclosure [Member] | 8.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	245,605	0
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Other Long Term Debt [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	4,425	4,425
Estimate of Fair Value Measurement [Member] | 7.50% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	459,518	624,750
Estimate of Fair Value Measurement [Member] | 6.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	674,375	672,750
Estimate of Fair Value Measurement [Member] | 8.25% Senior Notes [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	274,375	0
Estimate of Fair Value Measurement [Member] | Other Long Term Debt [Member]
Schedule of Fair Value of Debt Instruments [Line Items]
Long-term Debt, Gross	$ 4,445	$ 4,419

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Condensed Consolidating Financial Information (Narrative) (Details)	Dec. 31, 2017
Condensed Consolidating Financial Information [Abstract]
Voting interest of the subsidiary owned by the registrant	100.00%

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Balance Sheet) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Total current assets	$ 122,878,000	$ 72,988,000
Total property and equipment, net	2,635,810,000	1,545,760,000
Investment in subsidiaries	0	0
Other assets	19,616,000	7,579,000
Total Assets	2,778,304,000	1,626,327,000
Current Liabilities	372,822,000	211,959,000
Long-term liabilities	1,820,323,000	1,390,910,000
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	214,262,000	0
Total shareholders’ equity	370,897,000	23,458,000	$ 444,054,000	$ 1,103,441,000
Total Liabilities and Shareholders’ Equity	2,778,304,000	1,626,327,000
Reportable Legal Entities [Member] | Parent Company [Member]
Total current assets	3,441,633,000	2,735,830,000
Total property and equipment, net	5,953,000	42,181,000
Investment in subsidiaries	(999,793,000)	(1,282,292,000)
Other assets	9,270,000	7,423,000
Total Assets	2,457,063,000	1,503,142,000
Current Liabilities	165,701,000	114,805,000
Long-term liabilities	1,689,466,000	1,348,105,000
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	214,262,000	0
Total shareholders’ equity	387,634,000	40,232,000
Total Liabilities and Shareholders’ Equity	2,457,063,000	1,503,142,000
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member]
Total current assets	105,533,000	63,513,000
Total property and equipment, net	2,630,707,000	1,503,695,000
Investment in subsidiaries	0	0
Other assets	10,346,000	156,000
Total Assets	2,746,586,000	1,567,364,000
Current Liabilities	3,631,401,000	2,822,729,000
Long-term liabilities	114,978,000	26,927,000
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	0	0
Total shareholders’ equity	(999,793,000)	(1,282,292,000)
Total Liabilities and Shareholders’ Equity	2,746,586,000	1,567,364,000
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member]
Total current assets	0	0
Total property and equipment, net	3,028,000	3,800,000
Investment in subsidiaries	0	0
Other assets	0	0
Total Assets	3,028,000	3,800,000
Current Liabilities	3,028,000	3,800,000
Long-term liabilities	0	0
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	0	0
Total shareholders’ equity	0	0
Total Liabilities and Shareholders’ Equity	3,028,000	3,800,000
Consolidation, Eliminations [Member]
Total current assets	(3,424,288,000)	(2,726,355,000)
Total property and equipment, net	(3,878,000)	(3,916,000)
Investment in subsidiaries	999,793,000	1,282,292,000
Other assets	0	0
Total Assets	(2,428,373,000)	(1,447,979,000)
Current Liabilities	(3,427,308,000)	(2,729,375,000)
Long-term liabilities	15,879,000	15,878,000
Preferred stock, $0.01 par value, 10,000,000 shares authorized; 250,000 issued and outstanding as of December 31, 2017 and none issued and outstanding as of December 31, 2016	0	0
Total shareholders’ equity	983,056,000	1,265,518,000
Total Liabilities and Shareholders’ Equity	$ (2,428,373,000)	$ (1,447,979,000)

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Total revenues	$ 246,771	$ 181,279	$ 166,483	$ 151,355	$ 143,831	$ 111,177	$ 107,324	$ 81,262	$ 745,888	$ 443,594	$ 429,203
Total costs and expenses									654,748	1,119,068	1,727,963
Income (loss) from continuing operations before income taxes									91,140	(675,474)	(1,298,760)
Operating income (loss)	113,205	69,364	63,147	57,953	55,000	31,634	27,167	(7,491)
Income tax expense									(4,030)	0	140,875
Equity in income of subsidiaries									0	0	0
Income (Loss) From Continuing Operations									87,110	(675,474)	(1,157,885)
Income from discontinued operations, net of income taxes									0	0	2,731
Net income from discontinued operations, net of income taxes									0	0	2,731
Net Income (Loss)	(17,040)	7,823	56,306	40,021	(779)	(101,174)	(262,126)	(311,395)	87,110	(675,474)	(1,155,154)
Dividends on preferred stock	(5,500)	(2,200)							(7,781)	0	0
Accretion on preferred stock									(862)	0	0
Net Income (Loss) Attributable to Common Shareholders	$ (23,434)	$ 5,574	$ 56,306	$ 40,021	$ (779)	$ (101,174)	$ (262,126)	$ (311,395)	78,467	(675,474)	(1,155,154)
Reportable Legal Entities [Member] | Parent Company [Member]
Total revenues									302	482	1,708
Costs and Expenses									195,728	208,054
Total costs and expenses											95,464
Income (loss) from continuing operations before income taxes									(195,426)	(207,572)	(93,756)
Income tax expense									0	0	10,125
Equity in income of subsidiaries									(282,499)	467,410	(1,049,010)
Income (Loss) From Continuing Operations											(1,132,641)
Net income from discontinued operations, net of income taxes									0	0	2,731
Net Income (Loss)									87,073	(674,982)	(1,129,910)
Dividends on preferred stock									7,781	0	0
Accretion on preferred stock									(862)	0	0
Net Income (Loss) Attributable to Common Shareholders									78,430	(674,982)	(1,129,910)
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member]
Total revenues									745,586	443,112	427,495
Costs and Expenses									459,057	910,522
Total costs and expenses											1,603,515
Income (loss) from continuing operations before income taxes									286,529	(467,410)	(1,176,020)
Income tax expense									(4,030)	0	127,010
Equity in income of subsidiaries									0	0	0
Income (Loss) From Continuing Operations											(1,049,010)
Net income from discontinued operations, net of income taxes									0	0	0
Net Income (Loss)									282,499	(467,410)	(1,049,010)
Dividends on preferred stock									0	0	0
Accretion on preferred stock									0	0	0
Net Income (Loss) Attributable to Common Shareholders									282,499	(467,410)	(1,049,010)
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member]
Total revenues									0	0	0
Costs and Expenses									0	0
Total costs and expenses											0
Income (loss) from continuing operations before income taxes									0	0	0
Income tax expense									0	0	0
Equity in income of subsidiaries									0	0	0
Income (Loss) From Continuing Operations											0
Net income from discontinued operations, net of income taxes									0	0	0
Net Income (Loss)									0	0	0
Dividends on preferred stock									0	0	0
Accretion on preferred stock									0	0	0
Net Income (Loss) Attributable to Common Shareholders									0	0	0
Consolidation, Eliminations [Member]
Total revenues									0	0	0
Costs and Expenses									(37)	492
Total costs and expenses											28,984
Income (loss) from continuing operations before income taxes									37	(492)	(28,984)
Income tax expense									0	0	3,740
Equity in income of subsidiaries									282,499	(467,410)	1,049,010
Income (Loss) From Continuing Operations											1,023,766
Net income from discontinued operations, net of income taxes									0	0	0
Net Income (Loss)									(282,462)	466,918	1,023,766
Dividends on preferred stock									0	0	0
Accretion on preferred stock									0	0	0
Net Income (Loss) Attributable to Common Shareholders									$ (282,462)	$ 466,918	$ 1,023,766

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidating Statement Of Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net Cash Provided by (Used in) Operating Activities	$ 422,981	$ 272,768	$ 377,367
Net cash provided by (used in) operating activities from continuing operations	422,981	272,768	378,735
Net Cash Provided by (Used in) Investing Activities	(1,159,452)	(619,832)	(676,054)
Net cash used in investing activities from continuing operations	(1,159,452)	(619,832)	(673,376)
Net Cash Provided by (Used in) Financing Activities	741,817	308,340	330,767
Net cash provided by financing activities from continuing operations	741,817	308,340	330,767
Net cash used in discontinued operations	0	0	(4,046)
Net increase in cash and cash equivalents	5,346	(38,724)	32,080
Cash and cash equivalents, beginning of year	4,194	42,918	10,838
Cash and cash equivalents, end of year	9,540	4,194	42,918
Cash and cash equivalents	9,540	4,194	42,918	$ 10,838
Reportable Legal Entities [Member] | Parent Company [Member]
Net Cash Provided by (Used in) Operating Activities	(121,107)	(34,773)
Net cash provided by (used in) operating activities from continuing operations			2,655
Net Cash Provided by (Used in) Investing Activities	(615,364)	(312,291)
Net cash used in investing activities from continuing operations			(447,296)
Net Cash Provided by (Used in) Financing Activities	741,817	308,340
Net cash provided by financing activities from continuing operations			480,767
Net cash used in discontinued operations	0	0	(4,046)
Net increase in cash and cash equivalents	5,346	(38,724)	32,080
Cash and cash equivalents, beginning of year	4,194	42,918	10,838
Cash and cash equivalents, end of year	9,540	4,194	42,918
Cash and cash equivalents		4,194	42,918
Reportable Legal Entities [Member] | Combined Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities	544,088	307,541
Net cash provided by (used in) operating activities from continuing operations			376,080
Net Cash Provided by (Used in) Investing Activities	(1,155,340)	(575,824)
Net cash used in investing activities from continuing operations			(674,758)
Net Cash Provided by (Used in) Financing Activities	611,252	268,283
Net cash provided by financing activities from continuing operations			298,678
Net cash used in discontinued operations	0	0	0
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of year	0	0	0
Cash and cash equivalents, end of year	0	0	0
Cash and cash equivalents		0	0
Reportable Legal Entities [Member] | Combined Non-Guarantor Subsidiaries [Member]
Net Cash Provided by (Used in) Operating Activities	0	0
Net cash provided by (used in) operating activities from continuing operations			0
Net Cash Provided by (Used in) Investing Activities	0	(740)
Net cash used in investing activities from continuing operations			0
Net Cash Provided by (Used in) Financing Activities	0	740
Net cash provided by financing activities from continuing operations			0
Net cash used in discontinued operations	0	0	0
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of year	0	0	0
Cash and cash equivalents, end of year	0	0	0
Cash and cash equivalents		0	0
Consolidation, Eliminations [Member]
Net Cash Provided by (Used in) Operating Activities	0	0
Net cash provided by (used in) operating activities from continuing operations			0
Net Cash Provided by (Used in) Investing Activities	611,252	269,023
Net cash used in investing activities from continuing operations			448,678
Net Cash Provided by (Used in) Financing Activities	(611,252)	(269,023)
Net cash provided by financing activities from continuing operations			(448,678)
Net cash used in discontinued operations	0	0	0
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of year	0	0	0
Cash and cash equivalents, end of year	$ 0	0	0
Cash and cash equivalents		$ 0	$ 0

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Supplemental Cash Flow Information Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 10, 2017	Dec. 14, 2016
Supplemental Cash Flow Information [Line Items]
Cash paid for interest, net of amounts capitalized	$ 77,213	$ 75,231	$ 64,692
Cash paid for income taxes	0	0	0
Change in capital expenditure payables and accruals	102,272	(21,492)	(86,878)
Contingent Consideration, Liability, Acquisition Date Fair Value	52,300	0	0
Contingent Consideration, Asset, Divestiture Date Fair Value	(8,805)	0	0
Business Combination, Liabilities				$ 58,238	$ 4,897
Share-based Compensation, Capitalized Amount	4,482	4,591	4,574
Asset retirement obligation additions	3,726	1,927	4,853
Sanchez Acquisition [Member]
Supplemental Cash Flow Information [Line Items]
Business Combination, Liabilities	$ 0	$ 4,880	$ 0

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Subsequent Events (Unaudited) (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 20, 2018	Jan. 31, 2018	Jan. 24, 2018	Jul. 14, 2017	Jun. 30, 2017	Mar. 31, 2017
Subsequent Event [Line Items]
Net proceeds from divestitures of oil and gas properties			$ 197,564	$ 15,564	$ 8,047
Temporary Equity, Liquidation Preference Per Share			$ 1,000.00
Subsequent Event
Subsequent Event [Line Items]
Preferred Stock Shares Redeemed								50,000
Preferred Stock, Percentage Redeemed								20.00%
Payments for Repurchase of Redeemable Preferred Stock	$ 50,500
Temporary Equity, Liquidation Preference Per Share								$ 1,000.00
Niobrara Divestiture [Member] | Subsequent Event
Subsequent Event [Line Items]
Net proceeds from divestitures of oil and gas properties		$ 136,600
Eagle Ford Shale Divestiture [Member] | Subsequent Event
Subsequent Event [Line Items]
Net proceeds from divestitures of oil and gas properties		$ 246,200
7.50% Senior Notes [Member]
Subsequent Event [Line Items]
Debt instrument interest rate			7.50%
Debt Instrument, Repurchased Face Amount			$ 150,000
Debt Instrument, Redemption, Cash Consideration			156,000
Redemption Premium			2,800
Accrued interest paid associated with redemption of debt			3,200
Senior Secured Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Current Borrowing Capacity			900,000						$ 837,500	$ 900,000	$ 600,000
Line of Credit Facility, Elected Borrowing Capacity			$ 800,000							$ 800,000
Senior Secured Revolving Credit Facility [Member] | Subsequent Event
Subsequent Event [Line Items]
Line of Credit Facility, Current Borrowing Capacity							$ 830,000
February 2018 7.50% Senior Note Redemption [Member] | Subsequent Event
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount						$ 100,000
Debt Instrument, Redemption, Cash Consideration	105,100
Redemption Premium	1,900
Accrued interest paid associated with redemption of debt	3,200
March 2018 7.50% Senior Note Redemption [Member] | Subsequent Event
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount						$ 220,000
Debt Instrument, Redemption, Cash Consideration	231,800
Redemption Premium	4,100
Accrued interest paid associated with redemption of debt	$ 7,700

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Subsequent Events (Unaudited) (Schedule of Natural Gas Derivative Instruments) (Details) - Subsequent Event [Member] - Natural Gas [Member] - Fixed Price Swaps [Member] - March - December 2018 [Member]	Jan. 30, 2018 MMBTU / d $ / MMBTU
Derivative [Line Items]
Derivative, Volumes | MMBTU / d	25,000
Weighted Average Fixed Price | $ / MMBTU	3.01

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Supplemental Disclosures About Oil And Gas Producing Activities (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 $ / bbls $ / MMcf	Dec. 31, 2016 $ / bbls $ / MMcf	Dec. 31, 2015 $ / bbls $ / MMcf
Crude Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average market prices used in reserves estimates	49.87	39.60	47.24
Natural Gas Liquids (Bbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average market prices used in reserves estimates	19.78	11.66	12.00
Natural Gas (Mcf) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average market prices used in reserves estimates | $ / MMcf	2.96	1.89	1.87

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Supplemental Disclosures About Oil and Gas Producing Activities (Narrative 2) (Details) MBoe in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) MBoe	Dec. 31, 2016 USD ($) MBoe	Dec. 31, 2015 USD ($) MBoe
Supplemental Oil And Gas Reserve Information [Line Items]
Capitalized interest | $	$ 28,300	$ 17,000	$ 32,100
Asset retirement obligation additions | $	3,726	1,927	4,853
Internal costs capitalized, oil and gas producing activities | $	$ 14,800	$ 10,500	$ 15,800
Reserves discount factor	10.00%
Proved Developed Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries, Boe	6,473	6,525	5,237
Purchases of reserves in place, Boe	26,009	4,978
Sale of Mineral in Place, Boe	(22,249)
Proved Undeveloped Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries, Boe	74,281	52,047	32,067
Purchases of reserves in place, Boe	20,094	1,167
Sale of Mineral in Place, Boe	(7,297)
Barrel of Oil Equivalent (Boe) [Domain]
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries, Boe	80,754	58,572	37,304
Revisions of previous estimates, Boe	(16,118)	(19,713)	(4,323)
Purchases of reserves in place, Boe	46,103	6,145
Sale of Mineral in Place, Boe	(29,546)
Price Reserve Revisions [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe	2,684	(6,705)	(15,846)
Removed Reserves Of Uneconomic Wells [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe		(3,228)	(6,208)
Revisions Due To Reduced Tail Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe		(3,477)	(9,638)
Performance Reserve Revisions [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe	(4,500)	(6,083)	11,523
Development Plan Revisions [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Revisions of previous estimates, Boe	(14,302)	(6,925)
Eagle Ford Shale [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Percentage of reserve additions	51.00%	79.00%	89.00%
Delaware Basin [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Percentage of reserve additions	48.00%	20.00%
Property Acquisition Costs [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Asset retirement obligation additions | $	$ 100	$ 2,037
Exploration and Development Costs [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Asset retirement obligation additions | $	$ 3,527	$ 1,927

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Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved property acquisition costs	$ 303,307	$ 90,661	$ 0
Unproved properties	525,061	113,535	63,446
Total property acquisition costs	828,368	204,196	63,446
Exploration costs	91,098	37,508	117,227
Development costs	569,982	374,134	389,396
Total costs incurred	$ 1,489,448	$ 615,838	$ 570,069

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Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Net Proved Oil And Gas Reserves And Changes In Net Proved Oil And Gas Reserves) (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) MBoe MMcf MBbls	Dec. 31, 2016 USD ($) MBoe MMcf MBbls	Dec. 31, 2015 USD ($) MBoe MMcf MBbls	Dec. 31, 2014 MBoe MMcf MBbls
Reserve Quantities [Line Items]
Asset retirement obligation additions | $	$ 3,726	$ 1,927	$ 4,853
Crude Oil [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	128,318	109,588	100,704
Extensions and discoveries	50,476	40,074	26,358
Revisions of previous estimates	(19,838)	(16,731)	(9,059)
Purchases of reserves in place	21,634	4,810
Sales of Minerals in Place	(650)
Production	(12,566)	(9,423)	(8,415)
Proved developed and undeveloped reserves end of year	167,374	128,318	109,588
Proved developed reserves (volume)	69,632	51,062	42,311	35,238
Proved undeveloped reserve (volume)	97,742	77,256	67,277	65,466
Natural Gas Liquids (Bbls) [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year	23,937	20,221	13,513
Extensions and discoveries	13,781	8,612	5,292
Revisions of previous estimates	(909)	(3,230)	2,768
Purchases of reserves in place	8,642	122
Sales of Minerals in Place	(526)
Production	(2,327)	(1,788)	(1,352)
Proved developed and undeveloped reserves end of year	42,598	23,937	20,221
Proved developed reserves (volume)	17,447	9,387	7,933	5,294
Proved undeveloped reserve (volume)	25,151	14,550	12,288	8,219
Natural Gas [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year | MMcf	287,445	244,938	221,017
Extensions and discoveries | MMcf	98,980	59,318	33,925
Revisions of previous estimates | MMcf	27,774	1,481	11,808
Purchases of reserves in place | MMcf	94,962	7,282
Sales of Minerals in Place | MMcf	(170,219)
Production | MMcf	(28,472)	(25,574)	(21,812)
Proved developed and undeveloped reserves end of year | MMcf	310,470	287,445	244,938
Proved developed reserves (volume) | MMcf	131,355	187,054	154,725	149,697
Proved undeveloped reserve (volume) | MMcf	179,115	100,391	90,213	71,320
Barrel of Oil Equivalent (Boe) [Domain]
Proved Developed and Undeveloped Reserves [Abstract]
Proved developed and undeveloped reserves beginning of year, Boe | MBoe	200,163	170,632	151,053
Extensions and discoveries, Boe | MBoe	80,754	58,572	37,304
Revisions of previous estimates, Boe | MBoe	(16,118)	(19,713)	(4,323)
Purchases of reserves in place, Boe | MBoe	46,103	6,145
Sale of Mineral in Place, Boe | MBoe	(29,546)
Production, Boe | MBoe	(19,639)	(15,473)	(13,402)
Proved developed and undeveloped reserves end of year, Boe | MBoe	261,717	200,163	170,632
Proved developed reserves (energy) | MBoe	108,972	91,625	76,032	65,482
Proved undeveloped reserves (energy) | MBoe	152,745	108,538	94,600	85,571
Price Reserve Revisions [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Revisions of previous estimates, Boe | MBoe	2,684	(6,705)	(15,846)
Removed Reserves Of Uneconomic Wells [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Revisions of previous estimates, Boe | MBoe		(3,228)	(6,208)

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Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 10,109,752	$ 5,903,629	$ 5,878,348
Future production costs	(3,202,201)	(2,241,928)	(2,124,059)
Future development costs	(1,699,909)	(1,264,493)	(1,178,773)
Future income taxes (1)	(445,056)	0	0
Future net cash flows	4,762,586	2,397,208	2,575,516
Less 10% annual discount to reflect timing of cash flows	(2,297,544)	(1,093,779)	(1,210,292)
Standard measure of discounted future net cash flows	$ 2,465,042	$ 1,303,429	$ 1,365,224	$ 2,555,082

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Supplemental Disclosures About Oil And Gas Producing Activities (Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure — beginning of period	$ 1,303,429	$ 1,365,224	$ 2,555,082
Net change in sales prices and production costs related to future production	710,773	(346,763)	(2,547,213)
Net change in estimated future development costs	(51,854)	74,407	342,238
Net change due to revisions in quantity estimates	(42,214)	(150,245)	(157,271)
Accretion of discount	130,343	136,522	326,074
Changes in production rates (timing) and other	(116,056)	(111,137)	(139,533)
Total revisions to reserves proved in prior years	630,992	(397,216)	(2,175,705)
Net change due to extensions and discoveries, net of estimated future development and production costs	597,502	313,201	252,155
Net change due to purchases of reserves in place	452,932	43,426	0
Net change due to divestitures of reserves in place	(106,608)	0	0
Sales of crude oil, NGLs and natural gas produced, net of production costs	(566,258)	(320,272)	(312,213)
Previously estimated development costs incurred	326,383	299,066	340,247
Net change in income taxes	(173,330)	0	705,658
Net change in standardized measure of discounted future net cash flows	1,161,613	(61,795)	(1,189,858)
Standardized measure — end of period	$ 2,465,042	$ 1,303,429	$ 1,365,224

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Selected Quarterly Financial Data (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information [Line Items]
Gain (Loss) On Contingent Consideration	$ (23,900)	$ (8,000)
Dividends on preferred stock	5,500	$ 2,200				$ 7,781	$ 0	$ 0
Loss on extinguishment of debt	4,170					4,170	0	38,137
Impairment of proved oil and gas properties			$ 105,100	$ 197,100	$ 274,400	0	$ 576,540	$ 1,224,367
7.50% Senior Notes [Member]
Quarterly Financial Information [Line Items]
Loss on extinguishment of debt						4,170
Debt Instrument, Repurchased Face Amount	$ 150,000					$ 150,000
Debt instrument interest rate	7.50%					7.50%

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Selected Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Total revenues	$ 246,771	$ 181,279	$ 166,483	$ 151,355	$ 143,831	$ 111,177	$ 107,324	$ 81,262	$ 745,888	$ 443,594	$ 429,203
Operating profit (loss)	113,205	69,364	63,147	57,953	55,000	31,634	27,167	(7,491)
(Gain) loss on derivatives, net	86,107	24,377	(26,065)	(25,316)					59,103	49,073	(99,261)
Net income (loss)	(17,040)	7,823	56,306	40,021	(779)	(101,174)	(262,126)	(311,395)	87,110	(675,474)	(1,155,154)
Net Income (Loss) Attributable to Common Shareholders	$ (23,434)	$ 5,574	$ 56,306	$ 40,021	$ (779)	$ (101,174)	$ (262,126)	$ (311,395)	$ 78,467	$ (675,474)	$ (1,155,154)
Net Income (Loss) Attributable to Common Shareholders, Per Basic Share	$ (0.29)	$ 0.07	$ 0.86	$ 0.61	$ (0.01)	$ (1.72)	$ (4.46)	$ (5.34)	$ 1.07	$ (11.27)	$ (22.45)
Net Income (Loss) Attributable to Common Shareholders, Per Diluted Share	$ (0.29)	$ 0.07	$ 0.85	$ 0.61	$ (0.01)	$ (1.72)	$ (4.46)	$ (5.34)	$ 1.06	$ (11.27)	$ (22.45)