10-K 1 crzo201510-k.htm 10-K 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, 2015
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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting 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
¨
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, 2015, the aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $2.4 billion based on the closing price of such stock on such date of $49.24.
At February 19, 2016, the number of shares outstanding of the registrant’s Common Stock was 58,337,680.



 DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant’s 2016 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, 2015.




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



2



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

3



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.”

4



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 oil and gas primarily from resource plays located in the United States. Our current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South Texas, the Delaware Basin in West Texas, the Utica Shale in Ohio, the Niobrara Formation in Colorado and the Marcellus Shale in Pennsylvania.
The Company achieved record total production in 2015 of 13.4 MMBoe, a 12% increase from 2014, despite significantly lower capital expenditures in 2015 when compared to 2014. At year-end 2015, our proved reserves of 170.6 MMBoe were 64% crude oil, 12% natural gas liquids and 24% natural gas. Our reserves increased primarily as a result of our ongoing drilling program in the Eagle Ford.
The following table provides details about the Company’s proved reserves as of the dates indicated.
 
 
Proved Reserves
 
 
December 31, 2015
 
December 31, 2014
 
 
(MMBoe)
Eagle Ford
 
144.0

 
122.5

Delaware Basin
 
1.0

 

Utica
 
1.9

 
0.6

Niobrara
 
3.9

 
5.6

Marcellus
 
19.8

 
22.3

Other
 

 
0.1

Total
 
170.6

 
151.1

Our 2016 capital expenditure plan currently includes $270.0 million to $290.0 million for drilling and completion and $15.0 million for leasehold and seismic. This plan represents a decrease of approximately 46% from our 2015 capital expenditures and reflects our strategy of controlling capital costs and maintaining financial flexibility in a low commodity price environment. We currently expect to commit the majority of our 2016 capital expenditure plan to the continued exploration and development of our properties in the Eagle Ford, and to a lesser extent, the Delaware Basin. We intend to finance our 2016 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. The table below summarizes our actual capital expenditures for 2015 and our planned capital expenditures for 2016:
 
 
Capital Expenditures
 
 
2016 Plan
 
2015 Actual
 
 
(In millions)
Drilling and completion
 
 
 
 
Eagle Ford
 

$260.0

 

$393.9

Other
 
20.0

 
101.8

Total drilling and completion (1)
 
280.0

 
495.7

Leasehold and seismic
 
15.0

 
48.5

Total
 

$295.0

 

$544.2

 
(1)
Represents the midpoint of our 2016 drilling and completion capital expenditure plan of $270.0 million to $290.0 million.
Business Strategy
Our objective is to increase value through the execution of a business strategy focused on organic growth primarily through the drillbit and opportunistic acquisitions of oil and gas properties, while maintaining a sound financial position to provide liquidity to weather a prolonged downturn in commodity prices. Key elements of our business strategy include:
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 sale of assets, proceeds

5



from sales of securities, borrowings under our revolving credit facility and proceeds, payments or carried interest from our joint ventures.
Control operating and capital costs. 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 reduce or reallocate our spending in response to changes in market conditions. For example, we have reduced our 2016 capital expenditure plan by approximately 46% from our 2015 capital expenditures, which reflects our strategy of focusing on low-cost oil and condensate resource plays and maintaining financial flexibility in a low commodity price environment.
Manage risk exposure. We seek to limit our financial risks, in part by seeking well-funded partners to ensure that we are able to move forward on projects in a timely manner. We also attempt to limit our exposure to volatility in commodity prices by actively hedging production of crude oil. Our current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production to achieve a more predictable level of cash flows to support current and future capital expenditure plans.
Pursue opportunities to expand core positions. We pursue a growth strategy in crude oil plays primarily driven by the attractive relative economics associated with our core positions. By focusing on and implementing this strategy, our crude oil production as a percentage of total production has increased from 3% for the year ended December 31, 2010 to 63% for the year ended December 31, 2015. Nearly 100% of our 2016 drilling and completion capital expenditure plan is directed towards opportunities that we believe are predominantly prospective for crude oil development. 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. Additionally, we continue to take advantage of opportunities to expand our core positions through leasehold acquisitions as evidenced by our acquisition of bolt-on acreage in certain of our core plays during 2015.
Utilize our experience as a technical advantage. We believe we have developed a technical advantage from our extensive experience drilling over 800 horizontal wells in various resource plays, including the Eagle Ford, Delaware Basin, Utica, Niobrara, Marcellus, and previously, the Barnett, 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 capital expenditures in these resource plays, particularly during 2016, in the Eagle Ford and, to a lesser extent, the Delaware Basin.
Our Competitive Strengths
We believe we have the following competitive strengths that will support our efforts to successfully execute our business strategy:
Financial flexibility to withstand prolonged low commodity prices. We maintain a financial profile that provides operational flexibility, and our capital structure provides us with the ability to execute our business plan. As of December 31, 2015, we had no outstanding borrowings under our $685.0 million revolving credit facility, have no near-term debt maturities, and use commodity derivative instruments to reduce our exposure to commodity price volatility for a substantial, but varying, portion of our forecasted oil and gas production. We believe that we have the ability and financial flexibility to fund the planned development of our assets through 2016. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for further details.
Operational control. As of December 31, 2015, we operated approximately 90% of the wells in Eagle Ford in which we held an interest. We held an average 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.
Large inventory of oil-focused drilling locations. We have developed a significant inventory of future oil-focused drilling locations, primarily in our well-established positions in the Eagle Ford, Niobrara, and Utica, as well as our recent entrance into the Delaware Basin. As of December 31, 2015, we owned leases covering approximately 291,606 gross (165,472 net) acres in these areas. See “—Acreage Data” for further details. Approximately 55% of our estimated proved reserves at December 31, 2015 were undeveloped.
Successful drilling history. 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-

6



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.
Experienced management and professional workforce. Our management has executed multiple joint ventures, transitioned our focus to oil by entering new plays and completed non-core asset sales. 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.
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.
Primarily due to the depressed levels of oil and natural gas prices, we sometimes seek to reduce costs by deferring drilling or completion activity or drilling more wells on units where we hold a lower working interest than our historic average. In addition, we have historically sought to enter into joint ventures with well-funded partners that will pay a disproportionate share of the drilling and completion costs of wells that we drill.
In certain instances we may also seek to maximize the acreage that we can hold by drilling and producing by temporarily drilling fewer wells on each drilling unit in order to permit us to develop more drilling units with comparatively fewer rigs. Where possible, we also seek to maximize our liquidity, while increasing profitability of our projects through timing the completion and pipeline connection costs of our horizontal wells to coincide with periods of lower services costs.
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 frequently vertical wells, or 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 in the Eagle Ford, Niobrara, Marcellus and Barnett, along with our extensive experience in hydraulic fracturing and horizontal drilling technologies and the experience of our management 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 3-D survey design parameters and drilling and completion methods. As of December 31, 2015, we operated 474 gross (315.3 net) productive oil and gas 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 2015, we operated 71 of the 76 gross wells drilled in the Eagle Ford where we spent approximately 80% of our 2015 drilling and completion 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

7



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 2015 Proved Reserves, Production and Drilling by Area
 
 
Eagle Ford
 
Niobrara
 
Utica
 
Marcellus
 
Delaware Basin
& Other
 
Total
Proved reserves by product
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil (MMBbls)
 
105.8
 
2.8
 
0.6
 
 
0.4
 
109.6
NGLs (MMBbls)
 
19.0
 
0.5
 
0.4
 
 
0.3
 
20.2
Natural gas (Bcf)
 
115.4
 
3.4
 
5.4
 
118.8
 
1.9
 
244.9
Total proved reserves (MMBoe)
144.0
 
3.9
 
1.9
 
19.8
 
1.0
 
170.6
 
 
 
 
 
 
 
 
 
 
 
 
Proved reserves by classification (MMBoe)
 
 
 
 
 
 
 
 
 
Proved developed
 
52.4
 
3.5
 
1.9
 
17.2
 
1.0
 
76.0
Proved undeveloped
 
91.6
 
0.4
 
 
2.6
 
 
94.6
Total proved reserves
 
144.0
 
3.9
 
1.9
 
19.8
 
1.0
 
170.6
 
 
 
 
 
 
 
 
 
 
 
 
 
Percent of total reserves
 
84%
 
2%
 
1%
 
12%
 
1%
 
100%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 production (MMBoe)
 
9.6
 
1.1
 
0.5
 
2.1
 
0.1
 
13.4
 
 
 
 
 
 
 
 
 
 
 
 
 
Percent of total production
 
71%
 
8%
 
4%
 
16%
 
1%
 
100%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Eagle Ford
 
Niobrara
 
Utica
 
Marcellus
 
Delaware Basin
& Other
 
Total
Operated Well Data
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Year Ended December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wells drilled
 
71
 
65.1
 
13
 
7.5
 
 
 
 
 
4
 
3.6
 
88
 
76.2
Wells brought on production
 
67
 
60.1
 
11
 
5.8
 
2
 
1.7
 
 
 
2
 
1.7
 
82
 
69.3
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wells waiting on completion
 
29
 
27.3
 
9
 
5.2
 
 
 
11
 
4.3
 
2
 
1.9
 
51
 
38.7
Wells producing
 
263
 
230.8
 
123
 
53.4
 
4
 
3.1
 
82
 
26.3
 
2
 
1.7
 
474
 
315.3
Regional Overview
Eagle Ford
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, 2015, we held interests in approximately 107,021 gross (82,670 net) acres and were operating two rigs in the Eagle Ford. We currently plan for approximately 93% of our 2016 drilling and completion capital expenditure plan to be directed towards opportunities in the Eagle Ford. We are testing multiple initiatives aimed at increasing our drilling inventory in the Eagle Ford. We are pleased with the performance of our 330-ft. downspacing tests in the Eagle Ford and are working on initiatives for further downspacing.
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.
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, 2015, we held interests in approximately 41,178 gross (21,915 net) acres in the Delaware Basin. We drilled our first operated well in the Delaware Basin in the second quarter of 2015, and drilled a total of 4 gross (3.6 net) wells during the year and completed 2 gross (1.7 net) wells. We finished drilling our fifth operated well in early 2016. We continue to like the potential in the play and look to expand our acreage over time.

8



Niobrara
As of December 31, 2015, we held interests in approximately 105,825 gross (33,582 net) acres in the Niobrara, primarily in Weld and Adams counties, Colorado, and were not operating any rigs. During 2015, we drilled 13 gross (7.5 net) wells as operator and participated in 42 gross (3.6 net) additional wells as a non-operator. We currently expect to continue to participate as a non-operator in high-density projects in the Niobrara, but have no current plans to drill any operated wells in Niobrara in 2016. We have limited amounts allocated to Niobrara as part of our 2016 drilling and completion capital expenditure plan.
OIL JV Partners Joint Venture. In October 2012, we completed the sale of a portion of our interests in certain oil and gas properties in the Niobrara to OIL India (USA) Inc. and IOCL (USA) Inc., wholly owned subsidiaries of OIL India Ltd. and Indian Oil Corporation Ltd., respectively. For convenience, in this Annual Report on Form 10-K the term “OIL JV Partners” is used to refer collectively to OIL India (USA) Inc. and IOCL (USA) Inc. We also granted an option in favor of the OIL JV Partners to purchase a 30% share of acreage subsequently acquired by us in specified areas of the play.
Haimo Joint Venture. In December 2012, we completed the sale of an additional portion of our remaining interests in the same oil and gas properties sold to the OIL JV Partners in the transaction described above to Haimo Oil & Gas LLC (“Haimo”), a wholly owned subsidiary of Lanzhou Haimo Technologies Co. Ltd. We also granted an option in favor of Haimo to purchase a 10% share of acreage subsequently acquired by us in the same properties as the OIL JV Partners described above. Following the closing of the Haimo transaction in fourth quarter 2012, the joint venture ownership interests in our Niobrara development activities were 60% Carrizo, 30% the OIL JV Partners, and 10% Haimo.
We serve as operator of a significant percentage of the properties covered by our Niobrara joint venture arrangements.
Utica
As of December 31, 2015, we held interests in approximately 37,582 gross (27,305 net) acres in the Utica. During 2015, we did not drill any operated wells, but brought online 2 gross (1.7 net) wells. We also have 16 additional wells in inventory where we have drilled and cased the upper portions of such wells. We do not expect to complete the drilling of these wells until oil prices recover or we obtain additional funding. During 2015, we participated in the drilling and completion of 2 gross (0.5 net) additional wells as a non-operator. As of December 31, 2015, we were not operating any rigs in the Utica and have limited amounts of our 2016 drilling and completion expenditure plan allocated to this play.
Avista Utica Joint Venture. Effective September 2011, our wholly-owned subsidiary, Carrizo (Utica) LLC, entered into a joint venture in the Utica with ACP II Marcellus LLC (“ACP II”), which is also one of our joint venture partners in the Marcellus, and ACP III Utica LLC (“ACP III”), both affiliates of Avista Capital Partners, LP, a private equity fund (collectively with ACP II and ACP III, “Avista”). During the term of the Avista Utica joint venture, the joint venture partners acquired and sold acreage and we exercised options under the Avista Utica joint venture agreements to acquire acreage from Avista. The Avista Utica joint venture agreements were terminated on October 31, 2013 in connection with our purchase of certain ACP III assets. After giving effect to this transaction, we and Avista remain working interest partners and we will operate the jointly owned properties which are now subject to standard joint operating agreements. The joint operating agreements with Avista provide for limited areas of mutual interest around our remaining jointly owned acreage.
Steven A. Webster, Chairman of our Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP, which has the ability to control Avista and its affiliates. ACP II’s and ACP III’s Boards of Managers have the sole authority for determining whether, when and to what extent any cash distributions will be declared and paid to members of ACP II or ACP III, respectively. Mr. Webster is not a member of either entity’s Board of Managers. As previously disclosed, we have been a party to prior arrangements with affiliates of Avista Capital Holdings LP, including our existing joint venture with Avista in the Marcellus. The terms of the joint ventures with Avista in the Utica and the Marcellus and the related transactions that took place were each separately approved by a special committee of the Company’s independent directors. See also “Note 12. Related Party Transactions” of the Notes to our Consolidated Financial Statements.
Marcellus
We began active participation in the Marcellus in 2007. We leveraged the knowledge and experience that we gained in the Barnett Shale to effectively explore for and develop natural gas in the Marcellus. Our activities in the Marcellus are currently conducted through two joint ventures described below.
As of December 31, 2015, we held interests in approximately 59,979 gross (19,271 net) acres in the Marcellus. We will continue to monitor prices and, consistent with our existing contractual commitments, may increase our activity level and capital expenditures, if natural gas prices so warrant. As of December 31, 2015, we were not operating any rigs in the Marcellus.

9



Reliance Joint Venture. In September 2010, we completed the sale of 20% of our interests in substantially all of our oil and gas properties in Pennsylvania that had been subject to the Avista Marcellus joint venture described in “Avista Marcellus Joint Venture” below to Reliance Marcellus II, LLC (“Reliance”), a wholly owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited. As described in “Avista Marcellus Joint Venture” below, simultaneously with the closing of our transaction with Reliance, ACP II closed the sale of its entire interest in the same properties to Reliance. In connection with these sale transactions, we and Reliance also entered into agreements to form a new joint venture with respect to the interests purchased by Reliance from us and Avista. The joint venture properties are generally held 60% by Reliance and 40% by us.
We have agreed to various restrictions on our ability to transfer our properties covered by the Reliance joint venture. Additionally, we are subject to a mutual right of first offer on direct and indirect property transfers for the remainder of a ten-year development period (through September 2020), subject to specified exceptions. We generally serve as operator of the properties covered by the Reliance joint venture, with Reliance having the right to assume operatorship of 60% of undeveloped acreage in portions of central Pennsylvania.
Avista Marcellus Joint Venture. Effective August 2008, our wholly owned subsidiary Carrizo (Marcellus) LLC entered into a joint venture arrangement with ACP II, an affiliate of Avista. In September 2010, we completed the sale of 20% of our interests in substantially all of our oil and gas properties in Pennsylvania that had been subject to the Avista joint venture to Reliance as described above under “Reliance Joint Venture.” Simultaneously with the closing of this transaction, ACP II closed the sale of its entire interest in the same properties to Reliance. In connection with these sales transactions, we and Avista amended the participation agreement and other joint venture agreements with Avista to provide that the properties that we and Avista sold to Reliance, as well as the properties we committed to the new joint venture with Reliance, were no longer subject to the terms of the Avista Marcellus joint venture, and that the Avista Marcellus joint venture’s area of mutual interest would generally not include Pennsylvania, the state in which those properties were located. Our joint venture with Avista continues and covers acreage primarily in West Virginia and New York. Pursuant to the terms of the amended participation agreement, the areas of mutual interest with Avista have been reduced to specified halos around existing properties in New York and West Virginia. We conducted no material activity under this joint venture during 2015 and do not currently expect to conduct any activity in 2016. For further discussion, see “Note 12. Related Party Transactions” of the Notes to our Consolidated Financial Statements.
Additional Oil and Gas Disclosures
Proved Oil and Gas Reserves
The following table sets forth our estimated net proved oil and gas reserves and the PV-10 value of such reserves as of December 31, 2015. The reserve data and the present value as of December 31, 2015 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 at December 31, 2015, see the reserve report included as an exhibit to this Annual Report on Form 10-K. The PV-10 value was prepared using an unweighted arithmetic average of the first day of the month oil and gas prices for each month in the prior twelve-month period ended December 31, 2015, discounted at 10% per annum on a pre-tax basis, and is not intended to represent the current market value of the estimated oil and gas reserves owned by us. For further information concerning the present value of future net revenues from these proved reserves, see “Note 2. Summary of Significant Accounting Policies” and “Note 18. Supplemental Disclosures About Oil and Gas Producing Activities (Unaudited)” of the Notes to our Consolidated Financial Statements.
Summary of Proved Oil and Gas Reserves as of December 31, 2015
Based on Average 2015 Prices
(Dollars in millions)
 
 
Crude Oil and Condensate (MBbls)
 
Natural Gas
Liquids (MBbls)
 
Natural Gas
(MMcf)
 
Total Oil-Equivalent
(MBoe) (1)
 
PV-10
Value (2)
Developed
 
42,311

 
7,933

 
154,725

 
76,032

 

$857.1

Undeveloped
 
67,277

 
12,288

 
90,213

 
94,600

 

$508.1

Total Proved
 
109,588

 
20,221

 
244,938

 
170,632

 

$1,365.2


(1)
Barrel of oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or one Bbl of natural gas liquids which represents their approximate energy content. Despite holding this ratio constant at six Mcf to one Bbl, current prices are 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.
(2)
The PV-10 value as of December 31, 2015 is pre-tax and was determined by using the average of oil and gas prices at the beginning of each month in the twelve-month period prior to December 31, 2015, net of commodity price differentials, which averaged $47.24 per Bbl of oil, $12.00 per Bbl of natural gas liquids, and $1.87 per Mcf of natural gas. As a result of significant decreases in commodity prices,

10



the average prices used to calculate PV-10 value as of December 31, 2015 are significantly higher than recent prices. See “—Other Reserve Matters” below for further discussion.

We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it 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. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of a pre-tax PV-10 value provides greater comparability when evaluating oil and gas companies. The PV-10 value is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. The definition of PV-10 value 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, the PV-10 value as defined may not be comparable to similar measures provided by other companies. The most comparable U.S. GAAP financial measure, the standardized measure of discounted future net cash flows, and information reconciling the U.S. GAAP and non-U.S. GAAP measures are included in the table below. Both the PV-10 and standardized measure of discounted future net cash flows do not purport to present the fair value of our reserves.

Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (U.S. GAAP)
to PV-10 Value (Non-U.S. GAAP)
 
 
 
 
 
 
 
 
 
 
As of December 31, 2015 (In millions)
Standardized measure of discounted future net cash flows (U.S. GAAP)
 
 
 

$1,365.2

Add: present value of future income taxes discounted at 10% per annum
 
 
 

PV-10 value (Non-U.S. GAAP) (1)
 
 
 

$1,365.2

 
(1)
Additional presentations of PV-10 in this document similarly include amounts for present value of future income taxes, and therefore no additional reconciliation is provided.
Proved Undeveloped Reserves
The following table provides a reconciliation of our proved undeveloped reserves (“PUDs”) for the year ended December 31, 2015.
 
 
Crude Oil and Condensate (MBbls)
 
Natural Gas Liquids (MBbls)
 
Natural Gas (MMcf)
 
Total Oil-Equivalent (MBoe)
PUDs as of December 31, 2014
 
65,466

 
8,218

 
71,320

 
85,571

Extensions and discoveries
 
23,287

 
4,365

 
26,493

 
32,067

Converted to proved developed reserves
 
(16,443
)
 
(2,135
)
 
(13,631
)
 
(20,850
)
Revisions of previous estimates
 
(5,033
)
 
1,840

 
6,031

 
(2,188
)
PUDs as of December 31, 2015
 
67,277

 
12,288

 
90,213

 
94,600

In 2015, we added 82 gross (71.3 net) PUD locations, or 32.1 MMBoe, of which approximately 73% were crude oil, with approximately 99% of the additions as a result of drilling and additional offset locations in the Eagle Ford.
During 2015, we converted 61 gross (55.2 net) PUD locations, or 20.9 MMBoe of reserves from proved undeveloped to proved developed, primarily in the Eagle Ford, at a cost of approximately $288.1 million, or $13.78 per Boe. We spent $39.0 million on PUDs that existed in 2014 that were drilled in 2015 and waiting on completion. We also spent $19.2 million on locations that were added in 2015 and were drilled and waiting on completion.
Included in revisions during 2015, were negative price revisions of 7.5 MMBoe primarily as a result of the average oil price, as described above, of $47.24 in our 2015 reserves as compared to $92.24 in our 2014 reserves. Included in the negative price revisions were 42 gross (20.9 net) PUD locations, or 5.3 MMBoe, primarily in Niobrara, that were removed as a result of the lower prices. The negative price revision of 7.5 MMBoe was partially offset by positive performance revisions of 5.3 MMBoe as we realized better processing yields for NGLs and natural gas during the year.
At December 31, 2015, 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 drilling locations are scheduled to be converted 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, 2015, 2014, and 2013 as presented in this Annual Report on Form 10-K. The technical persons responsible for preparing the reserves estimates meet the requirements regarding qualifications,

11



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. Further, 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.
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 new PUD additions
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
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.”
In accordance with SEC regulations, Ryder Scott and our internal reserve engineers each used the price based on the unweighted average of benchmark oil and gas prices at the beginning of each month in the twelve-month period ended December 31, 2015, adjusted for commodity price differentials. 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 subsequent to December 31, 2015. As a result of significant decreases in commodity prices, the average prices used to calculate PV-10 value as of December 31, 2015 are significantly higher than recent prices. If commodity prices remain at low levels or decline, we will likely experience a reduction in PV-10 value. Using the assumptions included in our 2015 proved oil and gas reserves, substituting the spot price of oil on December 31, 2015 of $37.13 per Bbl for the SEC benchmark NYMEX oil price, our PV-10 value would have been approximately $609.0 million, or $756.2 million less than our actual PV-10 value of $1,365.2 million as of December 31, 2015. 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.

12



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.
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
Total production volumes -
 
 
 

 
 
Crude oil (MBbls)
 
8,415

 
6,906

 
4,231

NGLs (MBbls)
 
1,352

 
926

 
531

Natural gas (MMcf)
 
21,812

 
24,877

 
31,422

Total barrels of oil equivalent (MBoe)
 
13,402

 
11,978

 
9,999

 
 
 
 
 
 
 
Daily production volumes by product -
 
 
 
 
 
 
Crude oil (Bbls/d)
 
23,054

 
18,921

 
11,592

NGLs (Bbls/d)
 
3,705

 
2,537

 
1,455

Natural gas (Mcf/d)
 
59,758

 
68,156

 
86,088

Total barrels of oil equivalent per day (Boe/d)
 
36,719

 
32,816

 
27,395

 
 
 
 
 
 
 
Daily production volumes by region (Boe/d) -
 
 
 
 
 
 
Eagle Ford
 
26,377

 
21,131

 
12,628

Niobrara
 
2,957

 
2,585

 
1,724

Marcellus
 
5,850

 
8,354

 
6,139

Utica
 
1,286

 
288

 
10

Delaware Basin and other
 
249

 
458

 
269

Barnett
 

 

 
6,625

Total barrels of oil equivalent (Boe/d)
 
36,719

 
32,816

 
27,395

 
 
 
 
 
 
 
Average realized prices -
 
 
 

 
 
Crude oil ($ per Bbl)
 

$44.69

 

$88.40

 

$99.58

NGLs ($ per Bbl)
 

$11.54

 

$27.05

 

$29.25

Natural gas ($ per Mcf)
 

$1.72

 

$3.00

 

$2.65

Total average realized price ($ per Boe)
 

$32.03

 

$59.29

 

$52.02

 
 
 
 
 
 
 
Average production costs ($ per Boe) (1)
 

$6.72

 

$6.19

 

$4.68

 
(1)
Includes lease operating costs but excludes production tax and ad valorem tax.
Drilling Activity
The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2015, 2014 and 2013 by geographical area. 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. 
 
 
Year Ended December 31,
 
 
2015
 
2014
 
2013
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory Wells - Productive
 
77

 
19.5

 
128

 
23.0

 
75

 
13.9

Exploratory Wells - Nonproductive
 

 

 

 

 
2

 
2.0

Development Wells - Productive
 
65

 
55.4

 
77

 
63.5

 
119

 
64.6

Development Wells - Nonproductive
 

 

 

 

 

 

The wells are in various stages of development or stages of production.
As of December 31, 2015, we were in the process of drilling 6 gross (6.0 net) wells that are not included in the table above.

13



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, 2015. 
 
 
Company
Operated
 
Non-Operated
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Crude oil
 
383

 
281.8

 
213

 
17.2

 
596

 
299.0

Natural gas
 
91

 
33.5

 
22

 
0.6

 
113

 
34.1

Total
 
474

 
315.3

 
235

 
17.8

 
709

 
333.1

Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2015. Developed acreage refers to acreage on which wells have been drilled or 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
 
Percent of Net Undeveloped Acreage Expiring
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
2016
 
2017
 
2018
Eagle Ford
 
65,442

 
54,495

 
41,579

 
28,175

 
107,021

 
82,670

 
21
%
 
26
%
 
7
%
Niobrara
 
41,481

 
15,241

 
64,344

 
18,341

 
105,825

 
33,582

 
9
%
 
3
%
 
8
%
Utica
 
1,949

 
1,577

 
35,633

 
25,728

 
37,582

 
27,305

 
8
%
 
31
%
 
11
%
Delaware Basin
 
3,527

 
1,797

 
37,651

 
20,118

 
41,178

 
21,915

 
20
%
 
57
%
 
2
%
Marcellus
 
14,358

 
5,248

 
45,621

 
14,023

 
59,979

 
19,271

 
9
%
 
20
%
 
44
%
Other (1)
 
4,705

 
3,181

 
186,333

 
125,067

 
191,038

 
128,248

 
57
%
 
14
%
 
14
%
Total
 
131,462

 
81,539

 
411,161

 
231,452

 
542,623

 
312,991

 
37
%
 
21
%
 
13
%
 
(1)
Other includes acreage principally located in Texas, Colorado, Wyoming, West Virginia, Kentucky, Illinois and New York, where the Company does not currently intend to have any capital expenditures.
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 ten years depending on the area). In the ordinary course of business, based on the results of our exploration efforts, we have allowed certain acreage to expire and may allow additional acreage to expire in the future. See table above for the percentage of net undeveloped acreage expiring in 2016, 2017, and 2018, assuming no production is established on our leases within the primary term. The proved undeveloped reserves associated with the acreage expiring over the next three years are not material to the Company.
Marketing
Our production is marketed to third parties consistent with industry practices. Typically, our oil and gas is sold at the wellhead to unaffiliated third parties. Oil is sold at field-posted prices plus or minus a bonus or at a price based on NYMEX plus or minus a differential for the area. Natural gas is 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 (such as Houston Ship Channel, Dominion Transmission, Texas Eastern Zone M-3, Tennessee Gas Pipeline Zone 4-300, and Transco Leidy Hub) 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 sales point, 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 in natural gas pipeline operation, natural gas marketing and sales. In each case, we sell at competitive market prices based on a differential to several sales points. 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;

14



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 oil and gas 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.”
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 transportation and processing 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

15



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 (including Colorado and Ohio) allow the forced pooling or integration of tracts to facilitate exploration while other states (including Texas) rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws that establish maximum rates of production from oil and gas wells generally prohibit the venting or flaring of natural gas and impose specified requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our profitability. Because these laws and regulations are frequently expanded, amended and reinterpreted, we are unable to predict the future cost or impact of complying with such regulations.
Regulation of Sales and Transportation of Natural Gas
Federal legislation and regulatory controls have historically affected the price of natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (“NGA”), the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” of natural gas, including all of our sales of our own production. As a result, all of our domestically produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC’s jurisdiction over interstate natural gas transportation, however, was not affected by the Decontrol Act.
Under the NGA, facilities used in the production or gathering of natural gas are exempt from the FERC’s jurisdiction. We own certain natural gas pipelines that we believe satisfy the FERC’s criteria for establishing that these are all gathering facilities not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Some of the delay in bringing our natural gas to market has been the lack of available pipeline systems in the Marcellus and Utica, particularly those that would take natural gas production from the lease to existing infrastructure. In order to partly alleviate this issue, in the past, certain of our wholly owned subsidiaries have constructed non-jurisdictional gathering facilities in cases where we have determined that we can construct those facilities more quickly or more efficiently than waiting on an unrelated third-party pipeline company.
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

16



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.
Oil Price Controls and Transportation Rates
Our sales of crude oil, condensate and natural gas liquids 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 natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2015, to implement the latest required five-yearly re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes. For the five-year period beginning July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. Under FERC’s regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. We are not able at this time to predict the effects of this indexing system or any new FERC regulations on the transportation costs associated with oil production from our oil producing operations.
There regularly are legislative proposals pending in the federal and state legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, we cannot predict whether or to what extent the trend toward federal deregulation of the petroleum industry will continue, or what the ultimate effect on our sales of oil, gas and other petroleum products will be.
Environmental Regulations
Our operations are subject to numerous international, federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on specified lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations. The failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of investigatory or remedial obligations or the issuance of injunctions prohibiting or limiting the extent of our operations. Public interest in the protection of the environment has increased dramatically in recent years. The trend of applying more expansive and stricter environmental legislation and regulations to the oil and gas industry could continue, resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.
We currently own or lease numerous properties that for many years have been used for the exploration and production of oil and gas. Although we believe that we have generally implemented appropriate operating and waste disposal practices, prior owners and operators of these properties may not have used similar practices, and hydrocarbons or other waste may have been disposed of or released on or under the properties we own or lease or on or under locations where such waste has been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other waste was not under our control. These properties and the waste disposed thereon may be subject to the federal Resource Conservation and Recovery Act (“RCRA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), and analogous state laws as well as state laws governing the management of oil and gas waste. Under these laws, we could be required to remove or remediate previously disposed waste (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.
We generate waste that may be subject to RCRA and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”), 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”

17



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, in 2012 the Texas Commission on Environmental Quality revised certain air permit programs by significantly increasing the air permitting requirements for new and certain existing oil and gas production and gathering sites for 23 counties in the Barnett production area. 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 natural gas liquids 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. More recently, in September 2015, the EPA published proposed 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. Similarly in January 2016, the BLM proposed rules to require additional efforts by producers to reduce venting, flaring, and leaking of natural gas produced on federal and Native American lands. Compliance with these requirements 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

18



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 Indiana Bat and the Attwater’s Prairie Chicken. In these areas, we may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could restrict drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we operate could result in increased costs of or limitations on our ability to perform operations and thus have an adverse effect on our business. We believe that we are in substantial compliance with the ESA, and we are not aware of any proposed listings that will affect our operations. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.
The Safe Drinking Water Act (“SDWA”) and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities. We believe that we substantially comply with the SDWA and related state provisions.
We also are subject to a variety of federal, state, local and foreign permitting and registration requirements relating to protection of the environment. We believe we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on our financial position or results of operations.
Global Climate Change
There is increasing attention in the United States and worldwide being paid to the issue of climate change and the contributing effect of greenhouse gas (“GHG”) emissions. The EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, regulates GHG emissions from certain large stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA also expanded its existing GHG emissions reporting rule to apply to the oil and gas source category, including oil and natural gas production facilities and natural gas processing, transmission, distribution and storage facilities. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year were required to report annual GHG emissions to EPA, for the first time by September 28, 2012. In addition, in September 2015, the EPA published proposed 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 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. Most recently in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement will be open for signing on April 22, 2016 and will require 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.
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.

19



Title to Properties; Acquisition Risks
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.”
Customers
The following table presents customers that represent at least 10% of our crude oil and natural gas revenues for each respective year:
 
Year Ended December 31,
 
2015
 
2014
 
2013
Shell Trading (US) Company
65%
 
44%
 
47%
Flint Hills Resources, LP
(a)
 
26%
 
23%
 
(a)
Revenues from the customer were below 10% during the year.
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, 2015, we had 215 full-time employees. We believe that our relationships with our employees are satisfactory.
In order to optimize prospect generation and development, we utilize the services of independent consultants and contractors to perform various professional services, particularly in the areas of 3-D seismic data mapping, acquisition of leases and lease options, construction, design, well site surveillance, permitting and environmental assessment. Independent contractors generally provide field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testing. We believe that this use of third-party service providers has enhanced our ability to manage general and administrative expenses.
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. We make available on our website, through a direct link to the SEC’s website at www.sec.gov, free of charge, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file such materials with, or furnish them 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.
You may also find information related to our corporate governance, board committees and company code of ethics at our website. Among the information you can find there is 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 Us—Governance.”

20



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. Barrel of oil equivalent. A Boe is determined using the ratio of 6,000 cubic feet of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids 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.
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.
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.

21



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 an essential technology in shale reservoirs and other unconventional resource plays where nearly all wells are fractured in order to enable commercial hydrocarbon production.
MBbls. Thousand barrels of oil or other liquid hydrocarbons.
MBoe. Thousand barrels of oil equivalent.
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 natural gas liquids, which represents the approximate energy content of oil, condensate and natural gas liquids 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 natural gas liquids, which represents the approximate energy content of oil, condensate and natural gas liquids 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.

22



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.
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 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.
PV-10 value. When used with respect to oil and gas reserves, present value, or PV-10, means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices calculated as the average oil and gas price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date, and without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted to a present value using an annual discount rate of 10%.
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.

23



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.
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.
Undeveloped oil and gas reserves. 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 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 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 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.
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 continued 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;

24



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, are 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 few, if any, of our drilling locations if drilled would be economical at the commodity price lows seen in early 2016, and wells drilled on our drilling locations in the Utica, Niobrara and Marcellus are not expected to be profitable unless prices increase significantly from even higher more recent prices. There can be no assurance, however, that wells will actually be profitable at such estimated prices. Additionally, failure to drill such wells because they are not profitable or for other reasons may substantially affect our acreage that is not currently held by production, as the primary term of the leases for a majority of such acreage will expire by the end of 2018 if no production is established on such acreage. 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. Substantially all of our production is sold to purchasers under short-term (less than twelve-month) contracts at market-based prices. Low oil and natural gas prices will reduce our cash flows, borrowing ability, the present value of our reserves and our ability to develop future reserves. Low oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect the quantity of our proved reserves.
Low commodity prices have led us to recognize an impairment of our oil and gas properties and continued lower commodity prices or additional commodity price declines will likely lead to additional impairments in future periods, which could have a material adverse effect on our results of operations. See “—If oil and natural gas prices continue to decline, or remain at low levels, we expect to be required to record additional impairments of oil and gas properties that would constitute a charge to earnings and reduce our shareholders’ equity.”
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 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.

25



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 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, including prevailing and anticipated prices for oil and gas and the availability and prices of drilling rigs and crews; 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. In addition, our ability to produce oil and gas may be significantly affected by the availability and prices of hydraulic fracturing equipment and crews. There can be no assurance that these projects can be successfully developed or that any identified drill sites or budgeted wells will, if drilled, encounter reservoirs of commercially productive oil or gas. We may seek to sell or reduce all or a portion of our interest in a project area or with respect to prospects or budgeted wells within such project area.
Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future.
There are uncertainties inherent in estimating oil and gas reserves and their estimated value, including many factors beyond the control of the producer. The reserve data included herein represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. These include subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Reserve estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. Additionally, in recent years, there has been increased debate and disagreement over the classification of reserves, with particular focus on proved undeveloped reserves. The interpretation of SEC rules regarding the classification of reserves and their applicability in different situations remain unclear in many respects. Changing interpretations of the classification standards of reserves or disagreements with our interpretations could cause us to write down reserves.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe. We have deferred some of our exploration activities in response to the severe price downturn beginning in the summer of 2014 and such continued deferral may increase the impact of this requirement.
As of December 31, 2015, approximately 55% of our proved reserves were proved undeveloped. Moreover, some of the producing wells included in our reserve reports as of December 31, 2015 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.

26



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, 2015, with costs determined as of the date of the estimate. As a result of significant declines in commodity prices, such average sales prices are significantly in excess of more recent prices. Unless commodity prices or reserves increase, the estimated discounted future net cash flows from our proved reserves would generally be expected to decrease as additional months with lower commodity sales prices will be included in this calculation in the future.
In addition, lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically, which has an may again cause us to reduce the quantities of our proved reserves and may cause the value of our estimated proved reserves at future reporting dates to decline compared to the value of our estimated proved reserves. If oil and gas prices remain at low levels, holding other factors constant, we expect that will be required to reduce our proved reserves estimates due to economic limits. Any such reduction in proved reserve volumes combined with lower commodity prices would reduce the PV-10 and standardized measure values of our proved reserves as of December 31, 2015.
Actual future net cash flows also will be affected by factors such as:
the actual prices we receive for oil and gas;
our actual operating costs in producing oil and gas;
the amount and timing of actual production;
supply and demand for oil and gas;
increases or decreases in consumption of oil and gas; and
changes in governmental regulations or taxation.
In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.
In general, the volume of production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and gas production is, therefore, highly dependent on our level of success in developing, finding or acquiring additional reserves that are economically recoverable.
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 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. In addition, the sustained declines and volatility in oil and gas prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint

27



activity obligations. Some of these working interest owners have experienced liquidity and cash flow problems. These problems may lead these parties to attempt to delay the pace of drilling or project development in order to preserve cash. A working interest owner may be unable or unwilling to pay its share of project costs. In some cases, a working interest owner may declare bankruptcy. In the event any of these third party working interest owners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from such parties, which could materially adversely affect our financial position.
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. 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 of the Eagle Ford and Marcellus where we operate. See “—Interruption to crude oil and natural gas gathering systems, pipelines 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. Due to the limited available pipeline capacity in the Eagle Ford and Marcellus, 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.
Production in the Marcellus and Utica by oil and gas companies expanded over the last few years and the amount of natural gas currently being produced by us and others exceeds the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. It is necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for the Marcellus and Utica may not occur for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity or sell natural gas production at significantly lower prices than those we currently project, which could materially and adversely affect our results of operations.
A portion of our oil and gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss or unavailability of pipeline or gathering system access and capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions, including low oil and gas prices. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.

28



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 onshore and offshore 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 due 2020 and our 6.25% Senior Notes due 2023 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 the recent decline in oil prices.
In addition, the provisions of our revolving credit facility and our 7.50% Senior Notes and 6.25% 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 and 6.25% Senior Notes, making investments, acquisitions, mergers and asset dispositions, entering into hedging transactions and other matters. Our revolving credit facility also requires compliance with covenants to maintain specified financial ratios. Our business plan and our compliance with these covenants are based on a number of assumptions, the most important of which is relatively

29



stable oil and gas prices at economically sustainable levels. If the prices that we receive for our oil and gas production remain at their current level for an extended period of time or 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 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 prevailing oil and gas prices. A negative adjustment could occur if the estimates of future prices used by the banks in calculating the borrowing base remain significantly lower than those used in the last redetermination, including as a result of the decline in oil prices or an expectation that such reduced prices will continue. The next redetermination of our borrowing base is scheduled to occur in Spring 2016. 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 Utica Shale and 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 Utica and the Delaware Basin. We have participated in the drilling of only 18 gross (4.6 net) wells and 8 gross (3.9 net) wells in the Utica and the Delaware Basin, respectively. 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 Utica and the Delaware Basin than we have in some other areas 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 treat and dispose of water after drilling, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas. Furthermore, future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial performance. For example, in April 2011, the Pennsylvania Department of Environmental

30



Protection called on all Marcellus natural gas drilling operators to voluntarily cease by May 19, 2011 delivering wastewater to those centralized treatment facilities that were grandfathered from the application of PaDEP’s Total Dissolved Solids regulations. Additionally, in April 2015, the EPA proposed 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 natural gas liquids.
If we are unable to increase our acreage positions in the Eagle Ford, Delaware Basin, Niobrara or Utica, 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 natural gas liquids on similar terms or at all.
Restricted land access could reduce our ability to explore for and develop oil and gas reserves.
Our ability to adequately explore for and develop oil and gas resources is affected by a number of factors related to access to land. Examples of factors which reduce our access to land include, among others:
new municipal or state land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;
local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;
landowner or foreign governments’ opposition to infrastructure development;
regulation of federal land by the U.S. Department of the Interior Bureau of Land Management or other federal government agencies;
anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, disruption of drilling, or damage to equipment;
disputes regarding leases; and
disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements.
Loss of access to land for which we own mineral rights could result in a reduction in our proved reserves and a negative impact on our results of operations and cash flows. Reduced ability to obtain new leases could constrain our future growth and opportunity set by limiting the expansion of our operations.
We face strong competition from other oil and gas companies.
We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the oil and gas business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory projects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on favorable terms. These companies may also have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the current commodity price environment, and to absorb the burden of current and future governmental regulations and taxation. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.
We may not be able to keep pace with technological developments in our industry.
The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the

31



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 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.
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. For example, in January 2016, the Pennsylvania Department of Environmental Protection announced a final-form rulemaking amending Pennsylvania Code Chapter 78 which sets new performance standards for surface activities at conventional and unconventional oil and gas well sites and announced plans to regulate methane emissions from the drilling industry by revising its permitting process for new gas wells and pipelines and proposing new requirements regulating methane from existing sources. These regulations and other future regulations could add costs and cause delays in our operations. In addition, 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 2011-2016 National Enforcement Initiative, “Assuring 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.

32



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. 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, the EPA is conducting a comprehensive research study to investigate the potential adverse environmental impacts of hydraulic fracturing, including on water quality and public health. A draft report was released in June 2015, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there may be above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. 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. President Obama has created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources.
State and federal regulatory agencies recently have focused on a possible connection between the 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 Colorado, Ohio, and 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 2015, the United States Geological Study identified eight states including Colorado, Ohio, and Texas with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In addition, a number of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. 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 Colorado, Ohio, Pennsylvania, Texas and West Virginia, 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, and New York issued a statewide ban on hydraulic fracturing in June 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 states of Colorado, New York, Ohio, Pennsylvania, Texas and West Virginia, 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 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;

33



reducing access to federal and state owned lands;
delaying or canceling certain projects such as shale development and pipeline construction;
limiting or banning the use of hydraulic fracturing;
denying air-quality permits for drilling; and
advocating for increased regulations on shale drilling and hydraulic fracturing.
Future anti-development efforts could result in the following:
blocked development;
denial or delay of drilling permits;
shortening of lease terms or reduction in lease size;
restrictions on installation or operation of gathering or processing facilities;
restrictions on the use of certain operating practices, such as hydraulic fracturing;
reduced access to water supplies or restrictions on water disposal;
limited access or damage to or destruction of our property;
legal challenges or lawsuits;
increased regulation of our business;
damaging publicity and reputational harm;
increased costs of doing business;
reduction in demand for our products; and
other adverse effects on our ability to develop our properties and expand production.
Our need to incur costs associated with responding to these initiatives or complying with any new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations. In addition, the use of social media channels can be used to cause rapid, widespread reputational harm.
Our operations are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.
The oil and gas business involves operating hazards such as:
well blowouts;
mechanical failures;
explosions;
pipe or cement failures and casing collapses, which could release oil, natural gas, drilling fluids or hydraulic fracturing fluids;
uncontrollable flows of oil, natural gas or well fluids;
fires;
geologic formations with abnormal pressures;
spillage handling and disposing of materials, including drilling fluids and hydraulic fracturing fluids and other pollutants;
pipeline ruptures or spills;
releases of toxic gases;
adverse weather conditions, including drought, flooding, winter storms, snow, hurricanes or other severe weather events; and
other environmental hazards and risks including conditions caused by previous owners and lessors of our properties.
Any of these hazards and risks can result in substantial losses to us from, among other things, injury or loss or life,

34



severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. As a result we could incur substantial liabilities or experience reductions in revenue that could reduce or eliminate the funds available for our exploration and development programs and acquisitions.
We may not have enough insurance to cover all of the risks we face.
We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that management believes to be prudent; however, insurance against all operational risks is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if management believes that the cost of available insurance is excessive relative to the risks presented. In addition, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure you that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
We conduct a substantial portion of our operations through joint ventures, which subject 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 substantial portion of our operations through joint ventures with third parties, including GAIL, Haimo, the OIL JV Partners and Reliance. 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 substantial 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 substantially 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.

35



We cannot control the activities on properties we do not operate.
We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues or could create liability for us for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards. With respect to properties that we do not operate:
the operator could refuse to initiate exploration or development projects;
if we proceed with any of those projects the operator has refused to initiate, we may not receive any funding from the operator with respect to that project;
the operator may initiate exploration or development projects on a different schedule than we would prefer;
the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a project than we have funds for, which may mean that we cannot participate in those projects or participate in a substantial amount of the revenues from those projects; and
the operator may not have sufficient expertise or resources.
Any of these events could significantly and adversely affect our anticipated exploration and development activities.
Our business may suffer if we lose key personnel.
We depend to a large extent on the services of certain key management personnel, including our executive officers and other key employees, the loss of any of whom could have a material adverse effect on our operations. We have entered into employment agreements with many of our key employees as a way to assist in retaining their services and motivating their performance. We do not maintain key-man life insurance with respect to any of our employees. Our success will also be dependent on our ability to continue to employ and retain skilled technical personnel.
We may experience difficulty in achieving and managing future growth.
We have experienced growth in the past primarily through the expansion of our drilling program. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:
our ability to obtain leases or options on properties, including those for which we have 3-D seismic data;
our ability to acquire additional 3-D seismic data;
our ability to identify and acquire new exploratory prospects;
our ability to develop existing prospects;
our ability to continue to retain and attract skilled personnel;
our ability to maintain or enter into new relationships with project partners and independent contractors;
the results of our drilling program;
hydrocarbon prices; and
our access to capital.
We may not be successful in upgrading our technical, operations and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial position and results of operations.
We may continue to enter into or exercise 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, 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. The use of these arrangements limits our ability to benefit from increases in the prices of oil and gas. Additionally, some derivative transactions, such as certain of those entered

36



into in 2015, may help to assure favorable pricing in the near term, but at the cost of limiting our ability to benefit from price increases that occur in subsequent years. At any given time our derivative arrangements may apply to only a portion of our production, including following the exercise of any then-existing derivative instruments, thereby providing only partial protection against declines in oil and gas prices. These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of oil and gas or a sudden, unexpected event materially impacts oil or gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us or there may be an adverse change in the expected differential between the underlying price in the derivative instrument and the actual prices received for our production. During periods of declining commodity prices, our commodity price derivative positions increase, which increases our counterparty exposure.
As our derivatives expire, more of our future production will be sold at market prices unless we enter into additional derivative transactions. If we are unable to enter into new derivative contracts in the future at favorable pricing and for a sufficient amount of our production, our financial condition and results of operations could be materially adversely affected. It is also possible that a larger percentage of our future production will not be hedged as our derivative policies may change, which would result in our oil and gas revenue becoming more sensitive to commodity price changes.
The CFTC 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.
If oil and natural gas prices continue to decline, or remain at low levels, we expect to be required to record additional impairments of oil and gas properties that would constitute a charge to earnings and reduce our shareholders’ equity.
We use the full cost method of accounting for our oil and gas properties. Accordingly, we capitalize all productive and nonproductive costs directly associated with property acquisition, exploration and development activities to cost centers established on a country-by-country basis. Under the full cost method, the capitalized cost of oil and gas properties, less accumulated amortization and related deferred income taxes may not exceed the “cost center ceiling” which is 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. If the net capitalized costs exceed the cost center ceiling, we recognize the excess as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period. This evaluation is performed on a quarterly basis.
The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period. Due primarily to declines in the average realized prices for sales of oil and gas, the capitalized costs of oil and gas properties exceeded the cost center ceiling resulting in after-tax impairments in the carrying value of oil and gas properties for the year ended December 31, 2015 of $795.8 million. Based on the first calendar day of each month, oil and gas prices available for the 11 months ended February 1, 2016 as well as forecasted costs, we anticipate recording an additional after-tax impairment in the carrying value of oil and gas properties in the first quarter of 2016. Further impairments may occur if the trailing 12-month commodity prices continue to be lower than the comparable trailing 12-month commodity prices applicable to the 2015 year end.
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 oil and natural gas prices remain at their low levels or decline,

37



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.
This 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 oil and gas properties increases during periods of low oil or gas prices. As a result, there is an increased risk that we will incur additional impairments in 2016. 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 expect in the future to incur additional impairments of oil and gas properties, particularly if oil and natural gas prices remain at low levels or decline.
We could lose our ability to use net operating loss carryforwards that we have accumulated over the years.
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 upon the occurrence of certain ownership changes, including the purchase or sale of our stock by 5% shareholders and our offering of stock during any three-year period resulting in an aggregate change of more than 50% in our beneficial ownership. In the event of 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 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. As of December 31, 2015, we believe an ownership change occurred in February 2005, which imposed an annual limitation of approximately $12.6 million of the Company’s taxable income that can be offset by the pre-change carryforwards. Subsequent equity transactions involving us or our 5% shareholders (including, potentially, relatively small transactions and transactions beyond our control) could cause further ownership changes and therefore a limitation on the annual utilization of our U.S. loss carryforwards.
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 occurred in the third quarter of 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 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.
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

38



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.
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.
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 4. Acquisition and Divestiture” and “Note 5. 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. The Company strongly disagrees with the verdict and believes that the plaintiffs’ claims are without merit. Based on the Company’s position that the plaintiff's claims are without merit, we presently believe that the likelihood of material loss is remote. On December 22, 2015, the Company filed

39



its opening brief on the merits in its appeal to the Twelfth Court of Appeals at Tyler, Texas. If necessary, the Company intends to appeal to the Texas Supreme Court. The payment of damages per the judgment has been superseded by posting a bond in the amount of $25.0 million pending resolution of the appeals process (which could take an extended period of time).
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.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
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 sales prices per share of our common stock on the NASDAQ Global Select Market for the periods indicated.
 
 
High
 
Low
2015
 
 
 
 
First Quarter
 

$53.65

 

$38.44

Second Quarter
 
56.77

 
48.51

Third Quarter
 
49.28

 
27.79

Fourth Quarter
 
43.97

 
28.16

2014
 
 
 
 
First Quarter
 

$54.94

 

$39.78

Second Quarter
 
69.39

 
50.29

Third Quarter
 
70.49

 
53.05

Fourth Quarter
 
54.92

 
31.70

The closing market price of our common stock on February 19, 2016 was $21.48 per share. As of February 19, 2016, there were an estimated 117 owners of record of our common stock.
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 and our senior notes 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.”
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, 2010 to December 31, 2015, with the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index, over the same period.

40



The graph assumes an investment of $100 (with reinvestment of all dividends) was invested on December 31, 2010, 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, 2010
 
$100
 
$100
 
$100
December 31, 2011
 
$76
 
$102
 
$95
December 31, 2012
 
$61
 
$118
 
$99
December 31, 2013
 
$130
 
$157
 
$131
December 31, 2014
 
$121
 
$178
 
$117
December 31, 2015
 
$86
 
$181
 
$89
We did not repurchase any of our common stock in 2015.
On November 24, 2009, we entered into an agreement with an unrelated third party and its affiliate, under which we issued 118,200 warrants to purchase shares of the Company’s common stock. In May 2015, the holders of the warrants exercised all warrants outstanding on a “cashless” basis at an exercise price of $22.09, resulting in the issuance on May 4, 2015 of 71,913 net shares of the Company’s common stock. Such shares of common stock were issued pursuant to an exemption from registration under §3(a)(9) of the Securities Act of 1933, as amended.
See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding shares of common stock authorized for issuance under our stock incentive plans.


41



Item 6. Selected Financial Data
Our financial information set forth below for each of the five years in the period ended December 31, 2015, has been derived from continuing operations 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.”
 

Year Ended December 31,
 

2015
 
2014
 
2013
 
2012
 
2011
 

(In thousands, except per share data)
Statements of Operations from Continuing Operations Data:










Total revenues


$429,203



$710,187



$520,182



$368,180



$202,167

Costs and expenses

 
 
 
 
 
 
 
 
 
Oil and gas operating

116,990


112,151


75,340


54,826


37,636

Depreciation, depletion and amortization

300,035


317,383


214,291


165,993


84,841

General and administrative

67,224


77,029


77,492


48,708


41,539

(Gain) loss on derivatives, net
 
(99,261
)
 
(201,907
)
 
18,417

 
(31,371
)
 
(48,423
)
Interest expense, net
 
69,195

 
53,171

 
54,689

 
48,158

 
27,629

Impairment of oil and gas properties
 
1,224,367

 

 

 

 

Loss on extinguishment of debt
 
38,137

 

 

 

 
897

Loss on sale of oil and gas properties
 

 

 
45,377

 

 

Other (income) expense, net
 
11,276

 
2,150

 
(185
)
 
(267
)
 
(97
)
Total costs and expenses

1,727,963

 
359,977

 
485,421

 
286,047

 
144,022

Income (Loss) From Continuing Operations Before Income Taxes

(1,298,760
)

350,210


34,761


82,133


58,145

Income tax (expense) benefit

140,875


(127,927
)

(12,903
)

(30,956
)

(25,611
)
Income (Loss) From Continuing Operations


($1,157,885
)


$222,283



$21,858



$51,177



$32,534

Basic income (loss) from continuing operations per common share


($22.50
)


$4.90



$0.54



$1.29



$0.83

Diluted income (loss) from continuing operations per common share


($22.50
)


$4.81



$0.53



$1.28



$0.82

Basic weighted average common shares outstanding

51,457


45,372


40,781


39,591


39,077

Diluted weighted average common shares outstanding

51,457


46,194


41,355


40,026


39,668

Statements of Cash Flows from Continuing Operations Data:










Net cash provided by operating activities from continuing operations


$378,735



$502,275

 

$367,474



$253,071



$155,511

Net cash used in investing activities from continuing operations

(673,376
)

(940,676
)
 
(509,885
)

(465,151
)

(250,068
)
Net cash provided by financing activities from continuing operations

330,767


300,290

 
120,326


237,778


116,826

Other Cash Flows from Continuing Operations Data:










Capital expenditures - oil and gas properties


($674,612
)


($860,604
)


($786,976
)


($735,711
)


($516,004
)
Proceeds from sales of oil and gas properties, net
 
8,047

 
12,576

 
238,470

 
341,597

 
167,265

Proceeds from issuances of senior notes
 
650,000

 
301,500

 

 
300,000

 
197,000

Tender and redemption of senior notes and other payments of long-term debt
 
(776,681
)
 

 
(69,325
)
 
(55,228
)
 
(70,599
)
Sale of common stock, net of offering costs

470,158




189,686





Balance Sheets from Continuing Operations Data:










Working capital


($50,636
)


($141,278
)


($32,138
)


($43,432
)


($150,559
)
Total property and equipment, net

1,716,861


2,629,253


1,794,215


1,487,674


1,240,917

Total assets

2,026,905


2,981,476


2,110,760


1,749,488


1,445,075

Long-term debt

1,255,676


1,351,346


900,247


967,808


711,486

Total shareholders’ equity

444,054


1,103,441


841,604


585,016


509,855



42



Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General Overview
Production, Commodity Prices and Revenue. Total production for the year ended December 31, 2015 increased 12% from 2014 to a record 36,719 Boe/d, of which 72% was in the Eagle Ford. Crude oil production for 2015 was a record 23,054 Bbls/d, an increase of 22% from 2014, primarily driven by strong performance from our wells in the Eagle Ford, which averaged 20,182 Bbls/d for 2015. Driven primarily by the 49% decrease in average realized crude oil prices, our 2015 revenues decreased to $429.2 million. For further discussion of production, commodity prices and revenue, see “—Results of Operations” below.
Operational Highlights. See the table below for details of our operated drilling and completion activity by region:
 
 
Year Ended December 31, 2015
 
As of December 31, 2015
 
 
Drilled
 
Wells Brought
on Production
 
Waiting on Completion
 
Producing
 
Rig Count
Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Eagle Ford
 
71

 
65.1

 
67

 
60.1

 
29

 
27.3

 
263

 
230.8

 
2

Niobrara
 
13

 
7.5

 
11

 
5.8

 
9

 
5.2

 
123

 
53.4

 

Marcellus
 

 

 

 

 
11

 
4.3

 
82

 
26.3

 

Utica
 

 

 
2

 
1.7

 

 

 
4

 
3.1

 

Delaware Basin
 
4

 
3.6

 
2

 
1.7

 
2

 
1.9

 
2

 
1.7

 
1

Total
 
88

 
76.2

 
82

 
69.3

 
51

 
38.7

 
474

 
315.3

 
3

Approximately 80% of our 2015 drilling and completion capital expenditures were in the Eagle Ford where, as of December 31, 2015, we were operating two rigs. We began drilling in the Delaware Basin in 2015 and completed 2 gross (1.7 net) wells. As of December 31, 2015, we held an interest in 21,915 net acres in the Delaware Basin and we are continuing to pursue additional acreage in the oil and condensate windows of the Wolfcamp Formation.
At December 31, 2015, our estimated net proved oil and natural gas reserves were 170.6 MMBoe, an increase of 19.6 million MMBoe, or 13%, from December 31, 2014. Approximately 64% of our total estimated net proved reserves are crude oil. Our reserves increased primarily as a result of our ongoing drilling program in the Eagle Ford. See “Item 1. Business—Proved Oil and Gas Reserves” for additional discussion.
Financing Activities. In March 2015, we completed a public offering of 5.2 million shares of our common stock at a price of $44.75 per share, for proceeds of $231.3 million, net of offering costs. We used the net proceeds from the common stock offering to repay a portion of the borrowings under our revolving credit facility and for general corporate purposes.
In April 2015, we settled a cash tender offer for any or all of the outstanding $600.0 million aggregate principal amount of our 8.625% Senior Notes. In connection with the cash tender offer, we also redeemed in May 2015 all of the 8.625% Senior Notes that remained outstanding following the cash tender offer. See “—Financing Arrangements—8.625% Senior Notes” for details of the tender offer and redemption of our 8.625% Senior Notes.
Also in April 2015, we closed a public offering of $650.0 million aggregate principal amount of 6.25% Senior Notes due 2023. The 6.25% Senior Notes bear interest at 6.25% per annum which is payable semi-annually on each April 15 and October 15 and mature on April 15, 2023. The proceeds of $640.3 million, net of underwriting discounts and commissions, were used to fund the repurchase of the 8.625% Senior Notes in the tender offer described above, redeem the remaining outstanding 8.625% Senior Notes, and repay borrowings outstanding under our revolving credit facility.
In May 2015, we entered into the sixth amendment to the credit agreement governing the revolving credit facility to, among other things, (i) establish an approved borrowing base of $685.0 million until the next redetermination, (ii) establish a swing line commitment under our revolving credit facility not to exceed $15.0 million and (iii) include seven additional banks to our banking syndicate, bringing the total number of banks to 19 as of the date of such amendment.
In October 2015, we completed a public offering of 6.3 million shares of our common stock at a price of $37.80 per share, for net proceeds of $238.8 million, net of offering costs. We used the net proceeds from the common stock offering to repay borrowings under our revolving credit facility and for general corporate purposes.
In October 2015, we entered into the seventh amendment to the credit agreement governing the revolving credit facility to, among other things, (i) reaffirm the borrowing base at its current level of $685.0 million until the next redetermination and (ii) amend the financial covenant requiring the maintenance of a ratio of Total Debt to EBITDA (as defined in the credit agreement) of not more than 4.00 to 1.00, such that the permissible ratio is increased to 4.75 to 1.00 through December 31, 2016, reducing to 4.375 to 1.00 through December 31, 2017, and returning to 4.00 to 1.00 thereafter. As of December 31, 2015, we had no borrowings outstanding under our revolving credit facility.

43



2016 Capital Expenditure Plan. Our current 2016 capital expenditure plan includes $270.0 million to $290.0 million for drilling and completion and $15.0 million for leasehold and seismic, which represents a substantial decrease from our 2015 capital expenditures of $544.2 million and is in response to the continued lower crude oil prices that the industry has experienced throughout 2015 and into 2016. Approximately 93% of our 2016 drilling and completion capital expenditure plan is allocated to our continued exploration and development of the Eagle Ford. See “—Liquidity and Capital Resources—2016 Capital Expenditure Plan and Funding Strategy” for additional details.
Results of Operations
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the years ended December 31, 2015 and 2014:
 
 
Year Ended
December 31,
 
2015 Period
Compared to 2014 Period
 
 
2015
 
2014
 
Increase(Decrease)
 
% Increase(Decrease)
Total production volumes -
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
8,415

 
6,906

 
1,509

 
22
%
NGLs (MBbls)
 
1,352

 
926

 
426

 
46
%
Natural gas (MMcf)
 
21,812

 
24,877

 
(3,065
)
 
(12
%)
Total barrels of oil equivalent (MBoe)
 
13,402

 
11,978

 
1,424

 
12
%
 
 
 
 
 
 
 
 
 
Daily production volumes by product -
 
 
 
 
 
 
 
 
Crude oil (Bbls/d)
 
23,054

 
18,921

 
4,133

 
22
%
NGLs (Bbls/d)
 
3,705

 
2,537

 
1,168

 
46
%
Natural gas (Mcf/d)
 
59,758

 
68,156

 
(8,398
)
 
(12
%)
Total barrels of oil equivalent (Boe/d)
 
36,719

 
32,816

 
3,903

 
12
%
 
 
 
 
 
 
 
 
 
Daily production volumes by region (Boe/d) -
 
 
 
 
 
 
 
 
Eagle Ford
 
26,377

 
21,131

 
5,246

 
25
%
Niobrara
 
2,957

 
2,585

 
372

 
14
%
Marcellus
 
5,850

 
8,354

 
(2,504
)
 
(30
%)
Utica
 
1,286

 
288

 
998

 
347
%
Delaware Basin and other
 
249

 
458

 
(209
)
 
(46
%)
Total barrels of oil equivalent (Boe/d)
 
36,719

 
32,816

 
3,903

 
12
%
 
 
 
 
 
 
 
 
 
Average realized prices -
 
 
 
 
 
 
 
 
Crude oil ($ per Bbl)
 

$44.69

 

$88.40

 

($43.71
)
 
(49
%)
NGLs ($ per Bbl)
 
11.54

 
27.05

 
(15.51
)
 
(57
%)
Natural gas ($ per Mcf)
 
1.72

 
3.00

 
(1.28
)
 
(43
%)
Total average realized price ($ per Boe)
 

$32.03

 

$59.29

 

($27.26
)
 
(46
%)
 
 
 
 
 
 
 
 
 
Revenues (In thousands) -
 
 
 
 
 
 
 
 
Crude oil
 

$376,094