Texas
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76-0415919
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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500 Dallas Street, Suite 2300
Houston, Texas
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77002
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(Principal executive offices)
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(Zip Code)
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Common Stock, $0.01 par value
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NASDAQ Global Select Market
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(Title of class)
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(Name of exchange on which registered)
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Large accelerated filer
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þ
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Accelerated filer
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¨
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Non-accelerated filer
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¨
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(Do not check if a smaller reporting company)
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Smaller reporting company
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¨
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Forward-Looking Statements
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PART I
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Item 1. Business
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Item 1A. Risk Factors
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Item 1B. Unresolved Staff Comments
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Item 2. Properties
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Item 3. Legal Proceedings
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Item 4. Mine Safety Disclosures
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PART II
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Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
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Item 6. Selected Financial Data
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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Item 7A. Qualitative and Quantitative Disclosures about Market Risk
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Item 8. Financial Statements and Supplementary Data
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Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosures
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Item 9A. Controls and Procedures
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Item 9B. Other Information
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PART III
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Item 10. Directors, Executive Officers and Corporate Governance
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Item 11. Executive Compensation
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
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Item 13. Certain Relationships and Related Transactions, and Director Independence
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Item 14. Principal Accounting Fees and Services
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PART IV
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Item 15. Exhibits and Financial Statement Schedules
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•
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our growth strategies;
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•
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our ability to explore for and develop oil and gas resources successfully and economically;
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•
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our estimates and forecasts of the timing, number and results of wells we expect to drill and other exploration activities;
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•
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our estimates regarding timing and levels of production;
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•
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changes in reserves, acreage and working capital requirements;
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•
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commodity price risk management activities and the impact on our average realized prices;
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•
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anticipated trends in our business;
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•
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availability of pipeline connections and water disposal on economic terms;
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•
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the effects of competition on us;
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•
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our future results of operations;
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•
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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;
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•
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our planned expenditures, prospects budgeted and capital expenditure plan;
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•
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future market conditions in the oil and gas industry;
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•
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our ability to make, integrate and develop acquisitions and realize any expected benefits or effects of completed acquisitions;
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•
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the benefits, results, effects, availability of and results of new and existing joint ventures and sales transactions;
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•
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receipt of receivables, drilling carry and proceeds from sales;
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•
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our ability to complete planned transactions on desirable terms; and
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•
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the impact of governmental regulation, taxes, market changes and world events.
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Proved Reserves
(MMBoe)
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||||
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December 31, 2014
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December 31, 2013
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Eagle Ford
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122.5
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73.9
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Niobrara
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5.6
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5.3
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Utica
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0.6
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—
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Marcellus
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22.3
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22.2
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Other
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0.1
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0.1
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Total
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151.1
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101.5
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Capital Expenditures
(In millions)
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||||||
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2015 Plan
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2014 Actual
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||||
Drilling and completion
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||||
Eagle Ford (1)
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$377.0
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$518.7
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Niobrara
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37.0
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108.4
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Utica
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30.0
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48.3
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Marcellus
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7.0
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23.4
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Other
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9.0
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16.6
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Total drilling and completion (2)
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460.0
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715.4
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Leasehold and seismic (1)
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35.0
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142.9
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Total
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$495.0
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$858.3
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(1)
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Does not include the Eagle Ford Shale Acquisition (as defined below).
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(2)
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Represents the midpoint of our 2015 drilling and completion capital expenditure plan of $450.0 million to $470.0 million.
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•
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Grow primarily through drilling.
We pursue a manufacturing-style development drilling program. We seek to identify resource plays through our extensive experience with the help of geological and geophysical analysis of 3-D seismic and other data and then accumulate sizeable acreage positions in high-quality areas. This provides us with the scale to drive efficiencies through our operations and improve our margins. Our ability to successfully identify, define and develop resource plays is demonstrated by our consistent success in rapidly growing oil and gas reserves and production in our oil and gas focused plays.
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•
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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 from sales of securities, proceeds, payments or carried interest from our joint ventures and borrowings under our revolving credit facility.
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•
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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, 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 2015 capital expenditure plan by approximately 42% from our 2014 capital expenditures, which reflects our strategy of maintaining financial flexibility in a low commodity price environment.
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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 reductions in commodity prices by actively hedging production of both crude oil and natural gas. Our current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to
36
months.
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•
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Pursue growth in crude oil plays.
Since April 2010, we have pursued a growth strategy in crude oil plays driven by the attractive relative economics associated with this commodity. By focusing on and implementing this strategy, our crude oil production as a percentage of total production has increased significantly from
3%
for the year ended December 31, 2010 to
58%
for the year ended December 31, 2014, which resulted in a significant increase in crude oil revenue as a percentage of total revenues from
10%
for the year ended December 31, 2010 to
86%
for the year ended December 31, 2014. Additionally, over
95%
of our 2015 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.
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•
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Utilize our experience as a technical advantage.
We believe we have developed a technical advantage from our extensive experience drilling over 700 horizontal wells in various resource plays, including the Eagle Ford, 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. We now leverage this advantage in our existing as well as prospective shale trends. We plan to focus substantially all of our capital expenditures in these resource plays, particularly during 2015, in the Eagle Ford where we have acquired, or are acquiring significant acreage positions and hold a large prospect inventory.
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•
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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 of
December 31, 2014
, we owned leases covering approximately
253,968
gross (
144,063
net) acres in these areas. Approximately
57%
of our estimated U.S. proved reserves at
December 31, 2014
were undeveloped.
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•
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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-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.
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•
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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.
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•
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Operational control.
As of
December 31, 2014
, we operated approximately
90%
of the wells in Eagle Ford in which we held an interest. We held an average interest of approximately
89%
in these operated wells. Our significant operational control 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. We are generally able to adjust drilling plans in response to changes in commodity prices.
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Financial flexibility to fund expansion.
We maintain a financial profile that provides operational flexibility, and our capital structure provides us with the ability to execute our business plan. We believe that we have the ability and financial flexibility to fund the planned development of our assets through 2015.
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Crude Oil (MBbls)
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Natural Gas
Liquids (MBbls) |
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Natural Gas
(MMcf)
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Total
(MBoe) (1)
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PV-10
Value (2)
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||||||
Developed
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35,238
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5,294
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149,697
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65,482
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$1,616.2
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Undeveloped
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65,466
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8,218
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71,320
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85,571
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$1,644.5
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Total Proved
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100,704
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13,512
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221,017
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151,053
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$3,260.7
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(1)
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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.
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(2)
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The PV-10 value as of
December 31, 2014
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, 2014
, which averaged
$92.24
per Bbl of oil,
$27.80
per Bbl of natural gas liquids, and
$3.24
per Mcf of natural gas. 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 future net cash flows, and information reconciling the U.S. GAAP and non-U.S. GAAP measures are included in the table below.
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As of December 31, 2014 (In millions)
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Standardized measure of discounted future net cash flows (U.S. GAAP)
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$2,555.1
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||||||
Add: present value of future income taxes discounted at 10% per annum
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$705.6
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||||||
PV-10 value (Non-U.S. GAAP)
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$3,260.7
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Year Ended December 31,
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||||||||||
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2014
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2013
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2012
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||||||
Total production volumes -
|
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||||||
Crude oil (MBbls)
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6,906
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|
4,231
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|
2,862
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|||
NGLs (MBbls)
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|
926
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|
531
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|
305
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|||
Natural gas (MMcf)
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|
24,877
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|
|
31,422
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|
|
37,612
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|||
Total Natural gas and NGLs (MMcfe)
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30,433
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|
34,608
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|
39,442
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|||
Total barrels of oil equivalent (MBoe)
|
|
11,978
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|
9,999
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|
9,436
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|||
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||||||
Daily production volumes by product -
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||||||
Crude oil (Bbls/d)
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18,921
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11,592
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|
|
7,820
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|
|||
NGLs (Bbls/d)
|
|
2,537
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|
|
1,455
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|
|
833
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|
|||
Natural gas (Mcf/d)
|
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68,156
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|
86,088
|
|
|
102,765
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|
|||
Total Natural gas and NGLs (Mcfe/d)
|
|
83,378
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|
94,816
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|
|
107,765
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|||
Total barrels of oil equivalent per day (Boe/d)
|
|
32,816
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|
|
27,395
|
|
|
25,781
|
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|||
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|
|
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||||||
Daily production volumes by region (Boe/d) -
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|
||||||
Eagle Ford
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21,131
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|
|
12,628
|
|
|
7,950
|
|
|||
Niobrara
|
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2,585
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|
|
1,724
|
|
|
1,259
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|
|||
Barnett
|
|
—
|
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|
6,625
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|
|
11,614
|
|
|||
Marcellus
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8,354
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|
6,139
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|
|
3,608
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|||
Utica and other
|
|
746
|
|
|
279
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|
|
1,350
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|||
Total barrels of oil equivalent (Boe/d)
|
|
32,816
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|
|
27,395
|
|
|
25,781
|
|
|||
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||||||
Average realized prices -
|
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||||||
Crude oil ($ per Bbl)
|
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$88.40
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$99.58
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$99.97
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NGLs ($ per Bbl)
|
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$27.05
|
|
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$29.25
|
|
|
|
$34.86
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Natural gas ($ per Mcf)
|
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$3.00
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|
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$2.65
|
|
|
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$1.90
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Total Natural gas and NGLs ($ per Mcfe)
|
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$3.28
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$2.86
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$2.08
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Total average realized price ($ per Boe)
|
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$59.29
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$52.02
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$39.02
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||||||
Average production costs ($ per Boe)(1)
|
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$6.19
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$4.68
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$3.34
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(1)
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Includes lease operating costs but excludes production tax and ad valorem tax.
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Year Ended December 31,
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||||||||||||||||
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2014
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2013
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2012
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||||||||||||
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Gross
|
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Net
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Gross
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Net
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Gross
|
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Net
|
||||||
U.S.
|
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||||||
Exploratory Wells - Productive
|
|
128
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|
|
23.0
|
|
|
75
|
|
|
13.9
|
|
|
69
|
|
|
31.8
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Exploratory Wells - Nonproductive
|
|
—
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|
|
—
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|
|
2
|
|
|
2.0
|
|
|
1
|
|
|
0.5
|
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Development Wells - Productive
|
|
77
|
|
|
63.5
|
|
|
119
|
|
|
64.6
|
|
|
60
|
|
|
37.7
|
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Development Wells - Nonproductive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
||||||
U.K. North Sea
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Exploratory Wells - Productive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploratory Wells - Nonproductive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.2
|
|
Development Wells - Productive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.3
|
|
Development Wells - Nonproductive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Exploratory Wells - Productive
|
|
128
|
|
|
23.0
|
|
|
75
|
|
|
13.9
|
|
|
69
|
|
|
31.8
|
|
Exploratory Wells - Nonproductive
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2.0
|
|
|
2
|
|
|
0.7
|
|
Development Wells - Productive
|
|
77
|
|
|
63.5
|
|
|
119
|
|
|
64.6
|
|
|
62
|
|
|
38.0
|
|
Development Wells - Nonproductive
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Eagle Ford - Texas
|
|
57,010
|
|
|
47,674
|
|
|
54,529
|
|
|
33,309
|
|
|
111,539
|
|
|
80,983
|
|
Niobrara - Colorado
|
|
34,948
|
|
|
12,975
|
|
|
66,782
|
|
|
22,965
|
|
|
101,730
|
|
|
35,940
|
|
Utica - Ohio
|
|
716
|
|
|
503
|
|
|
39,983
|
|
|
26,637
|
|
|
40,699
|
|
|
27,140
|
|
Delaware Basin - Texas
|
|
960
|
|
|
120
|
|
|
32,879
|
|
|
17,251
|
|
|
33,839
|
|
|
17,371
|
|
Marcellus
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Pennsylvania
|
|
14,030
|
|
|
5,250
|
|
|
45,369
|
|
|
14,557
|
|
|
59,399
|
|
|
19,807
|
|
Other-Marcellus
|
|
2,303
|
|
|
236
|
|
|
37,937
|
|
|
13,408
|
|
|
40,240
|
|
|
13,644
|
|
Marcellus Total
|
|
16,333
|
|
|
5,486
|
|
|
83,306
|
|
|
27,965
|
|
|
99,639
|
|
|
33,451
|
|
Other U.S. (1)
|
|
5,461
|
|
|
3,995
|
|
|
167,024
|
|
|
126,259
|
|
|
172,485
|
|
|
130,254
|
|
Total U.S.
|
|
115,428
|
|
|
70,753
|
|
|
444,503
|
|
|
254,386
|
|
|
559,931
|
|
|
325,139
|
|
U.K. North Sea (discontinued operations)
|
|
—
|
|
|
—
|
|
|
139,924
|
|
|
103,227
|
|
|
139,924
|
|
|
103,227
|
|
Worldwide
|
|
115,428
|
|
|
70,753
|
|
|
584,427
|
|
|
357,613
|
|
|
699,855
|
|
|
428,366
|
|
|
(1)
|
“Other U.S.” includes acreage principally located in Colorado, Wyoming, Texas and Appalachia, where the Company does not currently intend to spend material sums.
|
•
|
demand for oil and gas;
|
•
|
the extent of production 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.
|
•
|
require permits for the drilling of wells;
|
•
|
mandate that we maintain bonding requirements in order to drill or operate wells; and
|
•
|
regulate the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, groundwater sampling requirements prior to drilling, the plugging and abandoning of wells and the disposal of fluids used in connection with operations.
|
|
Year Ended December 31,
|
||||
|
2014
|
|
2013
|
|
2012
|
Shell Trading (US) Company
|
44%
|
|
47%
|
|
(a)
|
Flint Hills Resources, LP
|
26%
|
|
23%
|
|
53%
|
Enterprise Products Operating, L.L.C.
|
(a)
|
|
(a)
|
|
10%
|
|
(a)
|
Revenues from the customer were below 10% during the year.
|
•
|
Audit Committee Charter;
|
•
|
Compensation Committee Charter;
|
•
|
Nominating and Corporate Governance Committee Charter;
|
•
|
Code of Ethics and Business Conduct; and
|
•
|
Compliance Employee Report Line.
|
•
|
the level of consumer product demand;
|
•
|
the levels and location of oil and gas supply and demand and expectations regarding supply and demand, including the supply of oil and natural gas due to increased production from resource plays;
|
•
|
overall economic conditions;
|
•
|
weather conditions;
|
•
|
domestic and foreign governmental relations, regulations and taxes;
|
•
|
the price and availability of alternative fuels;
|
•
|
political conditions or hostilities and unrest in oil producing regions;
|
•
|
the level and price of foreign imports of oil and liquefied natural gas;
|
•
|
the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree upon and maintain production constraints and oil price controls;
|
•
|
technological advances affecting energy consumption;
|
•
|
speculation by investors in oil and gas; and
|
•
|
variations between product prices at sales points and applicable index prices.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
limiting oil and gas development;
|
•
|
reducing access to federal and state owned lands;
|
•
|
delaying or canceling certain projects such as offshore drilling, 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.
|
•
|
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.
|
•
|
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.
|
•
|
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 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.
|
•
|
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.
|
•
|
currency restrictions and exchange rate fluctuations;
|
•
|
loss of revenue, property and equipment as a result of expropriation, nationalization, war or insurrection;
|
•
|
increases in taxes and governmental royalties;
|
•
|
renegotiation of contracts with governmental entities and quasi-governmental agencies;
|
•
|
changes in laws and policies governing operations of foreign-based companies;
|
•
|
labor problems; and
|
•
|
other uncertainties arising out of foreign government sovereignty over our international operations.
|
|
|
High
|
|
Low
|
||||
2013
|
|
|
|
|
||||
First Quarter
|
|
|
$27.33
|
|
|
|
$19.49
|
|
Second Quarter
|
|
29.89
|
|
|
22.90
|
|
||
Third Quarter
|
|
37.52
|
|
|
28.39
|
|
||
Fourth Quarter
|
|
47.87
|
|
|
37.42
|
|
||
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
|
|
|
|
CRZO
|
|
S&P 500
|
|
DJ U.S. E&P
|
December 31, 2009
|
|
$100
|
|
$100
|
|
$100
|
December 31, 2010
|
|
$130
|
|
$115
|
|
$116
|
December 31, 2011
|
|
$99
|
|
$117
|
|
$110
|
December 31, 2012
|
|
$79
|
|
$136
|
|
$115
|
December 31, 2013
|
|
$169
|
|
$180
|
|
$152
|
December 31, 2014
|
|
$157
|
|
$205
|
|
$135
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
|
|
(In thousands, except per share data)
|
||||||||||||||||||
Statements of Operations from Continuing Operations Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues
|
|
|
$710,187
|
|
|
|
$520,182
|
|
|
|
$368,180
|
|
|
|
$202,167
|
|
|
|
$138,123
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and gas operating
|
|
112,151
|
|
|
75,340
|
|
|
54,826
|
|
|
37,636
|
|
|
31,014
|
|
|||||
Depreciation, depletion and amortization
|
|
317,383
|
|
|
214,291
|
|
|
165,993
|
|
|
84,841
|
|
|
47,246
|
|
|||||
General and administrative
|
|
77,029
|
|
|
77,492
|
|
|
48,708
|
|
|
41,539
|
|
|
35,906
|
|
|||||
(Gain) loss on derivatives, net
|
|
(201,907
|
)
|
|
18,417
|
|
|
(31,371
|
)
|
|
(48,423
|
)
|
|
(47,782
|
)
|
|||||
Loss on extinguishment of debt
|
|
—
|
|
|
—
|
|
|
—
|
|
|
897
|
|
|
31,023
|
|
|||||
Interest expense, net
|
|
53,171
|
|
|
54,689
|
|
|
48,158
|
|
|
27,629
|
|
|
22,518
|
|
|||||
Loss on sale of oil and gas properties
|
|
—
|
|
|
45,377
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other (income) expense, net
|
|
2,150
|
|
|
(185
|
)
|
|
(267
|
)
|
|
(97
|
)
|
|
(212
|
)
|
|||||
Total costs and expenses
|
|
359,977
|
|
|
485,421
|
|
|
286,047
|
|
|
144,022
|
|
|
119,713
|
|
|||||
Income from continuing operations before income taxes
|
|
350,210
|
|
|
34,761
|
|
|
82,133
|
|
|
58,145
|
|
|
18,410
|
|
|||||
Income tax expense
|
|
(127,927
|
)
|
|
(12,903
|
)
|
|
(30,956
|
)
|
|
(25,611
|
)
|
|
(6,685
|
)
|
|||||
Income from continuing operations
|
|
|
$222,283
|
|
|
|
$21,858
|
|
|
|
$51,177
|
|
|
|
$32,534
|
|
|
|
$11,725
|
|
Basic income from continuing operations per common share
|
|
|
$4.90
|
|
|
|
$0.54
|
|
|
|
$1.29
|
|
|
|
$0.83
|
|
|
|
$0.34
|
|
Diluted income from continuing operations per common share
|
|
|
$4.81
|
|
|
|
$0.53
|
|
|
|
$1.28
|
|
|
|
$0.82
|
|
|
|
$0.34
|
|
Basic weighted average common shares outstanding
|
|
45,372
|
|
|
40,781
|
|
|
39,591
|
|
|
39,077
|
|
|
33,861
|
|
|||||
Diluted weighted average common shares outstanding
|
|
46,194
|
|
|
41,355
|
|
|
40,026
|
|
|
39,668
|
|
|
34,305
|
|
|||||
Statements of Cash Flows from Continuing Operations Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities from continuing operations
|
|
|
$502,275
|
|
|
|
$367,474
|
|
|
|
$253,071
|
|
|
|
$155,511
|
|
|
|
$94,416
|
|
Net cash used in investing activities from continuing operations
|
|
(940,676
|
)
|
|
(509,885
|
)
|
|
(465,151
|
)
|
|
(250,068
|
)
|
|
(264,115
|
)
|
|||||
Net cash provided by financing activities from continuing operations
|
|
300,290
|
|
|
120,326
|
|
|
237,778
|
|
|
116,826
|
|
|
169,990
|
|
|||||
Other Cash Flows from Continuing Operations Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures - oil and gas properties
|
|
|
($860,604
|
)
|
|
|
($786,976
|
)
|
|
|
($735,711
|
)
|
|
|
($516,004
|
)
|
|
|
($340,784
|
)
|
Proceeds from sales of oil and gas properties, net
|
|
12,576
|
|
|
238,470
|
|
|
341,597
|
|
|
167,265
|
|
|
54,217
|
|
|||||
Proceeds from borrowing and issuances (repayments of debt), net (1)
|
|
301,500
|
|
|
(69,325
|
)
|
|
244,772
|
|
|
126,401
|
|
|
(7,021
|
)
|
|||||
Proceeds from common stock offerings, net of offering costs
|
|
—
|
|
|
189,686
|
|
|
—
|
|
|
—
|
|
|
188,534
|
|
|||||
Balance Sheets from Continuing Operations Data:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Working deficit
|
|
|
($141,278
|
)
|
|
|
($32,138
|
)
|
|
|
($43,432
|
)
|
|
|
($150,559
|
)
|
|
|
($58,672
|
)
|
Total property and equipment, net
|
|
2,629,253
|
|
|
1,794,215
|
|
|
1,487,674
|
|
|
1,240,917
|
|
|
960,393
|
|
|||||
Total assets
|
|
2,981,476
|
|
|
2,110,760
|
|
|
1,749,488
|
|
|
1,445,075
|
|
|
1,121,470
|
|
|||||
Long-term debt
|
|
1,351,346
|
|
|
900,247
|
|
|
967,808
|
|
|
711,486
|
|
|
558,254
|
|
|||||
Total shareholders’ equity
|
|
1,103,441
|
|
|
841,604
|
|
|
585,016
|
|
|
509,855
|
|
|
456,636
|
|
|
(1)
|
Repayments include amounts refinanced.
|
|
|
For the Year Ended December 31, 2014
|
|
As of December 31, 2014
|
|||||||||||||||||||||||
|
|
Drilled
|
|
Wells Brought
on Production
|
|
Waiting on Completion
|
|
Producing
|
|
Rig Count
|
|||||||||||||||||
Region
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
||||||||||
Eagle Ford
|
|
69
|
|
|
58.0
|
|
|
73
|
|
|
58.7
|
|
|
25
|
|
|
22.5
|
|
|
193
|
|
|
170.9
|
|
|
3
|
|
Niobrara
|
|
32
|
|
|
13.0
|
|
|
38
|
|
|
15.1
|
|
|
7
|
|
|
3.7
|
|
|
112
|
|
|
47.7
|
|
|
1
|
|
Marcellus
|
|
3
|
|
|
1.2
|
|
|
19
|
|
|
5.1
|
|
|
11
|
|
|
4.3
|
|
|
82
|
|
|
26.3
|
|
|
—
|
|
Utica
|
|
3
|
|
|
2.2
|
|
|
2
|
|
|
1.4
|
|
|
2
|
|
|
1.7
|
|
|
1
|
|
|
0.9
|
|
|
1
|
|
Other
|
|
1
|
|
|
1.0
|
|
|
1
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
108
|
|
|
75.4
|
|
|
133
|
|
|
81.3
|
|
|
45
|
|
|
32.2
|
|
|
388
|
|
|
245.8
|
|
|
5
|
|
|
|
Year Ended
December 31,
|
|
2014 Period
Compared to 2013 Period
|
|||||||||||
|
|
2014
|
|
2013
|
|
Increase(Decrease)
|
|
% Increase(Decrease)
|
|||||||
Total production volumes -
|
|
|
|
|
|
|
|
|
|||||||
Crude oil (MBbls)
|
|
6,906
|
|
|
4,231
|
|
|
2,675
|
|
|
63
|
%
|
|||
NGLs (MBbls)
|
|
926
|
|
|
531
|
|
|
395
|
|
|
74
|
%
|
|||
Natural gas (MMcf)
|
|
24,877
|
|
|
31,422
|
|
|
(6,545
|
)
|
|
(21
|
%)
|
|||
Total Natural gas and NGLs (MMcfe)
|
|
30,433
|
|
|
34,608
|
|
|
(4,175
|
)
|
|
(12
|
%)
|
|||
Total barrels of oil equivalent (MBoe)
|
|
11,978
|
|
|
9,999
|
|
|
1,979
|
|
|
20
|
%
|
|||
|
|
|
|
|
|
|
|
|
|||||||
Daily production volumes by product -
|
|
|
|
|
|
|
|
|
|||||||
Crude oil (Bbls/d)
|
|
18,921
|
|
|
11,592
|
|
|
7,329
|
|
|
63
|
%
|
|||
NGLs (Bbls/d)
|
|
2,537
|
|
|
1,455
|
|
|
1,082
|
|
|
74
|
%
|
|||
Natural gas (Mcf/d)
|
|
68,156
|
|
|
86,088
|
|
|
(17,932
|
)
|
|
(21
|
%)
|
|||
Total Natural gas and NGLs (Mcfe/d)
|
|
83,378
|
|
|
94,816
|
|
|
(11,438
|
)
|
|
(12
|
%)
|
|||
Total barrels of oil equivalent (Boe/d)
|
|
32,816
|
|
|
27,395
|
|
|
5,421
|
|
|
20
|
%
|
|||
|
|
|
|
|
|
|
|
|
|||||||
Daily production volumes by region (Boe/d) -
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
|
|
21,131
|
|
|
12,628
|
|
|
8,503
|
|
|
67
|
%
|
|||
Niobrara
|
|
2,585
|
|
|
1,724
|
|
|
861
|
|
|
50
|
%
|
|||
Barnett
|
|
—
|
|
|
6,625
|
|
|
(6,625
|
)
|
|
(100
|
%)
|
|||
Marcellus
|
|
8,354
|
|
|
6,139
|
|
|
2,215
|
|
|
36
|
%
|
|||
Utica and other
|
|
746
|
|
|
279
|
|
|
467
|
|
|
167
|
%
|
|||
Total barrels of oil equivalent (Boe/d)
|
|
32,816
|
|
|
27,395
|
|
|
5,421
|
|
|
20
|
%
|
|||
|
|
|
|
|
|
|
|
|
|||||||
Average realized prices -
|
|
|
|
|
|
|
|
|
|||||||
Crude oil ($ per Bbl)
|
|
|
$88.40
|
|
|
|
$99.58
|
|
|
|
($11.18
|
)
|
|
(11
|
%)
|
NGLs ($ per Bbl)
|
|
27.05
|
|
|
29.25
|
|
|
(2.20
|
)
|
|
(8
|
%)
|
|||
Natural gas ($ per Mcf)
|
|
3.00
|
|
|
2.65
|
|
|
0.35
|
|
|
13
|
%
|
|||
Total Natural gas and NGLs ($ per Mcfe)
|
|
|
$3.28
|
|
|
|
$2.86
|
|
|
|
$0.42
|
|
|
15
|
%
|
Total average realized price ($ per Boe)
|
|
|
$59.29
|
|
|
|
$52.02
|
|
|
|
$7.27
|
|
|
14
|
%
|
|
|
|
|
|
|
|
|
|
|||||||
Revenues (In thousands) -
|
|
|
|
|
|
|
|
|
|||||||
Crude oil
|
|
|
$610,483
|
|
|
|
$421,311
|
|
|
|
$189,172
|
|
|
45
|
%
|
NGLs
|
|
25,050
|
|
|
15,530
|
|
|
9,520
|
|
|
61
|
%
|
|||
Natural gas
|
|
74,654
|
|
|
83,341
|
|
|
(8,687
|
)
|
|
(10
|
%)
|
|||
Total revenues
|
|
|
$710,187
|
|
|
|
$520,182
|
|
|
|
$190,005
|
|
|
37
|
%
|
|
|
Year Ended
December 31, |
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In thousands)
|
||||||
DD&A of proved oil and gas properties
|
|
|
$313,799
|
|
|
|
$211,157
|
|
Depreciation of other property and equipment
|
|
1,722
|
|
|
1,693
|
|
||
Amortization of other assets
|
|
1,152
|
|
|
970
|
|
||
Accretion of asset retirement obligations
|
|
710
|
|
|
471
|
|
||
Total DD&A
|
|
|
$317,383
|
|
|
|
$214,291
|
|
|
|
Year Ended
December 31, |
|
2013 Period
Compared to 2012 Period
|
|||||||||||
|
|
2013
|
|
2012
|
|
Increase(Decrease)
|
|
% Increase(Decrease)
|
|||||||
Total production volumes -
|
|
|
|
|
|
|
|
|
|||||||
Crude oil (MBbls)
|
|
4,231
|
|
|
2,862
|
|
|
1,369
|
|
|
48
|
%
|
|||
NGLs (MBbls)
|
|
531
|
|
|
305
|
|
|
226
|
|
|
74
|
%
|
|||
Natural gas (MMcf)
|
|
31,422
|
|
|
37,612
|
|
|
(6,190
|
)
|
|
(16
|
%)
|
|||
Total Natural gas and NGLs (MMcfe)
|
|
34,608
|
|
|
39,442
|
|
|
(4,834
|
)
|
|
(12
|
%)
|
|||
Total barrels of oil equivalent (MBoe)
|
|
9,999
|
|
|
9,436
|
|
|
563
|
|
|
6
|
%
|
|||
|
|
|
|
|
|
|
|
|
|||||||
Daily production volumes by product -
|
|
|
|
|
|
|
|
|
|||||||
Crude oil (Bbls/d)
|
|
11,592
|
|
|
7,820
|
|
|
3,772
|
|
|
48
|
%
|
|||
NGLs (Bbls/d)
|
|
1,455
|
|
|
833
|
|
|
622
|
|
|
75
|
%
|
|||
Natural gas (Mcf/d)
|
|
86,088
|
|
|
102,765
|
|
|
(16,677
|
)
|
|
(16
|
%)
|
|||
Total Natural gas and NGLs (Mcfe/d)
|
|
94,816
|
|
|
107,765
|
|
|
(12,949
|
)
|
|
(12
|
%)
|
|||
Total barrels of oil equivalent (Boe/d)
|
|
27,395
|
|
|
25,781
|
|
|
1,614
|
|
|
6
|
%
|
|||
|
|
|
|
|
|
|
|
|
|||||||
Daily production volumes by region (Boe/d) -
|
|
|
|
|
|
|
|
|
|||||||
Eagle Ford
|
|
12,628
|
|
|
7,950
|
|
|
4,678
|
|
|
59
|
%
|
|||
Niobrara
|
|
1,724
|
|
|
1,259
|
|
|
465
|
|
|
37
|
%
|
|||
Barnett
|
|
6,625
|
|
|
11,614
|
|
|
(4,989
|
)
|
|
(43
|
%)
|
|||
Marcellus
|
|
6,139
|
|
|
3,608
|
|
|
2,531
|
|
|
70
|
%
|
|||
Utica and other
|
|
279
|
|
|
1,350
|
|
|
(1,071
|
)
|
|
(79
|
%)
|
|||
Total barrels of oil equivalent (Boe/d)
|
|
27,395
|
|
|
25,781
|
|
|
1,614
|
|
|
6
|
%
|
|||
|
|
|
|
|
|
|
|
|
|||||||
Average realized prices -
|
|
|
|
|
|
|
|
|
|||||||
Crude oil ($ per Bbl)
|
|
|
$99.58
|
|
|
|
$99.97
|
|
|
|
($0.39
|
)
|
|
—
|
%
|
NGLs ($ per Bbl)
|
|
29.25
|
|
|
34.86
|
|
|
(5.61
|
)
|
|
(16
|
%)
|
|||
Natural gas ($ per Mcf)
|
|
2.65
|
|
|
1.90
|
|
|
0.75
|
|
|
39
|
%
|
|||
Total Natural gas and NGLs ($ per Mcfe)
|
|
|
$2.86
|
|
|
|
$2.08
|
|
|
|
$0.78
|
|
|
38
|
%
|
Total average realized price ($ per Boe)
|
|
|
$52.02
|
|
|
|
$39.02
|
|
|
|
$13.00
|
|
|
33
|
%
|
|
|
|
|
|
|
|
|
|
|||||||
Revenues (In thousands) -
|
|
|
|
|
|
|
|
|
|||||||
Crude oil
|
|
|
$421,311
|
|
|
|
$286,119
|
|
|
|
$135,192
|
|
|
47
|
%
|
NGLs
|
|
15,530
|
|
|
10,631
|
|
|
4,899
|
|
|
46
|
%
|
|||
Natural gas
|
|
83,341
|
|
|
71,430
|
|
|
11,911
|
|
|
17
|
%
|
|||
Total revenues
|
|
|
$520,182
|
|
|
|
$368,180
|
|
|
|
$152,002
|
|
|
41
|
%
|
|
|
Year Ended
December 31, |
||||||
|
|
2013
|
|
2012
|
||||
|
|
(In thousands)
|
||||||
DD&A of proved oil and gas properties
|
|
|
$211,157
|
|
|
|
$163,542
|
|
Depreciation of other property and equipment
|
|
1,693
|
|
|
1,543
|
|
||
Amortization of other assets
|
|
970
|
|
|
536
|
|
||
Accretion of asset retirement obligations
|
|
471
|
|
|
372
|
|
||
Total DD&A
|
|
|
$214,291
|
|
|
|
$165,993
|
|
•
|
Cash provided by operations.
Cash flows from operations are highly dependent on commodity prices. As such, we hedge a portion of our forecasted production to mitigate the risk of a decline in oil and gas prices.
|
•
|
Borrowings under our revolving credit facility
. At
February 20, 2015
, we had
$210.0 million
of borrowings outstanding and
$0.6
million in letters of credit outstanding under our revolving credit facility, which reduce the amounts available under our revolving credit facility. The amount we are able to borrow is subject to compliance with the financial covenants and other provisions of the credit agreement governing our revolving credit facility.
|
•
|
Asset sales
. In order to fund our capital expenditure plan, we may consider the sale of certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to sell such assets on terms that are acceptable to us.
|
•
|
Securities offerings
. In October 2014, we issued $300.0 million aggregate principal amount of 7.50% Senior Notes due 2020 in a private placement for net proceeds of $299.8 million. As situations or conditions arise, we may choose to issue debt, equity or other instruments to supplement our cash flows. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all.
|
•
|
Joint ventures
. Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage or purchase a portion of interests, or both.
|
•
|
Other sources
. We may consider sale/leaseback transactions of certain capital assets, such as our remaining pipelines and compressors, which are not part of our core oil and gas exploration and production business.
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020 and Thereafter
|
|
Total
|
||||||||||||||
Debt (1)
|
|
$150,000
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$600,000
|
|
|
|
$—
|
|
|
|
$604,425
|
|
|
|
$1,354,425
|
|
Interest on debt (2)
|
96,944
|
|
|
96,944
|
|
|
96,944
|
|
|
96,944
|
|
|
45,194
|
|
|
46,627
|
|
|
479,597
|
|
|||||||
Operating leases
|
3,795
|
|
|
3,773
|
|
|
3,902
|
|
|
3,975
|
|
|
4,103
|
|
|
10,139
|
|
|
29,687
|
|
|||||||
Drilling and completion services (3)
|
44,155
|
|
|
27,923
|
|
|
20,057
|
|
|
4,702
|
|
|
—
|
|
|
—
|
|
|
96,837
|
|
|||||||
Pipeline volume commitments
|
7,485
|
|
|
4,324
|
|
|
2,465
|
|
|
2,464
|
|
|
2,390
|
|
|
6,795
|
|
|
25,923
|
|
|||||||
Asset retirement obligations and other (4)
|
4,730
|
|
|
5,369
|
|
|
2,649
|
|
|
385
|
|
|
23
|
|
|
12,156
|
|
|
25,312
|
|
|||||||
Total Contractual Obligations
|
|
$307,109
|
|
|
|
$138,333
|
|
|
|
$126,017
|
|
|
|
$708,470
|
|
|
|
$51,710
|
|
|
|
$680,142
|
|
|
|
$2,011,781
|
|
|
(1)
|
Debt consists of the principal amounts of the 8.625% Senior Notes due 2018, the 7.50% Senior Notes due 2020, other long-term debt due 2028 and the deferred purchase payment due EFM on or before February 16, 2015.
|
(2)
|
Interest on debt includes cash payments for interest on the 8.625% Senior Notes due 2018, the 7.50% Senior Notes due 2020 and other long-term debt due 2028. There were no borrowings outstanding under our revolving credit facility as of December 31, 2014, therefore no interest was computed for our revolving credit facility as it relates to the table above.
|
(3)
|
Drilling and completion services represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs.
|
(4)
|
Asset retirement obligations and other are based on estimates and assumptions that affect the reported amounts as of December 31, 2014. Certain of such estimates and assumptions are inherently unpredictable and will differ from actuals results. See “Note
2.
Summary of Significant Accounting Policies-Use of Estimates” for further discussion of estimates and assumptions that may affect the reported amounts.
|
(5)
|
This table does not include deferred income tax liabilities or share-based payments classified as liabilities, as we cannot reasonably determine the timing of such payments.
|
Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments
|
|
Applicable Margin for Base Rate Loans
|
|
Applicable Margin for Eurodollar Loans
|
|
Commitment Fee
|
Less than 25%
|
|
0.50%
|
|
1.50%
|
|
0.375%
|
Greater than or equal to 25% but less than 50%
|
|
0.75%
|
|
1.75%
|
|
0.375%
|
Greater than or equal to 50% but less than 75%
|
|
1.00%
|
|
2.00%
|
|
0.500%
|
Greater than or equal to 75% but less than 90%
|
|
1.25%
|
|
2.25%
|
|
0.500%
|
Greater than or equal to 90%
|
|
1.50%
|
|
2.50%
|
|
0.500%
|
|
|
12 Month Average Realized Prices
|
|
Excess of cost center ceiling over net capitalized costs
|
|
Increase/(Decrease)
in excess of cost center ceiling over net capitalized costs
|
||
Full Cost Pool Scenarios
|
|
Crude Oil ($/Bbl)
|
|
Natural Gas ($/Mcf)
|
|
(In millions)
|
|
(In millions)
|
December 31, 2014 Actual
|
|
$92.24
|
|
$3.24
|
|
$747
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Price Sensitivity
|
|
|
|
|
|
|
|
|
Oil and Gas +10%
|
|
$101.72
|
|
$3.68
|
|
$1,103
|
|
$356
|
Oil and Gas -10%
|
|
$82.74
|
|
$2.80
|
|
$391
|
|
($356)
|
|
|
|
|
|
|
|
|
|
Oil Price Sensitivity
|
|
|
|
|
|
|
|
|
Oil +10%
|
|
$101.72
|
|
$3.24
|
|
$1,073
|
|
$326
|
Oil -10%
|
|
$82.74
|
|
$3.24
|
|
$421
|
|
($326)
|
|
|
|
|
|
|
|
|
|
Gas Price Sensitivity
|
|
|
|
|
|
|
|
|
Gas +10%
|
|
$92.24
|
|
$3.68
|
|
$778
|
|
$31
|
Gas -10%
|
|
$92.24
|
|
$2.80
|
|
$716
|
|
($31)
|
Counterparty
|
|
December 31, 2014
|
|
December 31, 2013
|
||
Wells Fargo
|
|
37
|
%
|
|
23
|
%
|
Societe Generale
|
|
26
|
%
|
|
31
|
%
|
Credit Suisse
|
|
24
|
%
|
|
46
|
%
|
Regions
|
|
8
|
%
|
|
—
|
%
|
Union Bank
|
|
4
|
%
|
|
—
|
%
|
Royal Bank of Canada
|
|
1
|
%
|
|
—
|
%
|
Total
|
|
100
|
%
|
|
100
|
%
|
Period
|
|
Type of Contract
|
|
Volumes
(in Bbls/d)
|
|
Weighted
Average
Floor Price
($/Bbl)
|
|
Weighted
Average
Ceiling Price
($/Bbl)
|
|
Weighted
Average
Short Put Price
($/Bbl)
|
|
Weighted
Average
Put Spread
($/Bbl)
|
|||||||||
January - December 2015
|
|
Fixed Price Swaps
|
|
10,370
|
|
|
|
$92.97
|
|
|
|
|
|
|
|
||||||
|
|
Costless Collars
|
|
700
|
|
|
|
$90.00
|
|
|
|
$100.65
|
|
|
|
|
|
||||
|
|
Three-way Collars
|
|
1,000
|
|
|
|
$85.00
|
|
|
|
$105.00
|
|
|
|
$65.00
|
|
|
|
$20.00
|
|
January - December 2016
|
|
Fixed Price Swaps
|
|
3,000
|
|
|
|
$91.09
|
|
|
|
|
|
|
|
||||||
|
|
Three-way Collars
|
|
667
|
|
|
|
$85.00
|
|
|
|
$104.00
|
|
|
|
$65.00
|
|
|
|
$20.00
|
|
Period
|
|
Type of Contract
|
|
Volumes
(in MMBtu/d)
|
|
Weighted
Average
Floor Price
($/MMBtu)
|
||
January - December 2015
|
|
Fixed Price Swaps
|
|
30,000
|
|
|
$4.29
|
|
•
|
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets;
|
•
|
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
|
•
|
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.
|
Exhibit
Number
|
|
Description
|
†2.1
|
—
|
Asset Purchase Agreement dated October 24, 2014 by and between Eagle Ford Minerals, LLC and Carrizo (Eagle Ford) LLC (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on October 27, 2014 (File No. 000-29187-87)).
|
†3.1
|
—
|
Amended and Restated Articles of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-29187-87)).
|
†3.2
|
—
|
Articles of Amendment to Amended and Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 25, 2008 (File No. 000-29187-87)).
|
†3.3
|
—
|
Amended and Restated Bylaws of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 19, 2015 (File No. 000-29187-87)).
|
†4.1
|
—
|
Indenture among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee, dated May 28, 2008 (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 28, 2008 (File No. 000-29187-87)).
|
†4.2
|
—
|
First Supplemental Indenture dated May 28, 2008 between Carrizo Oil & Gas, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on May 28, 2008 (File No. 000-29187-87)).
|
†4.3
|
—
|
Second Supplemental Indenture dated May 14, 2009 among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.21 to the Company’s Registration Statement on Form S-3 (Registration No. 333-159237)).
|
†4.4
|
—
|
Fourth Supplemental Indenture dated November 2, 2010 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on November 2, 2010 (File No. 000-29187-87)).
|
†4.5
|
—
|
Fifth Supplemental Indenture dated November 2, 2010 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on November 2, 2010 (File No. 000-29187-87)).
|
†4.6
|
—
|
Sixth Supplemental Indenture dated May 4, 2011 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 000-29187-87)).
|
†4.7
|
—
|
Seventh Supplemental Indenture dated May 4, 2011 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 000-29187-87)).
|
†4.8
|
—
|
Eighth Supplemental Indenture dated August 5, 2011 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 000-29187-87)).
|
†4.9
|
—
|
Ninth Supplemental Indenture dated August 5, 2011 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 000-29187-87)).
|
†4.10
|
—
|
Tenth Supplemental Indenture among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee, dated as of September 10, 2012 (incorporated herein by reference to Exhibit 4.2 to the Company Current Report on Form 8-K filed on September 13, 2012 (File No. 000-29187-87)).
|
†4.11
|
—
|
Eleventh Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
|
†4.12
|
—
|
Twelfth Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
|
†4.13
|
—
|
Thirteenth Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
|
†4.14
|
—
|
Fourteenth Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
|
†4.15
|
—
|
Fifteenth Supplemental Indenture dated November 6, 2014 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on November 17, 2011 (File No. 000-29187-87)).
|
†4.16
|
—
|
Officers’ Certificate of the Company dated as of November 17, 2011 (incorporated herein by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed on November 17, 2011 (File No. 000-29187-87)).
|
4.17
|
—
|
Officers’ Certificate of the Company dated as of February 23, 2015.
|
†4.18
|
—
|
Form of Warrant issued pursuant to Land Agreement dated November 24, 2009 (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 000-29187-87)).
|
†4.19
|
—
|
Registration Rights Agreement, dated October 30, 2014, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Securities, LLC, RBC Capital Markets, LLC and Citigroup Global Markets, Inc., as representatives of the several Initial Purchasers (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 30, 2014 (File No. 000-29187-87)).
|
*†10.1
|
—
|
Amended and Restated Incentive Plan of the Company effective as of May 15, 2014 (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 16, 2014 (File No. 000-29187-87)).
|
*†10.2
|
—
|
Amended and Restated Employment Agreement between the Company and S.P. Johnson IV (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 9, 2009 (File No. 000-29187-87)).
|
*†10.3
|
—
|
Amended and Restated Employment Agreement between the Company and Paul F. Boling (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on June 9, 2009 (File No. 000-29187-87)).
|
*†10.4
|
—
|
Retirement and Consulting Agreement effective as of August 11, 2014 by and between Carrizo Oil & Gas, Inc. and Paul F. Boling (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly report on Form 10-Q for the quarter ended September 30, 2014 (File No. 000-29187-87)).
|
*†10.5
|
—
|
Amended and Restated Employment Agreement between the Company and J. Bradley Fisher (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on June 9, 2009 (File No. 000-29187-87)).
|
†10.24
|
—
|
Credit Agreement dated as of January 27, 2011 among Carrizo Oil & Gas, Inc., as Borrower, BNP Paribas, as Administrative Agent, Credit Agricole Corporate and Investment Bank and Royal Bank of Canada, as Co-Syndication Agents, Capital One, N.A. and Compass Bank, as Co-Documentation Agents, BNP Paribas Securities Corp. as Sole Lead Arranger and Sole Bookrunner, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 2, 2011 (File No. 000-29187-87)).
|
†10.25
|
—
|
First Amendment, dated as of March 26, 2012, to Credit Agreement dated as of January 27, 2011, among Carrizo Oil & Gas, Inc., BNP Paribas as administrative agent, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 (File No. 000-29187-87)).
|
†10.26
|
—
|
Second Amendment to Credit Agreement, dated as of September 4, 2012, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 5, 2012 (File No. 000-29187-87)).
|
†10.27
|
—
|
Third Amendment to Credit Agreement, dated as of September 27, 2012, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 (File No. 000-29187-87)).
|
†10.28
|
—
|
Fourth Amendment to Credit Agreement, dated as of October 9, 2013, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 11, 2013 (File No. 000-29187-87)).
|
†10.29
|
—
|
Fifth Amendment to Credit Agreement, dated as of October 7, 2014, among Carrizo Oil & Gas, Inc., as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 9, 2014 (File No. 000-29187-87)).
|
†10.30
|
—
|
Form of Indemnification Agreement between the Company and each of its directors and executive officers (incorporated herein by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 000-29187-87)).
|
†10.31
|
—
|
Form of Amendment to Director Indemnification Agreement (incorporated herein by reference to Exhibit 99.8 to the Company’s Current Report a Form 8-K filed February 27, 2002 (File No. 000-29187-87)).
|
†10.32
|
—
|
Omnibus Amendment among Carrizo (Marcellus) LLC, Carrizo Oil & Gas, Inc., Avista Capital Partners II, L.P. and ACP II Marcellus LLC, dated as of September 10, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on September 16, 2010 (File No. 000-29187-87)).
|
†10.33
|
—
|
Amended and Restated Participation Agreement, dated as of November 16, 2010, and effective as of October 1, 2010, among Carrizo (Marcellus) WV LLC, Carrizo Oil & Gas, Inc., Avista Capital Partners II, L.P. and ACP II Marcellus LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 19, 2010 (File No. 000-29187-87)).
|
21.1
|
—
|
Subsidiaries of the Company.
|
23.1
|
—
|
Consent of KPMG LLP.
|
23.2
|
—
|
Consent of Ryder Scott Company, L.P.
|
31.1
|
—
|
CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
31.2
|
—
|
CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
32.1
|
—
|
CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
32.2
|
—
|
CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
99.1
|
—
|
Summary of Reserve Report and Report of Ryder Scott Company, L.P. as of December 31, 2014.
|
|
|
PAGE
|
Reports of Independent Registered Public Accounting Firm
|
|
Consolidated Balance Sheets, December 31, 2014 and 2013
|
|
Consolidated Statements of Income for the Years Ended December 31, 2014, 2013 and 2012
|
|
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012
|
|
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
|
|
Notes to Consolidated Financial Statements
|
|
|
December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
Assets
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
|
$10,838
|
|
|
|
$157,439
|
|
Accounts receivable, net
|
|
92,946
|
|
|
111,195
|
|
||
Derivative assets
|
|
171,101
|
|
|
—
|
|
||
Deferred income taxes
|
|
—
|
|
|
4,201
|
|
||
Other current assets
|
|
3,736
|
|
|
6,926
|
|
||
Total current assets
|
|
278,621
|
|
|
279,761
|
|
||
Property and equipment
|
|
|
|
|
||||
Oil and gas properties, full cost method
|
|
|
|
|
||||
Proved properties, net
|
|
2,086,727
|
|
|
1,408,484
|
|
||
Unproved properties, not being amortized
|
|
535,197
|
|
|
377,437
|
|
||
Other property and equipment, net
|
|
7,329
|
|
|
8,294
|
|
||
Total property and equipment, net
|
|
2,629,253
|
|
|
1,794,215
|
|
||
Derivative assets
|
|
43,684
|
|
|
9,284
|
|
||
Debt issuance costs
|
|
25,403
|
|
|
22,899
|
|
||
Other assets
|
|
4,515
|
|
|
4,601
|
|
||
Total Assets
|
|
|
$2,981,476
|
|
|
|
$2,110,760
|
|
|
|
|
|
|
||||
Liabilities and Shareholders’ Equity
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts payable
|
|
|
$106,819
|
|
|
|
$57,146
|
|
Revenues and royalties payable
|
|
66,954
|
|
|
79,136
|
|
||
Accrued capital expenditures
|
|
106,149
|
|
|
87,031
|
|
||
Accrued interest
|
|
21,149
|
|
|
17,430
|
|
||
Advances for joint operations
|
|
8,814
|
|
|
19,967
|
|
||
Liabilities of discontinued operations
|
|
4,405
|
|
|
10,936
|
|
||
Deferred income taxes
|
|
61,258
|
|
|
—
|
|
||
Other current liabilities
|
|
48,756
|
|
|
51,189
|
|
||
Total current liabilities
|
|
424,304
|
|
|
322,835
|
|
||
Long-term debt
|
|
1,351,346
|
|
|
900,247
|
|
||
Liabilities of discontinued operations
|
|
8,394
|
|
|
17,336
|
|
||
Deferred income taxes
|
|
77,349
|
|
|
16,856
|
|
||
Asset retirement obligations
|
|
12,187
|
|
|
6,576
|
|
||
Other liabilities
|
|
4,455
|
|
|
5,306
|
|
||
Total liabilities
|
|
1,878,035
|
|
|
1,269,156
|
|
||
Commitments and contingencies
|
|
|
|
|
|
|
||
Shareholders’ equity
|
|
|
|
|
||||
Common stock, $0.01 par value, 90,000,000 shares authorized; 46,127,924 issued and outstanding as of December 31, 2014 and 45,468,675 issued and outstanding as of December 31, 2013
|
|
461
|
|
|
455
|
|
||
Additional paid-in capital
|
|
915,436
|
|
|
879,948
|
|
||
Retained earnings (Accumulated deficit)
|
|
187,544
|
|
|
(38,799
|
)
|
||
Total shareholders’ equity
|
|
1,103,441
|
|
|
841,604
|
|
||
Total Liabilities and Shareholders’ Equity
|
|
|
$2,981,476
|
|
|
|
$2,110,760
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
Revenues
|
|
|
|
|
|
|
||||||
Crude oil
|
|
|
$610,483
|
|
|
|
$421,311
|
|
|
|
$286,119
|
|
Natural gas liquids
|
|
25,050
|
|
|
15,530
|
|
|
10,631
|
|
|||
Natural gas
|
|
74,654
|
|
|
83,341
|
|
|
71,430
|
|
|||
Total revenues
|
|
710,187
|
|
|
520,182
|
|
|
368,180
|
|
|||
|
|
|
|
|
|
|
||||||
Costs and Expenses
|
|
|
|
|
|
|
||||||
Lease operating
|
|
74,157
|
|
|
46,828
|
|
|
31,471
|
|
|||
Production taxes
|
|
29,544
|
|
|
19,811
|
|
|
13,542
|
|
|||
Ad valorem taxes
|
|
8,450
|
|
|
8,701
|
|
|
9,813
|
|
|||
Depreciation, depletion and amortization
|
|
317,383
|
|
|
214,291
|
|
|
165,993
|
|
|||
General and administrative
|
|
77,029
|
|
|
77,492
|
|
|
48,708
|
|
|||
(Gain) loss on derivatives, net
|
|
(201,907
|
)
|
|
18,417
|
|
|
(31,371
|
)
|
|||
Interest expense, net
|
|
53,171
|
|
|
54,689
|
|
|
48,158
|
|
|||
Loss on sale of oil and gas properties
|
|
—
|
|
|
45,377
|
|
|
—
|
|
|||
Other (income) expense, net
|
|
2,150
|
|
|
(185
|
)
|
|
(267
|
)
|
|||
Total costs and expenses
|
|
359,977
|
|
|
485,421
|
|
|
286,047
|
|
|||
|
|
|
|
|
|
|
||||||
Income From Continuing Operations Before Income Taxes
|
|
350,210
|
|
|
34,761
|
|
|
82,133
|
|
|||
Income tax expense
|
|
(127,927
|
)
|
|
(12,903
|
)
|
|
(30,956
|
)
|
|||
Income From Continuing Operations
|
|
|
$222,283
|
|
|
|
$21,858
|
|
|
|
$51,177
|
|
Income From Discontinued Operations, Net of Income Taxes
|
|
4,060
|
|
|
21,825
|
|
|
4,310
|
|
|||
Net Income
|
|
|
$226,343
|
|
|
|
$43,683
|
|
|
|
$55,487
|
|
|
|
|
|
|
|
|
||||||
Net Income Per Common Share - Basic
|
|
|
|
|
|
|
||||||
Income from continuing operations
|
|
|
$4.90
|
|
|
|
$0.54
|
|
|
|
$1.29
|
|
Income from discontinued operations, net of income taxes
|
|
0.09
|
|
|
0.53
|
|
|
0.11
|
|
|||
Net income
|
|
|
$4.99
|
|
|
|
$1.07
|
|
|
|
$1.40
|
|
|
|
|
|
|
|
|
||||||
Net Income Per Common Share - Diluted
|
|
|
|
|
|
|
||||||
Income from continuing operations
|
|
|
$4.81
|
|
|
|
$0.53
|
|
|
|
$1.28
|
|
Income from discontinued operations, net of income taxes
|
|
0.09
|
|
|
0.53
|
|
|
0.11
|
|
|||
Net income
|
|
|
$4.90
|
|
|
|
$1.06
|
|
|
|
$1.39
|
|
|
|
|
|
|
|
|
||||||
Weighted Average Common Shares Outstanding
|
|
|
|
|
|
|
||||||
Basic
|
|
45,372
|
|
|
40,781
|
|
|
39,591
|
|
|||
Diluted
|
|
46,194
|
|
|
41,355
|
|
|
40,026
|
|
|
|
Common Stock
|
|
Additional
Paid-in Capital |
|
Retained Earnings
(Accumulated Deficit) |
|
Total
Shareholders’ Equity |
|||||||||||
|
|
Shares
|
|
Amount
|
|
|
|
||||||||||||
Balance as of January 1, 2012
|
|
39,562,676
|
|
|
|
$395
|
|
|
|
$647,429
|
|
|
|
($137,969
|
)
|
|
|
$509,855
|
|
Stock options exercised for cash
|
|
20,500
|
|
|
1
|
|
|
106
|
|
|
—
|
|
|
107
|
|
||||
Stock-based compensation
|
|
—
|
|
|
—
|
|
|
17,396
|
|
|
—
|
|
|
17,396
|
|
||||
Common stock activity, net of forfeitures
|
|
488,052
|
|
|
5
|
|
|
(85
|
)
|
|
—
|
|
|
(80
|
)
|
||||
Other
|
|
93,289
|
|
|
1
|
|
|
2,250
|
|
|
—
|
|
|
2,251
|
|
||||
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
55,487
|
|
|
55,487
|
|
||||
Balance as of December 31, 2012
|
|
40,164,517
|
|
|
|
$402
|
|
|
|
$667,096
|
|
|
|
($82,482
|
)
|
|
|
$585,016
|
|
Stock options exercised for cash
|
|
206,501
|
|
|
2
|
|
|
1,251
|
|
|
—
|
|
|
1,253
|
|
||||
Stock-based compensation
|
|
—
|
|
|
—
|
|
|
19,531
|
|
|
—
|
|
|
19,531
|
|
||||
Common stock activity, net of forfeitures
|
|
552,831
|
|
|
6
|
|
|
(539
|
)
|
|
—
|
|
|
(533
|
)
|
||||
Sale of common stock, net of offering costs
|
|
4,500,000
|
|
|
45
|
|
|
189,641
|
|
|
—
|
|
|
189,686
|
|
||||
Other
|
|
44,826
|
|
|
—
|
|
|
2,968
|
|
|
—
|
|
|
2,968
|
|
||||
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43,683
|
|
|
43,683
|
|
||||
Balance as of December 31, 2013
|
|
45,468,675
|
|
|
|
$455
|
|
|
|
$879,948
|
|
|
|
($38,799
|
)
|
|
|
$841,604
|
|
Stock options exercised for cash
|
|
33,086
|
|
|
1
|
|
|
436
|
|
|
—
|
|
|
437
|
|
||||
Stock-based compensation
|
|
—
|
|
|
—
|
|
|
30,280
|
|
|
—
|
|
|
30,280
|
|
||||
Common stock activity, net of forfeitures
|
|
625,301
|
|
|
5
|
|
|
(96
|
)
|
|
—
|
|
|
(91
|
)
|
||||
Other
|
|
862
|
|
|
—
|
|
|
4,868
|
|
|
—
|
|
|
4,868
|
|
||||
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
226,343
|
|
|
226,343
|
|
||||
Balance as of December 31, 2014
|
|
46,127,924
|
|
|
|
$461
|
|
|
|
$915,436
|
|
|
|
$187,544
|
|
|
|
$1,103,441
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
Cash Flows From Operating Activities
|
|
|
|
|
|
|
||||||
Net income
|
|
|
$226,343
|
|
|
|
$43,683
|
|
|
|
$55,487
|
|
Income from discontinued operations, net of income taxes
|
|
(4,060
|
)
|
|
(21,825
|
)
|
|
(4,310
|
)
|
|||
Adjustments to reconcile income from continuing operations to net cash provided by operating activities from continuing operations
|
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
|
317,383
|
|
|
214,291
|
|
|
165,993
|
|
|||
Non-cash (gain) loss on derivatives, net
|
|
(215,436
|
)
|
|
30,908
|
|
|
7,553
|
|
|||
Loss on sale of oil and gas properties
|
|
—
|
|
|
45,377
|
|
|
—
|
|
|||
Stock-based compensation, net
|
|
25,878
|
|
|
29,373
|
|
|
11,689
|
|
|||
Deferred income taxes
|
|
127,927
|
|
|
10,934
|
|
|
30,142
|
|
|||
Non-cash interest expense, net
|
|
4,272
|
|
|
3,932
|
|
|
4,584
|
|
|||
Other, net
|
|
2,379
|
|
|
3,704
|
|
|
6,036
|
|
|||
Changes in operating assets and liabilities-
|
|
|
|
|
|
|
||||||
Accounts receivable
|
|
(1,334
|
)
|
|
11,557
|
|
|
(67,120
|
)
|
|||
Accounts payable
|
|
27,238
|
|
|
13,595
|
|
|
26,942
|
|
|||
Accrued liabilities
|
|
(3,096
|
)
|
|
(12,588
|
)
|
|
21,832
|
|
|||
Other, net
|
|
(5,219
|
)
|
|
(5,467
|
)
|
|
(5,757
|
)
|
|||
Net cash provided by operating activities from continuing operations
|
|
502,275
|
|
|
367,474
|
|
|
253,071
|
|
|||
Net cash used in operating activities from discontinued operations
|
|
(656
|
)
|
|
(623
|
)
|
|
(845
|
)
|
|||
Net cash provided by operating activities
|
|
501,619
|
|
|
366,851
|
|
|
252,226
|
|
|||
Cash Flows From Investing Activities
|
|
|
|
|
|
|
||||||
Capital expenditures - oil and gas properties
|
|
(860,604
|
)
|
|
(786,976
|
)
|
|
(735,711
|
)
|
|||
Capital expenditures - other property and equipment
|
|
(750
|
)
|
|
(968
|
)
|
|
(4,176
|
)
|
|||
Acquisitions of oil and gas properties from Eagle Ford Minerals, LLC
|
|
(92,961
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from sales of oil and gas properties, net
|
|
12,576
|
|
|
238,470
|
|
|
341,597
|
|
|||
Other, net
|
|
1,063
|
|
|
39,589
|
|
|
(66,861
|
)
|
|||
Net cash used in investing activities from continuing operations
|
|
(940,676
|
)
|
|
(509,885
|
)
|
|
(465,151
|
)
|
|||
Net cash provided by (used in) investing activities from discontinued operations
|
|
(7,834
|
)
|
|
124,533
|
|
|
(42,265
|
)
|
|||
Net cash used in investing activities
|
|
(948,510
|
)
|
|
(385,352
|
)
|
|
(507,416
|
)
|
|||
Cash Flows From Financing Activities
|
|
|
|
|
|
|
||||||
Proceeds from borrowings and issuances
|
|
1,287,541
|
|
|
582,000
|
|
|
1,040,772
|
|
|||
Debt repayments
|
|
(986,041
|
)
|
|
(651,325
|
)
|
|
(796,000
|
)
|
|||
Payments of debt issuance costs
|
|
(6,510
|
)
|
|
(3,257
|
)
|
|
(7,101
|
)
|
|||
Proceeds from common stock offerings, net of offering costs
|
|
—
|
|
|
189,686
|
|
|
—
|
|
|||
Excess tax benefits from stock-based compensation
|
|
4,863
|
|
|
1,969
|
|
|
—
|
|
|||
Proceeds from stock options exercised
|
|
437
|
|
|
1,253
|
|
|
107
|
|
|||
Net cash provided by financing activities from continuing operations
|
|
300,290
|
|
|
120,326
|
|
|
237,778
|
|
|||
Net cash provided by financing activities from discontinued operations
|
|
—
|
|
|
3,000
|
|
|
41,914
|
|
|||
Net cash provided by financing activities
|
|
300,290
|
|
|
123,326
|
|
|
279,692
|
|
|||
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
(146,601
|
)
|
|
104,825
|
|
|
24,502
|
|
|||
Cash and Cash Equivalents, Beginning of Year
|
|
157,439
|
|
|
52,614
|
|
|
28,112
|
|
|||
Cash and Cash Equivalents, End of Year
|
|
|
$10,838
|
|
|
|
$157,439
|
|
|
|
$52,614
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(In thousands)
|
||||||||||
Stock appreciation rights
|
|
|
$1,985
|
|
|
|
$17,303
|
|
|
|
($2,116
|
)
|
Restricted stock awards and units
|
|
29,597
|
|
|
18,997
|
|
|
17,049
|
|
|||
Performance share awards
|
|
1,395
|
|
|
—
|
|
|
—
|
|
|||
|
|
32,977
|
|
|
36,300
|
|
|
14,933
|
|
|||
Less: amounts capitalized
|
|
(7,099
|
)
|
|
(6,927
|
)
|
|
(3,244
|
)
|
|||
Total stock-based compensation expense
|
|
|
$25,878
|
|
|
|
$29,373
|
|
|
|
$11,689
|
|
Income Tax Benefit
|
|
|
$9,059
|
|
|
|
$10,281
|
|
|
|
$4,449
|
|
•
|
The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term at date of grant.
|
•
|
The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future.
|
•
|
The volatility of the Company’s common stock is based on daily, historical volatility of the market price of the Company’s common stock over a period of time equal to the expected term and ending on the grant date.
|
•
|
The expected term is based on historical exercises for various groups of directors, employees and independent contractors.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(In thousands, except per share amounts)
|
||||||||||
Income from Continuing Operations
|
|
|
$222,283
|
|
|
|
$21,858
|
|
|
|
$51,177
|
|
Basic weighted average common shares outstanding
|
|
45,372
|
|
|
40,781
|
|
|
39,591
|
|
|||
Effect of dilutive instruments
|
|
822
|
|
|
574
|
|
|
435
|
|
|||
Diluted weighted average common shares outstanding
|
|
46,194
|
|
|
41,355
|
|
|
40,026
|
|
|||
Income from Continuing Operations Per Common Share
|
|
|
|
|
|
|
||||||
Basic
|
|
|
$4.90
|
|
|
|
$0.54
|
|
|
|
$1.29
|
|
Diluted
|
|
|
$4.81
|
|
|
|
$0.53
|
|
|
|
$1.28
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(In thousands)
|
||||||||||
Revenues
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
|
|
|
|
|
||||||
Costs and expenses
|
|
|
|
|
|
|
||||||
General and administrative
|
|
656
|
|
|
916
|
|
|
62
|
|
|||
Accretion related to asset retirement obligations
|
|
—
|
|
|
36
|
|
|
363
|
|
|||
Gain on sale of discontinued operations
|
|
—
|
|
|
(37,294
|
)
|
|
—
|
|
|||
Increase (decrease) in estimated future obligations
|
|
(7,638
|
)
|
|
44
|
|
|
—
|
|
|||
(Gain) loss on derivatives, net
|
|
34
|
|
|
109
|
|
|
(258
|
)
|
|||
Other (income) expense, net
|
|
—
|
|
|
(438
|
)
|
|
591
|
|
|||
Income (Loss) From Discontinued Operations Before Income Taxes
|
|
6,948
|
|
|
36,627
|
|
|
(758
|
)
|
|||
Income tax (expense) benefit
|
|
(2,888
|
)
|
|
(14,802
|
)
|
|
5,068
|
|
|||
Income From Discontinued Operations, Net of Income Taxes
|
|
|
$4,060
|
|
|
|
$21,825
|
|
|
|
$4,310
|
|
Assets
|
|
(In thousands)
|
||
Other current assets
|
|
|
$485
|
|
Proved and unproved oil and gas properties
|
|
244,124
|
|
|
Total assets acquired
|
|
|
$244,609
|
|
|
|
|
||
Liabilities
|
|
|
||
Asset retirement obligations
|
|
|
$423
|
|
Total liabilities assumed
|
|
|
$423
|
|
Net Assets Acquired
|
|
|
$244,186
|
|
|
|
For the Years Ended December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In thousands, except per share data)
(Unaudited)
|
||||||
Total revenues
|
|
|
$761,199
|
|
|
|
$575,721
|
|
Income From Continuing Operations
|
|
264,714
|
|
|
36,356
|
|
||
|
|
|
|
|
||||
Income From Continuing Operations Per Common Share
|
|
|
|
|
||||
Basic
|
|
|
$5.83
|
|
|
|
$0.89
|
|
Diluted
|
|
|
$5.73
|
|
|
|
$0.88
|
|
|
|
|
|
|
||||
Weighted Average Common Shares Outstanding
|
|
|
|
|
||||
Basic
|
|
45,372
|
|
|
40,781
|
|
||
Diluted
|
|
46,194
|
|
|
41,355
|
|
|
|
December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In thousands)
|
||||||
Proved properties
|
|
|
$3,174,268
|
|
|
|
$2,182,226
|
|
Accumulated depreciation, depletion and amortization
|
|
(1,087,541
|
)
|
|
(773,742
|
)
|
||
Proved properties, net
|
|
2,086,727
|
|
|
1,408,484
|
|
||
Unproved properties, not being amortized
|
|
|
|
|
||||
Unevaluated leasehold and seismic costs
|
|
401,954
|
|
|
302,232
|
|
||
Exploratory wells in progress
|
|
71,402
|
|
|
30,196
|
|
||
Capitalized interest
|
|
61,841
|
|
|
45,009
|
|
||
Total unproved properties, not being amortized
|
|
535,197
|
|
|
377,437
|
|
||
Other property and equipment
|
|
16,017
|
|
|
15,260
|
|
||
Accumulated depreciation
|
|
(8,688
|
)
|
|
(6,966
|
)
|
||
Other property and equipment, net
|
|
7,329
|
|
|
8,294
|
|
||
Total property and equipment, net
|
|
|
$2,629,253
|
|
|
|
$1,794,215
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(In thousands)
|
||||||||||
Current income tax (expense) benefit
|
|
|
|
|
|
|
||||||
U.S. Federal
|
|
|
$—
|
|
|
|
$411
|
|
|
|
($411
|
)
|
State
|
|
—
|
|
|
(141
|
)
|
|
(403
|
)
|
|||
Total current income tax (expense) benefit
|
|
—
|
|
|
270
|
|
|
(814
|
)
|
|||
Deferred income tax expense
|
|
|
|
|
|
|
||||||
U.S. Federal
|
|
(122,342
|
)
|
|
(12,404
|
)
|
|
(28,723
|
)
|
|||
State
|
|
(5,585
|
)
|
|
(769
|
)
|
|
(1,419
|
)
|
|||
Total deferred income tax expense
|
|
(127,927
|
)
|
|
(13,173
|
)
|
|
(30,142
|
)
|
|||
Total income tax expense from continuing operations
|
|
|
($127,927
|
)
|
|
|
($12,903
|
)
|
|
|
($30,956
|
)
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(In thousands)
|
||||||||||
Income from continuing operations before income taxes
|
|
|
$350,210
|
|
|
|
$34,761
|
|
|
|
$82,133
|
|
Income tax expense at the statutory rate
|
|
(122,574
|
)
|
|
(12,166
|
)
|
|
(28,747
|
)
|
|||
State income taxes, net of U.S. federal income tax benefit
|
|
(5,585
|
)
|
|
(859
|
)
|
|
(1,681
|
)
|
|||
Nondeductible expenses
|
|
—
|
|
|
—
|
|
|
(93
|
)
|
|||
Other
|
|
232
|
|
|
122
|
|
|
(435
|
)
|
|||
Total income tax expense from continuing operations
|
|
|
($127,927
|
)
|
|
|
($12,903
|
)
|
|
|
($30,956
|
)
|
|
|
December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In thousands)
|
||||||
Deferred income tax assets
|
|
|
|
|
||||
Net operating loss carryforward - U.S. Federal and State
|
|
|
$56,876
|
|
|
|
$52,499
|
|
Asset retirement obligations
|
|
4,379
|
|
|
2,302
|
|
||
Stock-based compensation
|
|
7,867
|
|
|
7,563
|
|
||
Allowance for doubtful accounts
|
|
—
|
|
|
170
|
|
||
Fair value of derivative instruments
|
|
70
|
|
|
3,222
|
|
||
Other
|
|
2,989
|
|
|
2,471
|
|
||
Deferred income tax assets
|
|
72,181
|
|
|
68,227
|
|
||
Valuation allowance
|
|
(1,095
|
)
|
|
(1,084
|
)
|
||
Net deferred income tax assets
|
|
71,086
|
|
|
67,143
|
|
||
Deferred income tax liabilities
|
|
|
|
|
||||
Oil and gas properties
|
|
(134,518
|
)
|
|
(76,549
|
)
|
||
Fair value of derivative instruments
|
|
(75,175
|
)
|
|
(3,249
|
)
|
||
|
|
(209,693
|
)
|
|
(79,798
|
)
|
||
Net deferred income tax liability
|
|
|
($138,607
|
)
|
|
|
($12,655
|
)
|
|
|
December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In thousands)
|
||||||
Net current deferred income tax asset (liability)
|
|
|
($61,258
|
)
|
|
|
$4,201
|
|
Net noncurrent deferred income tax liability
|
|
(77,349
|
)
|
|
(16,856
|
)
|
||
Net deferred income tax liability
|
|
|
($138,607
|
)
|
|
|
($12,655
|
)
|
|
|
December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In thousands)
|
||||||
Long-term debt
|
|
|
|
|
||||
8.625% Senior Notes due 2018
|
|
|
$600,000
|
|
|
|
$600,000
|
|
Unamortized discount for 8.625% Senior Notes
|
|
(3,444
|
)
|
|
(4,178
|
)
|
||
7.50% Senior Notes due 2020
|
|
600,000
|
|
|
300,000
|
|
||
Unamortized premium for 7.50% Senior Notes
|
|
1,465
|
|
|
—
|
|
||
Other long-term debt due 2028
|
|
4,425
|
|
|
4,425
|
|
||
Senior Secured Revolving Credit Facility due 2018
|
|
—
|
|
|
—
|
|
||
Deferred purchase payment
|
|
150,000
|
|
|
—
|
|
||
Unamortized discount for deferred purchase payment
|
|
(1,100
|
)
|
|
—
|
|
||
Total long-term debt
|
|
|
$1,351,346
|
|
|
|
$900,247
|
|
Ratio of Outstanding Borrowings and Letters of Credit to Lender Commitments
|
|
Applicable
Margin for
Base Rate
Loans
|
|
Applicable
Margin for Eurodollar
Loans
|
|
Commitment Fee
|
Less than 25%
|
|
0.50%
|
|
1.50%
|
|
0.375%
|
Greater than or equal to 25% but less than 50%
|
|
0.75%
|
|
1.75%
|
|
0.375%
|
Greater than or equal to 50% but less than 75%
|
|
1.00%
|
|
2.00%
|
|
0.500%
|
Greater than or equal to 75% but less than 90%
|
|
1.25%
|
|
2.25%
|
|
0.500%
|
Greater than or equal to 90%
|
|
1.50%
|
|
2.50%
|
|
0.500%
|
|
|
Year Ended December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(In thousands)
|
||||||
Asset retirement obligations at beginning of period
|
|
|
$7,356
|
|
|
|
$6,159
|
|
Liabilities incurred
|
|
6,284
|
|
|
3,348
|
|
||
Increase due to acquisition of oil and gas properties
|
|
423
|
|
|
—
|
|
||
Liabilities settled
|
|
(1,784
|
)
|
|
(498
|
)
|
||
Reduction due to sales of oil and gas properties
|
|
—
|
|
|
(2,473
|
)
|
||
Accretion expense
|
|
710
|
|
|
471
|
|
||
Revisions of previous estimates
|
|
(477
|
)
|
|
349
|
|
||
Asset retirement obligations at end of period
|
|
12,512
|
|
|
7,356
|
|
||
Asset retirement obligations due within one year included in “Other current liabilities”
|
|
(325
|
)
|
|
(780
|
)
|
||
Long-term asset retirement obligations
|
|
|
$12,187
|
|
|
|
$6,576
|
|
|
Amount
|
||
|
(In thousands)
|
||
2015
|
|
$55,435
|
|
2016
|
36,020
|
|
|
2017
|
26,424
|
|
|
2018
|
11,141
|
|
|
2019
|
6,493
|
|
|
2020 and thereafter
|
16,934
|
|
|
Total
|
|
$152,447
|
|
|
|
Shares
|
|
Weighted-
Average
Exercise
Prices
|
|
Weighted-
Average
Remaining Life
(In years)
|
|
Aggregate
Intrinsic Value
(In millions)
|
|||||
For the Year Ended December 31, 2012
|
|
|
|
|
|
|
|
|
|||||
Outstanding, beginning of period
|
|
263,354
|
|
|
|
$7.11
|
|
|
|
|
|
||
Granted
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Exercised
|
|
(20,500
|
)
|
|
|
$5.50
|
|
|
|
|
|
||
Forfeited
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Outstanding, end of period
|
|
242,854
|
|
|
|
$7.24
|
|
|
|
|
|
||
Exercisable, end of period
|
|
242,854
|
|
|
|
$7.24
|
|
|
|
|
|
||
For the Year Ended December 31, 2013
|
|
|
|
|
|
|
|
|
|||||
Outstanding, beginning of period
|
|
242,854
|
|
|
|
$7.24
|
|
|
|
|
|
||
Granted
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Exercised
|
|
(206,501
|
)
|
|
|
$6.07
|
|
|
|
|
|
||
Forfeited
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Outstanding, end of period
|
|
36,353
|
|
|
|
$13.91
|
|
|
|
|
|
||
Exercisable, end of period
|
|
36,353
|
|
|
|
$13.91
|
|
|
|
|
|
||
For the Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|||||
Outstanding, beginning of period
|
|
36,353
|
|
|
|
$13.91
|
|
|
|
|
|
||
Granted
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Exercised
|
|
(33,086
|
)
|
|
|
$13.20
|
|
|
|
|
|
||
Forfeited
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Expired
|
|
(834
|
)
|
|
|
$27.25
|
|
|
|
|
|
||
Outstanding, end of period
|
|
2,433
|
|
|
|
$19.02
|
|
|
0.52
|
|
|
$0.1
|
|
Exercisable, end of period
|
|
2,433
|
|
|
|
$19.02
|
|
|
0.52
|
|
|
$0.1
|
|
|
|
Shares
|
|
Weighted-
Average
Exercise
Prices
|
|
Weighted-
Average
Remaining Life
(In years)
|
|
Aggregate
Intrinsic Value
(In millions)
|
|||||
For the Year Ended December 31, 2012
|
|
|
|
|
|
|
|
|
|||||
Outstanding, beginning of period
|
|
849,782
|
|
|
|
$22.02
|
|
|
|
|
|
||
Granted
|
|
193,336
|
|
|
|
$25.56
|
|
|
|
|
|
||
Exercised
|
|
(7,295
|
)
|
|
|
$20.22
|
|
|
|
|
|
||
Forfeited
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Outstanding, end of period
|
|
1,035,823
|
|
|
|
$22.69
|
|
|
|
|
|
||
Exercisable, end of period
|
|
613,934
|
|
|
|
$20.70
|
|
|
|
|
|
||
For the Year Ended December 31, 2013
|
|
|
|
|
|
|
|
|
|||||
Outstanding, beginning of period
|
|
1,035,823
|
|
|
|
$22.69
|
|
|
|
|
|
||
Granted
|
|
282,296
|
|
|
|
$28.68
|
|
|
|
|
|
||
Exercised
|
|
(207,184
|
)
|
|
|
$19.30
|
|
|
|
|
|
||
Forfeited
|
|
(24,704
|
)
|
|
|
$27.77
|
|
|
|
|
|
||
Outstanding, end of period
|
|
1,086,231
|
|
|
|
$24.78
|
|
|
|
|
|
||
Exercisable, end of period
|
|
681,867
|
|
|
|
$22.55
|
|
|
|
|
|
||
For the Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|||||
Outstanding, beginning of period
|
|
1,086,231
|
|
|
|
$24.78
|
|
|
|
|
|
||
Granted
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Exercised
|
|
(321,033
|
)
|
|
|
$30.24
|
|
|
|
|
|
||
Forfeited
|
|
—
|
|
|
—
|
|
|
|
|
|
|||
Outstanding, end of period
|
|
765,198
|
|
|
|
$22.49
|
|
|
2.05
|
|
|
$14.5
|
|
Exercisable, end of period
|
|
587,481
|
|
|
|
$20.78
|
|
|
1.98
|
|
|
$12.2
|
|
|
|
2013
|
|
2012
|
||
Grant date fair value
|
|
$13.36
|
|
$12.23
|
||
Volatility factor
|
|
44.5
|
%
|
|
48.2
|
%
|
Dividend yield
|
|
—
|
%
|
|
—
|
%
|
Risk-free interest rate
|
|
1.0
|
%
|
|
0.4
|
%
|
Expected term (in years)
|
|
3.5
|
|
|
3.0
|
|
|
|
Shares/
Units
|
|
Weighted-Average Grant Date
Fair Value
|
|||
For the Year Ended December 31, 2012
|
|
|
|
|
|||
Unvested restricted stock awards and units, beginning of period
|
|
800,498
|
|
|
|
$27.96
|
|
Granted
|
|
854,292
|
|
|
|
$25.25
|
|
Vested
|
|
(488,992
|
)
|
|
|
$25.63
|
|
Forfeited
|
|
(19,524
|
)
|
|
|
$27.61
|
|
Unvested restricted stock awards and units, end of period
|
|
1,146,274
|
|
|
|
$26.95
|
|
For the Year Ended December 31, 2013
|
|
|
|
|
|||
Unvested restricted stock awards and units, beginning of period
|
|
1,146,274
|
|
|
|
$26.95
|
|
Granted
|
|
932,763
|
|
|
|
$28.16
|
|
Vested
|
|
(557,136
|
)
|
|
|
$25.98
|
|
Forfeited
|
|
(77,034
|
)
|
|
|
$26.03
|
|
Unvested restricted stock awards and units, end of period
|
|
1,444,867
|
|
|
|
$28.03
|
|
For the Year Ended December 31, 2014
|
|
|
|
|
|||
Unvested restricted stock awards and units, beginning of period
|
|
1,444,867
|
|
|
|
$28.03
|
|
Granted
|
|
576,812
|
|
|
|
$48.64
|
|
Vested
|
|
(647,306
|
)
|
|
|
$32.64
|
|
Forfeited
|
|
(38,691
|
)
|
|
|
$32.89
|
|
Unvested restricted stock awards and units, end of period
|
|
1,335,682
|
|
|
|
$34.55
|
|
|
|
2014
|
|
Number of simulations
|
|
500,000
|
|
Grant price
|
|
$53.96
|
|
Volatility factor
|
|
49.9
|
%
|
Dividend yield
|
|
—
|
%
|
Risk-free interest rate
|
|
0.9
|
%
|
Expected term (in years)
|
|
2.97
|
|
Counterparty
|
|
December 31, 2014
|
|
December 31, 2013
|
||
Wells Fargo
|
|
37
|
%
|
|
23
|
%
|
Societe Generale
|
|
26
|
%
|
|
31
|
%
|
Credit Suisse
|
|
24
|
%
|
|
46
|
%
|
Regions
|
|
8
|
%
|
|
—
|
%
|
Union Bank
|
|
4
|
%
|
|
—
|
%
|
Royal Bank of Canada
|
|
1
|
%
|
|
—
|
%
|
Total
|
|
100
|
%
|
|
100
|
%
|
Period
|
|
Type of Contract
|
|
Volumes
(in Bbls/d)
|
|
Weighted
Average
Floor Price
($/Bbl)
|
|
Weighted
Average
Ceiling Price
($/Bbl)
|
|
Weighted Average
Short Put Price
($/Bbl)
|
|
Weighted Average
Put Spread
($/Bbl)
|
|||||||||
January - December 2015
|
|
Fixed Price Swaps
|
|
10,370
|
|
|
|
$92.97
|
|
|
|
|
|
|
|
|
|||||
|
|
Costless Collars
|
|
700
|
|
|
|
$90.00
|
|
|
|
$100.65
|
|
|
|
|
|
||||
|
|
Three-way Collars
|
|
1,000
|
|
|
|
$85.00
|
|
|
|
$105.00
|
|
|
|
$65.00
|
|
|
|
$20.00
|
|
January - December 2016
|
|
Fixed Price Swaps
|
|
3,000
|
|
|
|
$91.09
|
|
|
|
|
|
|
|
|
|||||
|
|
Three-way Collars
|
|
667
|
|
|
|
$85.00
|
|
|
|
$104.00
|
|
|
|
$65.00
|
|
|
|
$20.00
|
|
Period
|
|
Type of Contract
|
|
Volume
(in MMBtu/d)
|
|
Weighted
Average
Floor Price
($/MMBtu)
|
|||
January - December 2015
|
|
Fixed Price Swaps
|
|
30,000
|
|
|
|
$4.29
|
|
|
|
December 31, 2014
|
||||||||||
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
||||||
|
|
(In thousands)
|
||||||||||
Derivative assets
|
|
|
|
|
|
|
||||||
Derivative assets (current)
|
|
|
$183,625
|
|
|
|
($12,524
|
)
|
|
|
$171,101
|
|
Derivative assets (noncurrent)
|
|
44,725
|
|
|
(1,041
|
)
|
|
43,684
|
|
|||
Derivative liabilities
|
|
|
|
|
|
|
||||||
Other current liabilities
|
|
(12,707
|
)
|
|
12,524
|
|
|
(183
|
)
|
|||
Other liabilities (noncurrent)
|
|
(1,058
|
)
|
|
1,041
|
|
|
(17
|
)
|
|||
Total
|
|
|
$214,585
|
|
|
|
$—
|
|
|
|
$214,585
|
|
|
|
December 31, 2013
|
||||||||||
|
|
Gross Amounts Recognized
|
|
Gross Amounts Offset in the Consolidated Balance Sheets
|
|
Net Amounts Presented in the Consolidated Balance Sheets
|
||||||
|
|
(In thousands)
|
||||||||||
Derivative assets
|
|
|
|
|
|
|
||||||
Derivative assets (current)
|
|
|
$2,389
|
|
|
|
($2,389
|
)
|
|
|
$—
|
|
Derivative assets (noncurrent)
|
|
11,709
|
|
|
(2,425
|
)
|
|
9,284
|
|
|||
Derivative Liabilities
|
|
|
|
|
|
|
||||||
Other current liabilities
|
|
(12,336
|
)
|
|
2,389
|
|
|
(9,947
|
)
|
|||
Other liabilities (noncurrent)
|
|
(2,613
|
)
|
|
2,425
|
|
|
(188
|
)
|
|||
Total
|
|
|
($851
|
)
|
|
|
$—
|
|
|
|
($851
|
)
|
|
|
December 31, 2014
|
|
December 31, 2013
|
||||||||||||
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
|
|
(In thousands)
|
||||||||||||||
8.625% Senior Notes due 2018
|
|
|
$596,555
|
|
|
|
$597,000
|
|
|
|
$595,822
|
|
|
|
$644,978
|
|
7.50% Senior Notes due 2020
|
|
600,000
|
|
|
573,000
|
|
|
300,000
|
|
|
327,000
|
|
||||
Other long-term debt due 2028
|
|
4,425
|
|
|
4,071
|
|
|
4,425
|
|
|
4,115
|
|
||||
Deferred purchase payment
|
|
148,900
|
|
|
148,558
|
|
|
—
|
|
|
—
|
|
|
|
December 31, 2014
|
||||||||||||||||||
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total current assets
|
|
|
$2,380,445
|
|
|
|
$245,051
|
|
|
|
$111
|
|
|
|
($2,346,986
|
)
|
|
|
$278,621
|
|
Total property and equipment, net
|
|
613
|
|
|
2,562,029
|
|
|
39,939
|
|
|
26,672
|
|
|
2,629,253
|
|
|||||
Investment in subsidiaries
|
|
233,173
|
|
|
—
|
|
|
—
|
|
|
(233,173
|
)
|
|
—
|
|
|||||
Other assets
|
|
140,774
|
|
|
—
|
|
|
—
|
|
|
(67,172
|
)
|
|
73,602
|
|
|||||
Total Assets
|
|
|
$2,755,005
|
|
|
|
$2,807,080
|
|
|
|
$40,050
|
|
|
|
($2,620,659
|
)
|
|
|
$2,981,476
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Liabilities and Shareholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
|
|
$296,686
|
|
|
|
$2,434,649
|
|
|
|
$39,955
|
|
|
|
($2,346,986
|
)
|
|
|
$424,304
|
|
Long-term liabilities
|
|
1,364,793
|
|
|
139,353
|
|
|
—
|
|
|
(50,415
|
)
|
|
1,453,731
|
|
|||||
Total shareholders’ equity
|
|
1,093,526
|
|
|
233,078
|
|
|
95
|
|
|
(223,258
|
)
|
|
1,103,441
|
|
|||||
Total Liabilities and Shareholders’ Equity
|
|
|
$2,755,005
|
|
|
|
$2,807,080
|
|
|
|
$40,050
|
|
|
|
($2,620,659
|
)
|
|
|
$2,981,476
|
|
|
|
December 31, 2013
|
||||||||||||||||||
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total current assets
|
|
|
$1,820,069
|
|
|
|
$168,718
|
|
|
|
$—
|
|
|
|
($1,709,026
|
)
|
|
|
$279,761
|
|
Total property and equipment, net
|
|
2,797
|
|
|
1,768,553
|
|
|
2,058
|
|
|
20,807
|
|
|
1,794,215
|
|
|||||
Investment in subsidiaries
|
|
61,619
|
|
|
—
|
|
|
—
|
|
|
(61,619
|
)
|
|
—
|
|
|||||
Other assets
|
|
69,686
|
|
|
—
|
|
|
—
|
|
|
(32,902
|
)
|
|
36,784
|
|
|||||
Total Assets
|
|
|
$1,954,171
|
|
|
|
$1,937,271
|
|
|
|
$2,058
|
|
|
|
($1,782,740
|
)
|
|
|
$2,110,760
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Liabilities and Shareholders’ Equity
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities
|
|
|
$201,486
|
|
|
|
$1,828,314
|
|
|
|
$2,061
|
|
|
|
($1,709,026
|
)
|
|
|
$322,835
|
|
Long-term liabilities
|
|
922,571
|
|
|
47,335
|
|
|
—
|
|
|
(23,585
|
)
|
|
946,321
|
|
|||||
Total shareholders’ equity
|
|
830,114
|
|
|
61,622
|
|
|
(3
|
)
|
|
(50,129
|
)
|
|
841,604
|
|
|||||
Total Liabilities and Shareholders’ Equity
|
|
|
$1,954,171
|
|
|
|
$1,937,271
|
|
|
|
$2,058
|
|
|
|
($1,782,740
|
)
|
|
|
$2,110,760
|
|
|
|
For the Year Ended December 31, 2014
|
||||||||||||||||||
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Total revenues
|
|
|
$3,938
|
|
|
|
$706,121
|
|
|
|
$128
|
|
|
|
$—
|
|
|
|
$710,187
|
|
Total costs and expenses
|
|
(76,531
|
)
|
|
442,343
|
|
|
30
|
|
|
(5,865
|
)
|
|
359,977
|
|
|||||
Income From Continuing Operations Before Income Taxes
|
|
80,469
|
|
|
263,778
|
|
|
98
|
|
|
5,865
|
|
|
350,210
|
|
|||||
Income tax expense
|
|
(28,164
|
)
|
|
(92,322
|
)
|
|
—
|
|
|
(7,441
|
)
|
|
(127,927
|
)
|
|||||
Equity in income of subsidiaries
|
|
171,554
|
|
|
—
|
|
|
—
|
|
|
(171,554
|
)
|
|
—
|
|
|||||
Income From Continuing Operations
|
|
|
$223,859
|
|
|
|
$171,456
|
|
|
|
$98
|
|
|
|
($173,130
|
)
|
|
|
$222,283
|
|
Income From Discontinued Operations, Net of Income Taxes
|
|
4,060
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,060
|
|
|||||
Net Income
|
|
|
$227,919
|
|
|
|
$171,456
|
|
|
|
$98
|
|
|
|
($173,130
|
)
|
|
|
$226,343
|
|
|
|
For the Year Ended December 31, 2013
|
||||||||||||||||||
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Total revenues
|
|
|
$6,490
|
|
|
|
$513,692
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$520,182
|
|
Total costs and expenses
|
|
134,874
|
|
|
349,782
|
|
|
3
|
|
|
762
|
|
|
485,421
|
|
|||||
Income (Loss) From Continuing Operations Before Income Taxes
|
|
(128,384
|
)
|
|
163,910
|
|
|
(3
|
)
|
|
(762
|
)
|
|
34,761
|
|
|||||
Income tax (expense) benefit
|
|
44,934
|
|
|
(57,369
|
)
|
|
—
|
|
|
(468
|
)
|
|
(12,903
|
)
|
|||||
Equity in income of subsidiaries
|
|
106,538
|
|
|
—
|
|
|
—
|
|
|
(106,538
|
)
|
|
—
|
|
|||||
Income (Loss) From Continuing Operations
|
|
|
$23,088
|
|
|
|
$106,541
|
|
|
|
($3
|
)
|
|
|
($107,768
|
)
|
|
|
$21,858
|
|
Income From Discontinued Operations, Net of Income Taxes
|
|
21,825
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,825
|
|
|||||
Net Income (Loss)
|
|
|
$44,913
|
|
|
|
$106,541
|
|
|
|
($3
|
)
|
|
|
($107,768
|
)
|
|
|
$43,683
|
|
|
|
For the Year Ended December 31, 2012
|
||||||||||||||||||
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Total revenues
|
|
|
$20,195
|
|
|
|
$347,985
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$368,180
|
|
Total costs and expenses
|
|
56,817
|
|
|
241,883
|
|
|
—
|
|
|
(12,653
|
)
|
|
286,047
|
|
|||||
Income (Loss) From Continuing Operations Before Income Taxes
|
|
(36,622
|
)
|
|
106,102
|
|
|
—
|
|
|
12,653
|
|
|
82,133
|
|
|||||
Income tax (expense) benefit
|
|
12,658
|
|
|
(37,136
|
)
|
|
—
|
|
|
(6,478
|
)
|
|
(30,956
|
)
|
|||||
Equity in income of subsidiaries
|
|
73,150
|
|
|
—
|
|
|
—
|
|
|
(73,150
|
)
|
|
—
|
|
|||||
Income From Continuing Operations
|
|
|
$49,186
|
|
|
|
$68,966
|
|
|
|
$—
|
|
|
|
($66,975
|
)
|
|
|
$51,177
|
|
Income From Discontinued Operations, Net of Income Taxes
|
|
126
|
|
|
—
|
|
|
4,184
|
|
|
—
|
|
|
4,310
|
|
|||||
Net Income
|
|
|
$49,312
|
|
|
|
$68,966
|
|
|
|
$4,184
|
|
|
|
($66,975
|
)
|
|
|
$55,487
|
|
|
|
For the Year Ended December 31, 2014
|
||||||||||||||||||
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net cash provided by (used in) operating activities from continuing operations
|
|
|
($132,683
|
)
|
|
|
$634,970
|
|
|
|
($12
|
)
|
|
|
$—
|
|
|
|
$502,275
|
|
Net cash used in investing activities from continuing operations
|
|
(305,718
|
)
|
|
(906,509
|
)
|
|
(37,609
|
)
|
|
309,160
|
|
|
(940,676
|
)
|
|||||
Net cash provided by financing activities from continuing operations
|
|
300,290
|
|
|
271,539
|
|
|
37,621
|
|
|
(309,160
|
)
|
|
300,290
|
|
|||||
Net cash used in discontinued operations
|
|
(8,490
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,490
|
)
|
|||||
Net decrease in cash and cash equivalents
|
|
(146,601
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(146,601
|
)
|
|||||
Cash and cash equivalents, beginning of year
|
|
157,439
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
157,439
|
|
|||||
Cash and cash equivalents, end of year
|
|
|
$10,838
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$10,838
|
|
|
|
For the Year Ended December 31, 2013
|
||||||||||||||||||
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net cash provided by (used in) operating activities from continuing operations
|
|
|
($55,888
|
)
|
|
|
$423,366
|
|
|
|
($4
|
)
|
|
|
$—
|
|
|
|
$367,474
|
|
Net cash used in investing activities from continuing operations
|
|
(86,322
|
)
|
|
(513,710
|
)
|
|
(2,057
|
)
|
|
92,204
|
|
|
(509,885
|
)
|
|||||
Net cash provided by financing activities from continuing operations
|
|
120,326
|
|
|
90,143
|
|
|
2,061
|
|
|
(92,204
|
)
|
|
120,326
|
|
|||||
Net cash provided by (used in) discontinued operations
|
|
127,429
|
|
|
—
|
|
|
(519
|
)
|
|
—
|
|
|
126,910
|
|
|||||
Net increase (decrease) in cash and cash equivalents
|
|
105,545
|
|
|
(201
|
)
|
|
(519
|
)
|
|
—
|
|
|
104,825
|
|
|||||
Cash and cash equivalents, beginning of year
|
|
51,894
|
|
|
201
|
|
|
519
|
|
|
—
|
|
|
52,614
|
|
|||||
Cash and cash equivalents, end of year
|
|
|
$157,439
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$157,439
|
|
|
|
For the Year Ended December 31, 2012
|
||||||||||||||||||
|
|
Parent
Company
|
|
Combined
Guarantor
Subsidiaries
|
|
Combined
Non-
Guarantor
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net cash provided by operating activities from continuing operations
|
|
|
$75,546
|
|
|
|
$177,525
|
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$253,071
|
|
Net cash used in investing activities from continuing operations
|
|
(280,564
|
)
|
|
(493,145
|
)
|
|
—
|
|
|
308,558
|
|
|
(465,151
|
)
|
|||||
Net cash provided by financing activities from continuing operations
|
|
237,778
|
|
|
308,558
|
|
|
—
|
|
|
(308,558
|
)
|
|
237,778
|
|
|||||
Net cash used in discontinued operations
|
|
—
|
|
|
—
|
|
|
(1,196
|
)
|
|
—
|
|
|
(1,196
|
)
|
|||||
Net increase (decrease) in cash and cash equivalents
|
|
32,760
|
|
|
(7,062
|
)
|
|
(1,196
|
)
|
|
—
|
|
|
24,502
|
|
|||||
Cash and cash equivalents, beginning of year
|
|
19,134
|
|
|
7,263
|
|
|
1,715
|
|
|
—
|
|
|
28,112
|
|
|||||
Cash and cash equivalents, end of year
|
|
|
$51,894
|
|
|
|
$201
|
|
|
|
$519
|
|
|
|
$—
|
|
|
|
$52,614
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(In thousands)
|
||||||||||
Net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Cash paid for interest, net of amounts capitalized
|
|
|
$49,379
|
|
|
|
$50,770
|
|
|
|
$43,629
|
|
Cash paid for income taxes
|
|
—
|
|
|
505
|
|
|
587
|
|
|||
|
|
|
|
|
|
|
||||||
Non-cash investing and financing activities:
|
|
|
|
|
|
|
||||||
Capital expenditures included in accounts payable and accrued capital expenditures
|
|
|
$176,886
|
|
|
|
$114,988
|
|
|
|
$82,727
|
|
Purchase price adjustments related to the Eagle Ford Shale Acquisition
|
|
3,197
|
|
|
—
|
|
|
—
|
|
|||
EFM deferred purchase payment
|
|
148,900
|
|
|
—
|
|
|
—
|
|
Period
|
|
Type of Contract
|
|
Volumes
(in Bbls/d)
|
|
Weighted
Average
Floor Price
($/Bbl)
|
|
Weighted
Average
Ceiling Price
($/Bbl)
|
|
Weighted Average
Short Put Price
($/Bbl)
|
|||||||
March - December 2015
|
|
Fixed Price Swaps
|
|
10,370
|
|
|
|
$55.48
|
|
|
|
|
|
||||
|
|
Costless Collars
|
|
700
|
|
|
|
$90.00
|
|
|
|
$100.65
|
|
|
|
||
|
|
Three-way Collars
|
|
1,000
|
|
|
|
$85.00
|
|
|
|
$105.00
|
|
|
|
$65.00
|
|
January - December 2016
|
|
Fixed Price Swaps
|
|
3,000
|
|
|
|
$62.11
|
|
|
|
|
|
||||
|
|
Three-way Collars
|
|
667
|
|
|
|
$85.00
|
|
|
|
$104.00
|
|
|
|
$65.00
|
|
Period
|
|
Type of Contract
|
|
Volumes
(in Bbls/d)
|
|
Weighted Average Floor Price ($/Bbl)
|
|
Weighted Average Ceiling Price ($/Bbl)
|
|||||
March - December 2015
|
|
Costless Collars
|
|
12,200
|
|
|
|
$50.00
|
|
|
|
$66.46
|
|
January - December 2016
|
|
Costless Collars
|
|
4,000
|
|
|
|
$50.00
|
|
|
|
$76.50
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(In thousands)
|
||||||||||
U.S.
|
|
|
|
|
|
|
||||||
Property acquisition costs
|
|
|
|
|
|
|
||||||
Proved property acquisition costs
|
|
|
$183,633
|
|
|
|
$—
|
|
|
|
$—
|
|
Unproved property acquisition costs
|
|
215,021
|
|
|
254,099
|
|
|
139,344
|
|
|||
Total property acquisition costs
|
|
398,654
|
|
|
254,099
|
|
|
139,344
|
|
|||
Exploration costs
|
|
194,956
|
|
|
106,329
|
|
|
211,289
|
|
|||
Development costs
|
|
530,268
|
|
|
423,871
|
|
|
374,391
|
|
|||
Total costs incurred
|
|
|
$1,123,878
|
|
|
|
$784,299
|
|
|
|
$725,024
|
|
U.K.
|
|
|
|
|
|
|
||||||
Property acquisition costs
|
|
|
|
|
|
|
||||||
Proved property acquisition costs
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$—
|
|
Unproved property acquisition costs
|
|
—
|
|
|
—
|
|
|
11,135
|
|
|||
Total property acquisition costs
|
|
—
|
|
|
—
|
|
|
11,135
|
|
|||
Exploration costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Development costs
|
|
—
|
|
|
—
|
|
|
36,261
|
|
|||
Total costs incurred
|
|
|
$—
|
|
|
|
$—
|
|
|
|
$47,396
|
|
Total Worldwide
|
|
|
|
|
|
|
||||||
Property acquisition costs
|
|
|
|
|
|
|
||||||
Proved property acquisition costs
|
|
|
$183,633
|
|
|
|
$—
|
|
|
|
$—
|
|
Unproved property acquisition costs
|
|
215,021
|
|
|
254,099
|
|
|
150,479
|
|
|||
Total property acquisition costs
|
|
398,654
|
|
|
254,099
|
|
|
150,479
|
|
|||
Exploration costs
|
|
194,956
|
|
|
106,329
|
|
|
211,289
|
|
|||
Development costs
|
|
530,268
|
|
|
423,871
|
|
|
410,652
|
|
|||
Total costs incurred
|
|
|
$1,123,878
|
|
|
|
$784,299
|
|
|
|
$772,420
|
|
|
|
Crude Oil and Condensate (MBbls)
|
|
Natural Gas Liquids (MBbls)
|
||||||||||||||
|
|
U.S.
|
|
U.K.
|
|
Worldwide
|
|
U.S.
|
|
U.K.
|
|
Worldwide
|
||||||
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
January 1, 2012
|
|
25,101
|
|
|
5,437
|
|
|
30,538
|
|
|
4,121
|
|
|
—
|
|
|
4,121
|
|
Extensions and discoveries
|
|
15,403
|
|
|
—
|
|
|
15,403
|
|
|
1,750
|
|
|
—
|
|
|
1,750
|
|
Revisions of previous estimates
|
|
1,760
|
|
|
(196
|
)
|
|
1,564
|
|
|
740
|
|
|
—
|
|
|
740
|
|
Sales of reserves in place
|
|
(327
|
)
|
|
—
|
|
|
(327
|
)
|
|
(923
|
)
|
|
—
|
|
|
(923
|
)
|
Production
|
|
(2,862
|
)
|
|
—
|
|
|
(2,862
|
)
|
|
(305
|
)
|
|
—
|
|
|
(305
|
)
|
December 31, 2012
|
|
39,075
|
|
|
5,241
|
|
|
44,316
|
|
|
5,383
|
|
|
—
|
|
|
5,383
|
|
Extensions and discoveries
|
|
27,295
|
|
|
—
|
|
|
27,295
|
|
|
2,992
|
|
|
—
|
|
|
2,992
|
|
Revisions of previous estimates
|
|
778
|
|
|
—
|
|
|
778
|
|
|
308
|
|
|
—
|
|
|
308
|
|
Sales of reserves in place
|
|
(876
|
)
|
|
(5,241
|
)
|
|
(6,117
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
|
(4,231
|
)
|
|
—
|
|
|
(4,231
|
)
|
|
(531
|
)
|
|
—
|
|
|
(531
|
)
|
December 31, 2013
|
|
62,041
|
|
|
—
|
|
|
62,041
|
|
|
8,152
|
|
|
—
|
|
|
8,152
|
|
Extensions and discoveries
|
|
29,793
|
|
|
—
|
|
|
29,793
|
|
|
3,681
|
|
|
—
|
|
|
3,681
|
|
Revisions of previous estimates
|
|
3,046
|
|
|
—
|
|
|
3,046
|
|
|
1,270
|
|
|
—
|
|
|
1,270
|
|
Purchases of reserves in place
|
|
12,730
|
|
|
—
|
|
|
12,730
|
|
|
1,335
|
|
|
—
|
|
|
1,335
|
|
Production
|
|
(6,906
|
)
|
|
—
|
|
|
(6,906
|
)
|
|
(925
|
)
|
|
—
|
|
|
(925
|
)
|
December 31, 2014
|
|
100,704
|
|
|
—
|
|
|
100,704
|
|
|
13,513
|
|
|
—
|
|
|
13,513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
|
12,675
|
|
|
5,241
|
|
|
17,916
|
|
|
1,620
|
|
|
—
|
|
|
1,620
|
|
December 31, 2013
|
|
18,321
|
|
|
—
|
|
|
18,321
|
|
|
2,779
|
|
|
—
|
|
|
2,779
|
|
December 31, 2014
|
|
35,238
|
|
|
—
|
|
|
35,238
|
|
|
5,294
|
|
|
—
|
|
|
5,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
|
26,400
|
|
|
—
|
|
|
26,400
|
|
|
3,763
|
|
|
—
|
|
|
3,763
|
|
December 31, 2013
|
|
43,720
|
|
|
—
|
|
|
43,720
|
|
|
5,373
|
|
|
—
|
|
|
5,373
|
|
December 31, 2014
|
|
65,466
|
|
|
—
|
|
|
65,466
|
|
|
8,219
|
|
|
—
|
|
|
8,219
|
|
2014
|
Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation.
|
2013
|
Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation.
|
2012
|
Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation.
|
2014
|
Acquisition of proved developed and undeveloped reserves from Eagle Ford Minerals, LLC.
|
2013
|
Sales of U.K. North Sea properties to Iona Energy during the first quarter and sales of U.S. properties in East Texas in the third quarter.
|
|
|
Natural Gas (MMcf)
|
|
Oil-Equivalent Proved Reserves (MBoe)
|
||||||||||||||
|
|
U.S.
|
|
U.K.
|
|
Worldwide
|
|
U.S.
|
|
U.K.
|
|
Worldwide
|
||||||
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
January 1, 2012
|
|
722,847
|
|
|
4,838
|
|
|
727,685
|
|
|
149,697
|
|
|
6,243
|
|
|
155,940
|
|
Extensions and discoveries
|
|
72,916
|
|
|
—
|
|
|
72,916
|
|
|
29,305
|
|
|
—
|
|
|
29,305
|
|
Revisions of previous estimates
|
|
(20,996
|
)
|
|
(174
|
)
|
|
(21,170
|
)
|
|
(999
|
)
|
|
(225
|
)
|
|
(1,224
|
)
|
Sales of reserves in place
|
|
(313,483
|
)
|
|
—
|
|
|
(313,483
|
)
|
|
(53,497
|
)
|
|
—
|
|
|
(53,497
|
)
|
Production
|
|
(37,612
|
)
|
|
—
|
|
|
(37,612
|
)
|
|
(9,436
|
)
|
|
—
|
|
|
(9,436
|
)
|
December 31, 2012
|
|
423,672
|
|
|
4,664
|
|
|
428,336
|
|
|
115,070
|
|
|
6,018
|
|
|
121,088
|
|
Extensions and discoveries
|
|
73,360
|
|
|
—
|
|
|
73,360
|
|
|
42,514
|
|
|
—
|
|
|
42,514
|
|
Revisions of previous estimates
|
|
29,819
|
|
|
—
|
|
|
29,819
|
|
|
6,055
|
|
|
—
|
|
|
6,055
|
|
Sales of reserves in place
|
|
(307,472
|
)
|
|
(4,664
|
)
|
|
(312,136
|
)
|
|
(52,121
|
)
|
|
(6,018
|
)
|
|
(58,139
|
)
|
Production
|
|
(31,422
|
)
|
|
—
|
|
|
(31,422
|
)
|
|
(9,999
|
)
|
|
—
|
|
|
(9,999
|
)
|
December 31, 2013
|
|
187,957
|
|
|
—
|
|
|
187,957
|
|
|
101,519
|
|
|
—
|
|
|
101,519
|
|
Extensions and discoveries
|
|
30,343
|
|
|
—
|
|
|
30,343
|
|
|
38,531
|
|
|
—
|
|
|
38,531
|
|
Revisions of previous estimates
|
|
18,913
|
|
|
—
|
|
|
18,913
|
|
|
7,469
|
|
|
—
|
|
|
7,469
|
|
Purchases of reserves in place
|
|
8,681
|
|
|
—
|
|
|
8,681
|
|
|
15,512
|
|
|
—
|
|
|
15,512
|
|
Production
|
|
(24,877
|
)
|
|
—
|
|
|
(24,877
|
)
|
|
(11,978
|
)
|
|
—
|
|
|
(11,978
|
)
|
December 31, 2014
|
|
221,017
|
|
|
—
|
|
|
221,017
|
|
|
151,053
|
|
|
—
|
|
|
151,053
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
|
229,539
|
|
|
4,664
|
|
|
234,203
|
|
|
52,552
|
|
|
6,018
|
|
|
58,570
|
|
December 31, 2013
|
|
106,976
|
|
|
—
|
|
|
106,976
|
|
|
38,929
|
|
|
—
|
|
|
38,929
|
|
December 31, 2014
|
|
149,697
|
|
|
—
|
|
|
149,697
|
|
|
65,482
|
|
|
—
|
|
|
65,482
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
|
194,134
|
|
|
—
|
|
|
194,134
|
|
|
62,519
|
|
|
—
|
|
|
62,519
|
|
December 31, 2013
|
|
80,981
|
|
|
—
|
|
|
80,981
|
|
|
62,590
|
|
|
—
|
|
|
62,590
|
|
December 31, 2014
|
|
71,320
|
|
|
—
|
|
|
71,320
|
|
|
85,571
|
|
|
—
|
|
|
85,571
|
|
2014
|
Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Marcellus and Eagle Ford.
|
2013
|
Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Marcellus and Eagle Ford.
|
2012
|
Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett, Marcellus, and Eagle Ford.
|
2014
|
Positive price revisions in the U.S. primarily in the Marcellus.
|
2013
|
Positive price revisions in the U.S. primarily in the Marcellus.
|
2012
|
Negative price revisions in the U.S. primarily in the Barnett.
|
2014
|
Acquisition of proved developed and undeveloped reserves from Eagle Ford Minerals, LLC.
|
2013
|
Sale of U.S. properties in the Barnett Shale to EnerVest during the fourth quarter and U.K. properties to Iona during the first quarter.
|
2012
|
Sales of properties to Atlas during the second quarter and sale of Gulf Coast properties during the third quarter.
|
|
|
U.S.
|
|
U.K.
|
|
Worldwide
|
||||||
|
|
(In thousands)
|
||||||||||
2012
|
|
|
|
|
|
|
||||||
Future cash inflows
|
|
|
$4,960,687
|
|
|
|
$623,678
|
|
|
|
$5,584,365
|
|
Future production costs
|
|
(1,009,850
|
)
|
|
(87,727
|
)
|
|
(1,097,577
|
)
|
|||
Future development costs
|
|
(982,101
|
)
|
|
(11,194
|
)
|
|
(993,295
|
)
|
|||
Future income taxes
|
|
(511,790
|
)
|
|
(252,493
|
)
|
|
(764,283
|
)
|
|||
Future net cash flows
|
|
2,456,946
|
|
|
272,264
|
|
|
2,729,210
|
|
|||
Less 10% annual discount to reflect timing of cash flows
|
|
(1,277,463
|
)
|
|
(33,352
|
)
|
|
(1,310,815
|
)
|
|||
Standard measure of discounted future net cash flows
|
|
|
$1,179,483
|
|
|
|
$238,912
|
|
|
|
$1,418,395
|
|
2013
|
|
|
|
|
|
|
||||||
Future cash inflows
|
|
|
$6,936,276
|
|
|
|
$—
|
|
|
|
$6,936,276
|
|
Future production costs
|
|
(1,629,663
|
)
|
|
—
|
|
|
(1,629,663
|
)
|
|||
Future development costs
|
|
(1,340,722
|
)
|
|
—
|
|
|
(1,340,722
|
)
|
|||
Future income taxes
|
|
(835,840
|
)
|
|
—
|
|
|
(835,840
|
)
|
|||
Future net cash flows
|
|
3,130,051
|
|
|
—
|
|
|
3,130,051
|
|
|||
Less 10% annual discount to reflect timing of cash flows
|
|
(1,508,640
|
)
|
|
—
|
|
|
(1,508,640
|
)
|
|||
Standard measure of discounted future net cash flows
|
|
|
$1,621,411
|
|
|
|
$—
|
|
|
|
$1,621,411
|
|
2014
|
|
|
|
|
|
|
||||||
Future cash inflows
|
|
|
$10,380,951
|
|
|
|
$—
|
|
|
|
$10,380,951
|
|
Future production costs
|
|
(2,532,106
|
)
|
|
—
|
|
|
(2,532,106
|
)
|
|||
Future development costs
|
|
(1,680,795
|
)
|
|
—
|
|
|
(1,680,795
|
)
|
|||
Future income taxes
|
|
(1,354,524
|
)
|
|
—
|
|
|
(1,354,524
|
)
|
|||
Future net cash flows
|
|
4,813,526
|
|
|
—
|
|
|
4,813,526
|
|
|||
Less 10% annual discount to reflect timing of cash flows
|
|
(2,258,444
|
)
|
|
—
|
|
|
(2,258,444
|
)
|
|||
Standard measure of discounted future net cash flows
|
|
|
$2,555,082
|
|
|
|
$—
|
|
|
|
$2,555,082
|
|
|
|
U.S.
|
|
U.K.
|
|
Worldwide
|
||||||
|
|
(In thousands)
|
||||||||||
Standardized measure — January 1, 2012
|
|
|
$856,463
|
|
|
|
$184,573
|
|
|
|
$1,041,036
|
|
Revisions to reserves proved in prior years:
|
|
|
|
|
|
|
||||||
Net change in sales prices and production costs related to future production
|
|
(55,249
|
)
|
|
49,719
|
|
|
(5,530
|
)
|
|||
Net change in estimated future development costs
|
|
91,404
|
|
|
—
|
|
|
91,404
|
|
|||
Net change due to revisions in quantity estimates
|
|
(77,919
|
)
|
|
(46,803
|
)
|
|
(124,722
|
)
|
|||
Accretion of discount
|
|
107,451
|
|
|
37,453
|
|
|
144,904
|
|
|||
Changes in production rates (timing) and other
|
|
(3,369
|
)
|
|
(6,061
|
)
|
|
(9,430
|
)
|
|||
Total revisions
|
|
62,318
|
|
|
34,308
|
|
|
96,626
|
|
|||
Net change due to extensions and discoveries, net of estimated future development and production costs
|
|
599,544
|
|
|
—
|
|
|
599,544
|
|
|||
Net change due to sales of minerals in place
|
|
(212,910
|
)
|
|
—
|
|
|
(212,910
|
)
|
|||
Sales of oil and gas produced, net of production costs
|
|
(313,354
|
)
|
|
—
|
|
|
(313,354
|
)
|
|||
Previously estimated development costs incurred
|
|
202,187
|
|
|
32,760
|
|
|
234,947
|
|
|||
Net change in income taxes
|
|
(14,765
|
)
|
|
(12,729
|
)
|
|
(27,494
|
)
|
|||
Net change in standardized measure of discounted future net cash flows
|
|
323,020
|
|
|
54,339
|
|
|
377,359
|
|
|||
Standardized measure — December 31, 2012
|
|
|
$1,179,483
|
|
|
|
$238,912
|
|
|
|
$1,418,395
|
|
Revisions to reserves proved in prior years:
|
|
|
|
|
|
|
||||||
Net change in sales prices and production costs related to future production
|
|
(232,361
|
)
|
|
—
|
|
|
(232,361
|
)
|
|||
Net change in estimated future development costs
|
|
(10,602
|
)
|
|
—
|
|
|
(10,602
|
)
|
|||
Net change due to revisions in quantity estimates
|
|
205,686
|
|
|
—
|
|
|
205,686
|
|
|||
Accretion of discount
|
|
141,229
|
|
|
44,160
|
|
|
185,389
|
|
|||
Changes in production rates (timing) and other
|
|
56,052
|
|
|
(44,160
|
)
|
|
11,892
|
|
|||
Total revisions
|
|
160,004
|
|
|
—
|
|
|
160,004
|
|
|||
Net change due to extensions and discoveries, net of estimated future development and production costs
|
|
873,028
|
|
|
—
|
|
|
873,028
|
|
|||
Net change due to sales of minerals in place
|
|
(191,155
|
)
|
|
(441,597
|
)
|
|
(632,752
|
)
|
|||
Sales of oil and gas produced, net of production costs
|
|
(444,841
|
)
|
|
—
|
|
|
(444,841
|
)
|
|||
Previously estimated development costs incurred
|
|
217,395
|
|
|
—
|
|
|
217,395
|
|
|||
Net change in income taxes
|
|
(172,503
|
)
|
|
202,685
|
|
|
30,182
|
|
|||
Net change in standardized measure of discounted future net cash flows
|
|
441,928
|
|
|
(238,912
|
)
|
|
203,016
|
|
|||
Standardized measure — December 31, 2013
|
|
|
$1,621,411
|
|
|
|
$—
|
|
|
|
$1,621,411
|
|
Revisions to reserves proved in prior years:
|
|
|
|
|
|
|
||||||
Net change in sales prices and production costs related to future production
|
|
(240,533
|
)
|
|
—
|
|
|
(240,533
|
)
|
|||
Net change in estimated future development costs
|
|
89,401
|
|
|
—
|
|
|
89,401
|
|
|||
Net change due to revisions in quantity estimates
|
|
205,166
|
|
|
—
|
|
|
205,166
|
|
|||
Accretion of discount
|
|
202,672
|
|
|
—
|
|
|
202,672
|
|
|||
Changes in production rates (timing) and other
|
|
(61,099
|
)
|
|
—
|
|
|
(61,099
|
)
|
|||
Total revisions
|
|
195,607
|
|
|
—
|
|
|
195,607
|
|
|||
Net change due to extensions and discoveries, net of estimated future development and production costs
|
|
867,615
|
|
|
—
|
|
|
867,615
|
|
|||
Net change due to purchases of minerals in place
|
|
352,867
|
|
|
—
|
|
|
352,867
|
|
|||
Sales of oil and gas produced, net of production costs
|
|
(598,036
|
)
|
|
—
|
|
|
(598,036
|
)
|
|||
Previously estimated development costs incurred
|
|
415,963
|
|
|
—
|
|
|
415,963
|
|
|||
Net change in income taxes
|
|
(300,345
|
)
|
|
—
|
|
|
(300,345
|
)
|
|||
Net change in standardized measure of discounted future net cash flows
|
|
933,671
|
|
|
—
|
|
|
933,671
|
|
|||
Standardized measure — December 31, 2014
|
|
|
$2,555,082
|
|
|
|
$—
|
|
|
|
$2,555,082
|
|
2014
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
||||||||
|
(In thousands, except per share amounts)
|
|
||||||||||||||
Total revenues
|
|
$157,212
|
|
|
|
$193,475
|
|
|
|
$196,225
|
|
|
|
$163,275
|
|
|
Income from continuing operations
|
6,621
|
|
|
3,214
|
|
|
82,997
|
|
|
129,451
|
|
|
||||
Net income
|
|
$5,976
|
|
|
|
$2,319
|
|
|
|
$83,789
|
|
|
|
$134,259
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net income per common share - basic
|
|
|
|
|
|
|
|
|
||||||||
Income from continuing operations
|
|
$0.15
|
|
|
|
$0.07
|
|
|
|
$1.83
|
|
|
|
$2.85
|
|
|
Net income per common share
|
|
$0.13
|
|
|
|
$0.05
|
|
|
|
$1.85
|
|
|
|
$2.96
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net income per common share - diluted
|
|
|
|
|
|
|
|
|
||||||||
Income from continuing operations
|
|
$0.14
|
|
|
|
$0.07
|
|
|
|
$1.80
|
|
|
|
$2.80
|
|
|
Net income per common share
|
|
$0.13
|
|
|
|
$0.05
|
|
|
|
$1.82
|
|
|
|
$2.91
|
|
|
2013
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
||||||||
|
(In thousands, except per share amounts)
|
|
||||||||||||||
Total revenues
|
|
$111,901
|
|
|
|
$134,224
|
|
|
|
$144,329
|
|
|
|
$129,728
|
|
|
Income (loss) from continuing operations
|
2,524
|
|
|
35,837
|
|
|
5,712
|
|
|
(22,215
|
)
|
|
||||
Net income (loss)
|
|
$26,182
|
|
(1)
|
|
$36,969
|
|
|
|
$4,521
|
|
|
|
($23,989
|
)
|
(2)
|
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss) per common share - basic
|
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
|
$0.06
|
|
|
|
$0.89
|
|
|
|
$0.14
|
|
|
|
($0.52
|
)
|
(2)
|
Net income (loss) per common share
|
|
$0.66
|
|
(1)
|
|
$0.92
|
|
|
|
$0.11
|
|
|
|
($0.56
|
)
|
(2)
|
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss) per common share - diluted
|
|
|
|
|
|
|
|
|
||||||||
Income (loss) from continuing operations
|
|
$0.06
|
|
|
|
$0.88
|
|
|
|
$0.14
|
|
|
|
($0.52
|
)
|
(2)
|
Net income (loss) per common share
|
|
$0.65
|
|
(1)
|
|
$0.91
|
|
|
|
$0.11
|
|
|
|
($0.56
|
)
|
(2)
|
|
1)
|
First quarter 2013 results include the impact of pre-tax gain of
$37.3 million
related to the sale of the Company’s U.K. North Sea assets which were reported as discontinued operations.
|
2)
|
Fourth quarter 2013 results include the impact of a pre-tax loss of
$45.4 million
related to the sale of the Company’s remaining oil and gas properties in the Barnett.
|
|
|
|
|
CARRIZO OIL & GAS, INC.
|
|
|
|
|
|
By:
|
/s/ David L. Pitts
|
|
|
David L. Pitts
|
|
|
Vice President and Chief Financial Officer
|
|
|
|
|
Name
|
|
Capacity
|
Date
|
|
|
|
|
/s/ S.P. Johnson IV
|
|
President, Chief Executive Officer and Director
|
February 24, 2015
|
S. P. Johnson IV
|
|
(Principal Executive Officer)
|
|
|
|
|
|
/s/ David L. Pitts
|
|
Vice President and Chief Financial Officer
|
February 24, 2015
|
David L. Pitts
|
|
(Principal Financial Officer)
|
|
|
|
|
|
/s/ Gregory F. Conaway
|
|
Vice President and Chief Accounting Officer
|
February 24, 2015
|
Gregory F. Conaway
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
/s/ Steven A. Webster
|
|
Chairman of the Board
|
February 24, 2015
|
Steven A. Webster
|
|
|
|
|
|
|
|
/s/ Thomas L. Carter, Jr.
|
|
Director
|
February 24, 2015
|
Thomas L. Carter, Jr.
|
|
|
|
|
|
|
|
/s/ Robert F. Fulton
|
|
Director
|
February 24, 2015
|
Robert F. Fulton
|
|
|
|
|
|
|
|
/s/ F. Gardner Parker
|
|
Director
|
February 24, 2015
|
F. Gardner Parker
|
|
|
|
|
|
|
|
/s/ Roger A. Ramsey
|
|
Director
|
February 24, 2015
|
Roger A. Ramsey
|
|
|
|
|
|
|
|
/s/ Frank A. Wojtek
|
|
Director
|
February 24, 2015
|
Frank A. Wojtek
|
|
|
|
Notes
|
CUSIP Number
|
ISIN Number
|
Exchange Notes
|
144577AF0
|
US144577AF02
|
i.
|
a lump-sum cash payment equal to the product of (a) 80%, (B) the Executive’s annual base salary immediately prior to the Effective Date and (C) a fraction, the numerator of which is the number of days in calendar year 2014 through the Retirement Date and the denominator of which is 365; and
|
1.
|
I have reviewed this
Annual Report on Form 10-K
of Carrizo Oil & Gas, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 24, 2015
|
/s/ S.P. Johnson, IV
|
|
|
S.P. Johnson, IV
President and Chief Executive Officer
|
1.
|
I have reviewed this
Annual Report on Form 10-K
of Carrizo Oil & Gas, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
|
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date:
|
February 24, 2015
|
/s/ David L. Pitts
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David L. Pitts
Vice President and Chief Financial Officer
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1.
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the Company’s
Annual Report on Form 10-K for the year
ended
December 31, 2014
(the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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2.
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information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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Date:
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February 24, 2015
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/s/ S.P. Johnson, IV
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S.P. Johnson, IV
President and Chief Executive Officer
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1.
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the Company’s
Annual Report on Form 10-K for the year
ended
December 31, 2014
(the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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2.
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information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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Date:
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February 24, 2015
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/s/ David L. Pitts
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David L. Pitts
Vice President and Chief Financial Officer
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/s/ Michael F. Stell
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/s/ Stuart L. Filler
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Michael F. Stell, P.E.
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Stuart L. Filler, P.E.
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TBPE License No. 56416
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TBPE License No. 60823
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Advising Senior Vice President
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Senior Petroleum Engineer
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As of December 31, 2014
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Proved
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||||||||||||||
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Developed
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Total
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||||||||||
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Producing
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Non-Producing
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Undeveloped
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Proved
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Net Remaining Reserves
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Oil/Condensate – MBarrels
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33,624
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1,614
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65,466
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100,704
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||||
Plant Products – MBarrels
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4,987
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307
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8,219
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13,513
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Gas – MMCF
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133,170
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16,527
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71,321
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221,018
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Income Data (M$)
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Future Gross Revenue
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$3,486,038
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$197,792
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$6,229,808
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$9,913,638
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Deductions
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966,546
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37,212
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2,741,830
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3,745,588
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Future Net Income (FNI)
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$2,519,492
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$160,580
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$3,487,978
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$6,168,050
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Discounted FNI @ 10%
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$1,508,530
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$107,683
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$1,644,527
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$3,260,740
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Discounted Future Net Income (M$)
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As of December 31, 2014
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Discount Rate
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Total
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Percent
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Proved
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5
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$4,299,013
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15
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$2,611,400
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20
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$2,170,528
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25
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$1,853,180
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(1)
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completion intervals which are open at the time of the estimate, but which have not started producing;
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(2)
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wells which were shut-in for market conditions or pipeline connections; or
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(3)
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wells not capable of production for mechanical reasons.
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(i)
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Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
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