UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20092012
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period fromto
Commission file no.number: 333-134748
Chaparral Energy, Inc.
(Exact name of registrant as specified in its charter)
Delaware | 73-1590941 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
701 Cedar Lake Boulevard Oklahoma City, Oklahoma | 73114 | |
(Address of principal executive offices) | (Zip code) |
(405) 478-8770
(Registrant’s telephone number, including area code:code)
(405) 478-8770
Securities registered pursuant to Section 12(b) of the Act:
None.
Securities registered pursuant to Section 12(g) of the Act:
None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes x No ¨
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x
(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been required to file by Section 13 or 15(d) of the Securities Exchange Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934.)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer | ¨ | Accelerated Filer | ¨ | |||
Non-Accelerated Filer | x | Smaller Reporting Company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of common equity held by non-affiliates of the registrant is not determinable as such shares wereare privately placedheld and there is no public market for such shares.
1,401,376Number of shares outstanding of each of the registrant’sissuer’s classes of common stock were outstanding as of April 14, 2010.
Index to Form 10-K1, 2013:
Class | Number of shares | |||
Class A Common Stock, $0.01 par value | 73,117 | |||
Class B Common Stock, $0.01 par value | 357,882 | |||
Class C Common Stock, $0.01 par value | 209,882 | |||
Class D Common Stock, $0.01 par value | 279,999 | |||
Class E Common Stock, $0.01 par value | 504,276 | |||
Class F Common Stock, $0.01 par value | 1 | |||
Class G Common Stock, $0.01 par value | 3 |
CHAPARRAL ENERGY, INC.
Items 1. and 2. | ||||||
7 | ||||||
Item 1A. | ||||||
36 | ||||||
Item 1B. | ||||||
53 | ||||||
Item 2. | ||||||
53 | ||||||
Item 3. | ||||||
53 | ||||||
Item 4. | 53 | |||||
Item 5. | ||||||
54 | ||||||
Item 6. | ||||||
55 | ||||||
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||||
57 | ||||||
Item 7A. | ||||||
83 | ||||||
Item 8. | ||||||
86 | ||||||
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | |||||
136 | ||||||
Item 9A. | ||||||
136 | ||||||
Item 9B. | 137 | |||||
Item 10. | ||||||
137 | ||||||
Item 11. | ||||||
140 | ||||||
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | |||||
156 | ||||||
Item 13. | Certain Relationships and Related Transactions, and Director Independence | |||||
158 | ||||||
Item 14. | 159 | |||||
Item 15. | ||||||
160 | ||||||
164 |
CAUTIONARY NOTE
REGARDING FORWARD-LOOKING STATEMENTS
TheThis report includes statements contained in this report that are not purely historical are forward-looking statements. Theconstitute forward-looking statements include,within the meaning of the federal securities law. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements regarding our expectations, hopes, beliefs, intentions or strategies regarding the future. In addition, any statements that refer to projections, forecasts or other characterizations of future events or circumstances, including any underlying assumptions,generally are forward-looking statements. Theaccompanied by words such as “intend,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,“should,” “may,” “might,” “plan,” “possible,” “potential,” “predict,“seek,” “project,” “should,” “would” and“plan” or similar expressions may identifyexpressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements butare necessarily estimates reflecting the absencebest judgment of these words doessenior management, not meanguarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that a statement is not forward-looking.could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:
fluctuations in demand or the prices received for oil and natural gas;
the amount, nature and timing of capital expenditures;
drilling, completion and performance of wells;
competition and government regulations;
timing and amount of future production of oil and natural gas;
costs of exploiting and developing properties and conducting other operations, in the aggregate and on a per-unit equivalent basis;
increaseschanges in proved reserves;
operating costs and other expenses;
cash flow and anticipated liquidity;
estimates of proved reserves;
exploitation of property acquisitions; and
marketing of oil and natural gas.
The forward-looking statements contained in this report are based on our current expectations and beliefs concerning future developments and their potential effects. There can be no assurance that future developments affecting us will be those that we have anticipated.
These forward-looking statements involve a number ofrepresent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties (some of which are beyond our control) and other assumptions that mayfactors. Many of those factors are outside of our control and could cause actual results or performance to bediffer materially different from thosethe results expressed or implied by thesethose forward-looking statements. These risks and uncertainties include thoseIn addition to the risk factors described under the heading “Risk Factors.Factors,” Specifically, somethe factors that could cause actual results to differ include:
the significant amount of our debt;
worldwide supply of and demand for oil and natural gas;
volatility and declines in oil and natural gas prices;
drilling plans (including scheduled and budgeted wells);
the number, timing or results of any wells;
changes in wells operated and in reserve estimates;
• | supply of CO2; |
future growth and expansion;
future exploration;
integration of existing and new technologies into operations;
future capital expenditures (or funding thereof) and working capital;
borrowings and capital resources and liquidity;
changes in strategy and business discipline;
future tax matters;
any loss of key personnel;
future seismic data (including timing and results);
the plans for timing, interpretation and results of new or existing seismic surveys or seismic data;
geopolitical events affecting oil and natural gas prices;
outcome, effects or timing of legal proceedings;
the effect of litigation and contingencies; and
the ability to generate additional prospects.prospects; and
the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.
Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in thesethe forward-looking statements.statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.
Glossary of termsGLOSSARY OF TERMS
The terms defined in this section are used throughout this annual report on Form 10-K:
Basin | A large natural depression on the earth’s surface in which sediments generally brought by water accumulate. | |
Bbl | One stock tank barrel of 42 U.S. gallons liquid volume is used herein in reference to crude oil, condensate or natural gas liquids. | |
BBtu | One billion British thermal units. | |
Bcf | One billion cubic feet of natural gas. | |
Boe | Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil. | |
Boe/d | Barrels of oil equivalent per day. | |
Btu | British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. | |
Enhanced oil recovery (EOR) | The use of any improved recovery method, including injection of CO2 or polymer, to remove additional oil after secondary recovery. | |
Field | An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. | |
Horizontal drilling | A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval. | |
Infill wells | Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation. | |
Limestone/carbonate | A sedimentary rock composed primarily of calcium carbonate. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It can be composed of various calcium carbonate grains or chemically precipitated. It often contains variable amounts of silica, silt, and clay. It is highly soluble which often results in secondary porosity and karsting. This can vary greatly from place to place. These factors all generally make this rock type a more heterogeneous deposit than sandstone. |
MBbls | One thousand barrels of crude oil, condensate, or natural gas liquids. | |
MBoe | One thousand barrels of crude oil equivalent. | |
Mcf | One thousand cubic feet of natural gas. | |
MMBbls | One million barrels of crude oil, condensate, or natural gas liquids. | |
MMBoe | One million barrels of crude oil equivalent. | |
MMBtu | One million British thermal units. | |
MMcf | One million cubic feet of natural gas. | |
MMcf/d | ||
Net acres | The percentage of total acres an owner has out of a particular number of acres, or in a specified tract. An owner who has a 50% interest in 100 acres owns 50 net acres. | |
NYMEX | ||
PDP | Proved developed producing. | |
Play | A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves. | |
Proved developed reserves | Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. | |
Proved reserves | The quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. | |
Proved undeveloped reserves | Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. | |
PV-10 value | When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%. | |
Sandstone | A |
SEC | The Securities and Exchange Commission. | |
Secondary recovery | The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure. | |
Seismic survey | Also known as a seismograph survey, it is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations. | |
Spacing | The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies. | |
Unit | The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement. | |
Waterflood | The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process. | |
Wellbore | The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole. | |
Working interest | The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis. | |
Zone | A layer of rock which has distinct characteristics that differ from nearby layers of rock. |
Unless the context requires otherwise, references in this annual report to the “Company”, “we”, “our”, “ours”“Company,” “Chaparral,” “we,” “our,” and “us” refer to Chaparral Energy, Inc. and its subsidiaries on a consolidated basis. We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of terms” at the beginning of this annual report.
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
Overview
We are ana growing independent oil and natural gas company engagedproduction and exploitation company. Since our inception in the1988, we have increased reserves and production exploitation,primarily through property acquisitions and acquisitiondevelopment activities. Our core operations consist of drilling for and production of oil and natural gas properties. Our core areas of operation includefrom conventional and unconventional reservoirs as well as a focus on tertiary operations through enhanced oil recovery (“EOR”) projects utilizing CO2 and polymer in the Mid-Continent and Permian Basin with additional operations in the Gulf Coast, Ark-La-Tex, North Texas, and the Rocky Mountains.areas. We maintain a portfolio of proved and unproved reserves, development and exploratory drilling opportunities, and enhanced oil recovery (EOR)EOR projects.
On April 12, 2010, Starting in 2011, we sold 475,043 shares ofbegan to redirect our common stock to CCMP Capital investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”) for a purchase price of $325.0 million. In connection with the closing of the sale, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and gas properties, and is scheduled to mature on April 12, 2014. We used the proceedscapital expenditures from the saledrilling of common stockvertical wells to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing underdrilling of horizontal wells in repeatable resource plays and increased our Seventh Restated Credit Agreement. Aslevel of April 14, 2010, we had $275.3 million of availability under our Eight Restated Credit Agreement. See Note 14 to our consolidated financial statements for additional information regarding these transactions.expenditures on EOR projects.
As of December 31, 2009, based on SEC pricing as defined below,2012, we had estimated proved reserves of 141.9146.1 MMBoe with a PV-10 value of approximately $1.3$2.1 billion. These estimated proved reserves included 29.5 MMBoe of EOR reserves. Our reserves were 66%65% proved developed and 63%65% crude oil. For the year ended December 31, 2009,2012, our net average daily production was 20.925.0 MBoe, with anour estimated reserve life of 19was approximately 16 years, and our oil and natural gas revenues were $292.4 million.$509.5 million . We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value on page 24.
Our reserve estimates as of December 31, 2009 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC’sModernization of Oil and Gas Reporting. Our reserve estimates prior to December 31, 2009 were prepared using the spot price for oil and gas on the last day of the reporting period. If our reserves had been prepared based on the guidelines in effect prior to December 31, 2009, including spot prices on the last day of the reporting period of $79.36 per Bbl of oil and $5.79 per Mcf of natural gas at December 31, 2009, our estimated proved reserves would have been approximately 160.7 MMBoe with a PV-10 value of approximately $2.2 billion.26.
From 2003 to 2009,2012, our proved reserves and production grew at a compounded annual growth rate of 19%12% and 20%15%, respectively. During this period, we have grown primarily through a combination of developmental drilling and a disciplined strategy of acquiring proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We have typically pursuepursued properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. Since 2011, we have reduced the amount of costs incurred for proved property acquisitions and spent more on acquisition of leasehold acreage and exploration costs in resource plays with repeatable drilling opportunities. In 1993, we began acquiring properties with CO2 EOR potential. To date, over 72 of these propertiespotential, and we have been acquired andinitiated CO2 injection operations have been initiated in ten9 of these units.units to date. In 2005 and 2006, we completed two larger acquisitions of $152.9 million and $480.5 million, respectively, of oil and natural gas properties which contained substantial CO2 EOR potential and complemented our existing property base. We currently expect our futurelong-term growth to continue through a combination of developmental drilling, exploitation projects, and acquisitions, complemented by a modest amount of exploration activities.
Forcome from the year ended December 31, 2009, we made capital expenditures for oil and natural gas properties of $150.9 million, including $77.8 million for developmental drilling and $18.3 million for acquisitions. The majoritydevelopment of our capital expenditures for developmentalCO2 EOR operations, with our near term growth coming from drilling in 2009 were allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower-risk. We have budgeted $268.0 million for capital expenditures for oil and natural gas properties in 2010.activities.
Business StrengthsStrategy
Consistent track record of reserve additionsWe are positioned to grow our reserves and production growth.profitably through our oil focused drilling activities, primarily in our repeatable resource plays, in the near term and through our CO2 EOR projects in the long term. From 2003 to 2009,2012, we have grown proved reserves and production by a compounded annual growth rate of 19%12% and 20%15%, respectively. We have achieved thisrespectively, through a combination of drilling and acquisition success. A number of high impact wells that we expect will support our production throughout 2010 are currently being drilled and should be completed and on line during the first and second quarters of 2010. Six of these wells are located in the Texas Panhandle Atoka Wash and one is located in the Haley Area of Loving County, Texas. However, we cannot accurately predict the timing or level of future production.
Our reserve replacement ratio, which reflects our reserve additions from acquisitions, extensions and discoveries, and improved recoveries in a given period stated as a percentage of our production in the same period, has averaged 514%383% per year since 2002.from 2003 through 2012. We replaced approximately 243%, 200%, and 372%156% of our production in 2009, 2008, and 2007, respectively.
Disciplined approach to proved reserve acquisitions. We have a dedicated team that analyzes allAs part of our acquisition opportunities. This team conducts due diligence with reserve engineering on a well-by-well basis to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. The large number of acquisition opportunities we review allows us to be selective and focus on properties that we believe have the most potential for value enhancement. In 2009, 2008 and 2007, our capital expenditures for acquisitions of proved properties were $14.6 million, $39.2 million, and $41.7 million, respectively. These acquisition capital expenditures represented approximately 10%, 13%, and 18%, respectively, of our total capital expenditures and approximately 4%, 17%, and 13%, respectively, of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for those periods. We have budgeted $20.0 million, or 7% of our total capital expenditures, for acquisitions in 2010.
Property enhancement expertise. Our ability to enhance acquired properties allows us to increase their production rates and economic value. Our typical enhancements include the repair or replacement of casing and tubing, installation of plunger lifts and pumping units, installation of coiled tubing or siphon strings, compression, workovers and recompletion to new zones. Minimal amounts of investment have significantly enhanced the value of many of our properties.
Inventory of drilling locations. Based on SEC pricing for the year ended December 31, 2009 of $61.18 per Bbl of oil and $3.87 per Mcf of natural gas, we had an inventory of 1,333 proved undeveloped drilling locations.
| ||
| ||
| ||
| ||
| ||
| ||
| ||
Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. As more fully discussed in the section “Risk factors,” our actual drilling activities may change depending on the availability of financing and capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. We have experienced a high historical drilling success rate of approximately 99% on a weighted average basis during 2009, 2008 and 2007. For the year ended December 31, 2009, we spent $82.8 million of developmental drilling and exploration costs to drill 51 (48 net) operated wells and to participate in 121 (4 net) wells operated by others, representing 80% of our additions to reserves. For 2010, we have budgeted $173.0 for developmental and exploratory drilling.
Enhanced oil recovery expertise and asset. Beginning in 2000, we expanded our operations to include CO2 EOR. CO2 EOR involves the injection of CO2, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of eight engineers that have substantial expertise in CO2 EOR operations, and we also have specific software for modeling these projects. We own a 29% interest in and operate a large CO2 EOR unit in southern Oklahoma and have installed and operate a second CO2 EOR unit with a 54% interest in the Oklahoma and Texas panhandles. We began CO2 injection in our Perryton Unit in December 2006 and in our Booker Area Units in September 2009, and plan to initiate CO2 injection in our NW Camrick Unit, our North Farnsworth Unit, and our NW Velma Hoxbar Unit in 2010. At December 31, 2009, our proved reserves included nine units where CO2 EOR recovery methods are used, representing approximately 7% of our total proved reserves. In addition, we operate a polymer EOR flood in the North Burbank unit. This unit is in the early phases of a polymer EOR flood which was proven up by Phillips Petroleum Company through a pilot program in the early 1980’s before being shut down due to low prevailing oil prices at that time. We initiated polymer injection in this unit in a pilot program in December 2007. In the pilot area, we are seeing production response as production has increased from 90 Bbls of oil per day to 160 Bbls of oil per day. We plan to expand this polymer EOR program and introduce CO2 injection into this unit after acquiring a source of CO2 in this area.
Experienced management team. Mark A. Fischer, our Chief Executive Officer and founder, has operated in the oil and natural gas industry for 38 years after starting his career at Exxon Mobil Corporation as a petroleum engineer. Joe Evans, our Chief Financial Officer, has over 30 years of experience in the oil and natural gas industry. Individuals in our 23-person management team have an average of nearly 30 years of experience in the oil and natural gas industry.
Business Strategy
We seekstrategy to grow reserves and production profitably, through a balanced mix of developmental drilling, enhancements, acquisitions, EOR projects, and a modest number of exploration projects. Further, we strive to control our operations and costs and to minimize commodity price risk through a conservative financial hedging program. The principal elements of our strategy include:
Continue lower-risk developmental drilling program. During the year ended December 31, 2009, we spent approximately $77.8 million on development drilling, which represents 52% of our capital expenditures for such period. A majority of these drilling wells are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally infill or single stepout wells, which are characterized as lower risk. We currently plan to spend a total of approximately $163.0 million, or approximately 61% of our capital expenditures, on developmental drilling in 2010.
Acquire long-lived properties with enhancement opportunities. We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. During the year ended December 31, 2009, we made approximately $14.6 million of proved reserve acquisitions, or 10% of our total capital expenditures. We have budgeted $20.0 million, or 7% of our total capital expenditures, for acquisitions in 2010.
Apply technical expertise to enhance mature properties. Once we acquire a property and become the operator, we seek to maximize production through enhancement techniques and the reduction of operating costs. We have built our business around a strong engineering team with expertise in the areas where we operate. We believe retaining our own field staff and operating offices close to our properties allows us to maintain tight control over our operations. We have 21 field offices in Oklahoma, Texas and Kansas. Our personnel possess a high degree of expertise in working with lower pressure or depleted reservoirs and, as a result, are able to identify enhancement opportunities with low capital requirements such as installing a plunger lift, pumping unit or compressor, as well as returning inactive wells to production by repairing various mechanical problems. As of December 31, 2009, our reserve report included 840 shut-in and behind-pipe enhancement projects requiring total estimated capital expenditures of $69.6 million over the life of the reserves.
Expand CO2 EOR activities. As of December 31, 2009, we have accumulated interests in 72 properties in Oklahoma, Kansas, New Mexico and Texas that meet our criteria for CO2 EOR operations, and are expanding our CO2pipeline system to initiate CO2 injection in certain of these properties. We began CO2 injection in our Perryton Unit in December 2006 and in our Booker Area Units in September 2009, and plan to initiate CO2 injection in our NW Camrick Unit, our North Farnsworth Unit, and our NW Velma Hoxbar Unit in 2010. To support our existing CO2 EOR projects, we currently inject approximately 50 MMcf per day of purchased and recycled CO2 and have developed a CO2 pipeline infrastructure system with ownership interests in over 374 miles of CO2 pipelines. This consists of a 100% ownership interest in our 86-mile Borger CO2 pipeline, a 29% interest in the 120-mile Enid to Purdy CO2 pipeline, a 58% interest in the 23-mile Purdy to Velma CO2 pipeline, which we operate, and a 100% interest in the 126-mile Booker CO2 pipeline. Most of our injected CO2 is anthropogenic (man-made) CO2 which we capture from three different sources. We recently installed compression and purification facilities, on which we have applied for a patent, that are currently capturing approximately eight to ten MMcf per day of CO2 from the Arkalon ethanol plant in Liberal, Kansas. We began injecting CO2 captured from this plant into the Booker Area fields in the third quarter of 2009. After the completion of additional work, we expect these facilities to capture approximately 15 to 19 MMcf per day of CO2.
Pursue modest exploration program. During the year ended December 31, 2009, we spent $5.0 million on exploration activities. We have budgeted $10.0 million for exploration activities in 2010.
Control operations and costs. We seek to serve as operator of the wells in which we own a significant interest. As operator, we are better positioned to control the (1) timing and plans for future enhancement and exploitation efforts; (2) costs of enhancing, drilling, completing and producing the wells; and (3) marketing negotiations for our oil and natural gas production to maximize both volumes and wellhead price. As of December 31, 2009,2012, we operated properties comprising approximately 86%85% of our proved reserves. We also strive to minimize commodity price risk through our financial hedging program. The principal elements of our strategy are described further below.
Focus drilling program on repeatable resource plays. During the year ended December 31, 2012, we spent approximately $268.6 million on drilling. We consider our repeatable resource plays to include the Northern Oklahoma Mississippi Play, the Anadarko Granite Wash, the Anadarko Cleveland Sand, the Anadarko Woodford Shale, the Panhandle Marmaton, and the Bone Spring/Avalon Shale. During 2012, we spent $217.7 million of our drilling capital in these plays. Our drilling expenditures represented approximately 52% of our total capital expenditures for oil and natural gas properties and approximately 94% of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for 2012. In 2013, we currently plan to spend approximately 58% of our capital expenditures, or $234.0 million, on drilling, including $183.0 million in our repeatable resource plays mentioned above. As more fully discussed in the section “Risk factors,” our actual drilling activities may change depending on the availability of financing and capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.
Expand EOR activities. We define EOR activities as activities on properties that have proved EOR reserves, ongoing EOR operations, or that have an approved authorization for expenditure for EOR operations. As of December 31, 2012, we have 11 active EOR projects including nine units where we are actively injecting CO2 and one project at our North Burbank Unit where polymer is utilized. We plan to continue the polymer program and introduce CO2 into the North Burbank Unit in 2013. During 2012, we spent $194.0 million, which was an increase from $88.2 million in 2011 and included $52.2 million classified as exploration costs, on the development of our EOR assets. We have budgeted $137.0 million for development of our EOR assets in 2013. In 2014, our EOR capital investments are expected to increase somewhat but remain less than incurred in 2012 and should range between $75.0 million to $150.0 million in subsequent years.
CO2 used in EOR is an efficient method of producing crude oil. CO2 EOR involves the injection of CO2, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in alternating cycles to drive the oil to producing wells and control gas processing rates, a process known as water alternating gas (“WAG”). Since we commenced CO2 injection in the Camrick Unit in 2001, we have gradually increased our emphasis on EOR operations. Beginning in 2010, we have further heightened our focus on this aspect of our business. During the past decade, we have learned a significant amount about the production of CO2, transportation of CO2, and EOR operations. Our EOR operations accounted for approximately 9% of our 2012 production and approximately 20% of our proved reserves at December 31, 2012. We believe CO2-based EOR has many advantages, including: (1) it has a lower risk since we are working in fields that have substantial production histories and other historic data (i.e., known oil); (2) it provides a reasonable rate of return; and (3) we have limited competition for this type of activity in our primary EOR project areas.
Our active EOR projects are located in the Burbank area of northeast Oklahoma (“Burbank”), the Panhandle areas of Oklahoma and Texas (“Panhandle”), Central Oklahoma (“Central Oklahoma”), and the Permian Basin Area in West Texas and Southeast New Mexico (“Permian Basin Area”). In addition to our operated projects, we hold ownership interests in outside-operated CO2 projects in the Panhandle Area, and have a small ownership interest in one outside-operated active EOR property in the Permian Basin Area. We currently have a total of 74 properties that we are analyzing in regard to their CO2 EOR potential. To support our operated CO2 projects, we have CO2 supply agreements for the Panhandle and Central Oklahoma properties. We have also developed a CO2 pipeline infrastructure system with ownership interests in 405 miles (245 net) of CO2 pipelines, of which more than 328 miles are currently active. All of the CO2 injected in our operated EOR units is anthropogenic (man-made) CO2 which is captured from three different sources. A fourth source of CO2 will be added in 2013 as we begin taking CO2 from a fertilizer plant in Coffeyville, Kansas for injection in our North Burbank Unit. We believe we are the largest and one of only a few CO2 EOR operators that use exclusively anthropogenic CO2 from industrial manufacturing.
Acquire properties for future growth. In 2012, we redirected our acquisition expenditures from mature properties with enhancement opportunities to prospect acreage in areas we consider to be repeatable resource plays.
Our total acquisitions during the year ended December 31, 2012 were $48.0 million, including $1.1 million of proved reserve acquisitions, which represented approximately 0.1% of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for 2012. We have budgeted $25.0 million, or 6% of our total capital expenditures, for acquisitions in 2013. We will continue to consider individual field acquisitions that would complement our oil resource strategy.
Apply technical expertise to enhance mature properties. We seek to maximize the production and economic value of our base of mature properties through enhancement techniques and the reduction of operating costs. We have built our business around a strong engineering team with expertise in the areas where we operate. We believe retaining our own field staff and operating offices close to our properties allows us to maintain tight control over our operations. We have 25 field offices in Oklahoma, Texas, Kansas and Louisiana. Our personnel possess a high degree of expertise in working with lower pressure or depleted reservoirs and, as a result, are able to identify enhancement opportunities with low capital requirements such as installing a plunger lift, pumping unit or compressor, as well as returning inactive wells to production by repairing various mechanical problems. Minimal amounts of investment have significantly enhanced the value of many of our properties. As of December 31, 2012, our proved reserves included 840 shut-in and behind-pipe enhancement projects requiring total estimated capital expenditures of $78.6 million over the life of the reserves.
Maintain an experienced management team and strong investor support. Mark Fischer, our Chief Executive Officer and founder, has operated in the oil and natural gas industry for more than 40 years after starting his career at Exxon Mobil Corporation as a petroleum engineer. Joe Evans, our Chief Financial Officer, has over 35 years of experience in the oil and natural gas industry. Earl Reynolds, who became our Chief Operating Officer in February 2011, has 30 years of oil and natural gas production experience. Individuals in our 23-person management team have an average of 30 years of experience in the oil and natural gas industry.
CCMP Capital is a leading global private equity firm with more than 21years in the energy industry, investing approximately $1.4 billion in energy over its history. CCMP Managing Director Chris Behrens joined our board of directors in 2010. Mr. Behrens has worked in private equity for 18 years and leads CCMP Capital’s energy investment activities.
Hedge production to stabilize cash flow. Our long-lived reserves provide us with relatively predictable production. To protect cash flows that we use for on-going operations and for capital investments, and to lock in returns on acquisitions, we enter into commodity price swaps, costless collars, and basis protection swaps. We consider all these derivative instrumentsDerivative positions are adjusted in response to be economic hedgeschanges in prices and market conditions as part of an ongoing dynamic process.
Based on our year-end proved developed production, regardless of whether hedge accounting is applied. Asreserves estimated using SEC pricing as of December 31, 2009,2012, we had commodity price swaps and costless collarsderivative contracts in place for approximately 77%21% and 73%63%, respectively, of our most recent internally estimated proved developed oil and natural gas liquids and natural gas production forthrough 2014. During 2012, we received $11.8 million and in 2011 we paid $57.6 million on the net settlement of our derivative oil contracts and received $25.5 million and $34.1 million, respectively, on the net settlement of our derivative natural gas contracts through a period of increasing oil prices and decreasing natural gas prices. During 2010, through 2011. For the year ended December 31, 2009, we received net derivative settlements of $157.9 million. While our derivative activities protect our cash flows during periods of commodity price declines, we paid net derivative settlements of $51.6$40.0 million and $20.5 million for the years ended December 31, 2008 and 2007, respectively, through a period of increasing commodity prices.
During the fourth quarter of 2008, we monetized oil and natural gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32.6 million. During the first quarter of 2009, we monetized additional natural gas swaps with original settlement dates from May through October of 2009 for proceeds of $9.5 million. During the second quarter of 2009, we monetized additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. Thewhich included proceeds from theseearly derivative monetizations are included in the net settlements described above.of $7.1 million.
Properties
The following table presents our proved reserves, and PV-10 value as of December 31, 2009 and2012, average net daily production for the year ended December 31, 2009,2012, and average net daily production for the quarter ended December 31, 2012 , by our areas of operation. Reserves were estimated using a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period, unless prices were defined by contractual arrangements. Prices used as of December 31, 20092012 were estimated using SEC pricing, which was $61.18$94.71 per Bbl of oil and $3.87$2.76 per Mcf of gas.
Proved reserves as of December 31, 2009 | Average daily production (MBoe per day) Year ended December 31, 2009 | |||||||||||||
Oil (MBbl) | Natural gas (MMcf) | Total (MBoe) | Percent of total MBoe | PV-10 value ($MM) | ||||||||||
Mid-Continent | 76,837 | 208,590 | 111,602 | 78.7 | % | $ | 1,045.0 | 13.7 | ||||||
Permian Basin | 6,687 | 56,898 | 16,170 | 11.4 | % | 148.8 | 4.4 | |||||||
Gulf Coast | 1,785 | 30,300 | 6,835 | 4.8 | % | 57.3 | 1.3 | |||||||
Ark-La-Tex | 1,002 | 10,140 | 2,692 | 1.9 | % | 22.4 | 0.7 | |||||||
North Texas | 1,844 | 3,366 | 2,405 | 1.7 | % | 30.9 | 0.4 | |||||||
Rocky Mountains | 1,314 | 5,136 | 2,170 | 1.5 | % | 19.1 | 0.4 | |||||||
Total | 89,469 | 314,430 | 141,874 | 100.0 | % | $ | 1,323.5 | 20.9 | ||||||
Proved reserves as of December 31, 2012 | Average daily production (MBoe per day) Year ended December 31, 2012 | Average daily production (MBoe per day) Quarter ended December 31, 2012 | ||||||||||||||||||||||||||
Oil (MBbls)(1) | Natural gas (MMcf) | Total (MBoe) | Percent of total MBoe | PV-10 value ($MM) | ||||||||||||||||||||||||
Enhanced Oil Recovery Project Areas | 44,182 | 392 | 44,247 | 30.3 | % | $ | 705.2 | 3.7 | 4.0 | |||||||||||||||||||
Mid-Continent Area | 44,788 | 175,760 | 74,081 | 50.7 | % | 1,043.0 | 15.6 | 17.6 | ||||||||||||||||||||
Permian Basin Area | 8,731 | 47,040 | 16,571 | 11.3 | % | 185.4 | 3.3 | 3.5 | ||||||||||||||||||||
Other | 5,542 | 33,923 | 11,196 | 7.7 | % | 135.1 | 2.4 | 2.1 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||
Total | 103,243 | 257,115 | 146,095 | 100.0 | % | $ | 2,068.7 | 25.0 | 27.2 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) | Includes natural gas liquids. |
Our properties have relatively long reserve lives and highly predictable production profiles. In general, these properties have extensive production histories and production enhancement opportunities. While our portfolio of oil and natural gas properties is geographically diversified, 87% of our 2009 production was concentrated in our two core areas, which allows for substantial economies of scale in production and cost effective application of reservoir management techniques. As of December 31, 2009,2012, we owned interests in 8,1748,243 gross (2,807(2,843 net) producing wells and we operated wells representing approximately 86%85% of our proved reserves. The high proportion of reserves in our operated properties allows us to exercise more control over expenses, capital allocations and the timing of development and exploitation activities in our fields.
Mid-ContinentEnhanced Oil Recovery Project Areas
The Mid-Continent Area is the larger of our two core areasOur EOR Project Areas include both EOR activities and ongoing non-EOR activities, as of December 31, 2009, accounted for 79% of our proved reserves and 79% of our PV-10 value. We own a working interest in 5,392 producing wellsreflected in the Mid-Continent Area, of which we operate 2,100. The Mid-Continent Area has nine of our top ten largest plays in terms of PV-10 value. During the year ended December 31, 2009, our net average daily production in the Mid-Continent Area was approximately 13.7 MBoe per day, or 66% of our total net average daily production. This area is characterized by stable, long-life, shallow decline reserves. We produce and drill in most of the basins in the region and have significant holdings and activity in the areas described below.
As of and for the year ended December 31, 2012 | EOR | Non-EOR | Total for EOR Project Areas | |||||||||
Reserves (MBoe) | 29,450 | 14,797 | 44,247 | |||||||||
Production (Boe/d) | 2,246 | 1,503 | 3,749 | |||||||||
Drilling and enhancements (in thousands) | $ | 193,959 | $ | 108 | $ | 194,067 |
North Burbank Unit—Osage County, Oklahoma. The North Burbank Unit is our largest property. The unit was developed in the early 1920’s, is 23,080 acres in size and has cumulative production of approximately 317.1 MMBbls of oil (primary and secondary). The North Burbank Unit accounted for 27.2 MMBoe of our proved reserves and $187.1 million of our PV-10 value as of December 31, 2009, and 566 (492 net) MBoe of our production for the year ended December 31, 2009. The producing zones are the Red Fork and Bartlesville and occur at a depth of 3,000 feet. We own a 99% working interest in and are also the operator of this unit. As of December 31, 2009, the field was producing approximately 1,531 (1,330 net) Bbls of oil per day from 285 producing wells. There are also 201 active service wells and 469 temporarily abandoned wells at December 31, 2009. Upside potential exists in restoring a majority of the temporarily abandoned wells to production and in reinstituting the polymer EOR program that Phillips Petroleum Company instituted in the field from 1980 to 1986 as a project on 1,440 acres called “Block A.” Production increased from 500 Bbls of oil per day to 1,200 Bbls of oil per day in this project area as a result of the polymer injection program. The project was shut down in 1986 due to low oil prices. We reinstituted a polymer flood on 485 acres adjacent to Block A on a 19-well pattern in December 2007. Production has increased in this pilot area from approximately 90 Bbls of oil per day to approximately 160 Bbls of oil per day as of December 31, 2009. Since taking over the field on November 1, 2006, we have returned 99 temporarily abandoned wells to production with initial rates of production as high as 29 Bbls of oil per day. We believe that this field also may have upside with the injection of CO2.
Osage-Creek Area—Osage and Creek Counties, Oklahoma. The Osage-Creek area accounted for 16.2 MMBoe of our proved reserves and $228.1 million of our PV-10 value at December 31, 2009, and 846 (625 net) MBoe of our production for the year ended December 31, 2009. The majority of our recent activity has been in Osage County, with the largest portion of that being in our South Burbank Unit.
The South Burbank Unit is the southward extension of the “Stanley Stringer” sand development and lies to the south of the North Burbank Unit and covers 2,720 acres. It was discovered in 1934 and unitized in 1935. The South Burbank Unit has produced 56.9 MMBbls of oil from the Burbank Sand from both primary and secondary recovery efforts. The Burbank Sand occurs at a depth of 2,850 feet. Recently, we have been drilling infillactively implementing and stepout locations in the unit area for both the Mississippi Chat, which occurs some 50 feet below the Burbank Sand, and to the Burbank Sand. It is currently estimated that the Mississippi Chat may be productive under a significant portion of the southern half of the South Burbank Unit. Seventeen wells have been drilled in the South Burbank Unit in 2009. Ten wells have been completed in the Burbank Sand with initial potentials ranging between 5 and 150 Bbls of oil per day. Seven wells are completed and produce from the Mississippi Chat with initial potentials as high as 210 Bbls of oil per day and 100 Mcf of gas per day. Any well drilled inside the South Burbank Unit is being developed with a pattern and spacing plan that will maximize any future EOR efforts.
Numerous other properties throughout Osage and Creek Counties are held by production and hold significant upside development potential. Recent new drilling activity outside of the South Burbank Unit has focused on the Mississippi Chat and Burbank reservoirs. We currently have a Company-owned drilling rig working full time in this area. Many of our Osage County units in which we have a large working interest also hold promise for future EOR efforts.
Camrick Area—Beaver and Texas Counties, Oklahoma and Ochiltree County, Texas. The Camrick area accounted for 7.8 MMBoe of our proved reserves and $89.7 million of our PV-10 value at December 31, 2009. This area consists of three unitized fields, the Camrick Unit, which covers 9,168 acres, the NW Camrick Unit, which covers 2,980 acres and the Perryton Unit, which covers 2,508 acres. We currently operate these three units with an average working interest of 54%. Production in the Camrick area is from the Morrow reservoir that occurs between the depths of 6,900 and 7,500 feet. The three units have produced approximately 16.6 MMBbls of primary reserves and approximately 13.6 MMBbls of secondary reserves. There were 55 active producing wells in this area that produced 507 (249 net) MBbls during the year ended December 31, 2009. Currently, CO2 injection operations are continuing in the Phase I, II and III areas of the Camrick Unit and the Perryton Unit. CO2 injection has improved the gross production in the Camrick Area from approximately 115 Bbls of oil per day in 2001 from 11 wells to approximately 1,443 (710 net) Bbls of oil per day from 55 producing wells as of December 31, 2009. We plan to continue expansion of CO2 injection operations across all of the units.
Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma. SWAGSU accounted for 5.5 MMBoe of our proved reserves and $47.4 million of our PV-10 value at December 31, 2009, and 423 (368 net) MBoe of our production for the year ended December 31, 2009. SWAGSU encompasses approximately 9,520 acres with production from the Gibson Sand, which occurs between the depths of 6,500 and 7,200 feet. We currently operate this unit with an average working interest of 99%. The field has produced approximately 40.3 MMBbls of oil and 262.5 Bcf of natural gas since its discovery in 1946. The field was unitized in 1948 and began unitized production as a pressure maintenance operation, utilizing selective production (based on gas/oil ratios) and gas injection. Water injection began in 1952. Gas injection ceased in 1960 without significant blowdown of the injected gas. Field shutdown and plugging activities began in 1965, and all water injection ceased in 1970. A program is currently underway to re-enter abandoned wells and drill new wells to produce the injected gas. We have 37 active producing wells in this unit as of December 31, 2009. We drilled one well in this area in 2009.
Sycamore Unit—Carter County, Oklahoma. The Sycamore Unit, which is 2,120 acres, was discovered in 1950 and unitized in 1973. A three stage development of the Sycamore Unit began in 1975 and was completed in 1992. This unit accounted for 2.8 MMBoe of our proved reserves and $40.9 million of our PV-10 value at December 31, 2009, and 243 (158 net) MBoe of our production for the year ended December 31, 2009. We operate this unit with a working interest of approximately 76%. Producing zones include the Deese and Sycamore, which occur at depths between approximately 2,500 and 4,900 feet. Cumulative production is 11.0 MMBbls of oil and, as of December 31, 2009, the unit has 107 producing wells and 44 active service wells. The unit is currently producing approximately 560 (363 net) Bbls of oil per day.
Cleveland Sand Area—Ellis, Custer, and Dewey Counties, Oklahoma and Lipscomb County, Texas. The Cleveland Sand Area accounted for 4.9 MMBoe of our proved reserves and $38.7 million of our PV-10 value as of December 31, 2009, and 439 (242 net) MBoe of our production for the year ended December 31, 2009. This area includes the West Shattuck Cleveland Sand Play and the Aledo Bray Cleveland Sand Play.
We own approximately 6,864 net acres in the West Shattuck Cleveland Sand Play, which is located in Ellis County, Oklahoma and Lipscomb County, Texas. The Cleveland Sand occurs at depths between 7,900 and 8,300 feet and is considered a tight gas sand reservoir. As of December 31, 2009, we own interests in 27 Cleveland Sand producing wells. We participated in the drilling of one well in 2009. We employed horizontal drilling technology in most of our drilled wells in this area.
We own approximately 2,135 net acres in the Aledo Bray Cleveland Sand Play, which is located in Custer and Dewey Counties, Oklahoma. The Cleveland Sand occurs at 9,700 feet and is considered a tight gas sand reservoir. As of December 31, 2009, we own interests in two Aledo Bray vertical producing wells. We drilled one horizontal well in this play during 2009.
Granite Wash and Atoka Wash Areas—Washita County, Oklahoma and Wheeler County, Texas.The Granite Wash and Atoka Wash Areas accounted for 2.9 MMBoe of our proved reserves and $27.4 million of our PV-10 value as of December 31, 2009, and 781 (238 net) MBoe of our production for the year ended December 31, 2009. We have ongoing drilling activity in both these play areas.
The objective target of the Colony Granite Wash Horizontal Play, which is in Washita County, Oklahoma, is the Des Moinesian Granite Wash zones at an average depth of approximately 12,500 feet. To date, this play has encompassed an area approximately three townships in size. The Granite Wash is a quartz rich alluvial wash containing high concentrations of feldspar that results in reducing permeability and therefore reducing ultimate recoveries. Conventional vertical well bores in this area have recovered on average approximately 1.5 Bcfe. The technological advances of horizontal drilling allow maximum exposure of this tight gas filled reservoir to the well bore (most horizontal wells are drilled up to 4,800 feet horizontally in the Granite Wash), resulting in substantially improved recoveries that are currently estimated to be up to three to four times the recoveries of the typical vertical well in this play. We drilled and/or participated in the drilling of seven Colony Granite Wash wells in 2009.
The objective target of the Granite Wash and Atoka Wash Play, which is in Wheeler County, Texas, is the Des Moinesian Granite Wash and Atoka Wash zones at average depths ranging from approximately 12,600 feet to 14,500 feet. To date, this play has encompassed an area approximately two townships in size. The Granite Wash is a quartz rich alluvial wash containing high concentrations of feldspar that results in reducing permeability and therefore reducing ultimate recoveries. Conventional vertical well bores in this area have recovered on average approximately 1.5 Bcfe. The early Atoka Granite Wash is typically a carbonate wash sourced from the carbonates of the Wichita/Amarillo Uplift. The later Atoka Wash as found in the Britt area is an Arkosic wash with quartz with potassium and sodium feldspars. Other minerals present are calcite, dolomite, illite, and chlorite. The Britt Atoka Wash is producing a dryer gas with less condensate then the younger Des Moines Wash. The technological advances of horizontal drilling allow maximum exposure of this tight gas filled reservoir to the well bore (most horizontal wells utilize a lateral drilled up to 4,800 feet horizontally in the Granite Wash and Atoka Wash), resulting in substantially improved recoveries that are currently estimated to be up to three to four times the recoveries of the typical vertical well in this play. We participated in the drilling of six Atoka Wash wells in 2009. All of these wells were completed during the first quarter of 2010 and had initial producing rates of between 15 and 23 MMcf of gas per day.
Anadarko Basin Woodford Shale Play-Western Oklahoma. As of December 31, 2009, we have a significant acreage position in the emerging Woodford Shale Resource Play of western Oklahoma. We own and control approximately 68,780 gross acres and 22,270 net acres, which primarily are held by production from other formations. The Woodford Shale beneath our acreage ranges in thickness from approximately 80 to 280 feet thick at depths from 9,500 feet to 16,000 feet. The horizontal development of this non-conventional resource play began in 2007 in Canadian County and has expanded to include the nearby counties of Blaine, Grady and Caddo with approximately 100 Woodford targeted wells drilled to date. Natural gas in place is estimated to be between 120 to 160 Bcf per section with initial development well density to be four wells per section. The average recovery is expected to be four to six Bcf per well at an average cost of seven to nine million dollars. We participated in the drilling of two wells in this play during 2009, and an additional well in which we own a working interest was completed in the first quarter of 2010. These wells have reported initial daily production rates in the range of one to seven MMcf of natural gas per day per well.
Velma Sims Unit CO2 Flood—Stephens County, Oklahoma. The EVWB Sims Sand Unit accounted for 1.9 MMBoe of our proved reserves and $16.0 million of our PV-10 value as of December 31, 2009, and 342 (88 net) MBoe of our production for the year ended December 31, 2009. This unit, which covers approximately 1,300 acres, was discovered in 1949 and unitized in 1962. We currently operate this unit with an average working interest of 29%. Hydrocarbon gas injection into the Sims C2 Sand was initiated in the top of the structure in 1962. Waterflood operations began in 1972. Hydrocarbon gas injection ended around 1977 and a miscible CO 2 injection program was initiated in 1982. This miscible CO2 injection was first begun in the updip portion of the reservoir and in 1990 expanded into the mid-section area of the Sims C2 reservoir. In 1996, miscible CO2 injection began in the downdip section of the Sims C2. As of December 31, 2009, we had 43 active producing wells in this unit.
Fox Deese Springer Unit—Carter County, Oklahoma. The Fox Deese Springer Unit, which is 2,335 acres, was discovered in 1915 and unitized in 1977. This unit accounted for 4.7 MMBoe of our proved reserves and $39.8 million of our PV-10 value at December 31, 2009, and 138 (94 net) MBoe of our production for the year ended December 31, 2009. We operate this unit with a working interest of 82%. Producing zones include the Deese, Sims, and Morris, which occur at depths between 3,300 and 5,500 feet. Cumulative production is 12.6 MMBbls of oil and, as of December 31, 2009, the unit has 62 producing wells and 48 active service wells. The unit is currently producing approximately 330 (224 net) Bbls of oil per day.
Sivells Bend Unit—Cooke County, Texas. The Sivells Bend Unit is 3,863 acres in size, produces primarily from the Strawn, which occurs at depths between 6,200 and 7,000 feet, and has recovered 39.4 MMBbls of oil to date. This unit accounted for 2.6 MMBoe of our proved reserves and $35.9 million of our PV-10 value at December 31, 2009, and 83 (48 net) MBoe of our production for the year ended December 31, 2009. There are currently 26 producing wells and 14 active service wells, with production of approximately 218 (126 net) Bbls of oil per day. We operate the field with a working interest of 65%. Upside potential exists in increased density drilling from 80 acres to 40 acres in the Strawn. The only 40-acre increased density well drilled in the unit has recovered over 390 MBbls of oil. Additional potential exists in deeper Ellenburger, as an Ellenburger well tested approximately 193 Bbls of oil per day in 1964 in the adjacent East Sivells Bend Unit, and one well in our unit tested 104 Bbls of oil per day for a short time. 3-D seismic will be required to better define the fault blocks for an Ellenburger test. We own approximately 1,000 acres of fee minerals in this Sivells Bend Unit and own approximately half of the rights below the Strawn, which includes the Ellenburger.
CO2 EOR—Various counties, Oklahoma, Kansas, New Mexico and Texas. As of December 31, 2009, we have accumulated interests in 72 properties in Oklahoma, Kansas, New Mexico and Texas that meet our criteria formanaging CO2 EOR operations. Thesein the Panhandle and Central Oklahoma Areas since 2001. We now have CO2 EOR projects accounted for 6.2 MMBoe ofsupply agreements in place in the Burbank, Panhandle, and Central Oklahoma Areas, and we have built and/or expanded CO2 pipelines to reach our proved reservesvarious field locations in the Panhandle and $80.2 million of our PV-10 value as of December 31, 2009, and 1,512 (449 net) MBoe of our production for the year ended December 31, 2009. We own a 100% interest in our 86-mile BorgerCentral Oklahoma Areas. The CO2 pipeline a 29% interest inreaching the 120-mile Enid to Purdy CO2 pipeline, a 58% interest inBurbank Area is scheduled for completion near the 23-mile Purdy to Velma CO2 pipeline, which we operate, and a 100% interest in approximately 126 milesend of pipeline that includes a CO2 pipeline located between Liberal, Kansas and Booker, Texas as well as additional pipeline extensions in the SW Kansas and Texas Panhandle areas. We initiated CO2 injection in three Booker units in 2009, and plan to expand CO2 injections into our NW Camrick Unit, our North Farnsworth Unit, and our NW Velma Hoxbar Unit in 2010. As of December 31, 2009, we had in place transportation and supply agreements to provide the necessary CO2 for these projects. We have installed compression and purification facilities that are currently capturing approximately eight to ten MMcf per day of CO2 from the Arkalon ethanol plant in Liberal, Kansas. We initiated injection of CO2 captured from this facility into the Booker area fields in the thirdfirst quarter of 2009. After the completion of additional work, we expect these facilities to capture approximately 15 to 19 MMcf per day of CO2.
2013. Arrangements to secure additional sources of CO2 for potential future projects are currently in process. The U.S. Department of Energy-OfficeEnergy–Office of Fossil Energy provided a report in February 2006 estimating that significant oil reserves could be technicallyeconomically recovered in the State of Oklahoma and Texas through CO2 EOR processes. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of those reserves.
CO2 miscible flooding is implemented and managed as a closed system consisting of the reservoir and surface piping. The physical material balance of the system means that the CO2 is produced and recycled many times once it has been injected. Combined with the incoming purchased CO2 supply, the recycled CO2 supply allows us to systematically develop additional flood patterns in contiguous acreage to the active patterns. If larger volumes of CO2 become available, projects can be developed on accelerated timelines, while a more limited supply dictates a prolonged expansion. Due to the size of our EOR projects, the fixed rate of CO2 availability which is secured for the long-term period, and the limitation of third party services, we expect the development of our EOR projects will extend beyond five years in many cases. Our significant active EOR projects are discussed below.
Burbank Area
North Burbank Unit. As of December 31, 2012, the North Burbank Unit, which is our largest property, accounted for 28.7 MMBoe, or 20% of our proved reserves, including 14.1 MMBoe of proved undeveloped polymer EOR reserves. The producing zones are the Red Fork and Bartlesville formations and occur at a depth of approximately 3,000 feet. We own a 99% working interest in and are also the operator of this Unit. Our net average daily production from this Unit decreased by 7% from 1,455 Boe/d in 2011 to approximately 1,347 Boe/d in 2012, of which 46% or 49 Boe/d was due to a scheduled shut-in while we raised pressure in the Phase I Area, the northwestern sector of the field. As of December 31, 2012, we had 296 (294 net) producing wells, 243 active injection wells, and 471 shut-in and temporarily abandoned wells in this Unit. Upside potential exists in restoring a majority of the temporarily abandoned wells to production, expanding the polymer injection EOR program, and initiating CO2 EOR operations. Due to the size of the North Burbank Unit, there is insufficient fresh water and third party services available to complete the development of the North Burbank Unit within five years, and as a result the development of the North Burbank Unit will be an ongoing project.
Phillips Petroleum Company instituted a polymer flood in their “Block A” polymer project that originally covered 1,440 acres. Production increased from 500 Bbls of oil per day to 1,200 Bbls of oil per day in this original project area. The Phillips project was shut down in 1986 due to low oil prices.
In December 2007, we expanded a polymer flood into the Phase I area of the North Burbank Unit, which consists of 485 acres adjacent to Block A on a 19-well pattern. During 2010, we completed a review of this project, and the results of this review confirm that injection of polymer is successful in recovering commercial quantities of tertiary oil from the North Burbank Unit. Production has increased in this area from approximately 90 (78 net) Bbls of oil per day in 2008 to approximately 152 (132 net) Bbls of oil per day during 2012. Our review also indicated that additional oil recovery may be obtained with additional volumes of polymer injected into the Phase I area. We implemented this additional injection into the Phase I area in 2011 and continued injection during 2012.
We have scheduled expansion of the polymer project from the Phase I area into Phase II during 2014 with development of remaining phases to follow in future years as a sufficient volume of fresh water becomes available. We are also developing a Phase I CO2 flood as we believe the field to have additional upside with the injection of CO2. On March 24, 2011, we signed a 20-year contract with renewal options to purchase up to 100% of CO2 emissions from an existing nitrogen fertilizer plant in Coffeyville, Kansas that produces approximately 42 MMcf/d of CO2. In early 2013, we expect completion of gathering and compression facilities at Coffeyville and a 68-mile pipeline to transport the CO2 to the Burbank field. Beginning no later than July 2013, and assuming the fertilizer plant produces and delivers a specified quality of CO2, we will be obligated to purchase an average of approximately 24 MMcf/d the first year of the contract and 35 MMcf/d for the remaining contract years or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. After the first ten contract years, we may permanently reduce up to 100% of our purchase rate under this contract with six months’ notice. We expect to purchase an average of approximately 24 MMcf/d of CO2 under this contract starting in the second quarter of 2013 for injection into our North Burbank Unit. As a result of our success with polymer and additional technical analysis of the same, we are evaluating augmentation of our developing CO2-EOR project to include polymer during periods of water injection within WAG cycles.
Our total investment in the North Burbank Unit during 2012, including expenditures associated with construction of the CO2 compression facilities and pipeline, drilling two service wells, and reactivating 33 wells, was $141.0 million. Approximately $87.3 million of our capital expenditures budget for 2013 has been allocated for EOR operations in the North Burbank Unit.
Panhandle Area
Camrick Area Units. As of December 31, 2012, the Camrick Area Units accounted for 6.0 MMBoe, or 4% of our proved reserves, substantially all of which are considered EOR reserves. Approximately 2.8 MMBoe of the proved reserves in this area are undeveloped. The Camrick Area Units consist of three units, which we operate: the Camrick Unit, where we began CO2 injection in 2001; the North Perryton Unit, where we began CO2 injection in 2006; and the NW Camrick Unit, which will be initiated as recycled CO2 volumes become available from the other two Units. Currently, CO2 injection operations are continuing in the Phase I and II areas of the Camrick Unit and within the North Perryton Unit. As of December 31, 2012, we had 62 (37 net) producing wells, 47 active water injection wells, and 41 temporarily abandoned wells in this area. During the third quarter of 2010, we acquired an additional 6% working interest in these reserves.three Units, thereby increasing our average working interest to 60%. Our net average daily production from this area increased 4% to 1,006 Boe/d in 2012 compared to 966 Boe/d in 2011, which was a 7% increase compared to 902 Boe/d in 2010.
We have a long-term contract to purchase up to approximately 20 MMcf/d of CO2 produced at an existing nitrogen fertilizer plant in Borger, Texas. The fertilizer plant reserves the right to install additional equipment and use some of the CO2 to make certain fertilizer products, which could reduce our CO2 purchases. We own 100% of and operate the 74-mile Borger CO2 Pipeline, which transports CO2 from the fertilizer plant to the Camrick Area Units. As of December 31, 2012, we were injecting a combined 18 MMcf/d of purchased and recycled CO2 in this area.
Our total investment in the Camrick Area Units during 2012, including the purchase of CO2 for injection, the drilling and completion of three wells, and general well work, was $12.0 million. We have allocated approximately $8.8 million of our capital expenditures budget for 2013 to this area for continued purchase of CO2, drilling and completions, compression expansion, electrical upgrades, and remedial well work.
Farnsworth Unit. The Farnsworth Unit, which lies to the southeast of and is analogous to the Camrick Area Units, accounted for 6.4 MMBoe, or 4% of our proved reserves, at December 31, 2012. All of the reserves in this Unit, which includes 3.5 MMBoe of proved undeveloped reserves, are considered EOR reserves as of December 31, 2012. We acquired a 99% working interest in the Farnsworth Unit in November 2009 and we began CO2 injection in December 2010. CO2 injection has improved production in the Unit from approximately 394 (314 net) Bbls of oil per day in December 2011 to approximately 1,093 (870 net) Bbls of oil per day in December 2012. As of December 31, 2012, we had 23 producing wells, 18 active water and CO2 injection wells, and 44 shut-in and temporarily abandoned wells in the Unit. Our net average daily production from this Unit increased 184% to 475 Boe/d in 2012 compared to 167 Boe/d in 2011, which was a 56% increase compared to 107 Boe/d in 2010.
We have a long-term contract to purchase up to approximately 15 MMcf/d of CO2 produced at the Arkalon ethanol plant near Liberal, Kansas. We have installed compression and purification facilities that are capturing approximately 14 MMcf/d of CO2 from this plant as of December 31, 2012. We own 100% of and operate the 95-mile TexOk CO2 Pipeline that includes a CO2 pipeline located between Liberal, Kansas and Spearman, Texas. During 2010, we built a 14-mile pipeline extension through the Farnsworth Unit, connecting the TexOk CO2 Pipeline and the Borger CO2 Pipeline to allow flexibility in delivering CO2 to the Farnsworth Unit and future projects. We completed the final tie-in of this extension in the first quarter of 2011. As of December 31, 2012, we were injecting approximately 12 MMcf/d of purchased and recycled CO2 in the Farnsworth Unit.
During 2012, we invested $21.6 million in the Farnsworth Unit to drill two wells, return four production and injection wells to service, complete associated field facilities work, and completed modifications at Arkalon. We have allocated approximately $23.6 million of our capital expenditures budget for 2013 to this Unit for the continued development of the CO2 project and related field facilities.
Booker Area Units. As of December 31, 2012, the Booker Area Units accounted for 0.9 MMBoe of our proved reserves, all of which are developed. In September 2009, we began CO2 injection into our three Booker Area Units, which we operate with an average working interest of 99%. As of December 31, 2012, we had 12 producing wells, six active water and CO2 injection wells, and three shut-in and temporarily abandoned wells in the Unit. Our net average daily production from this area increased 473% to 402 Boe/d in 2012 compared to 70 Boe/d in 2011, which was a 55% increase compared to 45 Boe/d in 2010. Our total investment in the Booker Area Units during 2012 was $9.9 million, primarily spent on CO2 purchases. We have allocated approximately $9.6 million of our capital expenditures budget for 2013 to this area.
Permian Basin Area
We have identified and own several potential projects in the West Texas and Southeast New Mexico area. Currently, we do not have active operated CO2 EOR projects, and have a small ownership interest in one outside-operated active EOR property, the Adair San Andres Unit in this area.
Permian BasinMid-Continent Area
The Permian Basin Area is the second of our two core areas and, asAs of December 31, 2009,2012, the Mid-Continent Area accounted for 11%74.1 MMBoe, or 51% of our proved reserves and 11% of our PV-10 value. We own a working interest in 1,693 producing wells in the Permian Basin, of which we operate 318. The Permian Basin Area has one of our top ten plays in terms of PV-10 value.reserves. During the year ended December 31, 2009,2012, our net average daily production in the Mid-Continent Area was approximately 15.6 MBoe per day, or 62% of our total net average daily production. This Area is characterized by stable, long-life, shallow decline reserves. We produce and drill in most of the formations in the region and have significant holdings and activity in the areas described below.
Northern Oklahoma Mississippi Play (“NOMP”)—Various Counties, Oklahoma. The Northern Oklahoma Mississippi Play, as currently defined, spans from Woodward and Harper, Oklahoma counties on the west to Washington, Tulsa and Okmulgee, Oklahoma counties on the east and northward into Kansas.
We refer to the western portion of Osage County and the other counties of Northern Oklahoma as NOMP Core. This area has a long history of production from vertical wells and a well-developed infrastructure system to support further development. Several companies in the industry are devoting large amounts of capital toward leasing and horizontal drilling activities in further developing this shallow, cost-effective play. Leasing in the NOMP Core has become increasingly competitive as the play continues to yield positive results. During 2012, we spent $11.1 million on leasehold acquisitions, increasing our acreage position to approximately 117,000 acres for the NOMP Core portion of the play.
The NOMP Core accounted for 7.2 MMBoe, or 5% of our proved reserves as of December 31, 2012. Primarily as a result of our drilling activity, our net average daily production from this area has increased significantly to approximately 1,409 Boe/d in 2012 compared to 307 Boe/d in 2011. During 2012, we spent $85.8 million on developmental and exploratory activities in the NOMP Core. We drilled and/or participated in the drilling of 32 (16 net) horizontal wells that were completed during 2012. Our drilling activity for 2013 will continue to focus on the NOMP Core area with plans to drill and/or participate in the drilling of 25 wells. We have allocated approximately $78.3 million of our 2013 drilling budget to this portion of the play.
We consider the eastern portion of Osage County as NOMP Emerging. During the third quarter of 2011, we paid $1.5 million for an exclusive Concession Agreement with the Osage Minerals Council to lease and potentially develop oil and natural gas rights on 217,000 acres in Osage County, Oklahoma through June 30, 2014. This includes approximately 138,000 acres currently available to us, of which 16,112 acres are under active leases. The Concession Agreement provides for a 20% royalty payment to the Osage Indian Nation and a drilling commitment by us to drill a minimum number of wells in each of the three years covered by the Concession Agreement, for a total of 61 wells. During 2012, by virtue of our exclusive Concession Agreement we spent $1.8 million on lease acquisitions increasing our leased acreage from 2,400 acres in 2011 to 16,112 acres in NOMP Emerging. Our acreage position in NOMP Emerging outside the Concession Agreement is approximately 40,000 acres.
NOMP Emerging accounted for 0.5 MMBoe, or 0.4% of our proved reserves as of December 31, 2012. During 2012, we spent $23.5 million on developmental and exploratory activities in NOMP Emerging, which includes the area covered by the Concession Agreement. We drilled five horizontal wells that were completed during 2012.
Osage-Creek Area—Osage, Creek, and Kay Counties, Oklahoma. The Osage-Creek area accounted for 14.4 MMBoe, or 10%, of our proved reserves as of December 31, 2012. Our net average daily production from this area decreased by 6% to approximately 2,155 Boe/d in 2012 compared to 2,302 Boe/d in 2011 and 2,376 Boe/d in 2010, primarily due to normal production decline. The majority of our recent activity has been in Osage County, with the largest portion of that being in our South Burbank Unit, which is the southward extension of the “Stanley Stringer” sand development and lies to the south of the North Burbank Unit. Any well drilled inside the South Burbank Unit is being developed with a pattern and spacing plan that will maximize any future EOR efforts. Numerous other properties throughout Osage and Creek Counties are held by production and hold significant upside development potential. Many of our Osage County units in which we have a large working interest also hold promise for future EOR efforts. Our drilling investment was $3.7 million and we drilled three wells in this area during 2012. We have not allocated any significant amount of our 2013 drilling budget to this area.
Anadarko Granite Wash Play Area—Oklahoma and Texas.The Granite Wash Play area accounted for 6.4 MMBoe, or 4% of our proved reserves as of December 31, 2012. Objective targets in this area include the Des Moinesian Granite Wash and Atoka Wash zones at average depths ranging from approximately 12,500 feet to 14,500 feet. The technological advances of horizontal drilling allow maximum exposure of this low permeability reservoir to the well bore (most horizontal wells are drilled up to 4,800 feet horizontally in the Granite Wash and Atoka Wash), resulting in substantially improved recoveries.
We drilled and/or participated in the drilling of 10 (two net) Granite Wash horizontal wells that were completed during 2012. Our net average daily production from this area decreased by 2% to approximately 2,291 Boe/d in 2012 from 2,329 in 2011, which was 27% higher than 1,839 Boe/d in 2010, primarily due to the normal decline curve on this type of well. During 2012, our drilling investment in this area was $24.2 million and we have allocated approximately $7.7 million of our 2013 drilling budget to this area.
Anadarko Hogshooter Wash Play Area-Oklahoma and Texas. The Hogshooter Wash Play area was identified during 2012 and is located in the Anadarko Basin of the Texas Panhandle and western Oklahoma. The Hogshooter Wash Play accounted for 0.3 MMBoe, or 0.2% of our proved reserves as December 31, 2012. We drilled and/or participated in drilling four (one net) Hogshooter Wash horizontal wells that were completed during 2012. Production was 446 Boe/d as of December 31, 2012 and approximately 238 Boe/d for the 2012 average. Our drilling investment in this area was $7.0 million and we have not allocated any significant amount of our 2013 drilling budget to this area.
Anadarko Cleveland Sand Play Area—Oklahoma and Texas.The Cleveland Sand Play area accounted for 6.6 MMBoe, or 4.5% of our proved reserves as of December 31, 2012. This area includes the West Shattuck Cleveland Sand Play and the Aledo Bray Cleveland Sand Play, both of which are considered tight liquids rich sand reservoirs. We drilled and/or participated in the drilling of 12 (seven net) Cleveland Sand horizontal wells that were completed during 2012. Primarily as a result of these new wells, our production in this area increased 38% to approximately 2,955 Boe/d in 2012 compared to 2,134 Boe/d in 2011 and 961 Boe/d in 2010. Our production in the Cleveland Sand Play area was 3,476 Boe/d as of December 31, 2012. During 2012, our drilling investment was $54.3 million and we have allocated approximately $20.6 million of our 2013 drilling budget to this area. Our drilling activity for 2013 will focus on the West Shattuck Cleveland Sand Play that trends from Hansford County in the Texas Panhandle across our acreage position to eastern Ellis County in Oklahoma. It is characterized by a tight, shaley sand sequence that lends itself to the benefits of horizontal drilling.
Anadarko Woodford Shale Play Area—Western Oklahoma. The Anadarko Basin Woodford Shale Play area accounted for 2.5 MMBoe, or 2%, of our proved reserves as of December 31, 2012. The horizontal development of this non-conventional resource play began in 2007 in Canadian County and has expanded to include the nearby counties of Blaine, Dewey, Grady, and Caddo. Our production in this area increased 23% to approximately 190 Boe/d in 2012 compared to 154 Boe/d in 2011 and 133 Boe/d in 2010. Our drilling investment was $1.5 million and we participated in the drilling of three (zero net) wells in this area during 2012. We have not allocated any significant amount of our 2013 drilling budget to this area.
Permian Basin Area
As of December 31, 2012, the Permian Basin Area accounted for 16.6 MMBoe, or 11% of our proved reserves. During the year ended December 31, 2012, our net average daily production in the Permian Basin Area was approximately 4.43.3 MBoe per day, or 21%13% of our total net average daily production. Similar
Bone Spring/Avalon Shale Play—West Texas/New Mexico. We own approximately 19,590 (17,216 net) acres in the Bone Spring/Avalon oil play developing in West Texas and southeast New Mexico. Operators have switched from vertical to horizontal drilling to improve hydrocarbon recovery from this formation, and approximately 300 horizontal wells have been drilled to date. The average recovery is expected to be 200 to 550 MBoe per well at an average cost of five to six million dollars. Our acreage is attractively located on trend within the play, with active horizontal drilling recently offsetting us in two directions. Recent Avalon/Bone Spring production has been established immediately adjacent to our acreage block, and industry activity, which is drilling towards our acreage position from both directions, is continuing to prove up the value of our position. We have drilled and/or participated in the drilling of five (one net) wells in the Bone Spring/ Avalon Shale Play during 2012. Based on early results, we entered into a joint venture to satisfy our continuous drilling obligation for lease extension and created a significant cost advantage that allows us to reduce future capital spending. Our drilling investment in this Area was $12.6 million in 2012, and we have not allocated any significant amount of our 2013 drilling budget to this play.
Panhandle Marmaton Play—Texas and Oklahoma Panhandles. We currently own approximately 56,600 (44,500 net) acres in this emerging play. The horizontal play began in the fourth quarter of 2008 with a few wells drilled in Beaver, County, OK. In 2010, the play accelerated with 26 wells drilled and has expanded into Ochiltree, County, TX. The horizontal play has included infill drilling on the vertical Marmaton fields and has extended the play off the structures into lower energy facies and structurally lower areas. The multi-stage fracture stimulation jobs performed are a critical component for establishing economical production in the play. Their success has opened up the play into the tighter facies of the Marmaton. The average ultimate recovery is estimated to be 150 MBoe at an average completed well cost of approximately $3.5 million.
The Marmaton Play accounted for 0.5 MMBoe, or 0.4% of our proved reserves as of December 31, 2012. We drilled or participated in the drilling of five (two net) horizontal wells that were completed during 2012. Initial net average daily production in late 2012 resulted in 103 Boe/d. Our drilling investment in this area was $16.5 million in 2012 and we have allocated approximately $41.3 million of our 2013 drilling budget to the Mid-Continent Area, the Permian Basin AreaMarmaton Play.
Haley Area—Loving County, Texas. The Haley area accounted for 3.7 MMBoe, or 3% of our proved reserves at December 31, 2012. Our net production from this area, which is characterizedprimarily dry gas, decreased by stable, long-life, shallow decline reserves.28% to approximately 902 Boe/d in 2012 compared to 1,257 Boe/d in 2011 primarily due to compression facility upgrades and significant shut-in time by gas purchasers. Due to prevailing low natural gas prices, we did not invest any significant amounts to drilling in this area in 2012, and we have not allocated any significant amount of our 2013 drilling budget to this area.
Tunstill Field Play—Loving and Reeves Counties, Texas. Our Tunstill Field Play covers approximately 20,440 acres. We operate 86 producing wells in this play with an average working interest of 99%, and own a working interest in 120 producing wells operated by others. The Tunstill Field Play represented 2.72.8 MMBoe, or 1.9% of our proved reserves and $33.6 million of our PV-10 value at December 31, 2009, and 252 (179 net) MBoe of our production for the year ended December 31, 2009. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,200 to 4,200 feet and the Cherry Canyon Sands that occur at depths from 4,200 to 5,400 feet. Older wells produce from the shallower Bell Canyon Sands including the Ramsey and Olds, while more recent wells have established2012. Our net average daily production from the deeper Cherry Canyon Sands as well as the shallower sands. We drilled three wells in this play during the year ended December 31, 2009.
Haley Area Play—Loving County, Texas. The Haley Area—Bone Springs, Strawn, Atoka, and Morrow play encompasses 3,840 gross acres. We own interests in and operate ten producing wells in this play. The Haley Area accounted for 4.7 MMBoe of our proved reserves and $27.7 million of our PV-10 value at December 31, 2009, and 1,163 (805 net) MBoe of our production for the year ended December 31, 2009. Production has been established from four main intervals: (1) the Bone Springs at a depth of approximately 9,800 to 11,500 feet; (2) the Strawn at a depth of approximately 15,000 feet; (3) the Atoka at a depth of approximately 15,300 feet; and (4) the Morrow at a depth of approximately 17,500 feet. Recent activity in the area, on all four sides of our acreage, has established significant producing wells from the Strawn/Atoka/Morrow commingled interval with some initial potentials of 3 to 5 MBoe per day. The Bowdle 47 No. 2 began selling natural gas in late November 2008, and is currently producing at approximately 12.0 (8.7 net) MMcf per day. We are currently drilling an offset to the Bowdle 47 No. 2 well, the Bowdle 47 No. 4, which is expected to be completed in the second quarter of 2010.
Gulf Coast
The Gulf Coast Area is the most active of our four growth areas and accounted for 5% of our proved reserves and 4% of our PV-10 value as of December 31, 2009, and 6% of our production for the year ended December 31, 2009. We own an interest in 200 wells in the Gulf Coast Area, of which we operate 128. Unlike our core areas, the Gulf Coast Area is characterized by shorter-life and high initial potential production. We believe a balance of this type of production complements our long-life reserves and adds a dimension for increasing our near-term cash flow.
Mustang Island & Mesquite Bay—Aransas and Nueces Counties, TX. We own interests in approximately 1,700 net producing acres and 10,650 net non-producing acres. Multiple producing sand intervals are found from depths of 6,500 feet to 11,500 feet. We operate seven active producing wells in this area. As of December 31, 2009, this area accounted for 1.3 MMBoe ofdecreased 16% to approximately 736 Boe/d in 2012 from 876 Boe/d in 2011, primarily due to a reduction in drilling activity. Net average daily production was 669 Boe/d in 2010. During 2012, our proved reservesdrilling investment was $4.1 million, and $14.2 million of our PV-10 value. We recorded a 58-square mile proprietary 3-D seismic survey over parts of this area where we have entered into an area of mutual interest with a 50% ownership in an attempt to find bypassed reservesdrilled or other potential reservoirs. We drilled one Mustang Island well in 2009.
Ark-La-Tex
The Ark-La-Tex Area accounted for 2% of our proved reserves and 2% of our PV-10 value as of December 31, 2009, and 3% of our production for the year ended December 31, 2009. We own an interest in 120 wells in the Ark-La-Tex Area, of which we operate 53. These reserves are characterized by shorter life and higher initial potential. We participated in the drilling of one Ark-La-Tex welltwo wells in 2009.this area. We have allocated approximately $1.7 million of our 2013 drilling budget to this area.
North TexasOther Areas
Ark-La-Tex. The North Texas AreaArk-La-Tex area accounted for 2%5.4 MMBoe, or 4% of our proved reserves and 2% of our PV-10 value as of December 31, 2009, and 2%2012. Our net production from this area decreased to approximately 1,159 Boe/d in 2012 from 1,306 Boe/d in 2011. The 11% decline was primarily due to normal depletion of the reservoirs. Our total capital investment of $1.6 million during 2012 was primarily for workovers on existing wells. We have not allocated any significant amount of our production2013 drilling budget to this area.
Gulf Coast. The Gulf Coast area accounted for the year ended December 31, 2009. We own an interest in 588 wells in the North Texas Area, of which we operate 107. We participated in the drilling of 81 North Texas wells in 2009.
Rocky Mountains
The Rocky Mountains Area accounted for2.0 MMBoe, or 1% of our proved reserves and 2% of our PV-10 value as of December 31, 2009,2012. Our net average daily production from this area was approximately 753 Boe/d in 2012, 872 Boe/d in 2011, and 763 Boe/d in 2010. The 14% decline in 2012 as compared to 2011 is primarily due to strategic divestitures of properties within the area. Our total capital investment of $2.1 million during 2012 was primarily for workovers on existing wells. We have not allocated any significant amount of our 2013 drilling budget to this area.
North Texas. The North Texas area accounted for 3.8 MMBoe, or 3% of our proved reserves as of December 31, 2012. Our net average daily production from this area was approximately 438 Boe/d in 2012, 545 Boe/d in 2011, and 515 Boe/d in 2010. The 20% decrease in 2012 as compared to 2011 was primarily due to an extended shut-in time for lease repairs and the well’s normal decline. Our total capital investment was $4.0 million and we drilled 32 (one net) wells in this area during 2012. We have not allocated any significant amount of our 2013 drilling budget to this area.
Rocky Mountains. On November 28, 2011, we sold our non-strategic oil and natural gas properties consisting of 3.4 MMBoe located in the Rocky Mountains area to Charger Resources, LLC for a cash price of approximately $33.1 million. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale. Our Rocky Mountains area accounted for approximately 2% of our production for the year ended December 31, 2009. We own an interest in 181 wells in the Rocky Mountains Area, of which we operate 39. We participated in the drilling of five Rocky Mountains wells in 2009.2011.
Oil and Natural Gas Reserves
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and exclude escalations based upon future conditions.
Our policies regarding internal controls over the recording of reserves are structured to objectively estimate our oil and natural gas reserve quantities and values in compliance with SEC regulations. Users of this information should be aware that the process of estimating quantities of crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering, and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Responsibility for preparation of our reserve estimates is delegated to our reservoir engineeringCorporate Reserves group, which is led by our SeniorAssociate Vice President of ReservoirCorporate Reserves who has a Master of Science in Petroleum Engineering and Acquisitions who is a registered Professional Engineer with 3717 years of diversifiedindustry experience that includes diverse petroleum engineering roles and reserves management and operational and technical engineering experience.for a publicly traded company.
Technical reviews are performed throughout the year by our geologic and engineering staff who evaluate pertinent geological and engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of proved reserve quantities. We have internal auditing guidelines and controls in place to monitor the reservoir data and reporting parameters used in preparing the year-end reserves. TechnologiesTechnical and economic data used include updated production data, well performance, formation logs, geological maps, reservoir pressure tests, and wellbore mechanical integrity information. We have also added an analysis and reporting software system designed specifically for reserves management.
This data is then provided to the independent petroleum engineering firms of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. who prepare reserve estimates for the majority of our properties using their own engineering assumptions and the economic data which we provide. The person responsible for overseeing the preparation of our reserve estimates at Cawley, Gillespie & Associates, Inc. is a registered Professional Engineer with 26more than 30 years of petroleum consulting experience. The person responsible for overseeing the preparation of our reserve estimates at Ryder Scott Company, L.P. is a registeredlicensed Professional Engineer with over 2730 years of reservoir engineering experience.practical experience in the estimation and evaluation of petroleum reserves.
Our reserves are reviewed by senior management. Senior management, which includes the President and Chief Executive Officer, the Senior Vice President of Reservoir Engineering and AcquisitionsChief Operating Officer, and the Chief Financial Officer, isand they are responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. Members of senior management may also meet with the key representativerepresentatives from Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. to discuss their process and findings. Final approval of the reserves is required by our Senior Vice President of Reservoir Engineering and Acquisitions and our President and Chief Executive Officer, Chief Operating Officer, and Chief Financial Officer.
Proved Reserves. The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2009.2012. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (59%(50% of PV-10 value) and by Ryder Scott Company, L.P. (23%(34% of PV-10 value). Copies of the summary reserve reports prepared by these independent reserve engineers are attached as exhibits to this annual report. Our internal engineering staff has prepared a report of estimated proved reserves on the remaining smaller value properties (18%(16% of PV-10 value) at December 31, 2009.2012. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value on page 24.
Net proved reserves as of December 31, 2009 | |||||||||
Oil (MBbl) | Natural gas (MMcf) | Total (MBoe) | PV-10 value (In thousands) | ||||||
Developed—producing | 40,793 | 183,150 | 71,318 | $ | 813,407 | ||||
Developed—non-producing | 15,068 | 44,856 | 22,544 | 180,239 | |||||
Undeveloped | 33,608 | 86,424 | 48,012 | 329,895 | |||||
Total proved | 89,469 | 314,430 | 141,874 | $ | 1,323,541 | ||||
Our reserve estimates as of December 31, 2009 were prepared using new guidelines set forth in the SEC’sModernization of Oil and Gas Reporting.The following changes impacted our reserves:26.
Commodity prices used to estimate proved reserves were the average price based upon the first day of the month for the twelve months ended December 31, 2009, or $61.18 per Bbl of oil and $3.87 per Mcf of natural gas. Under the previous method, commodity prices used to calculate estimated proved reserves at December 31, 2009 would have been the year-end price of $79.36 per Bbl of oil and $5.79 per Mcf of natural gas. We estimate that the lower commodity prices used decreased estimated proved reserves and PV-10 value by approximately 15.9 MMBoe and $881.2 million, respectively.
Net proved reserves as of December 31, 2012 | ||||||||||||||||
Oil (MBbls)(1) | Natural gas (MMcf) | Total (MBoe) | PV-10 value (in thousands) | |||||||||||||
Developed-producing | 54,000 | 153,413 | 79,569 | $ | 1,384,128 | |||||||||||
Developed-non-producing | 9,956 | 32,412 | 15,361 | 171,527 | ||||||||||||
Undeveloped | 39,287 | 71,290 | 51,165 | 512,965 | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
Total proved | 103,243 | 257,115 | 146,095 | $ | 2,068,620 | |||||||||||
|
|
|
|
|
|
|
|
As a result of the expanded definition of estimated proved undeveloped reserves that can be recorded, we added proved undeveloped reserves and PV-10 value of approximately 0.9 MMBoe and $10.3 million, respectively, primarily related to horizontal wells.
The new guidelines limit the recording of estimated proved undeveloped reserves to those reserves in undrilled locations that are scheduled to be developed within five years, unless specific circumstances justify a longer time. As a result of implementing this change in the guidelines, our proved undeveloped reserves and PV-10 value decreased by approximately 3.8 MMBoe and $38.5 million, respectively.
(1) | Includes natural gas liquids. |
The following table summarizes our estimatedestimates of net proved oil and natural gas reserves, and PV-10 values at December 31, 2009, assuming they had been prepared under the old guidelines:
Net proved reserves as of December 31, 2009 based on prior methodology | |||||||||
Oil (MBbl) | Natural gas (MMcf) | Total (MBoe) | PV-10 value (In thousands) | ||||||
Developed—producing | 44,169 | 206,376 | 78,565 | $ | 1,281,588 | ||||
Developed—non-producing | 15,345 | 49,266 | 23,556 | 278,269 | |||||
Undeveloped | 35,934 | 135,774 | 58,563 | 673,040 | |||||
Total proved | 95,448 | 391,416 | 160,684 | $ | 2,232,897 | ||||
The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2009.
| |||
| |||
| |||
| |||
| |||
| |||
|
The estimated reserve life as of December 31, 2009, 2008 and 2007 was 18.6, 16.0, and 24.3 years, respectively. The estimated reserve life was calculated by dividing total proved reserves by production volumes for the year indicated. The shorter reserve life in 2009 and 2008 was primarily a result of reduced proven reserves associated with lower SEC pricing.
The following table sets forth the estimated future net revenues from proved reserves, the PV-10 value, the standardized measure of discounted future net cash flows, and the prices used in projecting those measures over the past three years. Estimates of our net proved oil and natural gas reserves as of December 31, 2012, 2011, and 2010 were prepared by Cawley, Gillespie & Associates, Inc. (50%, 50%, and 52% of PV-10 value, respectively) and Ryder Scott Company, L.P. (34%, 34%, and 31% of PV-10 value, respectively). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (16%, 16%, and 17% of PV-10 value in 2012, 2011, and 2010, respectively).
(Dollars in thousands, except prices) | 2009 | 2008 | 2007 | ||||||||||||||||||
As of December 31, | |||||||||||||||||||||
2012 | 2011 | 2010 | |||||||||||||||||||
Estimated proved reserve volumes: | |||||||||||||||||||||
Oil (Mbbls)(1) | 103,243 | 100,380 | 93,412 | ||||||||||||||||||
Natural gas (MMcf) | 257,115 | 335,280 | 335,220 | ||||||||||||||||||
Oil equivalent (MBoe) | 146,095 | 156,260 | 149,282 | ||||||||||||||||||
Proved developed reserve percentage | 65 | % | 64 | % | 66 | % | |||||||||||||||
Estimated proved reserve values (in thousands): | |||||||||||||||||||||
Future net revenue | $ | 3,080,410 | $ | 1,918,270 | $ | 6,203,720 | $ | 4,780,316 | $ | 5,473,678 | $ | 4,110,844 | |||||||||
PV-10 value | 1,323,541 | 932,692 | 2,671,982 | $ | 2,068,620 | $ | 2,309,089 | $ | 1,770,061 | ||||||||||||
Standardized measure of discounted future net cash flows | 971,364 | 755,013 | 1,793,980 | $ | 1,523,681 | $ | 1,597,912 | $ | 1,236,026 | ||||||||||||
Oil price (per Bbl) | $ | 61.18 | $ | 44.60 | $ | 96.01 | |||||||||||||||
Oil and natural gas prices:(2) | |||||||||||||||||||||
Oil price (per Bbl)(1) | $ | 94.71 | $ | 96.19 | $ | 79.43 | |||||||||||||||
Natural gas price (per Mcf) | $ | 3.87 | $ | 5.62 | $ | 6.80 | $ | 2.76 | $ | 4.11 | $ | 4.38 | |||||||||
Estimated reserve life in years(3) | 16.0 | 18.1 | 18.5 |
(1) | Includes natural gas liquids. |
(2) | Prices were based upon the average first day of the month prices for each month during the respective year. The prices shown were adjusted for location differentials to reflect the net prices we receive. |
(3) | Calculated by dividing net proved reserves by net production volumes for the year indicated. |
Proved Undeveloped Reserves. The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2012.
MBoe | ||||
Proved undeveloped reserves as of January 1, 2012 | 56,142 | |||
Undeveloped reserves transferred to developed(1) | (3,351 | ) | ||
Sales of minerals in place, net of purchases | (970 | ) | ||
Extensions and discoveries | 7,527 | |||
Improved recoveries | 281 | |||
Revisions and other | (8,464 | ) | ||
Proved undeveloped reserves as of December 31, 2012(2) | 51,165 | |||
(1) | Approximately $61.7 million of developmental costs incurred during 2012 related to undeveloped reserves that were transferred to developed. |
(2) | Includes 2.9 MMBoe and 14.1 MMBoe, respectively, of reserves that have been reported for more than five years that relate specifically to our Camrick area CO2 EOR projects and our North Burbank polymer EOR projects. Development of these projects is ongoing. See “Properties—Enhanced Oil Recovery Project Areas” for additional discussion of our CO2 EOR projects. |
Productive Wells
The following table sets forth information at December 31, 2009 relating to thedetails our gross and net interest in producing wells in which we ownedhave a working interest asand the number of that date.wells we operated at December 31, 2012 by area. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Wells are classified as oil or natural gas according to their predominant production stream. Gross wells is the total number of producing wells in which we have a working interest, and net wells is the sum of our working interest in all producing wells.
Total wells | ||||
Gross | Net | |||
Crude oil | 5,870 | 2,058 | ||
Natural gas | 2,304 | 749 | ||
Total | 8,174 | 2,807 | ||
Producing oil wells | Producing natural gas wells | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Operated Wells: | ||||||||||||||||||||||||
Enhanced Oil Recovery Project Areas | 419 | 392 | — | — | 419 | 392 | ||||||||||||||||||
Mid-Continent Area | 1,229 | 1,086 | 438 | 326 | 1,667 | 1,412 | ||||||||||||||||||
Permian Basin Area | 313 | 294 | 53 | 43 | 366 | 337 | ||||||||||||||||||
Other | 146 | 126 | 104 | 84 | 250 | 210 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total | 2,107 | 1,898 | 595 | 453 | 2,702 | 2,351 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Non-Operated Wells: | ||||||||||||||||||||||||
Enhanced Oil Recovery Project Areas | 254 | 8 | — | — | 254 | 8 | ||||||||||||||||||
Mid-Continent Area | 2,161 | 262 | 1,144 | 123 | 3,305 | 385 | ||||||||||||||||||
Permian Basin Area | 1,061 | 48 | 86 | 20 | 1,147 | 68 | ||||||||||||||||||
Other | 718 | 21 | 117 | 10 | 835 | 31 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total | 4,194 | 339 | 1,347 | 153 | 5,541 | 492 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total Wells: | ||||||||||||||||||||||||
Enhanced Oil Recovery Project Areas | 673 | 400 | — | — | 673 | 400 | ||||||||||||||||||
Mid-Continent Area | 3,390 | 1,348 | 1,582 | 449 | 4,972 | 1,797 | ||||||||||||||||||
Permian Basin Area | 1,374 | 342 | 139 | 63 | 1,513 | 405 | ||||||||||||||||||
Other | 864 | 147 | 221 | 94 | 1,085 | 241 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total | 6,301 | 2,237 | 1,942 | 606 | 8,243 | 2,843 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
The following table details our gross and net interest in producing wells in which we have a working interest and the number of wells we operated at December 31, 2009 by area.Drilling Activity
Total wells | Operated Wells | |||||
Gross | Net | |||||
Mid-Continent | 5,392 | 2,122 | 2,100 | |||
Permian Basin | 1,693 | 361 | 318 | |||
Gulf Coast | 200 | 117 | 128 | |||
Ark-La-Tex | 120 | 48 | 53 | |||
North Texas | 588 | 120 | 107 | |||
Rocky Mountains | 181 | 39 | 39 | |||
Total | 8,174 | 2,807 | 2,745 | |||
The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2009 by area.
Developed | Undeveloped | |||||||
Gross | Net | Gross | Net | |||||
Mid-Continent | 903,160 | 398,598 | 56,096 | 45,309 | ||||
Permian Basin | 71,962 | 49,302 | 18,101 | 16,983 | ||||
Gulf Coast | 73,356 | 43,891 | 25,546 | 19,476 | ||||
Ark-La-Tex | 22,366 | 10,106 | — | — | ||||
North Texas | 26,073 | 18,343 | 181 | 17 | ||||
Rocky Mountains | 48,837 | 15,921 | 3,251 | 2,611 | ||||
Total | 1,145,754 | 536,161 | 103,175 | 84,396 | ||||
The following table sets forth information with respect to wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. Development wells are wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return.
2009 | 2008 | 2007 | 2012 | 2011 | 2010 | |||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||
Development wells | ||||||||||||||||||||||||||||||||||||||||||
Productive | 168.0 | 49.5 | 319.0 | 74.9 | 214.0 | 51.7 | 134.0 | 43.0 | 279.0 | 65.9 | 234.0 | 100.0 | ||||||||||||||||||||||||||||||
Dry | 2.0 | 1.9 | 4.0 | 2.0 | 3.0 | 1.2 | 1.0 | 1.0 | 7.0 | 4.1 | 5.0 | 1.9 | ||||||||||||||||||||||||||||||
Exploratory wells | ||||||||||||||||||||||||||||||||||||||||||
Productive | 2.0 | 1.0 | 3.0 | 2.2 | 6.0 | 5.9 | 29.0 | 14.0 | 7.0 | 5.1 | 18.0 | 18.0 | ||||||||||||||||||||||||||||||
Dry | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | 0.0 | — | — | — | — | 1.0 | 1.0 | ||||||||||||||||||||||||||||||
Total wells | ||||||||||||||||||||||||||||||||||||||||||
Productive | 170.0 | 50.5 | 322.0 | 77.1 | 220.0 | 57.6 | 163.0 | 57.0 | 286.0 | 71.0 | 252.0 | 118.0 | ||||||||||||||||||||||||||||||
Dry | 2.0 | 1.9 | 4.0 | 2.0 | 3.0 | 1.2 | 1.0 | 1.0 | 7.0 | 4.1 | 6.0 | 2.9 | ||||||||||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||
Total | 172.0 | 52.4 | 326.0 | 79.1 | 223.0 | 58.8 | 164.0 | 58.0 | 293.0 | 75.1 | 258.0 | 120.9 | ||||||||||||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||
Percent productive | 99 | % | 96 | % | 99 | % | 97 | % | 99 | % | 98 | % | 99 | % | 98 | % | 98 | % | 95 | % | 98 | % | 98 | % |
Developed and Undeveloped Acreage
The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2012 by state. This does not include acreage in which we hold only royalty interests.
Developed | Undeveloped(1) | Total | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Arkansas | 1,895 | 1,041 | — | — | 1,895 | 1,041 | ||||||||||||||||||
Kansas | 11,322 | 8,533 | 160 | 160 | 11,482 | 8,693 | ||||||||||||||||||
Louisiana | 14,430 | 5,217 | 480 | 231 | 14,910 | 5,448 | ||||||||||||||||||
Mississippi | 790 | 36 | — | — | 790 | 36 | ||||||||||||||||||
New Mexico | 22,018 | 10,591 | 2,546 | 1,407 | 24,564 | 11,998 | ||||||||||||||||||
Oklahoma | 799,840 | 343,725 | 113,652 | 82,120 | 913,492 | 425,845 | ||||||||||||||||||
Texas | 211,611 | 135,814 | 60,004 | 39,779 | 271,615 | 175,593 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total | 1,061,906 | 504,957 | 176,842 | 123,697 | 1,238,748 | 628,654 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
(1) | Approximately 10%, 21%, and 38% of our net undeveloped acres will expire in 2013, 2014 and 2015, respectively, if not successfully developed or renewed. |
Property Acquisition, Development and Exploration Costs
The following table summarizes our estimates of net proved oil and natural gas reserves as of the dates indicated and the present value attributable to the reserves at such dates (using an average pricecosts incurred for oil and natural gas based uponproperties and our reserve replacement ratio for each of the first day of each month for the year ended December 31, 2009, and using prices in effect on December 31, 2008 and 2007), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2009 and 2008 were prepared by Cawley, Gillespie & Associates, Inc. (59% and 68% of PV-10 value, respectively), and Ryder Scott Company, L.P. (23% and 7% of PV-10 value, respectively). Estimates of our net proved oil and natural gas reserves as of December 31, 2007 were prepared by Cawley, Gillespie & Associates, Inc. (36% of PV-10 value), and Lee Keeling & Associates, Inc. (52% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (18%, 25%, and 12% of PV-10 value in 2009, 2008, and 2007, respectively).last three years.
As of December 31, | ||||||||||||
Proved Reserves | 2009 | 2008 | 2007 | |||||||||
Oil (Mbbl) | 89,469 | 51,283 | 99,104 | |||||||||
Natural gas (MMcf) | 314,430 | 372,366 | 392,269 | |||||||||
Oil equivalent (MBoe) | 141,874 | 113,344 | 164,482 | |||||||||
Proved developed reserve percentage | 66 | % | 74 | % | 65 | % | ||||||
PV-10 value (in thousands) | $ | 1,323,541 | $ | 932,692 | $ | 2,671,982 | ||||||
Estimated reserve life in years(1) | 18.6 | 16.0 | 24.3 | |||||||||
Cost incurred (in thousands): | ||||||||||||
Property acquisition costs | ||||||||||||
Proved properties(2) | $ | 14,552 | $ | 39,201 | $ | 41,724 | ||||||
Unproved properties | 3,781 | 6,677 | 8,032 | |||||||||
Total acquisition costs | 18,333 | 45,878 | 49,756 | |||||||||
Development costs(3) | 127,640 | 251,690 | 165,177 | |||||||||
Exploration costs | 4,942 | 5,108 | 15,287 | |||||||||
Total | $ | 150,915 | $ | 302,676 | $ | 230,220 | ||||||
Annual reserve replacement ratio(4) | 243 | % | 200 | % | 372 | % |
As of December 31, | ||||||||||||
(in thousands) | 2012 | 2011 | 2010 | |||||||||
Property acquisition costs | ||||||||||||
Proved properties | $ | 1,108 | $ | 1,024 | $ | 32,458 | ||||||
Unproved properties | 46,895 | 15,795 | 9,062 | |||||||||
|
|
|
|
|
| |||||||
Total acquisition costs | 48,003 | 16,819 | 41,520 | |||||||||
Development costs | 409,429 | 250,182 | 251,564 | |||||||||
Exploration costs(1) | 54,432 | 57,016 | 34,180 | |||||||||
|
|
|
|
|
| |||||||
Total | $ | 511,864 | $ | 324,017 | $ | 327,264 | ||||||
|
|
|
|
|
| |||||||
Annual reserve replacement ratio(2) | 156 | % | 169 | % | 247 | % |
(1) |
(2) |
|
Calculated by dividing the sum of reserve additions (from purchases of minerals in place, extensions and discoveries, and improved recoveries) by the production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table located in Note |
Year ended December 31, | Year ended December 31, | |||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2007 | 2012 | 2011 | 2010 | |||||||||||||||||||||||||||||||||||||
Reserves replaced | Percent of total | Reserves replaced | Percent of total | Reserves replaced | Percent of total | Reserves replaced | Percent of total | Reserves replaced | Percent of total | Reserves replaced | Percent of total | |||||||||||||||||||||||||||||||
Purchases of minerals in place | 9 | % | 3.5 | % | 35 | % | 17.2 | % | 46 | % | 12.5 | % | 1 | % | 0.1 | % | 5 | % | 2.6 | % | 52 | % | 21.2 | % | ||||||||||||||||||
Extensions and discoveries | 195 | % | 80.4 | % | 155 | % | 77.6 | % | 214 | % | 57.4 | % | 146 | % | 94.0 | % | 152 | % | 90.2 | % | 138 | % | 55.7 | % | ||||||||||||||||||
Improved recoveries | 39 | % | 16.1 | % | 10 | % | 5.2 | % | 112 | % | 30.1 | % | 9 | % | 5.9 | % | 12 | % | 7.2 | % | 57 | % | 23.1 | % | ||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||
Total | 243 | % | 100.0 | % | 200 | % | 100.0 | % | 372 | % | 100.0 | % | 156 | % | 100.0 | % | 169 | % | 100.0 | % | 247 | % | 100.0 | % | ||||||||||||||||||
|
|
|
|
|
|
Production and Price History
The following table sets forth certain information regarding our historical net production volumes, average prices realized and production costs associated with sales of oil and natural gas for the periods indicated.
Year ended December 31, | Year ended December 31, | ||||||||||||||||||||
2009 | 2008 | 2007 | 2012 | 2011 | 2010 | ||||||||||||||||
Production: | |||||||||||||||||||||
Oil (MBbls) | 3,874 | 3,773 | 3,356 | 5,812 | 5,048 | 4,093 | |||||||||||||||
Natural gas (MMcf) | 22,584 | 19,795 | 20,504 | 19,834 | 21,642 | 23,742 | |||||||||||||||
Combined (MBoe) | 7,638 | 7,072 | 6,773 | 9,118 | 8,655 | 8,050 | |||||||||||||||
Average daily production: | |||||||||||||||||||||
Oil (Bbls) | 10,614 | 10,309 | 9,195 | ||||||||||||||||||
Oil (Bbls)(2) | 15,880 | 13,830 | 11,214 | ||||||||||||||||||
Natural gas (Mcf) | 61,874 | 54,085 | 56,175 | 54,191 | 59,293 | 65,047 | |||||||||||||||
Combined (Boe) | 20,926 | 19,323 | 18,558 | 24,912 | 23,712 | 22,055 | |||||||||||||||
Average prices (excluding derivative settlements): | |||||||||||||||||||||
Oil (per Bbl) | $ | 55.04 | $ | 92.47 | $ | 69.85 | |||||||||||||||
Oil (per Bbl)(2) | $ | 78.65 | $ | 87.52 | $ | 74.53 | |||||||||||||||
Natural gas (per Mcf) | 3.51 | 7.72 | 6.41 | $ | 2.64 | $ | 4.08 | $ | 4.36 | ||||||||||||
Combined (per Boe) | $ | 38.28 | $ | 70.95 | $ | 54.03 | $ | 55.88 | $ | 61.24 | $ | 50.75 | |||||||||
Average costs per Boe: | |||||||||||||||||||||
Lease operating expenses | $ | 12.33 | $ | 17.05 | $ | 15.42 | $ | 14.37 | $ | 14.03 | $ | 13.18 | |||||||||
Production taxes | 2.66 | 4.78 | 3.87 | $ | 3.51 | $ | 3.97 | $ | 3.29 | ||||||||||||
Depreciation, depletion, and amortization | 13.62 | 14.24 | 12.61 | $ | 18.57 | $ | 16.88 | $ | 13.60 | ||||||||||||
General and administrative | 3.11 | 3.16 | 3.22 | $ | 5.46 | $ | 4.86 | $ | 3.72 |
(1) | The North Burbank Unit is the only field that contained 15% or more of our total proved reserve volumes at December 31, 2012. Production from this Unit, all of which was oil, was 492 MBbls, 531 MBbls, and 509 MBbls of our net production during 2012, 2011, and 2010, respectively. |
(2) | Includes natural gas liquids. |
Non-GAAP Financial Measures and Reconciliations
The PV-10 value is deriveda non-GAAP measure that differs from the standardized measure of discounted future net cash flows which is the most directly comparable financial measure computed using generally accepted accounting principles (“GAAP”).in that PV-10 value is a computation ofpre-tax number, while the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 value is equal to the standardized measure of discounted future net cash flows at December 31, 2009 before deducting future income taxes, discounted at 10%.an after-tax number. We believe that the presentation of the PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.
The following table provides a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows to PV-10 value as of December 31, 2009 for our major areas of operation:the periods shown:
(dollars in millions) | PV-10 Value | Present value of future income tax discounted at 10% | Standardized measure of discounted future net cash flow | ||||||
Mid-Continent | $ | 1,045.0 | $ | 256.1 | $ | 788.9 | |||
Permian Basin | 148.8 | 51.0 | 97.8 | ||||||
Gulf Coast | 57.3 | 18.6 | 38.7 | ||||||
Ark-La-Tex | 22.4 | 8.6 | 13.8 | ||||||
North Texas | 30.9 | 10.7 | 20.2 | ||||||
Rocky Mountains | 19.1 | 7.1 | 12.0 | ||||||
Total | $ | 1,323.5 | $ | 352.1 | $ | 971.4 | |||
We define adjusted EBITDA as net income (loss), adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) deferred compensation expense (gain), (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual non-cash charges. Any cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization are excluded from the calculation of adjusted EBITDA.
(in thousands) PV-10 value Present value of future income tax discounted at 10% Standardized measure of discounted future net cash flows As of December 31, 2012 2011 2010 $ 2,068,620 $ 2,309,089 $ 1,770,061 (544,939 ) (711,177 ) (534,035 ) $ 1,523,681 $ 1,597,912 $ 1,236,026
Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the financial measurementConsolidated EBITDAX calculation that is used in the covenant calculationratio required under our Credit Agreementsenior secured revolving credit facility described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.
We define adjusted EBITDA as net income (loss), adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on ineffective portion of hedge reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual non-cash charges. Through March 31, 2010, our calculation of adjusted EBITDA excluded any cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization, in accordance with the terms of our prior credit facility.
In July 2010, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to (1) permit cash proceeds received from the monetization of derivatives to be included in the calculation of Consolidated EBITDAX, to the extent that such monetizations, in any period between scheduled redeterminations, do not exceed 5% of the borrowing base then in effect, and (2) permit the exclusion from the calculation of Consolidated EBITDAX of up to $4.5 million in one-time cash expenses associated with our financing transactions that were incurred and paid during the second quarter of 2010. As a result, beginning with the second quarter of 2010, we changed our calculation of adjusted EBITDA to include cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization, to the extent permitted by our senior secured revolving credit facility. However, we did not change our calculation of adjusted EBITDA to exclude approximately $2.3 million of one-time cash expenses associated with our financing transactions. As a result of the permitted exclusion of these expenses, our Consolidated EBITDAX as calculated for covenant compliance purposes is higher than our adjusted EBITDA for the year ended December 31, 2010.
In April 2011, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.
In May 2012, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.875% Senior Notes due 2017.
The following table provides a reconciliation of net lossincome (loss) to adjusted EBITDA for the specified periods:
Year Ended December 31, | Year ended December 31, | |||||||||||||||||||||||
2009 | 2008 | 2007 | ||||||||||||||||||||||
Net loss | $ | (144,318 | ) | $ | (54,750 | ) | $ | (4,793 | ) | |||||||||||||||
(in thousands) | 2012 | 2011 | 2010 | |||||||||||||||||||||
Net income | $ | 64,403 | $ | 42,048 | $ | 33,713 | ||||||||||||||||||
Interest expense | 90,102 | 86,038 | 87,656 | 98,402 | 96,720 | 81,370 | ||||||||||||||||||
Income tax benefit | (85,936 | ) | (34,386 | ) | (2,745 | ) | ||||||||||||||||||
Income tax expense | 37,837 | 35,924 | 23,803 | |||||||||||||||||||||
Depreciation, depletion, and amortization | 104,734 | 101,973 | 85,842 | 169,307 | 146,083 | 109,503 | ||||||||||||||||||
Unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments | (21,752 | ) | (12,549 | ) | 8,343 | (46,746 | ) | 27,452 | 23,889 | |||||||||||||||
Non-cash change in fair value of non-hedge derivative instruments | 149,106 | (89,554 | ) | 23,031 | (12,411 | ) | (57,899 | ) | (2,523 | ) | ||||||||||||||
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from monetization date | (102,352 | ) | — | — | ||||||||||||||||||||
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date included in EBITDA | — | — | 9,418 | |||||||||||||||||||||
Interest income | (283 | ) | (409 | ) | (755 | ) | (225 | ) | (165 | ) | (144 | ) | ||||||||||||
Deferred compensation expense (gain) | 1,145 | (306 | ) | 831 | ||||||||||||||||||||
Gain on disposed assets | (10,463 | ) | (177 | ) | (712 | ) | ||||||||||||||||||
Stock-based compensation expense | 3,065 | 3,747 | 2,600 | |||||||||||||||||||||
Gain on sale of assets | (149 | ) | (1,284 | ) | (184 | ) | ||||||||||||||||||
Loss on extinguishment of debt | 21,714 | 20,592 | 2,241 | |||||||||||||||||||||
Loss on impairment of oil and natural gas properties | 240,790 | 281,393 | — | — | — | — | ||||||||||||||||||
Loss on impairment of ethanol plant | — | 2,900 | — | |||||||||||||||||||||
Loss on litigation settlement | 2,928 | — | — | |||||||||||||||||||||
Other non-cash charges | 2,000 | — | 4,150 | |||||||||||||||||||||
|
|
| ||||||||||||||||||||||
Adjusted EBITDA | $ | 223,701 | $ | 280,173 | $ | 196,698 | $ | 337,197 | $ | 313,218 | $ | 287,836 | ||||||||||||
|
|
|
Competition
The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil and natural gas companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.
We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed developmentdevelopmental drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program.
Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition.
Markets
The marketing of oil and natural gas we produce will be affected by a number of factors that are beyond our control and whose exact effect cannot be accurately predicted. These factors include:
the amount of crude oil and natural gas imports;
the availability, proximity and cost of adequate pipeline and other transportation facilities;
the success of efforts to market competitive fuels, such as coal and nuclear energy and the growth and/or success of alternative energy sources such as wind power;
the effect of Bureau of Indian Affairs and other federal and state regulation of production, refining, transportation and sales;
the laws of foreign jurisdictions and the laws and regulations affecting foreign markets;
other matters affecting the availability of a ready market, such as fluctuating supply and demand; and
general economic conditions in the United States and around the world.
The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated most trade and investment barriers between the United States, Canada and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before the Federal Energy Regulatory Commission (FERC)(“FERC”), as well as nondiscriminatory access requirements, could further increase the availability of natural gas imports to certain U.S. markets. Such imports could have an adverse effect on both the price and volume of natural gas sales from our wells.
Members of the Organization of Petroleum Exporting Countries establish prices and production quotas from time to time with the intent of reducingmanaging the current global oversupplysupply and maintaining, lowering or increasing certain price levels. We are unable to predict what effect, if any, such actions will have on both the price and volume of crude oil sales from our wells.
In several initiatives, FERC has required pipeline transportation companies to develop electronic communication and to provide standardized access via the Internet to information concerning capacity and prices on a nationwide basis, so as to create a national market. Parallel developments toward an electronic marketplace for electric power, mandated by FERC, are serving to create multi-national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions. Although this system may initially lower prices due to increased competition, it is anticipated it will ultimately expand natural gas markets and improve their reliability.
Environmental Matters and Regulation
We believe that our properties and operations are in substantial compliance with applicable environmental laws and regulations, and our operations to date have not resulted in any material environmental liabilities. To reduce our exposure to potential environmental risk, we typically have our field personnel inspect operated properties prior to completing each acquisition.
General
Our operations, like the operations of other companies in our industry, are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:
require the acquisition of various permits before drilling commences;
require the installation of expensive emission monitoring and/or pollution control equipment;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;
require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;
impose substantial liabilities for pollution resulting from our operations; and
with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.
These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the oil and natural gas industry could have a significant impact on our operating costs.
We monitor our properties and operations in an effort to ensure that our properties and operations are, and remain, in substantial compliance with all current applicable environmental laws and regulations. If, at any time, we determine that our properties and/or operations do not substantially comply with all current applicable environmental laws and regulations, we take action to remedy such noncompliance on our own volition and do not delay taking action until ordered to do so by a regulatory authority. For example, we are currently undertaking additional construction tests of our CO2 pipeline to fully document it is in substantial compliance with rules and regulations regarding natural gas pipeline safety. We cannot predict how future environmental laws and regulations may affect our properties or operations. For the years ended December 31, 20092012, 2011 and 2008,2010, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this report, we are not aware of any other environmental issues or claims that will require material capital expenditures during 20102013 or that will otherwise have a material impact on our financial position or results of operations.
Environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry include the following:
National Environmental Policy Act
Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (NEPA)(“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.
All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.
Waste Handling
The Resource Conservation and Recovery Act (RCRA)(“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (EPA)(“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions. However, there is no guarantee that the U.S. Congress, EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.
We believe that we are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our presently classified wastes to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)(“CERCLA”), also known as the “Superfund” law, imposes strict, and in certain circumstances joint and several liability, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Responsible parties include the current, as well as former, owner or operator of the site where the release occurred and persons that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
We currently own, lease, or operate numerous properties that have produced oil and natural gas for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under, or from the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.
Water Discharges
The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe we are in substantial compliance with the requirements of the Clean Water Act.
The Safe Drinking Water Act, groundwater protection,Groundwater Protection, and the Underground Injection Control Program
The federal Safe Drinking Water Act (SDWA)(“SDWA”) and the Underground Injection Control (UIC)(“UIC”) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. EPA directly administers the UIC program in some states and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal permits,wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater.
Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Congress has previously considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills previously proposed before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The U.S. Congressproposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which is considering legislationalready required by some state agencies governing our operations, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that wouldspecific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could repeal the exemptionexemptions for hydraulic fracturing from the SDWA, which wouldSafe Drinking Water Act.
These legislative efforts have halted while EPA studies the effectissue of allowinghydraulic fracturing. In 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water, as well as review the application of other environmental statutes to hydraulic fracturing activities, including RCRA and the Clean Water Act. As part of that process, EPA requested and received information from the major fracturing service providers regarding the chemical composition of fluids, standard operating procedures and the sites where they engage in hydraulic fracturing. In February 2011, EPA released its Draft Plan to promulgate regulations requiring permits and implementing potential new requirementsStudy the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, proposing to study the lifecycle of hydraulic fracturing under the SDWA. This could,fluid and providing a comprehensive list of chemicals identified in turn, require state regulatory agenciesfracturing fluid and flowback/produced water. EPA is scheduled to release its final draft report in states with programs delegated under the SDWA to impose additional requirements onlate 2014.
These developments, as well as increased scrutiny of hydraulic fracturing operations.activities by state and municipal authorities, may result in additional levels of regulation or level of complexity with respect to existing regulations that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
The Clean Air Act
The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air ActCAA and associated state laws and regulations. TheOn August 16, 2012, EPA proposed in a consent decree, which has not been approved by a federal court, that it will issue by January 31, 2011 a proposalpromulgated new CAA regulations addressing criteria pollutants, “Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews.” These new rules are intended to revise its nationalbroaden the current scope of EPA’s regulation to include standards governing emissions standards for hazardous air pollution for crudefrom most operations associated with oil and natural gas production as well asfacilities, natural gas transmission and storage and itsfacilities. EPA states that greenhouse gases will be controlled indirectly as a result of these new source performance standards for oil and natural gas production.rules.
Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new monitoring and reporting requirements and/or emission limitations. In December 2009, the EPA promulgated a finding that serves as the foundation under the CAA to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the CAA, even without Congressional action. As part of this array of new regulations, in September 2009, the EPA also promulgated a greenhouse gas monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their greenhouse gas emissions, including methane and carbon dioxide, to the EPA. In May 2010, EPA promulgated final rules subjecting greenhouse gas to regulation under the CAA, triggering application of other provisions of the CAA to major stationary sources of greenhouse gas emissions. In June 2010, EPA promulgated final rules limiting the scope of certain provisions of the CAA as applied to greenhouse gas emission sources. Additionally, in November 2010, EPA promulgated mandatory greenhouse gas emission reporting rules specifically applying to oil and natural gas exploration and production. These rules are published in the federal register and available on the Internet. These regulations govern our operations to the extent applicable. On April 17, 2012, EPA adopted new CAA regulations imposing new emissions standards for the oil and natural gas sector, including sources not previously regulated. See “Risk factors—Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.” These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. We believe we are in substantial compliance with the current requirements of the Clean Air Act.
In December 2009, the EPA promulgated a finding that serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas (GHG) regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, in September 2009, the EPA also promulgated a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. The emissions will be published on a register to be made available on the Internet. These regulations may apply to our operations. The EPA has proposed two other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and may affect sources in the oil and gas exploration and production industry and pipeline industry.
The EPA’s finding, the greenhouse gas reporting rule, and the proposed rules to regulate the emissions of greenhouse gases would result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry. See “Risk factors—Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.”CAA.
Other Laws and Regulation
The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress is considering proposed legislation directed at reducing greenhouse gas emissions. Also, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations limiting or otherwise addressing greenhouse gas emissions would impact our business.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. It is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.
Drilling and Production
Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds, and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:
the location of wells;
the method of drilling and casing wells;
the rates of production or “allowables”;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within its jurisdiction.
Natural Gas Sales Transportation
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.
FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and instate waters. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point-of-sale locations.
Natural Gas Pipeline Safety
The Department of Transportation, specifically the Pipeline and Hazardous Materials Safety Administration, regulates transportation of natural and other gas by pipeline and imposes minimum federal safety standards pursuant to the pipeline safety laws codified at 49 U.S.C. 60101, et seq. and the hazardous material transportation laws codified at 49 U.S.C. 5101, et seq.
Natural Gas Gathering Regulations
State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering is addressed in EPA’s proposed greenhouse gas monitoring and reporting rule, is subject to air permitting requirements where applicable, and may receive greater regulatory scrutiny in the future.
State Regulation
The various states regulate the drilling for, and the production, gathering, and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation, and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Seasonality
While our limited operations located in the Gulf Coast and the Rocky Mountains may experience seasonal fluctuations, we do not believe these fluctuations have had, or will have, a material impact on our consolidated results of operations.
Legal proceedings
PropertiesNaylor Farms, Inc. v. Chaparral Energy, L.L.C. On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5.0 million. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The matter is currently stayed pending resolution of unrelated cases currently on appeal with the U.S. Court of Appeals for the Tenth Circuit. These cases are expected to influence the ruling on class certification in the Plaintiff’s case. At the time that the matter was stayed no class had been certified and discovery was ongoing. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.
In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.
Title to properties
We believe that we have satisfactory title to all of our owned assets. As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to undeveloped leasehold acreage rights acquired through oil and natural gas leases or farm-in agreements. Prior to the commencement of drilling operations on undeveloped leasehold, we conduct a title examination and perform curative work with respect to any significant title defects. Prior to completing an acquisition of an interest in significant producing oil and natural gas properties, we conduct due diligence as to title for the specific interest we are acquiring. Our interests in oil and natural gas properties are subject to customary royalty interests, liens for current taxes and other similar burdens and minor easements, restrictions and encumbrances which we believe do not materially detract from the value of these interests either individually or in the aggregate and will not materially interfere with the operation of our business. We will take such steps as we deem necessary to assureensure that our title to our properties is satisfactory. We are free, however, to exercise our judgment as to reasonable business risks in waiving title requirements.
Employees
As of December 31, 2009,2012, we had 689746 full-time employees, including 1424 geologists and geophysicists, 3260 reservoir, production, and drilling engineers and 1625 land professionals. Of these, 293351 work in our Oklahoma City office and 396395 work in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.
The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.
Oil and natural gas prices are volatile. A decline in oil and natural gas prices could adversely affect our financial condition, financial results, cash flows, access to capital and ability to grow.
Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the cash flow we will have available for capital expenditures as well as our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include, but are not limited to, the following:
the level of consumer demand for oil and natural gas;
the domestic and foreign supply of oil and natural gas;
commodity processing, gathering and transportation availability, and the availability of refining capacity;
the price and level of foreign imports of oil and natural gas;
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
domestic and foreign governmental regulations and taxes;
• | the supply of CO2; |
the price and availability of alternative fuel sources;
weather conditions;
financial and commercial market uncertainty;
political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America; and
worldwide economic conditions.
These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas we can produce economically, and as a result, could have a material adverse effect on our financial condition, results of operations, and reserves. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations, including payments on our senior secured revolving credit facility and our Senior Notes,senior notes, or be unable to make planned capital expenditures.
Price declines at the end of 2008 and early 2009 resulted in write downscould cause write-downs of the carrying values of our properties, and further price declines could result in additional write downswrite-downs in the future, which could negatively impact our results of operations.
We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all costs incurred for both productive and nonproductive properties are capitalized and amortized on an aggregate basis using the units-of-production method. However, these capitalized costs are subject to a ceiling test which limits such pooled costs to the aggregate of the present value of estimated future net revenues attributable to proved oil and natural gas reserves discounted at 10%, adjusted for derivatives accounted for as cash flow hedges and net of tax considerations, plus the lower of cost or market value of unproved properties.properties not being amortized. The full cost ceiling is evaluated at the end of each quarter using the SEC prices for oil and natural gas in effect at that date as adjusted for our derivative positions deemed “cash flow hedge positions.” A write-down of oil and natural gas properties does not impact cash flow from operating activities, but does reduce net income. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.
During the fourth quarter of 2008, our evaluation of our full cost ceiling required a non-cash impairment charge of $281.4 million to the value of our oil and natural gas properties as a result of a decline in oil and natural gas prices at the measurement date. The impairment was calculated based on December 31, 2008 prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. During the first quarter of 2009, natural gas prices declined significantly (as compared to the December 31, 2008 spot price of $5.62 per Mcf), and based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of natural gas, our reserves declined by 13.5%, as a result of which we recorded a non-cash ceiling test impairment of $240.8 million during the first quarter of 2009. Oil and natural gas prices have remainedare volatile and this and other factors, without mitigating circumstances, could require us to further write down capitalized costs and incur corresponding non-cash charges to earnings. Any such write downsfurther write-downs could have a material adverse effect on our financial condition, results of operations, and our ability to comply with debt covenants.
The actual quantities and present value of our proved reserves may be lower than we have estimated.
Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates and assumptions, including estimates based upon assumptions relating to economic factors such as commodity prices, production costs, severance and excise taxes, capital expenditures, workovers, remedial costs, and the assumed effect of governmental regulation. There are numerous uncertainties about when a property may have proved reserves as compared to possible or probable reserves, including with respect to our EOR operations. Reserve estimates are, therefore, inherently imprecise and, although we are reasonably certain of recovering the quantities we disclose as proved reserves, actual results will vary from our estimates. Any significant variations in the interpretations or assumptions underlying our estimates or changes of conditions (e.g. economic growth and/or regulation) could cause the estimated quantities and net present value of our reserves to differ materially. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and developmental drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.
You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing of production and expenses associated with the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In accordance with requirements of the Securities and Exchange Commission,SEC, the estimates of present values are based on prices and costs in effecta twelve-month average price, calculated as the unweighted arithmetic average of the datefirst-day-of-the-month price for each month within the twelve-month period prior to the end of the estimates and excludereporting period unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of these estimates. In addition, the effects of derivative instruments are not reflected in these assumed prices. Our December 31, 20092012 reserve report used realized prices based on an average price of $3.87$2.76 per Mcf for natural gas and an average price of $61.18$94.71 per Bbl for oil.
A significant portion of total proved reserves as of December 31, 20092012 are undeveloped, and those reserves may not ultimately be developed.
As of December 31, 2009,2012, approximately 34%35% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requiresThese reserve estimates reflect our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves including approximately $749 million during the five years ending in 2017. You should be aware that actual development costs may exceed estimates, development may not occur as scheduled and successful drilling and EOR operations. The reserve data assumes thatresults may not be as estimated. If we can and will make these expenditures and conduct these operations successfully. Whilechoose not to develop our proved undeveloped reserves, or if we are reasonably certain ofnot otherwise able to successfully develop them, we will be required to remove the associated volumes from our ability to make these expenditures and to conduct these operationsreported proved reserves. In addition, under existing economic conditions, these assumptions may not prove correct and we may ultimately determine the development of all, or any portion of, suchSEC’s reserve reporting rules, proved but undeveloped reserves isgenerally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking. We may be required to write off any reserves that are not economically feasible.developed within this five-year time frame unless such reported reserves are otherwise exempted from the SEC’s five-year reporting rules.
Some of our reserves are subject to EOR methods and the failure of these methods may have a material adverse affect on our financial condition, results of operations and reserves.
As of December 31, 2009,2012, approximately 14%20% of our proved reserves were based on EOR methods including the injection of CO2 and polymers, a synthetic chemical. Some of these properties have not been injected with CO2or with polymers having the identical chemical composition as polymers used in historical production, and recovery factors cannot be estimated with precision. Accordingly, such projects may not result in significant proved reserves or improvements in anticipated production levels.
We do not currently have a supply of CO2 for all of our unproved properties with CO2 EOR potential, and we cannot assure you that we will be able to obtain such a supply on commercially reasonable terms. In addition, many of our planned EOR projects will require significant investments in pipeline, compression facilities, and other infrastructure, and we may need to raise additional capital to fund these projects. We cannot assure you that such funding will be available on commercially reasonable terms. The availability of CO2 supply and financing of CO2 projects could affect the timing of our planned EOR programs and impact our ability to implement such plans.
Our ability to develop futureour EOR reserves will depend on whether we can successfully implement our planned EOR programs, and our failure to do so could have a material adverse effect on our financial condition, results of operations and reserves.
The development of the proved undeveloped reserves in our North Burbank Unit, Camrick Area Units, and Farnsworth Unit may take longer and may require higher levels of capital expenditures than we currently anticipate.
As of December 31, 2012, undeveloped reserves comprised 49%, 43%, and 55%, respectively, of the total estimated proved reserves of our North Burbank Unit, Camrick Area Units, and Farnsworth Unit, respectively. As of December 31, 2012, we expect to incur future development costs of $229.4 million over the next 11 years at our North Burbank Unit, $123.3 million over the next 15 years at our Camrick Area Units, and $120.7 million over the next 12 years at our Farnsworth Unit to fully develop these reserves. Together, these fields encompass 50.6% of our total estimated future development costs of $934.7 million related to proved undeveloped reserves as of December 31, 2012. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, the development of these reserves will require the use of EOR techniques, including water flood and CO2 injection installations, the success of which is still subject to interpretation and predictability by reservoir engineers. Therefore, ultimate recoveries from these fields may not match current expectations.
The polymer reserves at our North Burbank Unit accounted for 14.1 MMBoe, or approximately 10% of our estimated proved reserves as of December 31, 2012. We and our independent petroleum engineers believe that the polymer EOR flood development plan continues to be sufficient to permit us to include the North Burbank Unit reserves in our proved reserves and, as such, those reserves are included in our total proved reserves as of December 31, 2012. We are continuing to develop our polymer plan while simultaneously instituting a pilot project for enhanced oil recovery from CO2 injection to determine the best long-term EOR technique. The SEC could determine that our recent increase in focus on our CO2 operations results in a change in our polymer development plan and could require us to reduce or eliminate all or a portion of the MMBoe proved reserves attributable to our polymer EOR flood.
Competition in the oil and natural gas industry is intense and many of our competitors have greater financial and other resources than we do.
We operate in the highly competitive areas of oil and natural gas production, acquisition, development, and exploration and we face intense competition from both major and other independent oil and natural gas companies:
seeking to acquire desirable producing properties or new leases for future development or exploration; and
seeking to acquire the equipment and expertise necessary to operate and develop our properties.
Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, select suitable prospects and consummate transactions in this highly competitive environment.
Significant capital expenditures are required to replace our reserves.
Our development, exploration, and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, debt financing, and debt financing.private issuances of common stock. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and natural gas, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt or other methods of financing on commercially reasonable terms to meet these requirements. If revenue were to decrease as a result of lower oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves which may have an adverse effect on our results of operations and financial condition.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop, or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 34%35% of our total estimated proved reserves (by volume) at December 31, 20092012 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and EOR operations. Our December 31, 20092012 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 14%19%, 11%14%, and 9%12% for the next three years. Thus, our future oil and natural gas reserves and production and, therefore, our financial condition, results of operations, and cash flows are highly dependent on our success in efficiently developing our current reserves and economically discovering or acquiring additional recoverable reserves.
Development and exploration drilling may not result in commercially productive reserves.
Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. We cannot assure you that new wells we drill will be productive or that we will recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be economically recovered and/or produced. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realizedthen-realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or cancelledcanceled as a result of numerous factors, including:
unexpected drilling conditions;
title problems;
pressure or lost circulation in formations;
equipment failures or accidents;
adverse weather conditions;
compliance with environmental and other governmental requirements; and
increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.
If, for any reason, we are unable to economically recover reserves through our exploration and drilling activities, our results of operations, cash flows, growth, and reserve replenishment may be materially affected.
We are subject to complex laws and regulations, including environmental and safety regulations, which can adversely affect the cost, manner, and feasibility of doing business.
Our operations and facilities are subject to certain federal, state, and local laws and regulations relating to the exploration for, and development, production, and transportation of, oil and natural gas, as well as environmental and safety matters. Although we believe that we are in substantial compliance with all applicable laws and regulations, and are currently evaluating the extent of applicability and preparing to comply to the extent applicable with proposed and newly adopted greenhouse gas reporting and permitting requirements, we cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with environmental and other governmental regulations such as:
land use restrictions;
drilling bonds and other financial responsibility requirements;
spacing of wells;
reporting or other limitations on emissions of greenhouse gases;
permitting of emissions of greenhouse gases and other regulated air pollutants;
unitization and pooling of properties;
habitat and endangered species protection, reclamation and remediation, and other environmental protection;
well stimulation processes;
produced water disposal;
• | CO2 pipeline requirements; |
safety precautions;
operational reporting; and
taxation.
Under these laws and regulations, we could be liable for:
personal injuries;
property and natural resource damages;
oil spills and releases or discharges of hazardous materials;
well reclamation costs;
remediation and clean-up costs and other governmental sanctions, such as fines and penalties;
other environmental damages; and
additional reporting permitting or other issues arising from emissions of greenhouse gas emissions.gases and other regulated air pollutants
Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. Additionally, future regulations promulgated pursuant to the Clean Air Act or other mandatory federal legislation may requirerequiring monitoring and reporting of greenhouse gasair pollutant emissions continue to evolve and eventually may impose new restrictions on these emissions resulting in liability for exceeding permitted air pollutant emission rates or other mandatory caps on greenhouse gas emissions. WeWhile we are preparing for compliance with newly adopted requirements, at this time we are unable to predict the ultimate cost of compliance with these requirements as they continue to evolve or their effect on our operations.
Properties that we acquire may not produce as projected and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties, or obtain protection from sellers against such liabilities.
Acquisitions of producing and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including recoverable reserves, exploration or development potential, future oil and natural gas prices, operating costs, and potential environmental and other liabilities. We perform an engineering, geological and geophysical review of the acquired properties, which we believe is generally consistent with industry practices, and also endeavor to evaluate environmental risks. However, such assessments are inexact and their accuracy is inherently uncertain for a number of reasons. For instance, in connection with our assessments, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not physically inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited. Often we are not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities associated with acquired properties. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. Additionally, properties previously acquired have not been subject to greenhouse gas requirements which have just recently been adopted. As a result, significant unknown liabilities, including environmental liabilities, may exist and we may experience losses due to title defects in acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, we may acquire oil and natural gas properties that contain economically recoverable reserves which are less than predicted. Thus, liabilities and uneconomically feasible oil and natural gas recoveries related to our acquisitions of producing and undeveloped properties may have a material adverse effect on our results of operations and reserve growth.
We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability of these non-operated properties.
We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others therefore will depend upon a number of factors outside of our control, including the operator’s:
timing and amount of capital expenditures;
expertise and diligence in adequately performing operations and complying with applicable agreements;
financial resources;
inclusion of other participants in drilling wells; and
use of technology.
As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.
If the third parties we rely on for gathering and distributing our oil and natural gas are unable to meet our needs for such services and facilities, our future exploration and production activities could be adversely affected.
The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and third-party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and refineries or processing facilities. Such third parties are subject to federal and state regulation of the production and transportation of oil and natural gas. If such third parties are unable to comply with such regulations and we are unable to replace such service and facilities providers, we may be required to shut-in producing wells or delay or discontinue development plans for our properties. A shut-in, delay or discontinuance could adversely affect our financial condition.
The loss of our Chief Executive Officer or other key personnel could adversely affect our business.
We depend, and will continue to depend in the foreseeable future, on the services of Mark A. Fischer, our Chief Executive Officer, and other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production, and developing and executing financing and hedging strategies. Our ability to retain our officers and key employees, or hire replacements if we should lose one or more, is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.
Oil and natural gas drilling and production operations can be hazardous and may expose us to environmental or other liabilities.
Oil and natural gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these events occur, we could sustain substantial losses as a result of:
injury or loss of life;
severe damage to or destruction of property, natural resources and equipment;
pollution or other environmental damage;
clean-up responsibilities;
regulatory investigations and administrative, civil and criminal penalties; and
injunctions or other proceedings that suspend, limit or prohibit operations.
Our liability for environmental hazards includes those created on properties prior to the date we acquired or leased them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover any or all resulting losses or liabilities. Moreover, in the future, we may not be able to obtain any such insurance on commercially reasonable terms. The occurrence of, or failure by us to obtain or maintain adequate insurance coverage for, any of the events listed above could have a material adverse effect on our financial condition and results of operations, as well as our growth, exploration, and employee recruitment activities.
Costs of environmental liabilities could exceed our estimates and adversely affect our operating results.
Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:
the uncertainties in estimating clean up costs;
the discovery of additional contamination or contamination more widespread than previously thought;
the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;
changes in interpretation and enforcement of existing environmental laws and regulations; and
future changes to environmental laws and regulations and their enforcement.
Although we believe we have established appropriate reserves for known liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties, incur material clean up costs, other liabilities, and/or expend significant sums to defend ourselves against litigation related to legacy environmental issues, which could have an adverse effect on our operating results.
If we areWe may not be able to generate sufficient cash to service all of our long-term indebtedness, and we may be forced to take other actions to satisfy our obligations under our Credit Agreement,senior secured revolving credit facility, which may not be successful.
Our ability to make scheduled payments on or to refinance our long-term indebtednessdebt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flowsflow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our long-term indebtedness.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or seek to restructure or refinance our long-term indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to attempt to meet our debt service and other obligations. Our Credit Agreement and theThe indentures governing our Senior Notes and our senior secured revolving credit facility restrict our ability to dispose of assets and use the proceeds from the disposition.asset sales. We may not be able to consummate those asset sales to raise capital or to sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due.
If we cannot make scheduled payments on our long-term indebtedness, we will be in default and, as a result:
debt holders could declare all outstanding principal and interest to be due and payable;
we may be in default under our master (ISDA) derivative contracts and counter-partiescounterparties could demand early termination;
the lenders under the Credit Agreementsenior secured revolving credit facility could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and
we could be forced into bankruptcy or liquidation.
Our level of indebtedness may adversely affect our operations and limit our growth.
As of December 31, 2009,2012, our total long-term indebtedness, including current maturities, was $1,177.0 million.$1.3 billion. As of April 14, 2010,1, 2013, our total long termlong-term indebtedness, including current maturities, was approximately $841.0 million, and our maximum commitment amount$1.3 billion, and the borrowing base under our Eighth Restated Credit Agreementsenior secured revolving credit facility was $450.0$500.0 million. We may incur additional indebtedness, including significant secured indebtedness, in order to make future acquisitions or to develop our properties for production or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future. Covenants set forth in the indentures for our Senior Notes, including the Adjusted Consolidated Net Tangible Asset debt incurrence test (the “ACNTA test”), limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and natural gas at specified dates.
Our high level of indebtedness affects our operations in several ways, including the following:
the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business;
we must use a significantsubstantial portion of our cash flowsflow from operating activities must be usedoperations to servicepay interest on our Senior Notes and our other indebtedness, which reduces the funds available to us for operations and therefore, is not available for other purposes such as acquisitions, exploration, or property development;purposes;
we may be at a competitive disadvantage as compared to similar companiesour competitors that may have proportionately less debt;
the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrowobtain additional funds, pay dividends and make certain investments andfinancing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions, or general corporate purposes may also affect be impaired, which could be exacerbated by further volatility in the credit markets;
our flexibility in planning for, andor reacting to, changes in our business and the economy andindustry in our industry;
additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposeswhich we operate may have higher costs and more restrictive covenants;
changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings may increase the interest rate and fees we pay on our revolving bank credit facility; andbe limited;
we may be more vulnerable to generaleconomic downturns and adverse economicdevelopments in our business; and industry conditions.
we may be vulnerable to interest rate increases, as our borrowings under our senior secured revolving credit facility are at variable rates.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, prospects, and ability to satisfy our debt obligations.
We may not have sufficient funds to repay bank borrowings if required as a result of a borrowing base redetermination.
Availability under our Credit Agreementsenior secured revolving credit facility is subject to a borrowing base, which was $450.0$500.0 million as of April 14, 2010,1, 2013, and which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the banks may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. If we issue Additional Permitted Debt, as defined in the Eighth Restated Credit Agreement,our senior secured revolving credit facility, the borrowing base will be automatically reduced by an amount equal to 25% of the aggregate stated principal amount of the debt issued.issued, unless otherwise agreed to by our lenders. If the outstanding borrowings under our Credit Agreementsenior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period,period; (2) to submit within 30 days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
Our use of derivative instruments could result in financial losses or reduce our income.
To reduce our exposure to the volatility in the price of oil and natural gas and provide stability to cash flows, we enter into derivative positions, some of which arewe had previously designated as cash flow hedges for accounting purposes. These derivative products include fixed-price swaps, collars, and basis swaps with financial institutions or other similar transactions. As of December 31, 2009,2012, we had entered into swaps for 23,70025,200 BBtu of our natural gas production for 20102013 through 20112014 at average monthly prices ranging from $6.90$3.85 to $8.00$4.46 per MMBtu of natural gas. We alsoAs of December 31, 2012, we had entered into swaps and three way collars for 3,3601,020 MBbls and 5,030 MBbls, respectively, of our crude oil and natural gas liquids production for 2013 through 2014. These swaps had average monthly prices ranging from $96.65 to $96.87 per Bbl of oil, and the three way collars had a weighted average call price, put price, and additional put price of $111.33, $98.00, and $77.37 per Bbl, respectively. As of December 31, 2012, we had basis protection swaps for 30,490 BBtu of our natural gas production for 20102013 at a floor of $10.00 per MMBtu. As of December 31, 2009, we had entered into swaps for 4,482 MBbls of our crude oil production for 2010 through 2011 at average monthly prices ranging from $67.39$0.20 to $69.03 per Bbl of oil. We also entered into collars for 444 MBbls of our crude oil production for 2010 through 2011 at a floor of $110.00 per Bbl of oil. As of December 31, 2009, we had basis protection swaps for 29,590 BBtu of our natural gas production for 2010 through 2011 at average monthly prices ranging from $0.70 to $0.94$0.23 per MMBtu. The fair value of our oil and natural gas derivative positions outstanding as of December 31, 20092012 was a liabilityan asset of approximately $26.8$40.4 million.
Derivative instruments expose us to risk of financial loss in some circumstances, including when:
our production is less than expected;
the counter-partycounterparty to the derivative instruments defaults on its contractual obligations; or
there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative instruments.
Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, derivatives that are not hedges must be adjusted to fair value through income. If the derivative qualifies and is designated as a cash flow hedge, the effective portion of changes in the fair value of the derivative is recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value, as measured using the dollar offset method, is immediately recognized in gain (loss) from oil and natural gas hedging activities in the statement of operations.
If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting must be discontinued and the gain or loss reported in accumulated other comprehensive income (loss) is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting must be discontinued. The gain or loss associated with the discontinued hedges remains in accumulated other comprehensive income (loss) and is reclassified into income as the hedged transactions occur.
While the primary purpose of our derivative transactions is to protect ourselves against the volatility in oil and natural gas prices, under certain circumstances, or if hedges are deemed ineffective, discontinued, or terminated for any reason, we may incur substantial losses in closing out our positions, which could have a material adverse effect on our financial condition, results of operations, and cash flows.
Our working capital could be adversely affected if we enter into derivative instruments that require cash collateral.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties (i.e. margin requirements). Although we currently do not, and do not anticipate that we will in the future, enter into derivative transactions that require an initial deposit of cash collateral, our working capital, and by extension, our growth, could be impacted if we enter into derivative transactions that require cash collateral and if commodity prices move in a manner adverse to us, we may be required to meet margin calls. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.
We are subject to financing and interest rate exposure risks.
Our future success depends on our ability to access capital markets and obtain financing on reasonable terms. Our ability to access financial markets and obtain financing on commercially reasonable terms in the future is dependent on a number of factors, many of which we cannot control, including changes in:
our credit ratings;
interest rates;
the structured and commercial financial markets;
market perceptions of us or the oil and natural gas exploration and production industry; and
tax burden due to new tax laws.
Assuming a constant debt level of $513.0$500.0 million, equal to our borrowing base at December 31, 2009,2012 (our only variable interest rate facility), the cash flow impact for a 12-month period resulting from a 100 basis point movement in interest rates, regardless of whether the spread widens or tightens, would be $5.1$5.0 million. As a result, any increases in our interest rates, or our inability to access the equity markets on reasonable terms, could have an adverse impact on our financial condition, results of operations, and growth prospects.
The concentration of accounts for our oil and natural gas sales, joint interest billings, or hedging with third parties could expose us to credit risk.
Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. The concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, we have not experienced any material credit losses on our receivables. Future concentrations of sales of oil and natural gas to a limited number of customers, combined with decreases in commodity prices could result in adverse effects.
In addition, our oil and natural gas swaps or other hedging contracts expose us to credit risk in the event of non-performance by counterparties. Generally, these contracts are with major investment grade financial institutions and historically we have not experienced any credit losses. We believe that the guarantee of a fixed price for the volume of oil and natural gas hedged reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk. However, as also discussed along with other risks specific to hedging activities, we may be exposed to greater credit risk in the future.
Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.
Recent scientific studies have suggested thatThe U.S. Congress has previously considered legislation to reduce emissions of greenhouse gases, commonly referred to as “greenhouse gases” including carbon dioxide, methane, and nitrous oxide among others, which some studies have suggested may be contributing to warming of the earth’s atmosphere. In response to such studies, the U.S. Congress is actively consideringHowever, legislation to reduce emissionsgreenhouse gases appears less likely in the near term. As a result, regulation of greenhouse gases. In addition,gases will continue to result primarily from regulatory action by the Environmental Protection Agency (EPA) or by the several states that have already taken legal measures to reduce emissions of greenhouse gases.
Federal regulation. EPA has adopted regulations requiring Clean Air Act (“CAA”) permitting of greenhouse gas emissions from stationary sources. As a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA 549 U.S. 497 (2007), finding that greenhouse gases fall within the Clean Air Act (“CAA”)CAA’s definition of “air pollutant,” the Environmental Protection Agency (“EPA”)EPA was required to determine whether concentrations of greenhouse gases in the atmosphere “endanger” public health or welfare, and whether emissions of greenhouse gases “endanger” public healthfrom motor vehicles may “cause or welfare. In April 2009, EPA proposed a finding of suchcontribute” to this endangerment. Consistent with its proposed endangerment finding, in September 2009, EPA proposed regulations to control greenhouse gas emissions from light duty vehicles. The EPA also announced that its proposed action to control greenhouse gas emissions from light duty vehicles, should it become final, would automatically trigger application of the CAA prevention of significant deterioration and Title V operating permit programs to major stationary sources of greenhouse gas emissions. In September 2009, EPA issued a proposed “tailoring” rule explaining the legal mechanism upon which it would rely to raise the “major stationary source” air pollutant emission threshold of 250 tons per year and 100 tons per year to 25,000 tons per year. With its proposed “tailoring rule,” EPA also explained the manner in which it would implement the CAA permitting programs to major stationary source greenhouse gas emission sources. In September 2009, EPA promulgated a final mandatory greenhouse gas reporting rule which will assist EPA in implementing the major stationary source permitting programs triggered by the mobile source rules. This reporting rule became effective on December 29, 2009. On December 15, 2009, EPA promulgated its final endangerment rule, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act.Act”. On May 7, 2010, EPA and the Department of Transportation’s National Highway Traffic and Safety Administration, or NHTSA, promulgated a final action establishing a national program providing new standards for certain motor vehicles to reduce greenhouse gas emissions and improve fuel economy. While these motor vehicle regulations do not directly impact oil and natural gas production operations, they automatically trigger application of the Prevention of Significant Deterioration (“PSD”) and Title V Operating Permit programs for stationary sources of greenhouse gas emissions, potentially including oil and natural gas production operations. On June 3, 2010, EPA promulgated its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule,” to add new higher thresholds of 75,000 tons per year carbon dioxide equivalents (“CO2e”) for modifications to existing sources and 100,000 tons per year CO2e for new sources.
EPA has promulgated separate regulations requiring greenhouse gas emission reporting from certain industry sectors, including natural gas production. On October 30, 2009, EPA promulgated a final mandatory greenhouse gas reporting rule which will assist EPA in developing policy approaches to greenhouse gas regulation. This finalreporting rule became effective on January 14, 2010. Currently,December 29, 2009. On November 30, 2010, EPA is expected to promulgate its final rules regulating and controllingpromulgated additional mandatory greenhouse gas reporting rules that apply specifically to oil and natural gas production for implementation in 2011.
On August 16, 2012, EPA promulgated new CAA regulations addressing criteria pollutants, “Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews.” These new rules are intended to broaden the current scope of EPA’s regulation to include standards governing emissions from light duty vehicles, as well as its final “tailoring rule,” in March 2010. Though subject to legal challenge, EPA’s rules promulgated thus far are currently finalmost operations associated with oil and effective,natural gas production facilities, natural gas transmission and will remain so unless successfully challenged directly in court, or unless Congress adopts legislation preempting EPA’s regulatory authority to addressstorage facilities. EPA states that greenhouse gases under the CAA.
Recent caselaw.Beyond legislative and regulatory developments, therelitigation against energy industry sectors emitting greenhouse gases have been several court cases impacting this area of risk. First, in September 2009, the United States Court of Appeals for the Second Circuit issued its decision in Connecticut v. American Electric Power Co., 2009 U.S. App. LEXIS 20873 (2d Cir. Sept. 21, 2009). With this case, the Second Circuit reversed a lower court’s dismissal of plaintiffarisen based upon common law claims, that public utilities greenhouse gas emissions created a “public nuisance.” In reversing, the Second Circuit rejected the lower court’s reliance on defenses including political question, preemptionmay expose us, as potentially an emitter of significant direct and lack of standing to dismiss. In this case, the plaintiffs consist of State entities and public trusts, and are seeking to enjoin excessive greenhouse gas emissions. Second, on October 16, 2009, the United States Court of Appeals for the Fifth Circuit issued its decision in Comer v. Murphy Oil USA, 2009 U.S. App. LEXIS 22774 (5th Cir. Oct. 16, 2009). With this case, the Fifth Circuit reversed a lower court’s dismissal of plaintiff claims that corporations operating energy, fossil fuel and chemical industries caused the emission of greenhouse gases that ultimately resulted in additional property damage from Hurricane Katrina, asserting claims of public and private nuisance, trespass, negligence, unjust enrichment, fraudulent misrepresentation and civil conspiracy. In reversing, the Fifth Circuit rejected the lower court’s reliance on similar defenses, including the political question defense. In this case, the plaintiffs consist of property owners and they are seeking only damages. A similar case, Native Village of Kivalina v. ExxonMobil Corp., Case No: C 08-1138 SBA (N.D. Cal., Oakland Div.) (Sept. 30, 2009) (order granting defendants’ motion to dismiss for lack of subject matter jurisdiction), was appealed to the Ninth Circuit in November, 2009. These cases expose other significantindirect emission sources of greenhouse gases, to similar litigation risk. The effect of this recent caselaw may be mitigated by actions that the courts determine displace federal common law, potentially including Congressional adoption of greenhouse gas legislation and, or, EPA’s final adoption of the light duty vehicle emission regulations which, without legislative intervention, will trigger application of other CAA provisions to greenhouse gas emissions.
International treaties. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Though the 15th meeting of the Council of the Parties in Copenhagen in December 2009 failed to result in a final agreement, international negotiations continue, with the participation of the United States.
International developments, passage of state or federal climate control legislation or other regulatory initiatives, the adoption of regulations by EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, or further development of caselaw allowing claims based upon greenhouse gas emissions, could have an adverse effect on our operations and financial condition as a result of material increases in operating and production costs and litigation expense due to expenses associated with monitoring, reporting, permitting and controlling greenhouse gas emissions or litigating claims related to emissions of greenhouse gases, as well as reduced demand for oil and natural gas.fossil fuels generally.
Potential legislative and regulatory actions could increase our costs, reduce our revenue and cash flow from oil and natural gas sales, reduce our liquidity or otherwise alter the way we conduct our business.
Pending federalIn 2009, 2010, 2011, and 2012 the administration of President Obama made budget proposals releasedwhich, if enacted into law by the White House on February 26, 2009 and February 1, 2010Congress, would potentially increase and accelerate the payment of federal income taxes ofby independent producers of oil and natural gas. Proposals that would significantly affect us include,have included, but arehave not been limited to, repealing the enhanced oil recovery credit, repealing the credit for oil and gas produced from marginal wells, repealing the expensing of intangible drilling costs, repealing the deduction for the cost of qualified tertiary expenses, repealing the exception to the passive loss limitation for working interests in oil and natural gas properties, repealing the percentage depletion allowance, repealing the manufacturing tax deduction for oil and natural gas companies, and increasing the amortization period of geological and geophysical expenses. Additionally,In 2009, 2010, and 2011, legislation which would have implemented the Senate Bill version of the Oil Industry Tax Break Repeal Act of 2009,proposed changes was introduced on April 23, 2009, and the Senate Bill version of the Energy Fairness for America Act, introduced on May 20, 2009, include many of the proposals outlined in the federal budget proposals.but not enacted. It is unclear however, whether legislation supporting any such changesof the above described proposals, or designed to accomplish similar objectives, will be introduced or, if introduced, would be enacted into law or, if enacted, how soon suchresulting changes could bewould become effective. TheHowever, the passage of any legislation as a result ofdesigned to implement changes in the budget proposals, either Senate Bill or any other similar change in U.S. federal income tax lawlaws similar to the changes included in the budget proposals offered by the White House in 2009, 2010, 2011 and 2012 could eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such changechanges (i) wouldcould make it more costly for us to explore for and develop our oil and natural gas resources and (ii) could negatively affect our financial condition and results of operation and, thus, our ability to make payments on the notes.
The U.S. Congress is considering measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivative markets and preventing excessive speculation. We maintain an active price and basis protection hedging program related to the oil and natural gas we produce.
Additionally, we have used the OTC market exclusively for our oil and natural gas derivative contracts and rely on our hedging activities to manage the risk of low commodity prices and to predict with greater certainty the cash flow from our hedged production. Proposals being considered would impose clearing and standardization requirements for all OTC derivatives and restrict trading positions in the energy futures markets. Such changes would likely materially reduce our hedging opportunities and could negatively affect our revenues and cash flow during periods of low commodity prices.
Unusual weather patterns or natural disasters, whether due to climate change or otherwise, could negatively impact our financial condition.
Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices to unacceptably low levels. In addition, because a majority of our properties are located in Oklahoma, Texas, and Louisiana, our operations are constantly at risk of extreme adverse weather conditions such as tornadoes and hurricanes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as hurricanes or floods, whether due to climate change or otherwise.
Climate change and government laws and regulations related to climate change could negatively impact our financial condition.
In addition to other climate-related risks set forth in this “Risk Factors” section, we are and will be, directly and indirectly, subject to the effects of climate change and may, directly or indirectly, be affected by government laws and regulations related to climate change. We cannot predict with any degree of certainty what effect, if any, possible climate change and government laws and regulations related to climate change will have on our operations, whether directly or indirectly. While we believe that it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on our business, we believe that climate change and government laws and regulations related to climate change may affect, directly or indirectly, (i) the cost of the equipment and services we purchase, (ii) our ability to continue to operate as we have in the past, including drilling, completion and operating methods, (iii) the timeliness of delivery of the materials and services we need and the cost of transportation paid by us and our vendors and other providers of services, (iv) insurance premiums, deductibles and the availability of coverage, (v) the cost of utility services, particularly electricity, in connection with the operation of our properties, and (vi) factors arising from possible greenhouse gas legislation, in addition to previously identified factors, depending upon, but not limited to, the following considerations: whether and to what extent legislation is enacted, the nature of the legislation (such as a cap and trade system or a tax on emissions); the GHG reductions required; the price and availability of offsets; the amount and allocation of allowances; costs required to improve facilities and equipment to reduce emissions in order to comply with regulatory limits or to mitigate the financial consequences of a GHG emission limitations; changes to profit or loss arising from increased or decreased demand for oil and natural gas we produce arising directly from legislation or regulation, and indirectly from changes in production costs. In addition, climate change may increase the likelihood of property damage and the disruption of our operations, especially in coastal states. As a result, our financial condition could be negatively impacted by significant climate change and related governmental regulation, and that impact could be material.operations.
Certain risks are amplified by the current economic environment.
During 2007, the U.S. and many other countries began to exhibit signs of economic weakness, which continued throughout 2008 and 2009.weakness. This weakness has had an adverse impact on the global financial system, stressing a number of large financial institutions. Capital constraints coupled with significant energy price volatility have produced pervasive liquidity issues for many companies. Such events have created uncertainty in the economic outlook, and have amplified the potential likelihood of certain risks inherent in our business, such as:
increased cost of capital and increased difficulties accessing capital to fund expansion and acquisition activities as well as routine operating requirements;
the failure of counterparties to fulfill their delivery or purchase obligations;
business failures by vendors, suppliers or customers that result in (i) delays in progress on our capital projects, (ii) nonpayment of receivables or (iii) expensive and protracted court or bankruptcy proceedings; and
decreases in domestic consumption or in volumes imported to or produced in the United States and related reductions in transportation, terminalling, or marketing margins.
Competition for experienced technical personnel may negatively impact our operations or financial results.
Our continued drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals. Despite the recent decline in commodity prices and lower industry activity levels, competition for these professionals remains strong. We are likely to continue to experience increased costs to attract and retain these professionals.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Congress is currently consideringhas previously considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pendingpreviously considered before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which is already required by some state agencies governing our operations, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could repeal the exemptions for hydraulic fracturing from the Safe Drinking Water Act which would allowAct.
These legislative efforts have halted while EPA studies the issue of hydraulic fracturing. In 2010, EPA initiated a Hydraulic Fracturing Research Study to establish anaddress concerns that hydraulic fracturing may affect the safety of drinking water, as well as review the application of other environmental statutes to hydraulic fracturing activities, including the RCRA and the Clean Water Act. As part of that process, EPA requested and received information from the major fracturing service providers regarding the chemical composition of fluids, standard operating procedures and the sites where they engage in hydraulic fracturing. In February 2011, EPA released its Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, proposing to study the lifecycle of hydraulic fracturing fluid and providing a comprehensive list of chemicals identified in fracturing fluid and flowback/produced waste. EPA is scheduled to release its final draft report in late 2014.
These developments, as well as increased scrutiny of hydraulic fracturing activities by state and municipal authorities may result in additional levellevels of regulation at the federal levelor complexity with respect to existing regulations that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities, which could decrease funds available for servicing our debt obligations and other operating expenses.
We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.
Unusual weather patterns or natural disasters, whether due to climate change or otherwise, could negatively impact our financial condition.
Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices to unacceptably low levels. In addition, because a majority of our properties are located in Oklahoma, Texas, and Louisiana, our operations are constantly at risk of extreme adverse weather conditions such as tornadoes and hurricanes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as hurricanes or floods, whether due to climate change or otherwise.
Climate change and government laws and regulations related to climate change could negatively impact our financial condition.
In addition to other climate-related risks set forth in this “Risk Factors” section, we are and will be, directly and indirectly, subject to the effects of climate change and are, and most likely will continue to be, affected by government laws and regulations related to climate change. We are currently evaluating compliance costs arising from newly adopted mandatory greenhouse gas reporting rules, and potential compliance costs arising from newly promulgated Clean Air Act reporting and permit regulations for greenhouse gas emissions. These new regulations could be preempted by new federal legislation if enacted. However, we cannot predict with any degree of certainty the ultimate effect possible climate change and government laws and regulations related to climate change will have on our operations. While it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on our business, we believe that climate change and government laws and regulations related to climate change may affect: (i) the cost of the equipment and services we purchase, (ii) our ability to continue to operate as we have in the past, including drilling, completion and operating methods, (iii) the timeliness of delivery of the materials and services we need and the cost of transportation paid by us and our vendors and other providers of services, (iv) insurance premiums, deductibles and the availability of coverage, (v) the cost of utility services, particularly electricity, in connection with the operation of our properties, and (vi) factors arising from new Clean Air Act greenhouse gas permitting and, or, possible greenhouse gas legislation, in addition to previously identified factors. These potential effects depend upon, but are not limited to, the following considerations: whether and to what extent legislation is enacted, the nature of the legislation (such as a cap and trade system or a tax on emissions); the greenhouse gas reductions required pursuant to either existing Clean Air Act regulatory requirements or new greenhouse gas legislation; the cost and availability of required offsets or emissions reductions; the amount and allocation of possible allowances; costs required to improve facilities and equipment to both monitor and reduce emissions in order to comply with regulatory limits or to mitigate the financial consequences of a greenhouse gas emission limitations; changes to profit or loss arising from increased or decreased demand for oil and natural gas we produce arising directly from legislation or regulation, and indirectly from changes in production costs. In addition, climate change may increase the likelihood of property damage and the disruption of our operations, especially in coastal states. As a result, our financial condition could be negatively impacted by significant climate change and related governmental regulation, and that impact could be material.
The adoption of The Dodd-Frank Wall Street Reform and Consumer Protection Act could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business.
In July of 2010, the U.S. Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivative markets and preventing excessive speculation. Certain companies that use swaps or other derivatives to hedge commercial risk, referred to as end-users, are permitted to continue to use OTC derivatives under newly adopted regulations. We maintain an active price and basis protection hedging program related to the natural gas and oil we produce to manage the risk of low commodity prices and to predict with greater certainty the cash flow from our hedged production. We have used the OTC market exclusively for our natural gas and oil derivative contracts. The Dodd-Frank Act and the rules and regulations promulgated thereunder should permit us, as an end user, to continue to utilize OTC derivatives. However, we may have increased costs or reduced liquidity in the OTC derivatives market due to the current or future regulations. Such changes could materially reduce our hedging opportunities and negatively affect our revenues and cash flow during periods of low commodity prices.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
See ItemsItem 1. and 2. Business and Properties—Properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See Liquidityour additional disclosures in “Liquidity and Capital Resources—Contractual ObligationsObligations” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, andas well as Note 13, “Commitments and Contingencies,” to the Consolidated Financial Statements.our consolidated financial statements. Such information is incorporated herein by reference.
Naylor Farms, Inc. v. Chaparral Energy, L.L.C. On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5.0 million. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The matter is currently stayed pending resolution of unrelated cases currently on appeal with the U.S. Court of Appeals for the Tenth Circuit. These cases are expected to influence the ruling on class certification in the Plaintiff’s case. At the time that the matter was stayed no class had been certified and discovery was ongoing. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.
In theour opinion, of management, there are no other material pending legal proceedings to which we or any of our subsidiaries are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.
ITEM 4. [RESERVED]MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock has not been registered under the Securities Exchange Act of 1934, and there is no established public trading market for our common equity.
As of April 14, 2010,1, 2013, we had 1,401,3761,425,160 shares of common stock outstanding held by 2131 record holders.
We have not paid any dividends on our common stock in either of the last two years and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also currently restricted in our ability to pay dividends under our Credit Agreement.senior secured revolving credit facility. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for more information regarding the restrictions on our ability to pay dividends.
ITEM 6. SELECTED FINANCIAL DATA
You should read the following historical financial data in connection with the financial statements and related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this report. The financial data as of and for each of the five years ended December 31, 20092012 was derived from our audited financial statements. Our historical results are not necessarily indicative of results to be expected in future periods.
Year Ended December 31, | Year ended December 31, | |||||||||||||||||||||||||||||||||||||||
(dollars in thousands, except per share data) | 2009 | 2008 | 2007 | 2006 | 2005 | |||||||||||||||||||||||||||||||||||
(in thousands) | 2012 | 2011 | 2010 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||
Operating results data: | ||||||||||||||||||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||||||||||||||||||
Oil and natural gas sales | $ | 292,387 | $ | 501,761 | $ | 365,958 | $ | 249,180 | $ | 201,410 | $ | 509,503 | $ | 530,041 | $ | 408,561 | $ | 292,387 | $ | 501,761 | ||||||||||||||||||||
Gain (loss) from oil and natural gas hedging activities | 19,403 | (76,417 | ) | (28,140 | ) | (4,166 | ) | (68,324 | ) | 46,746 | (27,452 | ) | (29,393 | ) | 19,403 | (76,417 | ) | |||||||||||||||||||||||
Other revenues | — | 4,070 | 4,127 | 2,864 | 8,735 | |||||||||||||||||||||||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||||||
Total revenues | 311,790 | 425,344 | 337,818 | 245,014 | 133,086 | 556,249 | 506,659 | 383,295 | 314,654 | 434,079 | ||||||||||||||||||||||||||||||
Costs and expenses | ||||||||||||||||||||||||||||||||||||||||
Lease operating | 94,155 | 120,547 | 104,469 | 71,663 | 42,147 | 130,960 | 121,420 | 106,127 | 94,070 | 120,487 | ||||||||||||||||||||||||||||||
Production tax | 20,341 | 33,815 | 26,216 | 18,710 | 14,626 | 32,003 | 34,321 | 26,495 | 20,341 | 33,815 | ||||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 103,998 | 100,672 | 85,431 | 52,299 | 31,423 | 169,307 | 146,083 | 109,503 | 104,193 | 101,026 | ||||||||||||||||||||||||||||||
Loss on impairment of oil & natural gas properties | 240,790 | 281,393 | — | — | — | — | — | — | 240,790 | 281,393 | ||||||||||||||||||||||||||||||
Loss on impairment of ethanol plant | — | 2,900 | — | — | — | |||||||||||||||||||||||||||||||||||
Loss on impairment of other assets | 2,000 | — | 4,150 | — | 2,900 | |||||||||||||||||||||||||||||||||||
General and administrative | 23,741 | 22,372 | 21,838 | 14,659 | 9,808 | 49,812 | 42,056 | 29,915 | 23,741 | 22,370 | ||||||||||||||||||||||||||||||
Litigation settlement | 2,928 | — | — | — | — | — | — | — | 2,928 | — | ||||||||||||||||||||||||||||||
Other expenses | — | 3,448 | 3,148 | 1,957 | 7,150 | |||||||||||||||||||||||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||||||
Total costs and expenses | 485,953 | 561,699 | 237,954 | 157,331 | 98,004 | 384,082 | 347,328 | 279,338 | 488,020 | 569,141 | ||||||||||||||||||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||||||
Operating income (loss) | (174,163 | ) | (136,355 | ) | 99,864 | 87,683 | 35,082 | 172,167 | 159,331 | 103,957 | (173,366 | ) | (135,062 | ) | ||||||||||||||||||||||||||
Non-operating income (expense) | ||||||||||||||||||||||||||||||||||||||||
Interest expense | (90,102 | ) | (86,038 | ) | (87,656 | ) | (45,246 | ) | (15,588 | ) | (98,402 | ) | (96,720 | ) | (81,370 | ) | (90,102 | ) | (86,038 | ) | ||||||||||||||||||||
Non-hedge derivative gains (losses) | 11,169 | 126,941 | (23,781 | ) | (4,677 | ) | — | |||||||||||||||||||||||||||||||||
Merger costs | (2,169 | ) | (1,400 | ) | — | — | — | |||||||||||||||||||||||||||||||||
Termination fee | — | 3,500 | — | — | — | |||||||||||||||||||||||||||||||||||
Non-hedge derivative gains | 49,685 | 34,408 | 38,595 | 11,169 | 126,941 | |||||||||||||||||||||||||||||||||||
Loss on extinguishment of debt | (21,714 | ) | (20,592 | ) | (2,241 | ) | — | — | ||||||||||||||||||||||||||||||||
Financing costs, net of termination fee | — | — | (1,812 | ) | (2,169 | ) | 2,100 | |||||||||||||||||||||||||||||||||
Other income | 14,403 | 1,845 | 2,276 | 792 | 665 | 504 | 1,545 | 387 | 13,921 | 1,394 | ||||||||||||||||||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||||||
Net non-operating income (expense) | (66,699 | ) | 44,848 | (109,161 | ) | (49,131 | ) | (14,923 | ) | (69,927 | ) | (81,359 | ) | (46,441 | ) | (67,181 | ) | 44,397 | ||||||||||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||||||
Income (loss) from continuing operations before income taxes and non-controlling interest | (240,862 | ) | (91,507 | ) | (9,297 | ) | 38,552 | 20,159 | ||||||||||||||||||||||||||||||||
Income (loss) from continuing operations before income taxes | 102,240 | 77,972 | 57,516 | (240,547 | ) | (90,665 | ) | |||||||||||||||||||||||||||||||||
Income tax expense (benefit) | (89,895 | ) | (35,301 | ) | (3,386 | ) | 14,817 | 7,309 | 37,837 | 35,924 | 23,803 | (89,777 | ) | (34,976 | ) | |||||||||||||||||||||||||
Non-controlling interest | — | — | — | (71 | ) | — | ||||||||||||||||||||||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||||||
Income (loss) from continuing operations | (150,967 | ) | (56,206 | ) | (5,911 | ) | 23,806 | 12,850 | 64,403 | 42,048 | 33,713 | (150,770 | ) | (55,689 | ) | |||||||||||||||||||||||||
Income from discontinued operations, net of related taxes | 6,649 | 1,456 | 1,118 | — | — | — | — | — | 6,452 | 939 | ||||||||||||||||||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||||||
Net income (loss) | $ | (144,318 | ) | $ | (54,750 | ) | $ | (4,793 | ) | $ | 23,806 | $ | 12,850 | $ | 64,403 | $ | 42,048 | $ | 33,713 | $ | (144,318 | ) | $ | (54,750 | ) | |||||||||||||||
|
|
|
|
| ||||||||||||||||||||||||||||||||||||
Income (loss) per share (basic and diluted): | ||||||||||||||||||||||||||||||||||||||||
Continuing operations | $ | (172.14 | ) | $ | (64.09 | ) | $ | (6.74 | ) | $ | 29.74 | $ | 16.58 | |||||||||||||||||||||||||||
Discontinued operations | 7.58 | 1.66 | 1.27 | — | — | |||||||||||||||||||||||||||||||||||
Net income (loss) per share (basic and diluted) | $ | (164.56 | ) | $ | (62.43 | ) | $ | (5.47 | ) | $ | 29.74 | $ | 16.58 | |||||||||||||||||||||||||||
Weighted average number of shares used in calculation of basic and diluted earnings (loss) per share | 877,000 | 877,000 | 877,000 | 800,500 | 775,000 | |||||||||||||||||||||||||||||||||||
Cash flow data: | ||||||||||||||||||||||||||||||||||||||||
Net cash provided by operating activities | $ | 98,675 | $ | 145,831 | $ | 113,070 | $ | 89,154 | $ | 55,744 | $ | 192,000 | $ | 259,616 | $ | 167,702 | $ | 98,675 | $ | 145,831 | ||||||||||||||||||||
Net cash provided by (used in) investing activities | 21,904 | (262,905 | ) | (239,069 | ) | (703,804 | ) | (325,068 | ) | (423,246 | ) | (324,998 | ) | (264,172 | ) | 21,904 | (262,905 | ) | ||||||||||||||||||||||
Net cash provided by (used in) financing activities | (99,274 | ) | 157,499 | 128,883 | 621,855 | 257,080 | 226,476 | 44,860 | 78,164 | (99,274 | ) | 157,499 |
(in thousands) Financial position data: Cash and cash equivalents Total assets Total debt Retained earnings (accumulated deficit) Accumulated other comprehensive income, net of income taxes Total stockholders’ equity (deficit) As of December 31, 2012 2011 2010 2009 2008 $ 29,819 $ 34,589 $ 55,111 $ 73,417 $ 52,112 2,007,552 1,669,733 1,529,292 1,353,920 1,712,836 1,293,402 1,034,573 962,087 1,177,007 1,271,589 17,186 (47,217 ) (89,265 ) (122,978 ) 21,340 23,223 51,846 34,974 17,618 82,133 462,857 424,013 363,557 (4,433 ) 204,400
As of December 31, | |||||||||||||||||||
(dollars in thousands, except per share amounts) | 2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||
Financial position data: | |||||||||||||||||||
Cash and cash equivalents | $ | 73,417 | $ | 52,112 | $ | 11,687 | $ | 8,803 | $ | 1,598 | |||||||||
Total assets | 1,353,920 | 1,712,836 | 1,530,898 | 1,331,435 | 647,379 | ||||||||||||||
Total debt | 1,177,007 | 1,271,589 | 1,114,237 | 976,272 | 446,544 | ||||||||||||||
Retained earnings (accumulated deficit) | (122,978 | ) | 21,340 | 76,090 | 80,883 | 58,126 | |||||||||||||
Accumulated other comprehensive income (loss), net of income taxes | 17,618 | 82,133 | (73,839 | ) | (3,946 | ) | (47,967 | ) | |||||||||||
Total stockholders’ equity (deficit) | (4,433 | ) | 204,400 | 103,178 | 177,864 | 10,167 | |||||||||||||
Cash dividends per common share | — | — | — | $ | 1.35 | $ | 4.40 |
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report. In addition to historical financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”
Overview
We are ana growing independent oil and natural gas company engaged in the production and exploitation company. Our core operations consist of drilling for and acquisitionproduction of oil and natural gas properties. Our areas of operation includefrom conventional and unconventional reservoirs as well as a focus on tertiary operations through enhanced oil recovery (“EOR”) projects utilizing CO2 and polymer in the Mid-Continent and Permian Basin Gulf Coast, Ark-La-Tex, North Texas and the Rocky Mountains.areas. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and EOR projects.
Our reserve estimate as Starting in 2011, we began to redirect our capital expenditures from the drilling of December 31, 2009 was prepared using an average price for oilvertical wells to repeatable resource plays and natural gas based upon the first dayto increase our level of each month for the prior twelve months as required by the SEC’sModernization of Oil and Gas Reporting.expenditures on EOR projects. As of December 31, 2009,2012, we had estimated proved reserves of 141.9146.1 MMBoe with a PV-10 value of approximately $1.3$2.1 billion. These estimated proved reserves included 29.5 MMBoe of EOR reserves. Our reserves were 66%65% proved developed reserves and 63% crude oil. Despite the decline in SEC gas price from $5.62 per Mcf as of December 31, 2008 to $3.87 per Mcf as of December 31, 2009, our estimated proved reserves have increased significantly since December 31, 2008 due in part to an increase in SEC oil price from $44.60 per Bbl as of December 31, 2008 to $61.18 per Bbl as of December 31, 2009. As of December 31, 2008, we had estimated proved reserves of 113.3 MMBoe with a PV-10 value of $932.7 million, of which 74% were proved developed reserves and 45% were65% crude oil.
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles (“GAAP”) requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and natural gas reserves. We use the full cost method of accounting for our oil and natural gas activities.
Generally, our producing properties have declining production rates. Our December 31, 2012 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 14%19%, 11%14%, and 9%12% for the next three years. To grow our production and cash flow, we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.
Oil and natural gas prices fluctuate widely. We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. The prices we receive for our oil and natural gas production affect our:
cash flow available for capital expenditures;
ability to borrow and raise additional capital;
ability to service debt;
quantity of oil and natural gas we can produce;
quantity of oil and natural gas reserves; and
operating results for oil and natural gas activities.
Operating summary
Our production for 2009 was 7,638 MBoe, an 8% increase over 2008, primarily due to our capital expenditures in the Permian and Mid-Continent areas during 2008 and 2009. However a 46% decline in our average sales price before derivative settlements resulted in a 42% decrease in revenue from oil and natural gas sales compared to 2008. Although total operating costs and expenses decreased by 13% compared to 2008, the decrease was not commensurate with the decrease in revenue. In addition, due primarily to changes in the NYMEX forward commodity price curves, our gain on non-hedge derivatives decreased by 91%. Primarily as a result of these factors, we had a net loss of $144.3 million in 2009 compared to a loss of $54.8 million in 2008.
The following are material events that have impacted our liquidity or results of operations, in 2009 and/or are expected to impact these items in future periods:
• |
|
• |
|
• |
|
• |
|
• |
|
Results of operations
Liquidity and capital resourcesOverview
CrudeTotal production and net income have increased in each year from 2010 to 2012. Oil and natural gas sales and cash flow from operations decreased from 2011 to 2012 after increasing from 2010 to 2011. During 2012, revenue decreased by 4% compared to 2011 as a result of lower oil and natural gas prices, have fallen significantly from their peak levelspartially offset by increased oil production. Revenue in 2011 increased by 30% compared to 2010 primarily due to higher oil production and prices, partially offset by lower natural gas production and prices. As a result of these and other transactions discussed below, we had net income in 2012, 2011, and 2010 of $64.4 million, $42.0 million, and $33.7 million, respectively.
Year ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Production (MBoe) | 9,118 | 8,655 | 8,050 | |||||||||
Oil and natural gas sales (in thousands) | $ | 509,503 | $ | 530,041 | $ | 408,561 | ||||||
Net income (loss) (in thousands) | $ | 64,403 | $ | 42,048 | $ | 33,713 | ||||||
Cash flow from operations (in thousands) | $ | 192,000 | $ | 259,616 | $ | 167,702 |
Revenues and production
The following table presents information about our oil and natural gas sales before the effects of commodity derivative settlements:
Year ended December 31, | Percentage | Year ended December 31, | Percentage | |||||||||||||||||
2012 | 2011 | change | 2010 | change | ||||||||||||||||
Oil and natural gas sales (in thousands) | ||||||||||||||||||||
Oil (1) | $ | 457,106 | $ | 441,801 | 3.5 | % | $ | 305,042 | 44.8 | % | ||||||||||
Natural gas | 52,397 | 88,240 | (40.6 | )% | 103,519 | (14.8 | )% | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | $ | 509,503 | $ | 530,041 | (3.9 | )% | $ | 408,561 | 29.7 | % | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Production | ||||||||||||||||||||
Oil (MBbls) (1) | 5,812 | 5,048 | 15.1 | % | 4,093 | 23.3 | % | |||||||||||||
Natural gas (MMcf) | 19,834 | 21,642 | (8.4 | )% | 23,742 | (8.8 | )% | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
MBoe | 9,118 | 8,655 | 5.3 | % | 8,050 | 7.5 | % | |||||||||||||
Average sales prices (excluding derivative settlements) | ||||||||||||||||||||
Oil per Bbl (1) | $ | 78.65 | $ | 87.52 | (10.1 | )% | $ | 74.53 | 17.4 | % | ||||||||||
Natural gas per Mcf | $ | 2.64 | $ | 4.08 | (35.3 | )% | $ | 4.36 | (6.4 | )% | ||||||||||
Average sales price per Boe | $ | 55.88 | $ | 61.24 | (8.8 | )% | $ | 50.75 | 20.7 | % |
(1) | Includes natural gas liquids. |
Oil and natural gas revenues decreased $20.5 million, or 4%, to $509.5 million during 2012 due to a 9% decrease in the average price per Boe offset in part by a 5% increase in sales volumes. Oil production for 2012 increased compared to 2011 primarily due to our drilling activity, especially in our Cleveland Sand and NOMP Core plays, which together accounted for approximately 18% and 11% of our total oil production during 2012 and 2011, respectively. Natural gas production for 2012 decreased compared to 2011 primarily due to the decline in production in the Permian Basin Area, which accounted for approximately 18% and 20% of total natural gas production during 2012 and 2011, respectively.
Oil and natural gas revenues increased $121.5 million, or 30%, to $530.0 million during 2011 due to a 21% increase in the average price per Boe combined with an 8% increase in sales volumes.
The relative impact of changes in commodity prices and sales volumes on our oil and natural gas sales before the effects of hedging is shown in the following table:
Year ended December 31, | ||||||||||||||||
2012 vs. 2011 | 2011 vs. 2010 | |||||||||||||||
(dollars in thousands) | Sales change | Percentage change in sales | Sales change | Percentage change in sales | ||||||||||||
Change in oil sales due to: | ||||||||||||||||
Prices | $ | (51,560 | ) | (11.6 | )% | $ | 65,585 | 21.5 | % | |||||||
Production | 66,865 | 15.1 | % | 71,174 | 23.3 | % | ||||||||||
|
|
|
|
|
|
|
| |||||||||
Total change in oil sales | $ | 15,305 | 3.5 | % | $ | 136,759 | 44.8 | % | ||||||||
|
|
|
|
|
|
|
| |||||||||
Change in natural gas sales due to: | ||||||||||||||||
Prices | $ | (28,471 | ) | (32.2 | )% | $ | (6,123 | ) | (6.0 | )% | ||||||
Production | (7,372 | ) | (8.4 | )% | (9,156 | ) | (8.8 | )% | ||||||||
|
|
|
|
|
|
|
| |||||||||
Total change in natural gas sales | $ | (35,843 | ) | (40.6 | )% | $ | (15,279 | ) | (14.8 | )% | ||||||
|
|
|
|
|
|
|
|
Production volumes by area were as follows (MBoe):
Year ended | Year ended December 31, | |||||||||||||||||||
December 31, | Percentage | Percentage | ||||||||||||||||||
2012 | 2011 | change | 2010 | change | ||||||||||||||||
Enhanced Oil Recovery Project Areas | 1,368 | 1,156 | 18.3 | % | 1,079 | 7.1 | % | |||||||||||||
Mid-Continent Area | 5,690 | 5,037 | 13.0 | % | 4,441 | 13.4 | % | |||||||||||||
Permian Basin Area | 1,196 | 1,315 | (9.0 | )% | 1,500 | (12.3 | )% | |||||||||||||
Other | 861 | 1,147 | (24.9 | )% | 1,030 | 11.4 | % | |||||||||||||
|
|
|
|
|
| |||||||||||||||
Total | 9,115 | 8,655 | 5.3 | % | 8,050 | 7.5 | % | |||||||||||||
|
|
|
|
|
|
Production has been increasing in our EOR Project Areas due to our drilling and development activities. We acquired a 99% working interest in our Farnsworth Unit in November 2009 and we began CO2 injection in the Unit in December 2010. We also acquired an additional 6% working interest in our Camrick Area Units during the secondthird quarter of 2010, thereby increasing our average working interest in these units to 60%. Our total capital investment in our EOR Project Areas was $194.4 million in 2012 compared to $91.8 million in 2011, with our primary focus in 2012 on drilling, development and third quartersexploitation activities in our North Burbank play.
The increase in production in our Mid-Continent Area is primarily due to our drilling activity. We made significant capital investments in our NOMP, Cleveland Sand and Granite Wash plays during 2012, 2011 and 2010, and these plays accounted for approximately 27%, 20%, and 13% of 2008. Lowerour total production during 2012, 2011, and 2010, respectively.
Our production in the Permian Basin Area has been decreasing primarily due to the natural decline in production from natural gas wells in the Haley Area, which accounted for approximately 4% of our total production in 2012, compared to 5% in 2011 and 9% in 2010. Due to prevailing low natural gas prices, we reduced our capital expenditures for natural gas projects during 2012 and 2011.
On May 30, 2012, we sold certain mature oil and natural gas properties located in our Velma Area in southern Oklahoma for a cash price of $37,000 subject to post-closing adjustments. Our Velma area, which is included in the line item “Enhanced Oil Recovery Project Areas” in the production table above, accounted for approximately 1% of our total production prior to the sale and in years ended December 31, 2011 and 2010.
On November 28, 2011, we sold certain oil and natural gas properties located in our Rocky Mountains area to Charger Resources, LLC for a cash price of approximately $33.1 million. Our Rocky Mountains area, which is included in the line item “Other” in the production table above, accounted for approximately 2% of our total production in each of the years ended December 31, 2011 and 2010.
Derivative activities
Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. Certain commodity price swaps qualified and were designated as cash flow hedges.
Entering into derivative instruments allows us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. In December 2011, we amended our senior secured revolving credit facility to provide greater flexibility when hedging our anticipated production. The terms of the amendment allow us to protect a portion of our natural gas liquids production from price volatility using crude oil derivatives. We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss. Our derivative activities are dynamic to allow us to respond to the volatile commodity markets.
Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements, excluding early derivative monetizations, on realized prices:
Year ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Oil (per Bbl): (1) | ||||||||||||
Before derivative settlements | $ | 78.65 | $ | 87.52 | $ | 74.53 | ||||||
After derivative settlements | $ | 80.67 | $ | 76.11 | $ | 71.91 | ||||||
Post-settlement to pre-settlement price | 102.6 | % | 87.0 | % | 96.5 | % | ||||||
Natural gas (per Mcf): | ||||||||||||
Before derivative settlements | $ | 2.64 | $ | 4.08 | $ | 4.36 | ||||||
After derivative settlements | $ | 3.93 | $ | 5.65 | $ | 6.20 | ||||||
Post-settlement to pre-settlement price | 148.9 | % | 138.5 | % | 142.2 | % |
(1) | Includes natural gas liquids. |
The estimated fair values of our oil and natural gas derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values.
As of December 31, | ||||||||||||
(in thousands) | 2012 | 2011 | 2010 | |||||||||
Derivative assets (liabilities): | ||||||||||||
Natural gas swaps | $ | 12,155 | $ | 30,124 | $ | 32,408 | ||||||
Oil swaps | 3,618 | (5,912 | ) | (58,200 | ) | |||||||
Oil collars | 26,231 | 5,049 | 1,509 | |||||||||
Natural gas basis differential swaps | (1,599 | ) | (1,268 | ) | (5,623 | ) | ||||||
|
|
|
|
|
| |||||||
Net derivative asset (liability) | $ | 40,405 | $ | 27,993 | $ | (29,906 | ) | |||||
|
|
|
|
|
|
Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, all gains and losses from changes in the fair value of our derivative contracts subsequent to March 31, 2010 are recognized immediately in non-hedge derivative gains (losses) in the consolidated statement of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Prior to March 31, 2010, a portion of the change in fair value was deferred through other comprehensive income. As of December 31, 2012, accumulated other comprehensive income (“AOCI”) consists of deferred net gains of $37.1 million ($23.2 million net of tax) related to discontinued cash flow hedges that will be recognized as gains from oil and natural gas hedging activities through December 2013 as the hedged production is sold.
The effects of derivative activities on our results of operations and cash flows were as follows:
Year ended December 31, | ||||||||||||||||||||||||
2012 | 2011 | 2010 | ||||||||||||||||||||||
(in thousands) | Non-cash fair value adjustment | Cash receipts (payments) | Non-cash fair value adjustment | Cash receipts (payments) | Non-cash fair value adjustment | Cash receipts (payments) | ||||||||||||||||||
Gain (loss) from oil and natural gas hedging activities: | ||||||||||||||||||||||||
Oil swaps | $ | 46,746 | $ | — | $ | (27,452 | ) | $ | — | $ | (25,399 | ) | $ | (5,504 | ) | |||||||||
Natural gas swaps | — | — | — | — | 1,510 | — | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Gain (loss) from oil and natural gas hedging activities | $ | 46,746 | $ | — | $ | (27,452 | ) | $ | — | $ | (23,889 | ) | $ | (5,504 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Non-hedge derivative gains (losses): | ||||||||||||||||||||||||
Oil swaps and collars | $ | 30,710 | $ | 11,761 | $ | 55,828 | $ | (57,619 | ) | $ | (8,660 | ) | $ | (5,225 | ) | |||||||||
Natural gas swaps and collars | (17,968 | ) | 27,184 | (2,284 | ) | 42,068 | (7,769 | ) | 53,728 | |||||||||||||||
Natural gas basis differential contracts | (331 | ) | (1,671 | ) | 4,355 | (7,940 | ) | 9,341 | (10,110 | ) | ||||||||||||||
Derivative monetizations | — | — | — | — | 193 | 7,097 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Non-hedge derivative gains (losses) | $ | 12,411 | $ | 37,274 | $ | 57,899 | $ | (23,491 | ) | $ | (6,895 | ) | $ | 45,490 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total gains (losses) from derivative activities | $ | 59,157 | $ | 37,274 | $ | 30,447 | $ | (23,491 | ) | $ | (30,784 | ) | $ | 39,986 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
Our gain (loss) from oil and natural gas hedging activities during 2012, 2011, and 2010 included net gains (losses) of $46.7 million, $(27.5) million, and $(23.9) million, respectively, which were associated with derivatives for which hedge accounting was previously discontinued.
The fluctuation in non-hedge derivative gains from period to period is due primarily to the significant volatility of oil and natural gas prices and basis differentials and to changes in our outstanding derivative contracts during the periods. Non-hedge derivative gains also included proceeds from the early monetization of derivatives. During 2010, we unwound and monetized certain oil and natural gas derivative contracts with original settlement dates from April 2010 through December 2012 for net proceeds of $7.1 million.
Total gains on derivative activities recognized in our statements of operations were $96.4 million, $7.0 million, and $9.2 million in 2012, 2011, and 2010, respectively.
Lease operating expenses
Year ended December 31, | Percentage | Year ended December 31, | Percentage change | |||||||||||||||||
2012 | 2011 | change | 2010 | |||||||||||||||||
Lease operating expenses (in thousands) | $ | 130,960 | $ | 121,420 | 7.9 | % | $ | 106,127 | 14.4 | % | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Lease operating expenses per Boe | $ | 14.36 | $ | 14.03 | 2.4 | % | $ | 13.18 | 6.4 | % | ||||||||||
|
|
|
|
|
|
|
|
|
|
Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices.
Our lease operating expenses during 2012 increased $9.5 million or 7.8% compared to 2011 primarily due to additional workovers and increased oilfield service costs associated with new wells added during 2012. On a per Boe basis, lease operating expense increased 2.4% to $14.37, reflecting the increased production levels in 2012. Workover and well work costs for operated properties increased to $29.9 million in 2012, as compared to $23.0 million in 2011, largely in our Camrick, Farnsworth, Ark-La-Tex and Permian Basin—Other areas.
Our lease operating expenses during 2011 were $121.4 million, an increase of $15.3 million or 14% (6.4% on a per Boe basis) compared to 2010. The increase was primarily due to our increased activity combined with the upward pressure on operating and service costs associated with the improvement in oil prices during 2011. Electricity and fuel costs for operated properties increased to $26.9 million in 2011, as compared to $22.8 million in 2010, primarily associated with new wells we added during 2011 and increased activity in our EOR operations. Workover and well work costs for operated properties increased to $23.0 million in 2011, as compared to $19.5 million in 2010, primarily due to a higher number of workovers being conducted in our Gulf Coast, Permian Basin—Other, Tunstill, Golden Trend, Velma, and Sho-Vel-Tum plays.
Our lease operating expenses on a BOE basis, increased from $13.18 during 2010 to $14.03 in 2011. This increase of 6% on a BOE basis was primarily the result of the increase in well workover, electricity and fuel expense, as discussed above.
Production taxes (which include ad valorem taxes)
Year ended December 31, | Percentage | Year ended December 31, | Percentage change | |||||||||||||||||
2012 | 2011 | change | 2010 | |||||||||||||||||
Production taxes (in thousands) | $ | 32,003 | $ | 34,321 | (6.8 | )% | $ | 26,495 | 29.5 | % | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Production taxes per Boe | $ | 3.51 | $ | 3.97 | (11.6 | )% | $ | 3.29 | 20.7 | % | ||||||||||
|
|
|
|
|
|
|
|
|
|
Production taxes generally change in proportion to oil and natural gas sales. The 2012 decrease in production taxes from 2011 was primarily due to the 8.7% decrease in average realized prices combined with the 3.9% decrease in oil and natural gas sales. The 2011 increase in production taxes from 2010 was primarily due to the 21% increase in average realized prices combined with an 8% increase in production volumes.
Depreciation, depletion and amortization (“DD&A”) and losses on impairment
Year ended December 31, | Percentage | Year ended December 31, | Percentage change | |||||||||||||||||
2012 | 2011 | change | 2010 | |||||||||||||||||
DD&A (in thousands): | ||||||||||||||||||||
Oil and natural gas properties | $ | 154,788 | $ | 132,307 | 17.0 | % | $ | 96,676 | 36.9 | % | ||||||||||
Property and equipment | 10,574 | 10,146 | 4.2 | % | 9,567 | 6.1 | % | |||||||||||||
Accretion of asset retirement obligation | 3,945 | 3,630 | 8.7 | % | 3,260 | 11.3 | % | |||||||||||||
|
|
|
|
|
| |||||||||||||||
Total DD&A | $ | 169,307 | $ | 146,083 | 15.9 | % | $ | 109,503 | 33.4 | % | ||||||||||
|
|
|
|
|
| |||||||||||||||
DD&A per Boe: | ||||||||||||||||||||
Oil and natural gas properties | $ | 16.98 | $ | 15.29 | 11.1 | % | $ | 12.01 | 27.3 | % | ||||||||||
Other fixed assets | $ | 1.59 | $ | 1.59 | — | $ | 1.59 | — | ||||||||||||
|
|
|
|
|
| |||||||||||||||
Total DD&A per Boe | $ | 18.57 | $ | 16.88 | 10.0 | % | $ | 13.60 | 24.1 | % | ||||||||||
|
|
|
|
|
|
We adjust our revenues. An extendedDD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties increased $22.5 million from 2011 to 2012, of which $15.5 million was due to a higher rate per equivalent unit of production and $7.0 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $1.69 to $16.98 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.
DD&A on oil and natural gas properties increased $35.6 million from 2010 to 2011, of which $28.4 million was due to a higher rate per equivalent unit of production and $7.2 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $3.28 to $15.29 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.
We record the estimated future value of a liability for an asset retirement obligation in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.
Impairment of oil and natural gas properties. In accordance with the full-cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the cost of unproved properties not being amortized.
Our estimates of oil and natural gas reserves as of December 31, 2012, 2011, and 2010 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC’sModernization of Oil and Gas Reporting and the guidance of the Financial Accounting Standard Board (“FASB”) relating toOil and Gas Reserve Estimation and Disclosures. As of December 31, 2012, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, and no additional ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $94.71 per Bbl of oil and $2.76 per Mcf of gas for the year ended December 31, 2012.
A decline in oil orand natural gas prices subsequent to December 31, 2012 could result in ceiling test write-downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.
Impairment of other assets.In 2012, we recognized $1.5 million of impairment losses on certain of our owned drilling rigs due to our expectation that these may materiallynot sell at a price that will exceed their carrying values. Also in 2012, we recognized $0.5 million of additional impairment losses primarily related to drill pipe.
We owned an interest in the Levelland/Hockley County ethanol plant in Levelland, Texas, and adversely affectwe own a pipeline constructed for the sole purpose of supplying natural gas to the ethanol plant. During the fourth quarter of 2010, we determined that any future cash flows generated by either the ethanol plant or by our pipeline which supplies gas to the ethanol plant would probably not be sufficient to allow us to recover our investment in these assets. We accordingly recorded an impairment charge of $4.2 million, which included our $2.1 million investment in the ethanol plant and the $2.1 million carrying value of our pipeline assets.
General and administrative expenses (“G&A”) and litigation settlement
Year ended December 31, | Percentage | Year ended December 31, | Percentage change | |||||||||||||||||
(dollars in thousands, excluding per Boe amounts) | 2012 | 2011 | change | 2010 | ||||||||||||||||
Gross G&A expenses | $ | 67,176 | $ | 58,745 | 14.4 | % | $ | 44,575 | 31.8 | % | ||||||||||
Capitalized exploration and development costs | (17,364 | ) | (16,689 | ) | 4.0 | % | (14,660 | ) | 13.8 | % | ||||||||||
|
|
|
|
|
| |||||||||||||||
Net G&A expenses | $ | 49,812 | $ | 42,056 | 18.4 | % | $ | 29,915 | 40.6 | % | ||||||||||
|
|
|
|
|
| |||||||||||||||
Average G&A cost per Boe | $ | 5.46 | $ | 4.86 | 12.3 | % | $ | 3.72 | 30.6 | % | ||||||||||
|
|
|
|
|
| |||||||||||||||
Full-time office employees as of December 31 | 353 | 337 | 4.7 | % | 328 | 2.7 | % | |||||||||||||
|
|
|
|
|
|
G&A expenses in 2012 increased $7.8 million from 2011, primarily due to compensation and benefit cost increases related to the competitive nature of our market and our growing operations. Expenses for non-recurring professional services for certain projects and initiatives increased, approximately $2.2 million compared to 2011. Stock-based compensation expense included in G&A for 2012 was $3.1 million.
G&A expenses in 2011 increased $12.1 million from 2010, primarily due to higher compensation, land, and legal costs caused by our heightened level of activity and our high level of investment in EOR properties. Stock-based compensation expense included in G&A for 2011 was $3.7 million.
Other income and expenses
Interest expense.The following table presents interest expense for the periods indicated:
Year ended December 31, | ||||||||||||
(in thousands) | 2012 | 2011 | 2010 | |||||||||
Senior secured revolving credit facility | $ | 1,193 | $ | 156 | $ | 10,119 | ||||||
8.5% Senior Notes due 2015 | — | 4,587 | 28,489 | |||||||||
8.875% Senior Notes due 2017 | 10,420 | 29,756 | 29,675 | |||||||||
9.875% Senior Notes due 2020 | 31,115 | 30,211 | 9,119 | |||||||||
8.25% Senior Notes due 2021 | 33,579 | 28,781 | — | |||||||||
7.625% Senior Notes due 2022 | 21,420 | — | — | |||||||||
Bank fees and other interest | 5,112 | 5,608 | 6,004 | |||||||||
Capitalized interest | (4,437 | ) | (2,379 | ) | (2,036 | ) | ||||||
|
|
|
|
|
| |||||||
Total interest expense | $ | 98,402 | $ | 96,720 | $ | 81,370 | ||||||
|
|
|
|
|
| |||||||
Average long-term borrowings | $ | 1,166,349 | $ | 1,036,541 | $ | 968,114 | ||||||
|
|
|
|
|
|
Total interest expense increased in 2012 by $1.7 million, or 2%, compared to 2011 primarily due to increased levels of borrowing, partially offset by a lower weighted-average interest rate. Total interest expense increased $15.4 million in 2011, or 19%, compared to 2010 primarily due to a higher weighted-average interest rate combined with increased levels of borrowing.
Loss on extinguishment of debt. On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. Net proceeds from the 7.625% Senior Notes were used to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. During the second quarter of 2012, we recorded a loss of $21.7 million associated with the refinancing of our 8.875% Senior Notes, including $15.8 million in repurchase or redemption-related fees and a $5.9 million write-off of deferred financing costs and unaccreted discount.
On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. During the first quarter of 2011, we recorded a $20.6 million loss associated with the refinancing of our 8.5% Senior Notes due 2015, including $15.1 million in repurchase or redemption-related fees and a $5.5 million write-off of deferred financing costs.
On April 12, 2010, we entered into and closed an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”). We used the proceeds available under our senior secured revolving credit facility to repay the amounts owing under our Seventh Restated Credit Agreement (our “prior credit facility”). During the year ended December 31, 2010, we recorded a loss of $2.2 million related to the write-off of prepaid bank fees associated with our prior credit facility.
Income taxes
Year ended December 31, | ||||||||||||
(dollars in thousands) | 2012 | 2011 | 2010 | |||||||||
Current income tax expense (benefit) | $ | 118 | $ | 179 | $ | 79 | ||||||
Deferred income tax expense (benefit) | 37,719 | 35,745 | 23,724 | |||||||||
|
|
|
|
|
| |||||||
Total income tax expense (benefit) | $ | 37,837 | $ | 35,924 | $ | 23,803 | ||||||
|
|
|
|
|
| |||||||
Effective tax rate | 37.0 | % | 46.1 | % | 41.4 | % | ||||||
Total net deferred tax asset (liability) | $ | (35,773 | ) | $ | (16,178 | ) | $ | 30,148 | ||||
|
|
|
|
|
|
As of December 31, 2012, our federal and state net operating loss carryforwards were approximately $439.0 million and $413.0 million, respectively, and will begin to expire in 2013. As of December 31, 2012, approximately $300.0 million of the state net operating loss carryforwards have been reduced by a valuation allowance based on our assessment that it is more likely than not that a portion will not be realized. No additional adjustment was made to the valuation allowance during 2012.
Realization of our deferred tax assets is dependent upon generating sufficient future business,taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.
Liquidity and capital resources
Historically, our primary sources of liquidity or abilityhave been cash generated from our operations, debt, and private equity sales. On April 12, 2010, we sold an aggregate of 475,043 shares of our common stock to finance planned capital expendituresCCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”) for proceeds of $313.2 million, net of fees and other expenses of $11.8 million.
On September 16, 2010, we issued $300.0 million aggregate principal amount of 9.875% Senior Notes maturing on October 1, 2020. We used the proceeds from the 9.875% Senior Notes due 2020 to pay down outstanding amounts under our senior secured revolving credit facility and for working capital. As a result of our issuance of the 9.875% Senior Notes due 2020, the borrowing base under our senior secured revolving credit facility was reduced from $450.0 million to $375.0 million.
On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes.
On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the 7.625% Senior Notes to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes.
On November 15, 2012, we issued $150.0 million aggregate principal amount of 7.625% Senior Notes due 2022 under the same indenture covering our $400.0 million issuance made on May 2, 2012. The net proceeds from the sale of the Add-on Notes were used to repay all of our outstanding indebtedness under our senior secured revolving credit facility and for general corporate purposes.
We maintain a senior revolving credit facility, which has a borrowing base of $500.0 million, that is collateralized by our oil and natural gas properties, and, following an amendment effective November 1, 2012, is scheduled to mature on November 1, 2017. We pledge our producing oil and natural gas properties to secure our Credit Agreement.senior secured revolving credit facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. We have the capacity to utilize the available funds as needed to supplement our operating cash flows as a financing source for our capital expenditures. Our ability to fund our capital expenditures is dependent on the level of product prices and the success of our acquisition and development program in adding to our available borrowing base. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available for our capital expenditures.under the borrowing base. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and natural gas prices through the use of commodity derivatives.
Historically, our primary sources of liquidity have been cash generated from our operations and debt. At December 31, 2009, we had approximately $73.4 million of cash and cash equivalents and $3.1 million of availability under our Seventh Restated Credit Agreement with a borrowing base of $513.0 million.
On March 23, 2010, we entered into a stock purchase agreement (the “Stock Purchase Agreement”) with CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”). On April 12, 2010, we sold 475,043 shares of our common stock to CCMP for a purchase price of $325.0 million. In connection with the closing of the Stock Purchase Agreement, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement. As of April 14, 2010, we had $275.3 million of availability under our Eighth Restated Credit Agreement. See Note 14 to our consolidated financial statements for additional information regarding these transactions.
Covenants set forth in the indentures for our 8 1/2% Senior Notes and the 8 7/8% Senior Notes, including the ACNTA test, limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and natural gas at specified dates. The amount of secured debt permitted under our Senior Notes is set at a minimum of $500.0 million. We have the ability to borrow under our senior secured revolving credit facility, subject to maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than 4.50 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. As of April 1, 2013 our availability under the borrowing base was limited to $245.4 million based on the Consolidated Net Debt to Consolidated EBITDAX ratio.
Sources and uses of cash
Our net increase (decrease) in cash is summarized as follows:
Year ended December 31, | Year ended December 31, | |||||||||||||||||||||||
(dollars in thousands) | 2009 | 2008 | 2007 | |||||||||||||||||||||
(in thousands) | 2012 | 2011 | 2010 | |||||||||||||||||||||
Cash flows provided by operating activities | $ | 98,675 | $ | 145,831 | $ | 113,070 | $ | 192,000 | $ | 259,616 | $ | 167,702 | ||||||||||||
Cash flows provided by (used in) investing activities | 21,904 | (262,905 | ) | (239,069 | ) | (423,246 | ) | (324,998 | ) | (264,172 | ) | |||||||||||||
Cash flows provided by (used in) financing activities | (99,274 | ) | 157,499 | 128,883 | 226,476 | 44,860 | 78,164 | |||||||||||||||||
|
|
| ||||||||||||||||||||||
Net increase in cash during the period | $ | 21,305 | $ | 40,425 | $ | 2,884 | ||||||||||||||||||
Net increase (decrease) in cash during the period | $ | (4,770 | ) | $ | (20,522 | ) | $ | (18,306 | ) | |||||||||||||||
|
|
|
Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas, reduced or increased by associated hedging activities.gas. Cash inflows from oil and natural gas sales net of hedging settlementsdecreased in 2012 compared to 2011 primarily due to lower oil and natural gas prices, partially offset by increased oil production, and increased expenses and interest payments. Cash inflows from oil and natural gas sales and cash outflows for operating expenses both decreased sharply from 2008 to 2009 due to the decline in commodity prices after having increased significantly from 20072010 to 20082011 as commodityoil prices rose. Operating cash flows also include production tax credits of $13.7 million, $1.0 million, and $0.3 million for the years ended December 31, 2009, 2008, and 2007, respectively. This source of cash received will not be available in future periods. Primarily as a result of the above activity, cash flowflows from operating activities decreased by 32%26% in 2012 from 2008 to 2009 after having2011 and increased by 29%55% from 2007.2011 to 2010.
We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the years ended December 31, 2009, 2008,2012, 2011, and 2007,2010, cash flows provided by operating activities were approximately 55%38%, 48%76%, and 51%54%, respectively, of cash used for the purchase of property and equipment and oil and natural gas properties. In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. Total costs attributable to the loss of well control were approximately $10.6 million. Our insurance policy has covered 100% of these costs, with the $0.6 million insurance retention and deductible being payable by us. We received insurance proceeds of $1.9 million and $8.1 million in 2009 and 2008, respectively, and no further receipts are expected. Insurance proceeds received are recorded as a reduction ofcapital expenditures for oil and natural gas properties on the balance sheet andduring 2012 are detailed in the statement ofnext section. During 2012, cash flows.
During 2009, 2008, and 2007, the monetization of derivatives providedflows used in investing cash inflows of $111.9 million, $32.6 million, and $0, respectively, and the return of our prepaid production tax credits provided investing cash inflows of $13.5 million, $1.1 million, and $0.4 million, respectively. Cash flows provided by investing activities for the year ended December 31, 2009 also included proceeds of $25.3$46.0 million from property dispositions, including approximately $37.0 million from the sale of certain mature oil and natural gas properties located in our Velma Area in southern Oklahoma. During 2011, cash flows used in investing activities included proceeds of $33.1 million from the sale of certain non-strategic oil and natural gas properties located in our Rocky Mountains area, and proceeds of $4.4 million from the sale of the ESPremaining assets of Green Country Supply, Inc., a wholly owned subsidiary.
We received (paid) net derivative settlements totaling $37.3 million, $(23.5) million, and Chemicals divisions$45.5 million during 2012, 2011 and 2010, respectively. Cash flows used in investing activities in 2010 included proceeds from early derivative monetizations of GCS. See theResults$7.1 million. Primarily as a result of operations section for additional discussion of these transactions.our net capital investments and derivative settlements, cash flows used in investing activities were $423.2 million, $325.0 million, and $264.2 million during 2012, 2011, and 2010, respectively.
Net cash provided by (used in) financing activities was ($99.3)$226.5 million, $157.5$44.9 million, and $128.9$78.2 million, during 2009, 2008,2012, 2011, and 2007,2010, respectively. On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the 7.625% Senior Notes to consummate a tender offer for all of our 8.875% Senior Notes, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 7.625% Senior Notes and the repurchase or redemption of our 8.875%Senior Notes, we capitalized approximately $8.8 million of issuance costs related to underwriting and other fees and we expensed approximately $21.7 million of refinancing costs, including a $5.9 million non-cash write-off of deferred financing costs and unaccreted discount.
On November 15, 2012, we issued $150.0 million aggregate principal amount of 7.625% Senior Notes (the “Add-on Notes”) under the same indenture covering our $400.0 million issuance made on May 2, 2012. The net proceeds from the sale of the Add-on Notes were used to repay all of our outstanding indebtedness under our senior secured revolving credit facility and for general corporate purposes. In connection with the issuance of the Add-on Notes, we recorded a premium of $6.8 million and capitalized $3.5 million of issuance costs related to underwriting and other fees.
On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 8.25% Senior Notes and the repurchase or redemption of our 8.5% Senior Notes, we paid approximately $8.8 million of issuance costs related to underwriting and other fees and approximately $15.1 million of repurchase and redemption-related costs.
On April 12, 2010, we sold an aggregate of 475,043 shares of our common stock to CCMP for proceeds of $313.2 million, net of fees and other expenses of $11.8 million, and we entered into and closed our senior secured revolving credit facility. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under our senior secured revolving credit facility, to repay the amounts owing under our prior credit facility.
On September 16, 2010 we issued $300.0 million aggregate principal amount of 9.875% Senior Notes maturing on October 1, 2020 for net proceeds of $293.0 million, less fees and other expenses of $6.6 million. As a result of our monetizationissuance of derivatives in the second quarter of 2009,9.875% Senior Notes, the borrowing base under our Seventh Restated Credit Agreementsenior secured revolving credit facility was reduced from $600.0$450.0 million to $513.0$375.0 million, and proceeds from the monetization of $87.0 million were paid to the banks. Borrowings under our Seventh Restated Credit Agreement were $147.0 million and $110.0 million in 2008 and 2007, respectively, and were used to finance our capital expenditures. On January 18, 2007, we issued $325.0 million aggregate principal amount of 8 7/8% Senior Notes maturing on February 1, 2017. The net proceeds from the issuance of the notes$206.0 million were used to pay down outstanding amountsamounts. The remaining $80.4 million was used for working capital.
Capital expenditures
Our oil and natural gas property capital expenditure budget for 2012 was expanded during the third quarter of 2012 from $316.0 million to $443.0 million to accelerate capital investment associated with our North Burbank Unit CO2 project. Expenditures were expected to occur over the next four years have been accelerated as field-wide communication was higher than anticipated. We have also made significant acquisitions of unproved leasehold acreage in the NOMP and the Panhandle Marmaton play, and participated in incremental outside-operated drilling opportunities in the NOMP, Anadarko Cleveland Sand and Anadarko Granite Wash plays. Investing in EOR reduces near-term growth opportunities but enhances longer-term growth and is consistent with our strategy of driving near-term growth through drilling and long-term growth through EOR development. The expanded budget was funded through net cash provided by operations, borrowings under our Seventh Restated Credit Agreement.
Capital expendituressenior secured revolving credit facility, and sales of non-strategic properties. Expanded budget dollars that were unused in various areas were reallocated to complete our drilling program in the fourth quarter.
Our actual costs incurred for the year ended December 31, 20092012 and our current 2010 budgeted 2013 capital expenditures for oil and natural gas properties are detailedsummarized in the table below:following table:
(dollars in thousands) | Year ended December 31, 2009(1) | 2010 budgeted capital expenditures | ||||
Development activities: | ||||||
Developmental drilling(2) | $ | 77,826 | $ | 163,000 | ||
Enhancements | 34,767 | 12,000 | ||||
Tertiary recovery | 15,047 | 63,000 | ||||
Acquisitions: | ||||||
Proved properties | 14,552 | 20,000 | ||||
Unproved properties | 3,781 | — | ||||
Exploration activities | 4,942 | 10,000 | ||||
Total | $ | 150,915 | $ | 268,000 | ||
2012 Capital Expenditures | ||||||||||||||||||||||||
(in thousands) | EOR Project Areas | Mid-Continent Area | Permian Basin Area | Other | Total | Budgeted 2013 capital expenditures(1) | ||||||||||||||||||
Acquisitions | $ | 314 | $ | 40,530 | $ | 6,778 | $ | 381 | $ | 48,003 | $ | 25,000 | ||||||||||||
Drilling | 20,337 | 229,378 | 16,866 | 2,047 | 268,628 | 234,000 | ||||||||||||||||||
Enhancements | 53,922 | 9,487 | 6,674 | 5,342 | 75,425 | 55,000 | ||||||||||||||||||
Pipeline and field infrastructure | 109,517 | — | — | 109,517 | 67,000 | |||||||||||||||||||
CO2 purchases | 10,291 | — | — | — | 10,291 | 20,000 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Total | $ | 194,381 | $ | 279,395 | $ | 30,318 | $ | 7,770 | $ | 511,864 | $ | 401,000 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Includes |
In addition to the capital expenditures for oil and natural gas properties, we spent approximately $2.6$19.0 million for acquisition and construction of new office and administrative facilitiesproperty and equipment during 2009.2012.
Our oil and natural gas property capital expenditures for 2009 represent a 50% reduction from our 2008 levels. Despite this reduction, production for 2009 increased to 7,638 MBoe as a result of capital investments made in 2008 and the first quarter of 2009.
Our actual costs incurred for the year ended December 31, 20092012 and our current 2010 budgeted capital expenditures for oil and natural gas properties for 2013 are summarized by area are detailed in the table below:following table:
(dollars in thousands) | 2009 capital expenditures(1) | Percent of total | 2010 budgeted capital expenditures | Percent of total | ||||||||
Mid-Continent(2) | $ | 117,820 | 78 | % | $ | 209,000 | 78 | % | ||||
Permian Basin | 17,390 | 11 | % | 34,000 | 13 | % | ||||||
Gulf Coast | 11,881 | 8 | % | 14,000 | 5 | % | ||||||
Ark-La-Tex | 2,306 | 2 | % | 1,000 | 0 | % | ||||||
North Texas | 1,262 | 1 | % | 4,000 | 2 | % | ||||||
Rocky Mountains | 256 | 0 | % | 6,000 | 2 | % | ||||||
$ | 150,915 | 100 | % | $ | 268,000 | 100 | % | |||||
(in thousands) | Actual 2012 capital expenditures | Percent of total | Budgeted 2013 capital expenditures | Percent of total | ||||||||||||
Enhanced Oil Recovery Project Areas | $ | 194,381 | 38 | % | $ | 137,000 | 34 | % | ||||||||
Mid-Continent Area | 279,395 | 55 | % | 180,000 | 45 | % | ||||||||||
Permian Basin Area | 30,318 | 6 | % | 84,000 | 21 | % | ||||||||||
Other | 7,770 | 1 | % | — | — | |||||||||||
|
|
|
|
|
|
|
| |||||||||
Total | $ | 511,864 | 100 | % | $ | 401,000 | 100 | % | ||||||||
|
|
|
|
|
|
|
|
|
A majorityDuring 2012, we increased our focus on the development of our EOR assets which is consistent with our strategy of driving near-term growth through drilling and long-term growth through EOR development. Investing in EOR reduces near-term growth opportunities but enhances longer-term growth. Our developmental and exploratory expenditures for EOR increased to $194.0 in 2012 from $88.2 million in 2011 and $37.7 million in 2010. Our oil and natural gas property capital expenditure budget for development drilling in 20102013 is set at $401.0 million, of which $137.0 million, or 34%, is allocated to the development of our core areas of the Mid-ContinentEOR assets. In 2014, our EOR capital investments are expected to increase somewhat but remain less than incurred in 2012 and Permian Basin. The wells we drillare expected to range between $75.0 million and $150.0 million in these areas are primarily infill or single stepout wells. A number of high impact wells that we expect will support our production throughout 2010 are currently being drilled and should be completed and on line during the first and second quarters of 2010. Six of these wells are located in the Texas Panhandle Atoka Wash and one is located in the Haley Area of Loving County, Texas. However, we cannot accurately predict the timing or level of future production.subsequent years.
We continually evaluate our capital needs and compare them to our capital resources. Our actual expenditures during 20102013 may be higher or lower than our budgeted amounts. Our level of exploration and development expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.
As of December 31, 2009, we had cash and cash equivalents of $73.4 million and long-term debt obligations of $1.2 billion.
Credit AgreementsSenior Notes
At December 31, 2009,On May 2, 2012, we wereissued $400,000 aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the May 2, 2012 7.625% Senior Notes issuance to consummate a party to a Seventh Restated Credit Agreement, which was scheduled to mature on October 31, 2010, and was collateralized by our oil and natural gas properties. As a result of our derivative monetization during the second quarter of 2009, the borrowing base was reduced from $600.0 million to $513.0 million effective June 8, 2009. At December 31, 2009, we had $507.0 million outstanding under our Seventh Restated Credit Agreement andtender offer for all of our borrowings8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes.
On November 15, 2012, we issued an additional $150,000 aggregate principal amount of 7.625% Senior Notes under the same indenture covering the issuance on May 2, 2102 (the “Add-on Notes”). The net proceeds from the Add-on Notes were Eurodollar loans. The borrowing base,used to repay the outstanding balance of the indebtedness under our senior secured revolving credit facility and for general corporate purposes. In connection with the sale of the Add-on Notes, we entered into a registration rights agreement in which was reaffirmedwe agree to file a registration statement with the SEC related to an offer to exchange the Add-on Notes for an issue of registered notes within 270 days of the closing date (the “Target Registration Date”). If we fail to complete the exchange offer by the Target Registration Date, we will be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the Target Registration Date. After the first 90 days, the rate increases an additional 0.25% for each additional 90-day period, up to a maximum of 1.0% per annum.
In connection with the issuance of the May 2, 2012 7.625% Senior Notes, we capitalized approximately $8.8 million of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. In connection with the issuance of the November 23, 2009, was $513.015, 2012 Add-on Notes, we recorded a premium of $6.8 million asand capitalized $3.5 million of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method.
On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 8.25% Senior Notes and the repurchase or redemption of our 8.5% Senior Notes, we capitalized approximately $8.8 million of issuance costs related to underwriting and other fees and we expensed approximately 20.6 million refinancing costs, including a $5.5 million non-cash write-off of deferred financing costs.
Senior Notes at December 31, 2009. We believe we were2012 and 2011 consisted of the following:
December 31, | ||||||||
(in thousands) | 2012 | 2011 | ||||||
8.875% Senior Notes due 2017 | — | 325,000 | ||||||
9.875% Senior Notes due 2020 | 300,000 | 300,000 | ||||||
8.25% Senior Notes due 2021 | 400,000 | 400,000 | ||||||
7.625 % Senior Notes due 2022 | 550,000 | — | ||||||
Discount on 8.875% Senior Notes due 2017 | — | (1,658 | ) | |||||
Discount on 9.875% Senior Notes due 2020 | (5,969 | ) | (6,441 | ) | ||||
Premium on 7.625% Senior Notes due 2022 | 6,631 | — | ||||||
|
|
|
| |||||
$ | 1,250,662 | $ | 1,016,901 | |||||
|
|
|
|
The Senior Notes are our senior unsecured obligations, rank equally in complianceright of payment with all our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the Senior Notes is fully and unconditionally guaranteed on a senior unsecured basis by our material existing and future domestic restricted subsidiaries, as defined in the indentures.
On or after the date that is five years before the maturity date, we may redeem some or all of the Senior Notes at any time at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption.
Prior to the date that is five years before the maturity date, the Senior Notes may be redeemed in whole or in part at a redemption price equal to the principal amount of the notes plus accrued and unpaid interest to the date of redemption plus an applicable premium specified in the indentures.
We and our restricted subsidiaries are subject to certain negative and financial covenants under the Seventh Restated Credit Agreement asindentures governing the Senior Notes. The provisions of December 31, 2009.the indentures limit our and our restricted subsidiaries’ ability to, among other things:
On April 12, 2010, in connection with
incur or guarantee additional indebtedness, or issue preferred stock;
pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
make investments;
incur liens on assets;
create restrictions on the closingability of our Stock Purchase Agreementrestricted subsidiaries to pay dividends, make loans, or transfer property to us;
engage in transactions with CCMP,affiliates;
sell assets, including capital stock of our subsidiaries;
consolidate, merge or transfer assets; and
enter into other lines of business.
If we experience a change of control (as defined in the indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.
Senior secured revolving credit facility
In April 2010, we entered into and closed an Eighth Restated Credit Agreement,our senior secured revolving credit facility, which has an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to maturematures on April 12, 2014. We used the proceeds from1, 2016. The balance outstanding under our senior secured revolving credit facility at December 31, 2012 and 2011 was $25.0 million and $0.0 million, respectively. As of April 1, 2013, we have drawn down $45.0 million under our senior secured revolving credit facility.
During 2012, we had three amendments to our senior secured revolving credit facility. The Eighth Amendment to our senior secured revolving credit facility, effective April 30, 2012, amended our Asset Sale Covenant to permit the sale of common stockcertain oil and natural gas properties located in southern Oklahoma and increased our permitted ratio of Consolidated Net Debt to CCMP, along with proceeds available underConsolidated EBITDAX. The Ninth Amendment to our senior secured revolving credit facility, effective May 24, 2012, changed the Eighth Restatedcalculation of Consolidated EBITDAX to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.875% Senior Notes. The Tenth Amendment to our senior secured revolving credit facility, effective November 1, 2012, increased our borrowing base from $375.0 million to $500.0 million; increased the Aggregate Maximum Credit Agreement,Amount from $450.0 million to repay$750.0 million and the amounts owingmaximum Aggregate Maximum Credit Amount (after giving effect to any exercise of the accordion option on the terms and conditions set forth in the senior secured revolving credit facility) to $850.0 million; extended the maturity date to November 1, 2017; reduced the applicable margins added to the Adjusted LIBO Rate for the purposes of determining the interest rate (i) on Eurodollar loans to a margin ranging from1.50% to 2.50% and (ii) on Alternate Base Rate (“ABR”) loans to a margin ranging from 0.50% to 1.50%, each depending on the utilization percentage of the conforming borrowing base; reduced commitment fees to 0.375% if less than 50% of the borrowing base is utilized; reaffirmed the borrowing base through May 1, 2013 and permitted the offering of the Add-on Notes without triggering the automatic 25% reduction of the borrowing base.
Amounts borrowed under our Seventh Restated Credit Agreement.senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the ABR. As of December 31, 2012, the balance outstanding under our senior secured revolving credit facility was $25.0 million, all of which was subject to the Eurodollar rate.
The termsEurodollar rate is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our senior secured revolving credit facility, plus a margin that varies depending on our utilization percentage. During 2012, the margin varied from 1.50% to 2.75%. Interest payments on Eurodollar borrowings are due the last day of the Eighth Restated Credit Agreement are described below. The termsinterest period, if shorter than three months, or every three months.
Interest on loans subject to the ABR is computed as the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in our senior secured revolving credit facility, plus 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus1.0%, plus a margin that varies depending on our utilization percentage. During 2012, the margin varied from 0.50% to 1.75%.
Commitment fees of 0.375% to 0.50% accrued on the unused portion of the Seventh Restated Credit Agreement were substantially similar to those contained inborrowing base amount based on the Eighth Restated Credit Agreement. All discussionsutilization percentage and are included as a component of interest rates and ratios asexpense. We have the right to make prepayments of dates prior to April 12, 2010 relate to the Seventh Restated Credit Agreement. borrowings at any time without penalty or premium.
Availability under our Credit Agreementsenior secured revolving credit facility is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. If we issue Additional Permitted Debt, as defined in the Eighth Restated Credit Agreement, theEffective November 1, 2012, our borrowing base will be automatically reduced by an amount equalwas increased to 25% of the aggregate stated principal amount of the debt issued. As of April 14, 2010, we had $275.3$500.0 million of availability under our Eighth Restated Credit Agreement.
The agreement has certain negative and affirmative covenants that require, among other things, maintaining a specified current ratio and debt service ratio.
Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans.
Interest on Eurodollar loans is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the Credit Agreement, plus a margin where the margin varies from 2.500% to 3.500% depending on the utilization percentage of the conforming borrowing base. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.
Interest on ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, (2) the Federal Funds Effective Rate, as defined in our Credit Agreement, plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in our Credit Agreement, plus 1%; plus a margin where the margin varies from 1.625% to 2.625%, depending on the utilization percentage of the borrowing base.
Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount, depending on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.
Interest was paid at least every three months during 2009 and 2008. The effective rate of interest on the entire outstanding balance was 6.081% and 5.299% as of December 31, 2009 and 2008, respectively, and was based upon LIBOR.through May 1, 2013.
Our Credit Agreementsenior secured revolving credit facility contains restrictive covenants that may limit our ability, among other things, to:
incur additional indebtedness;
create or incur additional liens on our oil and natural gas properties;
pay dividends in cash or other property, redeem our capital stock or prepay certain indebtedness;
make investments in or loans to others;
change our line of business;
enter into operating leases;
merge or consolidate with another person, or lease or sell all or substantially all of our assets;
sell, farm-out or otherwise transfer property containing proved reserves;
enter into transactions with affiliates;
issue preferred stock;
enter into negative pledge agreements or agreements restricting the ability of our subsidiaries to pay dividends;
enter into or terminate certain swap agreements;
amend our organizational documents; and
amend, modify or waive under our permitted bond documents (i) any covenants that would make the terms materially more onerous to us or (ii) certain other provisions.
Our Credit Agreementsenior secured revolving credit facility requires us to maintain a current ratio, as defined in our Credit Agreement,senior secured revolving credit facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our Credit Agreement,senior secured revolving credit facility, we consider the current ratio calculated under our Credit Agreementsenior secured revolving credit facility to be a useful measure of our liquidity because it includes the funds available to us under our Credit Agreementsenior secured revolving credit facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 20092012 and 2008,2011, our current ratio as computed using GAAP was 1.380.84 and 1.34,0.74, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.513.11 and 1.19,2.91, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance:
(dollars in thousands) | December 31, 2009 | December 31, 2008 | ||||||
Current assets per GAAP | $ | 161,682 | $ | 218,363 | ||||
Plus—Availability under Credit Agreement | 3,145 | 3,270 | ||||||
Less—Short-term derivative instruments | (18,226 | ) | (51,412 | ) | ||||
Less—Deferred tax asset on derivative instruments and asset retirement obligations | (1,079 | ) | — | |||||
Current assets as adjusted | $ | 145,522 | $ | 170,221 | ||||
Current liabilities per GAAP | $ | 117,529 | $ | 163,123 | ||||
Less—Short term derivative instruments | (20,677 | ) | — | |||||
Less—Deferred tax liability on derivative instruments and asset retirement obligations | — | (19,755 | ) | |||||
Less—Short-term asset retirement obligation | (300 | ) | (300 | ) | ||||
Current liabilities as adjusted | $ | 96,552 | $ | 143,068 | ||||
Current ratio for loan compliance | 1.51 | 1.19 | ||||||
December 31, | ||||||||
(in thousands) | 2012 | 2011 | ||||||
Current assets per GAAP | $ | 163,617 | $ | 124,123 | ||||
Plus—Availability under senior secured revolving credit facility | 474,080 | 372,080 | ||||||
Less—Short-term derivative instruments | (42,516 | ) | (12,840 | ) | ||||
Less—Deferred tax asset on derivative instruments and asset retirement obligations | — | — | ||||||
|
|
|
| |||||
Current assets as adjusted | $ | 595,181 | $ | 483,363 | ||||
|
|
|
| |||||
Current liabilities per GAAP | $ | 194,590 | $ | 167,717 | ||||
Less—Short term derivative instruments | (436 | ) | (1,505 | ) | ||||
Less—Short-term asset retirement obligations | (2,900 | ) | ||||||
Less—Deferred tax liability on derivative instruments and asset retirement obligations | ||||||||
|
|
|
| |||||
Current liabilities as adjusted | $ | 191,254 | $ | 166,212 | ||||
|
|
|
| |||||
Current ratio for loan compliance | 3.11 | 2.91 | ||||||
|
|
|
|
The monetizationIn April 2011, we amended our senior secured revolving credit facility to extend its maturity date from April 12, 2014 to April 1, 2016 and to permit the exclusion of derivatives in the fourth quarter of 2008our reasonable and the firstcustomary fees and second quarters of 2009 allowed us to exceed our required current ratio by a higher margin.
Priorexpenses related to the amendment described below,refinancing of our 8.5% Senior Notes due 2015 from the Seventh Restated Credit Agreement requiredcalculation of Consolidated EBITDAX.
Our senior secured revolving credit facility, as amended, requires us to maintain a Consolidated Total Debt to Consolidated EBITDAX Ratio, as defined in our Seventh Restated Credit Agreement, of not greater than 5.00 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on March 31, 2007. As of March 31, 2007, we did not meet this ratio.
Effective May 11, 2007, the Seventh Restated Credit Agreement was amended to replace the Total Debt to EBITDAX ratio with a Consolidated Senior Total Debt to Consolidated EBITDAX ratio. For purposes of the amended ratio, Consolidated Senior Total Debt consisted of all outstanding loans under the Seventh Restated Credit Agreement, letters of credit and obligations under capital leases, as defined in the First Amendment to our Seventh Restated Credit Agreement. The amended Seventh Restated Credit Agreement required us to maintain a Consolidated Senior TotalNet Debt to Consolidated EBITDAX ratio, as defined in our Seventh Restated Credit Agreement,senior secured revolving credit facility, of not greater than:
2.75than 4.50 to 1.0 for the annualized periods commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on March 31, 2007, June 30, 2007 and September 30, 2007 and for the four consecutive fiscal quarters ending on December 31, 2007; and
2.50 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2008 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters thereafter.quarter.
The Seventh Restated Credit Agreement, as amended effective May 21, 2009, required us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX Ratio, as defined in the Fifth Amendment to our Seventh Restated Credit Agreement, of not greater than:
2.50 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2009; and
3.00 to 1.0 for the four consecutive fiscal quarters ending on June 30, 2009, September 30, 2009, December 31, 2009, and March 31, 2010.
For purposes of the amended ratio, Consolidated Senior Total Debt consisted of all outstanding loans under the Seventh Restated Credit Agreement, letters ofOur senior secured revolving credit and obligations under capital leases, minus cash on hand in excess of accounts payable and accrued liabilities that are more than 90 days past the invoice date, as defined in the Fifth Amendment to our Seventh Restated Credit Agreement.
The Eighth Restated Credit Agreement requires us to maintain a Consolidated Total Debt to Consolidated EBITDAX ratio, as defined in the Eight Restated Credit Agreement, of not greater than:
4.50 to 1.0 for the annualized periods commencing on April 1, 2010 and ending on the last day of the fiscal quarter ending on June 30, 2010, September 30, 2010, and December 31, 2010;
4.25 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2011, June 30, 2011, and September 30, 2011; and
4.00 to 1.0 for the four consecutive fiscal quarters ending on December 31, 2011 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters thereafter.
The Credit Agreementfacility also specifies events of default, including:
our failure to pay principal or interest under the Credit Agreementour senior secured revolving credit facility when due and payable;
our representations or warranties proving to be incorrect, in any material respect, when made or deemed made;
our failure to observe or perform certain covenants, conditions or agreements under the Credit Agreement;our senior secured revolving credit facility;
our failure to make payments on certain other material indebtedness when due and payable;
the occurrence of any event or condition that requires the redemption or repayment of, or an offer to redeem or repay, certain other material indebtedness prior to its scheduled maturity;
the commencement of a voluntary or involuntary proceeding seeking liquidation, reorganization or other relief, or the appointment of a receiver, trustee, custodian or other similar official for us or our subsidiaries, and the proceeding or petition continues undismissed for 60 days or an order approving the foregoing is entered;
our inability, admission or failure generally to pay our debts as they become due;
the entry of a final, non-appealable judgment for the payment of money in excess of $5.0 million that remains undischarged for a period of 60 consecutive days;
a Change of Control (as defined in the Credit Agreement)our senior secured revolving credit facility); and
the occurrence of a default under any permitted bond document, which such default continues unremedied or is not waived prior to the expiration of any applicable grace or cure under any permitted bond document.
If the outstanding borrowings under our Credit Agreementsenior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 30 days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days.
Senior Notes
Senior Notes at December 31, 2009 and December 31, 2008 consisted of the following:
December 31, | ||||||||
2009 | 2008 | |||||||
8.5% Senior Notes due 2015 | $ | 325,000 | $ | 325,000 | ||||
8.875% Senior Notes due 2017(1) | 325,000 | 325,000 | ||||||
Discount on Senior Notes due 2017 | (2,123 | ) | (2,325 | ) | ||||
$ | 647,877 | $ | 647,675 | |||||
|
|
|
As part of the indenture, we entered into a registration rights agreement in which we agreed to file a registration statement with the SEC related to an offer to exchange the notes for an issue of registered notes within 270 days of the closing date. The exchange offer was not completed within the 270-day period ending October 15, 2007 as required by the registration rights agreement. As a result, we accrued liquidated damages of $0.3 million during the year ended December 31, 2007. On February 29, 2008, we completed the exchange offer, and liquidated damages ceased to accrue as of that date. Total liquidated damages paid in 2008 were $0.4 million.
The Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the Senior Notes is fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries, as defined in the indentures.
On and after the fifth anniversary of the issue date, we may redeem some or all of the Senior Notes at any time at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption.
Prior to the fifth anniversary of the issue date, the Senior Notes may be redeemed in whole or in part at a redemption price equal to the principal amount of the notes plus accrued and unpaid interest to the date of redemption plus an applicable premium specified in the indentures.
We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the Senior Notes. The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:
incur additional indebtedness;
pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;
make investments;
incur liens;
create any consensual limitation on the ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us;
engage in transactions with our affiliates;
sell assets, including capital stock of our subsidiaries; and
consolidate, merge or transfer assets.
As of December 31, 2009, we are not able to incur additional secured debt as a result of the ACNTA test under the Senior Notes.
If we experience a change of control (as defined in the indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell to us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.
Alternative capital resources
We have historically used cash flow from operations, and debt financing, and private issuances of common stock as our primary sources of capital. As done on April 12, 2010, and as may be done inIn the future we may use additional sources such as asset sales, additional public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain funds through one or more of these alternative sources, if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.
Contractual obligations
The following table summarizes our contractual obligations and commitments as of December 31, 2009:2012:
(Dollars in thousands)(1) | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | Total | ||||||||||
Debt: | |||||||||||||||
Revolving credit line—including estimated interest(2) | $ | 532,695 | $ | — | $ | — | $ | — | $ | 532,695 | |||||
Senior notes, including estimated interest | 56,469 | 112,938 | 112,938 | 735,414 | 1,017,759 | ||||||||||
Other long-term notes including estimated interest | 5,548 | 6,627 | 2,739 | 15,552 | 30,466 | ||||||||||
Capital leases including estimated interest | 265 | 134 | — | — | 399 | ||||||||||
Abandonment obligations | 300 | 600 | 600 | 35,965 | 37,465 | ||||||||||
Derivative obligations | 20,677 | 30,163 | — | — | 50,840 | ||||||||||
Purchase commitments | 4,876 | 3,641 | — | — | 8,517 | ||||||||||
Total | $ | 620,830 | $ | 154,103 | $ | 116,277 | $ | 786,931 | $ | 1,678,141 | |||||
(in thousands) | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | Total | |||||||||||||||
Debt: | ||||||||||||||||||||
Senior secured revolving credit facility | $ | — | $ | — | $ | 25,000 | $ | — | $ | 25,000 | ||||||||||
Senior Notes, including estimated interest | 104,563 | 209,125 | 209,125 | 1,656,798 | 2,179,611 | |||||||||||||||
Other long-term notes and capital leases, including estimated interest | 4,566 | 4,874 | 2,437 | 12,068 | 23,945 | |||||||||||||||
Commitment fees on senior secured revolving credit facility | 1,875 | 3,750 | 3,464 | — | 9,089 | |||||||||||||||
Abandonment obligations | 2,900 | 5,800 | 5,800 | 34,714 | 49,214 | |||||||||||||||
Derivative obligations | 436 | 2,192 | — | — | 2,628 | |||||||||||||||
CO2 purchase commitments | 1,397 | 6,263 | 2,578 | 22,648 | 32,886 | |||||||||||||||
Operating lease obligations | 309 | 273 | 147 | — | 729 | |||||||||||||||
Other commitments | 20,623 | — | — | — | 20,623 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | $ | 136,669 | $ | 232,277 | $ | 248,551 | $ | 1,726,228 | $ | 2,343,725 | ||||||||||
|
|
|
|
|
|
|
|
|
|
We have a long-term contractscontract to purchase up to all of the CO2 manufactured at twoan existing ethanol plants. Under one contract,plant. As of December 31, 2012, we own the rights to purchase or otherwise take all of the plant’s CO2 production, which is an average of approximately four MMcf per day. The contract’s ten-year term will begin upon our first purchase. We are currentlywere purchasing approximately eight to ten MMcf per day14 MMcf/d of CO2 under the secondthis contract, and we expect to purchase an average of approximately 15 to 19 MMcf per day13 MMcf/d over the fifteen-yearremainder of the contract term, which began onexpires in May 1, 2009. There2024. Purchases under this contract were no significant purchases under either$1.1 million, $0.5 million, and $0.3 million during 2012, 2011, and 2010, respectively. Pricing is fixed for the remainder of these contracts in 2009, 2008, or 2007. Pricing under both contracts is variable over timethe contract and both contracts havethe contract has renewal language.
We have rights under two additional contracts that require us towith fertilizer plants under which we purchase CO2 that is restricted, in whole or in part, for use only in EOR projects. Under both contracts, the fertilizer plants retain the right to install additional equipment and use some of the CO2 to make certain fertilizer products, which could reduce the CO2 available to us. Under one of these contracts, as of December 31, 2012, we may purchase a variable amount of CO2, up to 20 MMcf per day. We have historically taken approximately 10 MMcf per day under this contract, and we project we would purchasewere purchasing an average of approximately 16 MMcf per day19 MMcf/d and expect our purchases to remain at that level over the remainder of the initialcontract term, of the contract, which expires in February 2011.2021. Purchases under this contract were $0.8$1.5 million, $0.9$1.5 million, and $0.3$1.0 million during 2009, 2008,2012, 2011, and 2007,2010, respectively. The contract automatically renews for an additional ten years unless terminated by the other party in the event we fail to match a higher competing offer for the CO2, or unless otherwise terminated by us. Under the second of these contracts, we currently purchase an average of approximately six MMcf per day of CO2 and we have nominatedelected to purchase ten MMcf per day10 MMcf/d of CO2 through 2011.2014, subject to availability. During 2012, we purchased approximately 1 MMcf/d of CO2 under this contract. Purchases under this contract, which include transportation charges, were $2.3$1.2 million, $2.3$3.1 million, and $1.5$1.3 million during 2009, 2008,2012, 2011, and 2007,2010, respectively. The contract expires in 2016. We may terminate or permanently reduce our purchase rate under this second additional contract, which expires in 2016, at the end of any calendar year with 13 months notice. Pricing under both of these contracts is dependent on certain variable factors, including the price of oil.
ResultsOn March 24, 2011, we signed a long-term contract to purchase up to 100% of CO2 emissions from an existing nitrogen fertilizer plant that produces approximately 42 MMcf/d of CO2.We intend to use these CO2 volumes for injection into our North Burbank Unit. The initial term of the contract is 20 years from commencement of operations
Overview
Production has increased in each of the last three years. However, oilcompression facilities and natural gaspipeline, and the contract has renewal language. Pricing under the contract is fixed for the first five contract years and variable thereafter. Beginning no later than July 2013, and assuming the fertilizer plant produces and delivers a specified quality of CO2, we will be obligated to purchase an average of approximately 23.5 MMcf/d the first year of the contract and 35.3 MMcf/d for the remaining contract years or pay for any deficiencies at the price volatility has had a significant impact on our revenues and cash flows from operations. Average sales prices and oil and natural gas sales decreased by 46% and 42%, respectively, from 2008in effect when the minimum delivery was to 2009 after having increased by 31% and 37%, respectively, from 2007have occurred. After the first ten contract years, we may permanently reduce up to 2008. In addition, we recorded non-cash pre-tax ceiling test impairments100% of our oil and natural gas propertiespurchase rate under this contract with six months notice. We expect to purchase an average of $240.8 million and $281.4 million in 2009 and 2008, respectively. As a resultapproximately 24 MMcf/d of these and other transactions discussed below, our net loss increased $89.6 million from 2008 to 2009 and $50.0 million from 2007 to 2008.
Year ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Production (MBoe) | 7,638 | 7,072 | 6,773 | |||||||||
Oil and natural gas sales (in thousands) | $ | 292,387 | $ | 501,761 | $ | 365,958 | ||||||
Net loss (in thousands) | $ | (144,318 | ) | $ | (54,750 | ) | $ | (4,793 | ) | |||
Net loss per share (basic and diluted) | $ | (164.56 | ) | $ | (62.43 | ) | $ | (5.47 | ) | |||
Cash flow from operations (in thousands) | $ | 98,675 | $ | 145,831 | $ | 113,070 |
CORevenues and production2
The following table presents information about our oil and natural gas sales before the effects of hedging:
Year ended December 31, | Percent increase | Year ended December 31, | Percent increase | ||||||||||||
2009 | 2008 | (decrease) | 2007 | (decrease) | |||||||||||
Oil and natural gas sales (dollars in thousands) | |||||||||||||||
Oil | $ | 213,207 | $ | 348,907 | (38.9 | )% | $ | 234,428 | 48.8 | % | |||||
Natural gas | 79,180 | 152,854 | (48.2 | )% | 131,530 | 16.2 | % | ||||||||
Total | $ | 292,387 | $ | 501,761 | (41.7 | )% | $ | 365,958 | 37.1 | % | |||||
Production | |||||||||||||||
Oil (MBbls) | 3,874 | 3,773 | 2.7 | % | 3,356 | 12.4 | % | ||||||||
Natural gas (MMcf) | 22,584 | 19,795 | 14.1 | % | 20,504 | (3.5 | )% | ||||||||
MBoe | 7,638 | 7,072 | 8.0 | % | 6,773 | 4.4 | % | ||||||||
Average sales prices (excluding derivative settlements) | |||||||||||||||
Oil per Bbl | $ | 55.04 | $ | 92.47 | (40.5 | )% | $ | 69.85 | 32.4 | % | |||||
Natural gas per Mcf | $ | 3.51 | $ | 7.72 | (54.5 | )% | $ | 6.41 | 20.4 | % | |||||
Boe | $ | 38.28 | $ | 70.95 | (46.0 | )% | $ | 54.03 | 31.3 | % |
Oil and natural gas revenues decreased $209.4 million, or 42%, to $292.4 million during 2009 due to a 46% decrease under this contract starting in the average price per Boe, partially offset by an 8% increase in sales volumes. Oilsecond quarter of 2013 and natural gas revenues increased $135.8 million, or 37%, to $501.8 million during 2008 due to a 31% increase incontinuing for the average price per Boeremainder of 2013.
We have entered into operating lease agreements for the use of office space and a 4% increase in sales volumes.
The relative impact of changes in commodity prices and sales volumesequipment. We also rent equipment for use on our oil and natural gas sales beforeproperties. We have leases relating to office space and equipment that have terms of up to five years. As of December 31, 2011, total remaining payments associated with these operating leases were $0.7 million.
Other commitments that are not currently recorded on our balance sheet relate to contracts in place as of December 31, 2012, primarily for the effectspurchase of hedging is shown in the following table:
Year ended December 31, | ||||||||||||||
2009 vs. 2008 | 2008 vs. 2007 | |||||||||||||
(dollars in thousands) | Sales increase (decrease) | Percentage increase (decrease) in sales | Sales increase (decrease) | Percentage increase (decrease) in sales | ||||||||||
Change in oil sales due to: | ||||||||||||||
Prices | $ | (145,040 | ) | (41.6 | )% | $ | 85,350 | 36.4 | % | |||||
Production | 9,340 | 2.7 | % | 29,129 | 12.4 | % | ||||||||
Total increase (decrease) in oil sales | $ | (135,700 | ) | (38.9 | )% | $ | 114,479 | 48.8 | % | |||||
Change in natural gas sales due to: | ||||||||||||||
Prices | $ | (95,210 | ) | (62.3 | )% | $ | 25,872 | 19.7 | % | |||||
Production | 21,536 | 14.1 | % | (4,548 | ) | (3.5 | )% | |||||||
Total increase (decrease) in natural gas sales | $ | (73,674 | ) | (48.2 | )% | $ | 21,324 | 16.2 | % | |||||
Oilpipe and natural gas production for 2009 increased primarily dueother equipment relating to our CO2 projects, drilling programrig services, and enhancements of our existing properties, much of which was accomplishedother assets. These purchases are generally expected to be finalized within the next several months and are included in 2008 and the first quarter of 2009. Oil production for 2008 increased primarily due to the addition of volumes from acquisitions, our expanded drilling program, and enhancements of our existing properties. Production volumes by area were as follows (MBoe):
Year ended December 31, | Percent increase | Year ended December 31, | Percent increase | |||||||||
2009 | 2008 | (decrease) | 2007 | (decrease) | ||||||||
Mid-Continent | 5,014 | 4,733 | 5.9 | % | 4,389 | 7.8 | % | |||||
Permian Basin | 1,600 | 1,145 | 39.7 | % | 1,047 | 9.4 | % | |||||
Gulf Coast | 461 | 564 | (18.3 | )% | 631 | (10.6 | )% | |||||
Ark-La-Tex | 260 | 291 | (10.7 | )% | 317 | (8.2 | )% | |||||
North Texas | 164 | 184 | (10.9 | )% | 230 | (20.0 | )% | |||||
Rocky Mountains | 139 | 155 | (10.3 | )% | 159 | (2.5 | )% | |||||
Total | 7,638 | 7,072 | 8.0 | % | 6,773 | 4.4 | % | |||||
We have focused our capital expenditures budget for 2013. We generally have the ability to terminate the contracts for purchase of equipment and other assets, in the Mid-Continent and Permian areas. As a result, production inwhich case our four growth areas has declined and is expected to continue to decline, since our planned capital expenditures for 2010 are also focused in our core areas of the Mid-Continent and Permian Basin.
The increase in production in the Permian area is primarily dueliability would be limited to the Bowdle 47 No. 2, which began selling natural gas in late November 2008 and accounted for approximately 9% of total production for 2009. We expect production from this wellcost incurred by the vendor up to decline by approximately 52% in 2010. We arethat point. Because we do not currently drilling an offset, the Bowdle 47 No. 4, which is expected to come online in the second quarter of 2010. If successful, this well, combined with several other high impact wells that we are currently drilling or participating in, will support our production levels throughout 2010. However, we cannot accurately predict the timing or level of future production.
Derivative activities
Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. Certain commodity price swaps qualified and were designated as cash flow hedges. All of our derivative instruments are considered to be economic hedges regardless of whether they are designated as cash flow hedges for accounting purposes.
Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements, excluding derivative monetizations, on realized prices:
Year ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Oil (per Bbl): | ||||||||||||
Before derivative settlements | $ | 55.04 | $ | 92.47 | $ | 69.85 | ||||||
After derivative settlements | $ | 56.36 | $ | 71.95 | $ | 61.35 | ||||||
Post-settlement to pre-settlement price | 102.4 | % | 77.8 | % | 87.8 | % | ||||||
Natural gas (per Mcf): | ||||||||||||
Before derivative settlements | $ | 3.51 | $ | 7.72 | $ | 6.41 | ||||||
After derivative settlements | $ | 5.32 | $ | 7.38 | $ | 6.80 | ||||||
Post-settlement to pre-settlement price | 151.6 | % | 95.6 | % | 106.1 | % |
The estimated fair values of our oil and natural gas derivative instruments are provided below. The associated carrying values ofanticipate canceling these instruments are equal tocontracts, the estimated fair values.
As of December 31, | |||||||||||
(dollars in thousands) | 2009 | 2008 | 2007 | ||||||||
Oil swaps | $ | (68,551 | ) | $ | 111,416 | $ | (155,782 | ) | |||
Natural gas swaps | 30,340 | 13,312 | 4,709 | ||||||||
Oil collars | 12,290 | 57,716 | — | ||||||||
Natural gas collars | 14,065 | 21,682 | — | ||||||||
Natural gas basis differential swaps | (14,964 | ) | 1,618 | 539 | |||||||
Net derivative asset (liability) | $ | (26,820 | ) | $ | 205,744 | $ | (150,534 | ) | |||
During the fourth quarter of 2008, we determined that our natural gas swaps are no longer expected to be highly effective, primarily due to the increased volatility in the basis differentials between the contract price and the indexed price at the point of sale. As a result, we discontinued hedge accounting and applied mark-to-market accounting treatment to all outstanding natural gas swaps. The change in fair value related topayments under these instruments, after hedge accounting was discontinued, is recorded immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. In the past, a portion of the change in fair value would have been deferred through other comprehensive income (loss), and the ineffective portion wouldcontracts have been included in the gain (loss) from oil and natural gas hedging activities, which is a component of revenue.
In addition, we monetized certain oil and natural gas swaps and collars in 2009 and 2008. Certain swaps that were monetized had previously been accounted for as cash flow hedges. As of December 31, 2009 and 2008, accumulated other comprehensive income (loss) (“AOCI”) included $83.4 million and $23.7 million, respectively, of deferred gains related to discontinued cash flow hedges that will be recognized as a gain from oil and natural gas hedging activities when the hedged production is sold.
The effects of derivative activities on our results of operations and cash flows were as follows:
Year ended December 31, | ||||||||||||||||||||||||
2009 | 2008 | 2007 | ||||||||||||||||||||||
(dollars in thousands) | Non-cash fair value adjustment | Cash receipts (payments) | Non-cash fair value adjustment | Cash receipts (payments) | Non-cash fair value adjustment | Cash receipts (payments) | ||||||||||||||||||
Gain (loss) from oil and natural gas hedging activities: | ||||||||||||||||||||||||
Oil swaps | $ | 14,114 | $ | (2,349 | ) | $ | 7,770 | $ | (73,170 | ) | $ | (6,636 | ) | $ | (28,528 | ) | ||||||||
Natural gas swaps | 7,638 | — | 4,779 | (15,796 | ) | (1,707 | ) | 8,731 | ||||||||||||||||
Gain (loss) from oil and natural gas hedging activities | $ | 21,752 | $ | (2,349 | ) | $ | 12,549 | $ | (88,966 | ) | $ | (8,343 | ) | $ | (19,797 | ) | ||||||||
Non-hedge derivative gains (losses): | ||||||||||||||||||||||||
Oil swaps and collars | $ | (30,791 | ) | $ | 7,490 | $ | 80,297 | $ | (4,258 | ) | $ | (24,416 | ) | $ | — | |||||||||
Natural gas swaps and collars | 9,455 | 46,100 | 24,144 | 3,086 | — | — | ||||||||||||||||||
Natural gas basis differential contracts | (16,582 | ) | (5,189 | ) | 1,079 | 5,970 | 1,385 | (750 | ) | |||||||||||||||
Derivative monetizations | (111,188 | ) | 111,874 | (15,966 | ) | 32,589 | — | — | ||||||||||||||||
Non-hedge derivative gains (losses) | $ | (149,106 | ) | $ | 160,275 | $ | 89,554 | $ | 37,387 | $ | (23,031 | ) | $ | (750 | ) | |||||||||
Total gains (losses) from derivative activities | $ | (127,354 | ) | $ | 157,926 | $ | 102,103 | $ | (51,579 | ) | $ | (31,374 | ) | $ | (20,547 | ) | ||||||||
Due to the low oil prices prevalent during 2009, we received payments on oil derivatives of $5.1 million; however, we recognized non-cash losses on oil derivatives of $16.6 million in 2009 primarily due to the significant improvement in the NYMEX forward strip oil price as of December 31, 2009 compared to December 31, 2008. This includes gains of $14.5 million reclassified into earnings that are associated with derivatives for which hedge accounting was discontinued in 2008.
Due primarily to the low natural gas prices prevalent throughout 2009 and to lower average NYMEX forward strip gas prices as of December 31, 2009 compared to December 31, 2008, we recognized a gain on gas derivatives of $63.2 million in 2009. This includes gains of $7.7 million reclassified into earnings that are associated with derivatives for which hedge accounting was discontinued in 2008. Losses on natural gas basis differential contracts were $21.8 million during 2009, primarily due to lower differentials indicated by the forward commodity price curves as well as low differentials throughout 2009.
In addition, during the first quarter of 2009, we monetized natural gas swaps with original settlement dates from May through October of 2009 for proceeds of $9.5 million. During the second quarter of 2009, we monetized additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. As a result of these monetizations, gains of $0.7 million were recognized in earnings, and gains of $81.9 million were deferred through AOCI.
Due primarily to the high commodity prices prevalent during the first nine months of 2008, we made payments on oil and natural gas derivatives of $77.4 million and $12.7 million, respectively. However, these losses were offset by non-cash gains on oil and natural gas derivatives of $88.1 million and $28.9 million, respectively, which resulted from the decline in the NYMEX forward strip oil and natural gas prices as of December 31, 2008 compared to December 31, 2007, and which included gains of $57.7 million and $21.7 million, respectively, on costless collars covering 1,666 MBbls of oil at a weighted average floor of $103.75 per Bbl and 6,540 BBtu of natural gas at a floor of $10.00 per MMBtu that were entered into during 2008 and remained outstanding as of December 31, 2008. Gains on natural gas basis differential swaps were $7.0 million in 2008, primarily due to high differentials during 2008.
In addition, during the fourth quarter of 2008, we monetized oil and natural gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32.6 million. As a result of this monetization, gains of $16.6 million were recognized in earnings, and gains of $17.9 million were deferred through AOCI.
Primarily as a result of higher average NYMEX forward strip oil prices during 2007 compared to 2006 and strong oil prices during 2007, losses on oil swaps were $59.5 million in 2007. These losses were partially offset by gains on natural gas swaps and natural gas basis differential swaps of $7.0 million and $0.6 million, respectively.
As a result of the above transactions, total gains (losses) on derivative activities recognized in our statements of operations were $30.6 million, $50.5 million, and ($51.9) million in 2009, 2008, and 2007, respectively.
Lease operating expenses
Year ended | Year ended | ||||||||||||||
(dollars in thousands) | December 31, | Percent | December 31, | Percent | |||||||||||
2009 | 2008 | decrease | 2007 | increase | |||||||||||
Lease operating expenses | $ | 94,155 | $ | 120,547 | (21.9 | )% | $ | 104,469 | 15.4 | % | |||||
Lease operating expenses per Boe | $ | 12.33 | $ | 17.05 | (27.7 | )% | $ | 15.42 | 10.6 | % | |||||
Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. Our lease operating expenses decreased by 22% from 2008 to 2009 after having increased by 15% from 2007 to 2008, which is consistent, though not commensurate, with the changes in commodity prices during the same periods. Commodity prices have recently started to improve, and if this upward trend continues, we expect absolute and per Boe operating costs to increase as well.
Due primarily to higher production mostly associated with the Bowdle 47 No. 2 well, the shut-in of uneconomic wells, and our efforts to reduce production costs, lease operating expenses for 2009 decreased by $26.4 million, or $4.72 per Boe, compared to 2008. Per unit expenses were lower for all categories of lease operating expenses due to downward pressure on service costs, labor, and materials resulting from the low commodity prices prevalent throughout 2009. Electricity and fuel costs and workover costs decreased by $4.4 million and $8.3 million, respectively, for operated properties from 2008 to 2009.
During 2008, lease operating expenses increased $16.1 million, or $1.63 per Boe, compared to 2007, primarily due to increases in the number of net producing wells and higher oilfield service costs, including costs associated with artificial lift on oil properties. Per unit expenses were higher for all categories of lease operating expenses due to upward pressure on service costs, labor and materials resulting from the strength of commodity prices during the first nine months of 2008. Electricity and fuel costs and workover costs increased by $4.0 million and $1.8 million, respectively, for operated properties from 2007 to 2008.
Production taxes (which include ad valorem taxes)
Year ended | Year ended | ||||||||||||||
December 31, | Percent | December 31, | Percent | ||||||||||||
(dollars in thousands) | 2009 | 2008 | decrease | 2007 | increase | ||||||||||
Production taxes | $ | 20,341 | $ | 33,815 | (39.8 | )% | $ | 26,216 | 29.0 | % | |||||
Production taxes per Boe | $ | 2.66 | $ | 4.78 | (44.4 | )% | $ | 3.87 | 23.5 | % | |||||
Production taxes generally change in proportion to oil and natural gas sales. The decrease in production taxes from 2008 to 2009 was primarily due to the 46% decrease in average realized prices, partially offset by an 8% increase in production volumes. The increase in production taxes from 2007 to 2008 was due primarily to the 31% increase in average realized prices and the 4% increase in production volumes.
Depreciation, depletion and amortization (“DD&A”) and losses on impairment
Year ended | Percent | Year ended | |||||||||||||
December 31, | increase | December 31, | Percent | ||||||||||||
(dollars in thousands) | 2009 | 2008 | (decrease) | 2007 | increase | ||||||||||
Total DD&A: | |||||||||||||||
Oil and natural gas properties | $ | 92,561 | $ | 91,316 | 1.4 | % | $ | 78,717 | 16.0 | % | |||||
Property and equipment | 8,510 | 6,644 | 28.1 | % | 4,322 | 53.7 | % | ||||||||
Accretion of asset retirement obligation | 2,927 | 2,712 | 7.9 | % | 2,392 | 13.4 | % | ||||||||
Total DD&A | $ | 103,998 | $ | 100,672 | 3.3 | % | $ | 85,431 | 17.8 | % | |||||
DD&A per Boe: | |||||||||||||||
Oil and natural gas properties | $ | 12.12 | $ | 12.91 | (6.1 | )% | $ | 11.62 | 11.1 | % | |||||
Other fixed assets | 1.50 | 1.33 | 12.8 | % | 0.99 | 34.3 | % | ||||||||
Total DD&A per Boe | $ | 13.62 | $ | 14.24 | (4.4 | )% | $ | 12.61 | 12.9 | % | |||||
We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties increased $1.2 million from 2008 to 2009. Higher production volumes increased DD&A by $7.3 million, which was offset by a $6.1 million reduction in DD&A due to a lower rate per equivalent unit of production. Our DD&A rate per equivalent unit of production decreased $0.79 to $12.12 per Boe primarily due to the decrease in capitalized costs resulting from the ceiling test impairments recorded in the fourth quarter of 2008 and the first quarter of 2009, combined with lower estimated future development costs for proved undeveloped reserves. DD&A on oil and natural gas properties increased $12.6 million from 2007 to 2008. Higher production volumes increased DD&A by $3.5 million, and an increase in the rate per equivalent unit of production increased DD&A by $9.1 million. Our DD&A rate per equivalent unit of production increased $1.29 to $12.91 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.
Our DD&A expense for property and equipment increased in both 2008 and 2009 primarily due to drilling rigs that were acquired and placed into service in 2008 and the expansion of our corporate office space during 2008.
We record the estimated future value of a liability for an asset retirement obligation in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.
Impairment of oil and natural gas properties. In accordance with the full-cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10%, as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties.
During the fourth quarter of 2008, we recorded a ceiling test impairment of oil and natural gas properties of $281.4 million as a result of a decline in oil and natural gas prices at the measurement date. The impairment was calculated based on December 31, 2008 spot prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. The effect of derivative contracts accounted for as cash flow hedges, based on the December 31, 2008 spot prices, increased the full-cost ceiling by $192.1 million, thereby reducing the ceiling test write down by the same amount.
During the first quarter of 2009, gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of natural gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to our PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and natural gas properties of $240.8 million during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169.0 million, thereby reducing the ceiling test write down by the same amount.
As of December 31, 2009, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties by $294.2 million, and no additional ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $61.18 per Bbl of oil and $3.87 per Mcf of gas for the year ended December 31, 2009. The effect of derivative contracts accounted for as cash flow hedges, based on these average prices, increased the full cost ceiling by $25.5 million. The qualifying cash flow hedges as of December 31, 2009, which consisted of commodity price swaps, covered 3,741 MBbls of oil production for the period from January 2010 through December 2011. See Note 4 to our consolidated financial statements for a further discussion of hedging activity.
A decline in oil and natural gas prices subsequent to December 31, 2009 could result in additional ceiling test write downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.
Impairment of ethanol plant.We owned a 66.67% interest in Oklahoma Ethanol LLC, a joint venture to construct and operate an ethanol production plant in Blackwell, Oklahoma. Oklahoma Ethanol LLC retained a financial advisor to arrange project financing to fund construction costs and for related start-up working capital. Because financing did not close by September 15, 2008, the minority owner, Oklahoma Sustainable Energy LLC, was no longer able to participate in the joint venture, and we now own 100% of Oklahoma Ethanol LLC. The City of Blackwell was also unable to obtain financing for the railroad upgrades and storage facilities that would be necessary to support ethanol production. During the third quarter of 2008, we determined that we would be unlikely to obtain equity capital or new project financing for an ethanol plant. We accordingly recorded an impairment charge of $2.9 million, which was the amount of our investment in the ethanol plant.
General and administrative expenses (“G&A”) and litigation settlement
Year ended | Percent | Year ended | Percent | |||||||||||||||
December 31, | increase | December 31, | increase | |||||||||||||||
(dollars in thousands) | 2009 | 2008 | (decrease) | 2007 | (decrease) | |||||||||||||
Gross G&A expenses | $ | 34,565 | $ | 33,552 | 3.0 | % | $ | 32,652 | 2.8 | % | ||||||||
Capitalized exploration and development costs | (10,824 | ) | (11,180 | ) | (3.2 | )% | (10,814 | ) | 3.4 | % | ||||||||
Net G&A expenses | $ | 23,741 | $ | 22,372 | 6.1 | % | $ | 21,838 | 2.4 | % | ||||||||
Average G&A cost per Boe | $ | 3.11 | $ | 3.16 | (1.6 | )% | $ | 3.22 | (1.9 | )% | ||||||||
Full-time employees as of December 31 | 689 | 859 | (19.8 | )% | 726 | 18.3 | % | |||||||||||
G&A expenses increased $1.4 million from 2008 to 2009, primarily due to higher deferred compensation costs. Due to a reduction in the fair value of our phantom stock during 2008, we recognized a deferred compensation gain which reduced G&A expenses by $0.3 million. The fair value of our phantom stock increased during 2009, and deferred compensation expense increased G&A expenses by $1.0 million in 2009. G&A expenses increased $0.5 million from 2007 to 2008, primarily due to an increase in our office staff and related requirements caused by the increase in our level of activity. On a per Boe basis, G&A decreased by 2% in both 2009 and 2008 as higher production more than offset the increase in costs.
Litigation settlement—Effective April 15, 2009, we settled our pending lawsuit against John Milton Graves Trust u/t/a 6/11/2004, et al. This case was related to (i) a post-closing adjustment of the price we paid for Calumet Oil Company (“Calumet”) in 2006 (the “Working Capital Adjustment”) and (ii) a contractual payment related to an election to be made by the sellers of Calumet (collectively, the “Sellers”) under the federal tax code (the “Tax Election”).
Pursuant to the settlement agreement, which was based upon net calculations of the receivable and payable, the Sellers paid us $7.1 million, which amount is intended to settle all claims related to both the Working Capital Adjustment and the Tax Election claims, and we retained $0.4 million contained in an escrow account covering any losses incurred by us for title defects related to our purchase of Calumet. In addition, the parties issued mutual releases, dismissed with prejudice the pending litigation and the claims made therein, and the Sellers will take action to clear the title to certain properties purchased by us in the Calumet acquisition.
As of December 31, 2008, the recorded receivable for the Working Capital Adjustment was $14.4 million, and was included in other assets on the consolidated balance sheet. As of December 31, 2008, the recorded payable related to the Tax Election was $4.4 million, and was included in accounts payable and accrued liabilities on the consolidated balance sheet. As a result of the settlement, as of December 31, 2009, the receivable related to the Working Capital Adjustment and the Tax Election payable were eliminated, the escrow cash account was reclassified to operating cash, and we recorded a charge to expense of $2.9 million.
Other income and expenses
Interest expense. Interest expense increased by $4.1 million, or 5%, from 2008 to 2009 primarily as a result of increased levels of borrowings accompanied by slightly higher interest rates. Interest expense decreased by $1.6 million, or 2%, from 2007 to 2008 primarily as a result of lower interest rates, partially offset by increased levels of borrowings. The following table presents interest expense:
Year ended December 31, | |||||||||
(dollars in thousands) | 2009 | 2008 | 2007 | ||||||
Revolver interest | $ | 26,950 | $ | 23,574 | $ | 27,387 | |||
8 1/2% Senior Notes due 2015 | 28,415 | 28,348 | 28,285 | ||||||
8 7/8% Senior Notes due 2017 | 29,601 | 29,578 | 28,413 | ||||||
Bank fees and other interest | 5,136 | 4,538 | 3,571 | ||||||
Total interest expense | $ | 90,102 | $ | 86,038 | $ | 87,656 | |||
Average long-term borrowings | $ | 1,216,540 | $ | 1,178,243 | $ | 1,057,142 | |||
Merger costs and termination fee.On October 9, 2009, we entered into an Agreement and Plan of Reorganization with United Refining Energy Corp. (“United”) under which we would merge with United, a publicly held Special Purpose Acquisition Company, in a reverse merger. The merger was to be accounted for as a reverse recapitalization, whereby we would be the continuing entity for financial reporting purposes and would be deemed, for accounting purposes, to be the acquirer of United. On December 11, 2009, United announced that the merger did not receive the stockholder vote required for approval, and the Agreement and Plan of Reorganization was terminated. As a result, costs of $2.2 million associated with the merger were expensed.
On July 14, 2008, we entered into an Agreement and Plan of Merger (“Merger Agreement”) with Edge Petroleum Corporation (“Edge”), whereby Edge would merge with and into our wholly owned subsidiary, Chaparral Exploration, L.L.C. During the fourth quarter of 2008, the parties concluded that it was highly unlikely that all of the closing conditions set forth in the Merger Agreement would be met, and therefore the merger would not be consummated on or prior to December 31, 2008, the date on which either party could, subject to the terms of the Merger Agreement, terminate the Merger Agreement unilaterally. As a result, we and Edge executed a Merger Termination Agreement on December 16, 2008, and costs of $1.4 million associated with the merger were expensed.
On July 14, 2008, we entered into a Stock Purchase Agreement with Magnetar Financial LLC (“Magnetar”), which provided for Magnetar and its affiliates to purchase 1.5 million shares of our Series B convertible preferred stock for an aggregate purchase price of $150.0 million. On December 16, 2008, we executed a Termination and Settlement Agreement (the “Magnetar Termination Agreement”) with Edge and Magnetar, which terminated the Stock Purchase Agreement. Pursuant to the Magnetar Termination Agreement, Magnetar paid a total of $5.0 million, of which $1.5 million was paid to Edge at our direction to reimburse Edge for certain expenses, and $3.5 million was paid to us and recorded as a termination fee.
Production tax credits. During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. Our return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments were accounted for as a production tax benefit asset and were netted against tax credits realized in other income using the effective yield method over the expected recovery period. Other income for 2009, 2008, and 2007 includes Oklahoma production tax credits of $13.5 million, $0.7 million, and $0.8 million, respectively. This source of income will not be available in future periods.“Other commitments” above.
Income taxes
Year ended December 31, | ||||||||||||
(dollars in thousands) | 2009 | 2008 | 2007 | |||||||||
Current income tax benefit | $ | 23 | $ | 28 | $ | 16 | ||||||
Deferred income tax benefit | 89,872 | 35,273 | 3,370 | |||||||||
Total income tax benefit | $ | 89,895 | $ | 35,301 | $ | 3,386 | ||||||
Effective tax rate | 37.3 | % | 38.6 | % | 36.4 | % | ||||||
Total net deferred tax asset (liability) | $ | 64,212 | $ | (62,395 | ) | $ | 1,632 | |||||
Our income tax provision was based on an estimated statutory rate of approximately 39% in 2009, 2008 and 2007. Our effective tax rate has generally been less than our estimated statutory rate due to the impact of our deduction for statutory depletion and other adjustments.
As of December 31, 2009, our federal and state net operating loss carryforwards were approximately $235.4 million and $214.9 million, respectively, and will begin to expire in 2010. As of December 31, 2009, approximately $103.3 million of the state net operating loss carryforwards have been reduced by a valuation allowance based on our assessment that it is more likely than not that a portion will not be realized.
Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.
Discontinued operations
Discontinued operations consist of third-party revenue and operating expenses of GCS, which was acquired on April 16, 2007. Revenues are generated through the sale of oilfield supplies, chemicals, downhole submersible pumps and related services to oil and natural gas operators primarily in Oklahoma, Texas, and Wyoming. Operating expenses consist of costs of sales related to product sales and general and administrative expenses.
During the second quarter of 2009, we committed to a plan to sell the assets of GCS, and on May 14, 2009, we entered into an agreement to sell the assets of the ESP division of GCS to Global Oilfield Services, Inc. (“Global”) for a cash price of approximately $24.6 million after working capital adjustments as provided in the agreement. We paid off notes payable attributed to certain assets sold to Global in the amount of $1.6 million, and recorded a pre-tax gain associated with the sale of $9.1 million.
On December 11, 2009, we entered into an agreement with Reef Services, LLC (“Reef”) under which we exchanged the assets of the Chemicals division of GCS for the assets of the Reef Acid Division and cash of $0.7 million. The assets received consist primarily of acid trucks and related equipment and have an estimated fair value of approximately $3.0 million. This transaction is considered a non-monetary exchange accounted for at fair value. We paid off notes payable attributed to certain assets sold to Reef in the amount of $0.3 million, and recorded a pre-tax gain associated with the exchange of $1.3 million.
The operating results of GCS have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below:
April 16, 2007 | ||||||||||||
Year ended December 31, | through December 31, | |||||||||||
(dollars in thousands) | 2009 | 2008 | 2007 | |||||||||
Revenues | $ | 11,142 | $ | 33,821 | $ | 20,611 | ||||||
Operating expenses | (10,983 | ) | (31,450 | ) | (18,852 | ) | ||||||
Gain on sale | 10,449 | — | — | |||||||||
Income before income taxes | 10,608 | 2,371 | 1,759 | |||||||||
Income tax provision | 3,959 | 915 | 641 | |||||||||
Income from discontinued operations | $ | 6,649 | $ | 1,456 | $ | 1,118 | ||||||
There were no assets held for sale or liabilities associated with discontinued operations as of December 31, 2009. At December 31, 2008, the assets and liabilities of GCS are classified as assets held for sale and liabilities associated with discontinued operations, respectively, on our consolidated balance sheet.
Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and other sources that we believe are reasonable at the time. Actual results may differ from the estimates and assumptions we used in preparation of our financial statements. We evaluate our estimates and assumptions on a regular basis. Described below are the most significant policies and the related estimates and assumptions we apply in the preparation of our financial statements. See Note 1 to our consolidated financial statements for an additional discussion of accounting policies and estimates made by management.
Revenue recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded in the month payment is received.
Derivative instruments. Certain of our oil and natural gas derivative contracts are designed to be treated as cash flow hedges under GAAP. This policy significantly impacts the timing of revenue or expense recognized from this activity, as our contracts are adjusted to their fair value at the end of each month. The effective portion of the hedge gain or loss, meaning the portion of the change in the fair value of the contract that offsets the change in the expected future cash flows from our forecasted sales of production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “Gain (loss) from oil and natural gas hedging activities” line in our consolidated statements of operations. Until hedged production is reported in earnings and the contract settles, the effective portion of change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in stockholders’ equity. The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) from oil and natural gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment, or have not been designated as cash flow hedges, are marked to their period end market values and the change in the fair value of the contracts is included in the “Non-hedge derivative gains (losses)” line in our consolidated statements of operations. As a result, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.
We determine the fair value of our crude oil, natural gas, and basis swaps by reference to forward pricing curves for oil and natural gas futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit risk adjusted discount rate. In certain less liquid markets, forward prices are not as readily available. In these circumstances, swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3 in accordance with the fair value hierarchy defined by the Financial Accounting Standards Board (“FASB”). We have determined that the fair value methodology described above for the remainder of our swaps is consistent with observable market inputs and have categorized them as Level 2. We determine fair value for our oil and natural gas collars using an option pricing model which takes into account market volatility, market prices, contract parameters, and credit risk. Due to unavailability of observable volatility data input for our collars, we have determined that all of our collars’ fair value measurements are categorized as Level 3. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable.
Certain of our oil and natural gas derivative contracts have historically been treated as cash flow hedges under GAAP. This policy significantly impacts the timing of revenue or expense recognized from this activity, as our contracts are adjusted to their fair value at the end of each month. The effective portion of the hedge gain or loss, meaning the portion of the change in the fair value of the contract that offsets the change in the expected future cash flows from our forecasted sales of production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “Gain (loss) from oil and natural gas hedging activities” line in our consolidated statements of operations. Until hedged production is reported in earnings and the contract settles, the effective portion of change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in stockholders’ equity. The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) from oil and natural gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment, or have not been designated as cash flow hedges, are marked to their period end market values and the change in the fair value of the contracts is included in the “Non-hedge derivative gains (losses)” line in our consolidated statements of operations. Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.
Oil and natural gas properties.
• | Full cost accounting. We use the full cost method of accounting for our oil and natural gas properties. Under this method, all costs incurred in the exploration and development of oil and natural gas properties are capitalized into a cost center. These costs include drilling and equipping productive wells, dry hole costs, seismic costs and delay rentals. Capitalized costs also include salaries, employee benefits, consulting services and other expenses that directly relate to our exploration and development activities. |
• | Proved oil and natural gas reserves quantities. Proved oil and natural gas reserves are the quantities of crude oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The estimates of proven reserves for a given reservoir may change significantly over time as a result of changing prices, operating cost, additional development activity and the actual operating performance. |
Our proved reserve information included in this report is based on estimates prepared by Cawley, Gillespie & Associates, Inc., and Ryder Scott Company, L.P., and Lee Keeling & Associates, Inc., each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 82%85% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2009,2012, and our engineering staff evaluated the remainder. We continually make revisions to reserve estimates throughout the year as additional information becomes available.
• | Depreciation, depletion and amortization. The quantities of proved oil and natural gas reserves are a significant component of our calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. The depreciation, depletion and amortization rate is determined using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based on the relative energy content. |
• | Full cost ceiling limitation. Under the full cost method, the net capitalized costs of oil and natural gas properties recorded on our balance sheet cannot exceed the estimated future net revenues discounted at 10%, adjusted for the impact of derivatives accounted for as cash flow hedges, plus the |
• | Costs not subject to amortization. Costs of unevaluated properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and seismic data, exploratory wells currently drilling, and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well or are assessed quarterly for possible impairment. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves. |
• | Future development and abandonment costs. Our future development costs include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and natural gas properties and related facilities. We develop estimates of these costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. These judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis. |
We record a liability for the estimated fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.
We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. Significant assumptions used in estimating such obligations include estimates of the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments, all of which are Level 3 inputs in the fair value hierarchy. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required for the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our estimated future cash flows.
Income taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.
Valuation allowance for NOL carryforwards. In computing our income tax expense, we assess the need for a valuation allowance on deferred tax assets, which consist primarily of net operating loss, or NOL, carryforwards. For federal income tax purposes these NOL carryforwards expire 15 to 20 years from the year of origination. We generally assess our ability to fully utilize these carryforwards by estimating expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report and by analyzing the expected reversal of existing deferred tax liabilities. These computations are imprecise due to the extensive use of estimates and assumptions. Each quarter we assess our ability to utilize NOL carryforwards. We will record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such asset will not be realized.
Impairment of long-lived assets.Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
Assets Held for Sale.The accounting for assets held for sale is in accordance with ASC 360-10, Property, Plant and Equipment. Under this guidance, the assets are carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less.
Recent accounting pronouncements
In May 2011, the FASB issued authoritative guidance that clarifies the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we adopted it on January 2010,1, 2012. There was no significant impact on our consolidated financial statements other than additional disclosures.
In June 2011, the FASB issued new authoritative guidance regarding “Improving Disclosures about Fair Value Measurements and Disclosures” that requires additional disclosureentities that report other comprehensive income to present the components of transfersnet income and comprehensive income in either one continuous financial statement or two consecutive financial statements. It does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This guidance is effective for interim and outannual periods beginning after December 15, 2011, and we applied it beginning on January 1, 2012. We have elected to present the components of Levelnet income and comprehensive income in two consecutive financial statements.
In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and 2 measurementsis not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance is effective for calendar years beginning after December 15, 2013, once the fee is instituted. We are currently assessing the impact that this fee and the reasons foradoption of the transfers, and a gross presentationrelated authoritative guidance will have on our financial statements.
In December 2011, the FASB issued authoritative guidance requiring entities to provide enhanced disclosures that will enable users of activity withinits financial statements to evaluate the Level 3 roll forward. The guidance also includes clarifications to existing disclosure requirementseffect or potential effect of netting arrangements on the level of disaggregation and disclosures regarding inputs and valuation techniques.an entity’s financial position. The guidance is effective for the first interim orand annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years.January 1, 2013. We will adopt the guidance on January 1, 2010, exceptrequirements with the preparation of our Form 10-Q for requirements regarding the gross presentation of Level 3 roll forward information,quarter ending March 31, 2013, which we will adopt on January 1, 2011. Because this guidance only requiresrequire additional footnote disclosures it isfor our derivative instruments and are not expected to have a significant impactmaterial effect on our consolidated financial statements.
In December 2008, the SEC issued its Modernization of Oil and Gas Reporting, which revises reserves requirements for oil and natural gas companies. The most significant amendments to the requirements include the following:
economic producibility of reserves and discounted cash flows is now estimated using an average price for oil and natural gas based upon the first day of each month for the prior twelve months rather than prices on the last day of the reporting period;
proved reserves may be estimated through the use of new technologies if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes;
reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years;
additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process and the internal controls used to assure the objectivity of the reserves estimate; and
probable and possible reserves may be disclosed separately on a voluntary basis.
In January 2010, the Financial Accounting Standards Board also issued guidance regardingOil and Gas Reserve Estimation and Disclosuresto provide consistency with the new SEC rules. The new guidance amends existing standards to align the reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules.
We adopted the new SEC reserves requirements and GAAP reserves guidance as a change in accounting principle that is inseparable from a change in estimate, and applied the guidance prospectively effective December 31, 2009. See Note 16 to our financial statements for a discussion of the impact of these changes on our reserves.
See recently adopted and issued accounting standards in Part II, Item 8. Financial Statements, Note 1, to the financial statements for a discussion“Nature of additionaloperations and summary of significant accounting pronouncements adopted during 2009.policies.”
Effects of inflation and pricing
While the general level of inflation affects certain of our costs, factors unique to the oil and natural gas industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and natural gas prices. In addition, changing prices often cause costs of equipment and supplies to vary as industry activity levels increase and decrease to reflect perceptions of future price levels. Although it is difficult to estimate future prices of oil and natural gas, price fluctuations have had, and will continue to have, a material effect on us.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oil and natural gas prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Agreementsenior secured revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration, and development activities.
Based on our production for the year ended December 31, 2009,2012, our gross revenues from oil and natural gas sales would change approximately $2.3$5.8 million for each $1.00 change in oil prices and $2.0 million for each $0.10 change in natural gas prices and $3.9 million for each $1.00 change in oil prices.
To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into commodity price swaps, costless collars, and basis protection swaps.
Effective April 1, 2010, we elected to de-designate all of our commodity contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. Therefore, the changes in fair value and settlement of all our derivative contracts subsequent to March 31, 2010 are recognized as non-hedge derivative gains (losses). This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.
For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. Our collars have not been designated as hedges. Therefore,A three-way collar contract consists of a standard collar contract plus a put option contract sold by us with a price below the changes in fair value and settlementfloor price of these derivative contracts are recognized as non-hedge derivative gains (losses).the collar. This can haveadditional put option requires us to make a significant impact on our results of operations duepayment to the volatilitycounterparty if the market price is below the additional put option price. If the market price is greater than the additional put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the underlying commodity prices.standard collar and the additional put option price if the market price falls below the additional put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while defraying the associated cost with the sale of the additional put option.
We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. We do not designate these instruments as hedges; therefore, the
Derivative positions are adjusted in response to changes in fair valueprices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change, we may execute a cash settlement of thesewith our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original derivative contracts are recognized as non-hedge derivative gains (losses).position.
Our outstanding oil and natural gas derivative instruments as of December 31, 20092012, are summarized below:
Crude oil swaps | Crude oil collars | |||||||||||||||||
Hedge | Non-hedge | Non-hedge | ||||||||||||||||
Volume MBbl | Weighted average fixed price to be received | Volume MBbl | Weighted average fixed price to be received | Volume MBbl | Weighted average range | Percent of PDP production(1) | ||||||||||||
1Q 2010 | 520 | $ | 68.13 | 102 | $ | 65.80 | 60 | $ | 110.00 - $168.55 | 78.2 | % | |||||||
2Q 2010 | 516 | 68.06 | 90 | 65.47 | 60 | 110.00 - 168.55 | 79.0 | % | ||||||||||
3Q 2010 | 499 | 68.24 | 90 | 65.10 | 60 | 110.00 - 168.55 | 79.2 | % | ||||||||||
4Q 2010 | 480 | 68.08 | 90 | 64.75 | 60 | 110.00 - 168.55 | 78.7 | % | ||||||||||
1Q 2011 | 444 | 70.05 | 99 | 64.24 | 51 | 110.00 - 152.71 | 75.9 | % | ||||||||||
2Q 2011 | 444 | 69.97 | 90 | 63.93 | 51 | 110.00 - 152.71 | 76.4 | % | ||||||||||
3Q 2011 | 424 | 69.02 | 90 | 63.61 | 51 | 110.00 - 152.71 | 75.2 | % | ||||||||||
4Q 2011 | 414 | 68.40 | 90 | 63.30 | 51 | 110.00 - 152.71 | 75.3 | % | ||||||||||
3,741 | 741 | 444 | ||||||||||||||||
1Q 2010 2Q 2010 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 4Q 2014 Natural gas swaps Natural gas collars Non-hedge Non-hedge Volume
BBtu Weighted
average
fixed price
to be
received Volume
BBtu Weighted
average
range Percent of
PDP
production(1) 3,300 $ 7.62 840 $ 10.00 - $11.53 74.3 % 3,300 6.98 840 10.00 - 11.53 79.6 % 3,150 7.27 840 10.00 - 11.53 81.4 % 3,150 7.69 840 10.00 - 11.53 85.6 % 2,700 7.80 — — 60.6 % 2,700 6.95 — — 63.1 % 2,700 7.12 — — 65.5 % 2,700 7.47 — — 67.7 % 23,700 3,360 Oil derivatives Swaps Three-way collars Weighted average fixed price per Bbl Volume
MBbls Weighted
average
fixed price
per Bbl Volume
MBbls Additional
put option Put Call Percent of
production(1) 255 $ 96.82 930 $ 78.06 $ 100.10 $ 114.41 81.1 % 255 96.87 950 77.89 99.92 114.06 81.5 % 255 96.78 930 77.74 99.81 114.11 83.3 % 255 96.65 900 77.83 99.94 114.49 85.2 % — — 330 75.91 92.54 103.08 24.3 % — — 330 75.91 92.54 103.08 20.7 % — — 330 75.91 92.54 103.08 19.9 % — — 330 75.91 92.54 103.08 19.5 % 1,020 5,030
Natural gas basis protection swaps | |||||
Non-hedge | |||||
Volume BBtu | Weighted average fixed price to be paid | ||||
1Q 2010 | 4,950 | $ | 0.94 | ||
2Q 2010 | 4,120 | 0.73 | |||
3Q 2010 | 3,930 | 0.74 | |||
4Q 2010 | 3,600 | 0.79 | |||
1Q 2011 | 3,600 | 0.80 | |||
2Q 2011 | 3,260 | 0.71 | |||
3Q 2011 | 3,120 | 0.71 | |||
4Q 2011 | 3,010 | 0.72 | |||
29,590 | |||||
Natural gas swaps | Natural gas basis protection swaps | |||||||||||||||||||
Volume BBtu | Weighted average fixed price per Btu | Percent of production(1) | Volume BBtu | Weighted average fixed price per Btu | ||||||||||||||||
1Q 2013 | 4,200 | $ | 4.30 | 80.1 | % | 4,050 | $ | 0.20 | ||||||||||||
2Q 2013 | 4,200 | 4.19 | 78.9 | % | 4,250 | 0.20 | ||||||||||||||
3Q 2013 | 4,200 | 4.27 | 84.8 | % | 4,050 | 0.20 | ||||||||||||||
4Q 2013 | 4,200 | 4.46 | 91.7 | % | 4,050 | 0.20 | ||||||||||||||
1Q 2014 | 2,100 | 4.00 | 45.9 | % | 3,750 | 0.23 | ||||||||||||||
2Q 2014 | 2,100 | 3.85 | 41.4 | % | 3,620 | 0.23 | ||||||||||||||
3Q 2014 | 2,100 | 3.91 | 40.0 | % | 3,360 | 0.23 | ||||||||||||||
4Q 2014 | 2,100 | 4.05 | 39.3 | % | 3,360 | 0.23 | ||||||||||||||
|
|
|
| |||||||||||||||||
25,200 | 30,490 | |||||||||||||||||||
|
|
|
|
(1) | Based on our |
Subsequent to December 31, 2009,2012, we entered into the following derivative instruments:
Crude Oil Swaps | Natural Gas Swaps | |||||||||
Hedge | Non-hedge | |||||||||
Volume MBbl | Weighted average fixed price to be received | Volume BBtu | Weighted average fixed price to be received | |||||||
1Q 2010 | — | $ | — | 540 | $ | 5.54 | ||||
2Q 2010 | 48 | 79.54 | 930 | 5.45 | ||||||
3Q 2010 | 48 | 80.57 | 550 | 5.56 | ||||||
4Q 2010 | 48 | 81.39 | 300 | 6.05 | ||||||
1Q 2011 | 45 | 87.31 | 450 | 6.83 | ||||||
2Q 2011 | 45 | 87.57 | 300 | 6.09 | ||||||
3Q 2011 | 45 | 87.82 | 300 | 6.21 | ||||||
4Q 2011 | 45 | 88.05 | 300 | 6.63 | ||||||
1Q 2012 | 150 | 89.90 | — | |||||||
2Q 2012 | 150 | 90.27 | — | |||||||
3Q 2012 | 150 | 90.65 | — | |||||||
4Q 2012 | 150 | 91.01 | — | |||||||
924 | 3,670 | |||||||||
Crude oil enhanced swaps | Crude oil swaps | Crude oil three-way collars | Natural gas swaps | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted average fixed price per Bbl | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Volume MBbls | Additional put option | Swap | Volume MBbls | Weighted average fixed price to be received | Volume MBbls | Additional put option | Put | Call | Volume BBtu | Weighted average fixed price to be received | ||||||||||||||||||||||||||||||||||||||||||||||
1Q 2013 | — | — | — | 30,000 | $ | 93.06 | — | $ | — | $ | — | $ | — | 460,000 | $ | 3.16 | ||||||||||||||||||||||||||||||||||||||||
2Q 2013 | — | — | — | 65,000 | 93.68 | — | — | — | — | 830,000 | 3.39 | |||||||||||||||||||||||||||||||||||||||||||||
3Q 2013 | — | — | — | 60,000 | 94.00 | — | — | — | — | 690,000 | 3.40 | |||||||||||||||||||||||||||||||||||||||||||||
4Q 2013 | — | — | — | 90,000 | 93.73 | — | — | — | — | 690,000 | 3.61 | |||||||||||||||||||||||||||||||||||||||||||||
1Q 2014 | 210,000 | 80.00 | 99.76 | 120,000 | 95.22 | 270,000 | 75.00 | 94.11 | 100.55 | 2,100,000 | 4.05 | |||||||||||||||||||||||||||||||||||||||||||||
2Q 2014 | 210,000 | 80.00 | 98.94 | 120,000 | 94.16 | 270,000 | 75.00 | 94.11 | 100.55 | 2,160,000 | 3.95 | |||||||||||||||||||||||||||||||||||||||||||||
3Q 2014 | 210,000 | 80.00 | 98.20 | 120,000 | 93.16 | 270,000 | 75.00 | 94.11 | 100.55 | 2,430,000 | 4.02 | |||||||||||||||||||||||||||||||||||||||||||||
4Q 2014 | 210,000 | 80.00 | 97.58 | 120,000 | 92.37 | 270,000 | 75.00 | 94.11 | 100.55 | 2,430,000 | 4.18 | |||||||||||||||||||||||||||||||||||||||||||||
1Q 2015 | — | — | — | — | — | — | — | — | — | 2,400,000 | 4.36 | |||||||||||||||||||||||||||||||||||||||||||||
2Q 2015 | — | — | — | — | — | — | — | — | — | 2,400,000 | 4.11 | |||||||||||||||||||||||||||||||||||||||||||||
3Q 2015 | — | — | — | — | — | — | — | — | — | 2,400,000 | 4.18 | |||||||||||||||||||||||||||||||||||||||||||||
4Q 2015 | — | — | — | — | — | — | — | — | — | 2,400,000 | 4.33 | |||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||||
840,000 | 725,000 | 1,080,000 | 21,390,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
FiveAn enhanced swap contract consists of a standard swap contract plus a put option contract sold by us with a price below the swap. This additional put option requires us to make a payment to the counterparty if the market price is below the additional put option price. If the market price is greater than the additional put option price, the result is the same as it would have been with a standard swap contract only. By combining the swap contract with the additional put option, we are entitled to a net payment equal to the difference between the swap price and the additional put option price if the market price falls below the additional put option price. This strategy enables us to increase the swap price beyond the range of a traditional swap while defraying the associated cost with the sale of the counterparties to our derivative contracts as of December 31, 2009 are no longer lenders under our Eighth Restated Credit Agreement, which closed on April 12, 2010. As a result, we will novate oil swaps covering a total of 2,175 MBbls from April 2010 through December 2012, natural gas swaps covering a total of 8,180 Bbtu from April 2010 through December 2011, and natural gas basis swaps covering a total of 10,860 Bbtu from April 2010 through December 2011. In addition, we have unwound oil swaps and collars covering a total of 255 MBbls from April 2010 through December 2011 and gas collars covering a total of 1,170 Bbtu from April 2010 through December 2010 for net proceeds of approximately $7.2 million.additional put option.
Interest rates. All of the outstanding borrowings under our Credit Agreementsenior secured revolving facility as of December 31, 20092012 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreementsenior secured revolving credit facility as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the discount rate established bygreater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Reserve Board.Funds Effective Rate, as defined in the senior secured revolving credit facility, plus 1/2 of 1%, or (3) the Adjusted LIBO rate, as defined in our senior secured revolving credit facility, plus 1%. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $513.0$500.0 million, equal to our borrowing base at December 31, 2009,2012, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.1$5.0 million.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page | ||||
Chaparral Energy, Inc. consolidated financial statements: | ||||
87 | ||||
Consolidated balance sheets as of December 31, | ||||
88 | ||||
90 | ||||
91 | ||||
92 | ||||
93 | ||||
94 |
Report of independent registered public accounting firm
Board of Directors
Chaparral Energy, Inc.
We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. and subsidiaries (the “Company”) as of December 31, 20092012 and 2008,2011, and the related consolidated statements of operations, stockholders’ equity (deficit) and comprehensive income, (loss)stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009.2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chaparral Energy, Inc. and subsidiaries as of December 31, 20092012 and 2008,2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009,2012 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
April 1, the Company changed its method of estimating oil and gas reserves and related disclosures in 2009.2013
|
|
|
Chaparral Energy, Inc. and subsidiaries
December 31, | ||||||||
(dollars in thousands, except per share data) | 2009 | 2008 | ||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 73,417 | $ | 52,112 | ||||
Accounts receivable, net | 51,950 | 64,937 | ||||||
Production tax benefit | 19 | 13,685 | ||||||
Inventories | 10,551 | 17,289 | ||||||
Prepaid expenses | 5,729 | 4,177 | ||||||
Derivative instruments | 18,226 | 51,412 | ||||||
Deferred income taxes | 1,790 | — | ||||||
Assets held for sale | — | 14,751 | ||||||
Total current assets | 161,682 | 218,363 | ||||||
Property and equipment—at cost, net | 62,197 | 66,925 | ||||||
Oil & natural gas properties, using the full cost method: | ||||||||
Proved | 1,910,583 | 1,751,096 | ||||||
Unproved (excluded from the amortization base) | 19,728 | 16,865 | ||||||
Work in progress (excluded from the amortization base) | 19,206 | 31,893 | ||||||
Accumulated depreciation, depletion, amortization and impairment | (906,584 | ) | (573,233 | ) | ||||
Total oil & natural gas properties | 1,042,933 | 1,226,621 | ||||||
Funds held in escrow | 1,672 | 2,350 | ||||||
Derivative instruments | 5,794 | 157,720 | ||||||
Deferred income taxes | 62,422 | — | ||||||
Assets held for sale | — | 6,343 | ||||||
Other assets | 17,220 | 34,514 | ||||||
$ | 1,353,920 | $ | 1,712,836 | |||||
Liabilities and stockholders’ equity | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 48,283 | $ | 90,165 | ||||
Accrued payroll and benefits payable | 10,849 | 9,215 | ||||||
Accrued interest payable | 14,394 | 15,408 | ||||||
Revenue distribution payable | 18,673 | 19,827 | ||||||
Current maturities of long-term debt and capital leases | 4,653 | 5,890 | ||||||
Derivative instruments | 20,677 | — | ||||||
Deferred income taxes | — | 19,696 | ||||||
Liabilities associated with discontinued operations | — | 2,922 | ||||||
Total current liabilities | 117,529 | 163,123 | ||||||
Long-term debt and capital leases, less current maturities | 524,477 | 615,953 | ||||||
Senior notes, net | 647,877 | 647,675 | ||||||
Derivative instruments | 30,163 | 3,388 | ||||||
Deferred compensation | 1,142 | 762 | ||||||
Asset retirement obligations | 37,165 | 33,075 | ||||||
Deferred income taxes | — | 42,699 | ||||||
Liabilities associated with discontinued operations | — | 1,761 | ||||||
Commitments and contingencies (Note 13) | ||||||||
Stockholders’ equity (deficit): | ||||||||
Preferred stock, 600,000 shares authorized, none issued and outstanding | — | — | ||||||
Common stock, $.01 par value, 3,000,000 shares authorized; 877,000 shares issued and outstanding as of December 31, 2009 and 2008, respectively | 9 | 9 | ||||||
Additional paid in capital | 100,918 | 100,918 | ||||||
Retained earnings (accumulated deficit) | (122,978 | ) | 21,340 | |||||
Accumulated other comprehensive income, net of taxes | 17,618 | 82,133 | ||||||
(4,433 | ) | 204,400 | ||||||
$ | 1,353,920 | $ | 1,712,836 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of operations
Year Ended December 31, | ||||||||||||
(dollars in thousands, except per share data) | 2009 | 2008 | 2007 | |||||||||
Revenues: | ||||||||||||
Oil and natural gas sales | $ | 292,387 | $ | 501,761 | $ | 365,958 | ||||||
Gain (loss) from oil and natural gas hedging activities | 19,403 | (76,417 | ) | (28,140 | ) | |||||||
Total revenues | 311,790 | 425,344 | 337,818 | |||||||||
Costs and expenses: | ||||||||||||
Lease operating | 94,155 | 120,547 | 104,469 | |||||||||
Production tax | 20,341 | 33,815 | 26,216 | |||||||||
Depreciation, depletion and amortization | 103,998 | 100,672 | 85,431 | |||||||||
Loss on impairment of oil & natural gas properties | 240,790 | 281,393 | — | |||||||||
Loss on impairment of ethanol plant | — | 2,900 | — | |||||||||
General and administrative | 23,741 | 22,372 | 21,838 | |||||||||
Litigation settlement | 2,928 | — | — | |||||||||
Total costs and expenses | 485,953 | 561,699 | 237,954 | |||||||||
Operating income (loss) | (174,163 | ) | (136,355 | ) | 99,864 | |||||||
Non-operating income (expense): | ||||||||||||
Interest expense | (90,102 | ) | (86,038 | ) | (87,656 | ) | ||||||
Non-hedge derivative gains (losses) | 11,169 | 126,941 | (23,781 | ) | ||||||||
Merger costs | (2,169 | ) | (1,400 | ) | — | |||||||
Termination fee | — | 3,500 | — | |||||||||
Other income | 14,403 | 1,845 | 2,276 | |||||||||
Net non-operating income (expense) | (66,699 | ) | 44,848 | (109,161 | ) | |||||||
Loss from continuing operations before income taxes | (240,862 | ) | (91,507 | ) | (9,297 | ) | ||||||
Income tax benefit | (89,895 | ) | (35,301 | ) | (3,386 | ) | ||||||
Loss from continuing operations | (150,967 | ) | (56,206 | ) | (5,911 | ) | ||||||
Income from discontinued operations, net of related taxes | 6,649 | 1,456 | 1,118 | |||||||||
Net loss | $ | (144,318 | ) | $ | (54,750 | ) | $ | (4,793 | ) | |||
Income (loss) per share (basic and diluted) | ||||||||||||
Continuing operations | $ | (172.14 | ) | $ | (64.09 | ) | $ | (6.74 | ) | |||
Discontinued operations | 7.58 | 1.66 | 1.27 | |||||||||
Net loss per share (basic and diluted) | $ | (164.56 | ) | $ | (62.43 | ) | $ | (5.47 | ) | |||
Weighted average number of shares used in calculation of basic and diluted earnings (loss) per share | 877,000 | 877,000 | 877,000 |
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of stockholders’ equity (deficit)
and comprehensive income (loss)
(dollars in thousands) | Common stock | Additional paid in capital | Retained earnings (accumulated deficit) | Accumulated other comprehensive income (loss) | Total | |||||||||||||||
Shares | Amount | |||||||||||||||||||
Balance at January 1, 2007 | 877,000 | $ | 9 | $ | 100,918 | $ | 80,883 | $ | (3,946 | ) | $ | 177,864 | ||||||||
Net loss | — | — | — | (4,793 | ) | — | (4,793 | ) | ||||||||||||
Other comprehensive loss, net | ||||||||||||||||||||
Unrealized loss on hedges, net of taxes of $52,048 | — | — | — | — | (82,512 | ) | (82,512 | ) | ||||||||||||
Reclassification adjustment for hedge losses included in net loss, net of taxes of $7,960 | — | — | — | — | 12,619 | 12,619 | ||||||||||||||
Total comprehensive loss | (74,686 | ) | ||||||||||||||||||
Balance at December 31, 2007 | 877,000 | 9 | 100,918 | 76,090 | (73,839 | ) | 103,178 | |||||||||||||
Net loss | — | — | — | (54,750 | ) | — | (54,750 | ) | ||||||||||||
Other comprehensive income, net | ||||||||||||||||||||
Unrealized gain on hedges, net of taxes of $65,602 | — | — | — | — | 103,998 | 103,998 | ||||||||||||||
Reclassification adjustment for hedge losses included in net loss, net of taxes of $32,784 | — | — | — | — | 51,974 | 51,974 | ||||||||||||||
Total comprehensive income | 101,222 | |||||||||||||||||||
Balance at December 31, 2008 | 877,000 | 9 | 100,918 | 21,340 | 82,133 | 204,400 | ||||||||||||||
Net loss | — | — | — | (144,318 | ) | — | (144,318 | ) | ||||||||||||
Other comprehensive loss, net | ||||||||||||||||||||
Unrealized loss on hedges, net of taxes of $32,601 | — | — | — | — | (51,683 | ) | (51,683 | ) | ||||||||||||
Reclassification adjustment for hedge gains included in net loss, net of taxes of $8,095 | — | — | — | — | (12,832 | ) | (12,832 | ) | ||||||||||||
Total comprehensive loss | (208,833 | ) | ||||||||||||||||||
Balance at December 31, 2009 | 877,000 | $ | 9 | $ | 100,918 | $ | (122,978 | ) | $ | 17,618 | $ | (4,433 | ) | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of cash flows
Year Ended December 31, | ||||||||||||
(dollars in thousands) | 2009 | 2008 | 2007 | |||||||||
Cash flows from operating activities | ||||||||||||
Net loss | $ | (144,318 | ) | $ | (54,750 | ) | $ | (4,793 | ) | |||
Adjustments to reconcile net loss to net cash provided by operating activities | ||||||||||||
Depreciation, depletion & amortization | 103,998 | 100,672 | 85,431 | |||||||||
Depreciation, depletion & amortization of discontinued operations | 736 | 1,301 | 411 | |||||||||
Loss on impairments | 240,790 | 284,293 | — | |||||||||
Deferred income taxes | (85,913 | ) | (34,358 | ) | (2,729 | ) | ||||||
Unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments | (21,752 | ) | (12,549 | ) | 8,343 | |||||||
Non-hedge derivative (gains) losses | (11,169 | ) | (126,941 | ) | 23,781 | |||||||
Gain on sale of business and other assets | (10,463 | ) | (177 | ) | (712 | ) | ||||||
Other | 2,141 | 2,750 | 1,404 | |||||||||
Litigation settlement | 2,928 | — | — | |||||||||
Change in assets & liabilities, net of assets and liabilities of business acquired | ||||||||||||
Accounts receivable | 17,648 | (3,599 | ) | (13,660 | ) | |||||||
Inventories | 6,048 | (8,278 | ) | 3,568 | ||||||||
Prepaid expenses and other assets | 12,084 | 1,373 | (1,452 | ) | ||||||||
Accounts payable and accrued liabilities | (13,265 | ) | (1,957 | ) | 8,426 | |||||||
Revenue distribution payable | (1,154 | ) | (1,643 | ) | 4,221 | |||||||
Deferred compensation | 336 | (306 | ) | 831 | ||||||||
Net cash provided by operating activities | 98,675 | 145,831 | 113,070 | |||||||||
Cash flows from investing activities | ||||||||||||
Purchase of property and equipment and oil and gas properties | (178,154 | ) | (304,568 | ) | (220,651 | ) | ||||||
Acquisition of a business, net of cash acquired | — | — | (21,569 | ) | ||||||||
Proceeds from dispositions of property and equipment and oil and gas properties | 515 | 1,808 | 526 | |||||||||
Cash in escrow | 378 | 1,385 | (2,156 | ) | ||||||||
Proceeds from sale of a business | 25,346 | — | 3,158 | |||||||||
Return of prepaid production tax asset | 13,544 | 1,083 | 373 | |||||||||
Settlement of non-hedge derivative instruments | 160,275 | 37,387 | (750 | ) | ||||||||
Other | — | — | 2,000 | |||||||||
Net cash provided by (used in) investing activities | 21,904 | (262,905 | ) | (239,069 | ) | |||||||
Cash flows from financing activities | ||||||||||||
Proceeds from long-term debt | 158 | 162,511 | 119,865 | |||||||||
Repayment of long-term debt | (94,795 | ) | (5,692 | ) | (304,240 | ) | ||||||
Proceeds from senior notes | — | — | 322,329 | |||||||||
Principal payments under capital lease obligations | (258 | ) | (244 | ) | (171 | ) | ||||||
Settlement of derivative instruments acquired | — | 184 | (1,898 | ) | ||||||||
Fees paid related to financing activities | (2,210 | ) | (1,360 | ) | (7,002 | ) | ||||||
Proceeds from termination fee | — | 3,500 | — | |||||||||
Fees paid related to merger activities | (2,169 | ) | (1,400 | ) | — | |||||||
Net cash provided by (used in) financing activities | (99,274 | ) | 157,499 | 128,883 | ||||||||
Net increase in cash and cash equivalents | 21,305 | 40,425 | 2,884 | |||||||||
Cash and cash equivalents at beginning of period | 52,112 | 11,687 | 8,803 | |||||||||
Cash and cash equivalents at end of period | $ | 73,417 | $ | 52,112 | $ | 11,687 | ||||||
Supplemental cash flow information | ||||||||||||
Cash paid (received) during the period for: | ||||||||||||
Interest, net of capitalized interest | $ | 86,778 | $ | 82,334 | $ | 73,892 | ||||||
Income taxes | (23 | ) | (28 | ) | (16 | ) |
December 31, | ||||||||
(dollars in thousands, except per share data) | 2012 | 2011 | ||||||
Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 29,819 | $ | 34,589 | ||||
Accounts receivable, net | 77,307 | 64,788 | ||||||
Inventories, net | 10,510 | 8,641 | ||||||
Prepaid expenses | 3,465 | 3,265 | ||||||
Derivative instruments | 42,516 | 12,840 | ||||||
|
|
|
| |||||
Total current assets | 163,617 | 124,123 | ||||||
Property and equipment—at cost, net | 65,601 | 65,711 | ||||||
Oil and natural gas properties, using the full cost method: | ||||||||
Proved | 2,860,611 | 2,535,404 | ||||||
Unevaluated (excluded from the amortization base) | 162,921 | 22,831 | ||||||
Accumulated depreciation, depletion, amortization and impairment | (1,290,356 | ) | (1,135,567 | ) | ||||
|
|
|
| |||||
Total oil and natural gas properties | 1,733,176 | 1,422,668 | ||||||
Derivative instruments | 517 | 16,785 | ||||||
Assets held for sale | 5,689 | — | ||||||
Deferred income taxes | — | 7,526 | ||||||
Other assets | 38,952 | 32,920 | ||||||
|
|
|
| |||||
$ | 2,007,552 | $ | 1,669,733 | |||||
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statementsbalance sheets — continued
(dollars in thousands, except per share data) | ||||||||
Liabilities and stockholders’ equity | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 101,598 | $ | 68,930 | ||||
Accrued payroll and benefits payable | 19,655 | 18,818 | ||||||
Accrued interest payable | 24,131 | 30,882 | ||||||
Revenue distribution payable | 18,152 | 20,800 | ||||||
Current maturities of long-term debt and capital leases | 3,746 | 3,078 | ||||||
Derivative instruments | 436 | 1,505 | ||||||
Deferred income taxes | 26,872 | 23,704 | ||||||
|
|
|
| |||||
Total current liabilities | 194,590 | 167,717 | ||||||
Long-term debt and capital leases, less current maturities | 1,289,656 | 1,031,495 | ||||||
Derivative instruments | 2,192 | 127 | ||||||
Stock-based compensation | 3,042 | 2,788 | ||||||
Asset retirement obligations | 46,314 | 43,593 | ||||||
Deferred income taxes | 8,901 | — | ||||||
Commitments and contingencies (Note 13) | ||||||||
Stockholders’ equity: | ||||||||
Preferred stock, 600,000 shares authorized, none issued and outstanding | — | — | ||||||
Class A Common stock, $0.01 par value, 10,000,000 shares authorized 67,991 and 66,165 shares issued and outstanding at December 31, 2012 and 2011, respectively | — | — | ||||||
Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 357,882 shares issued and outstanding | 4 | 4 | ||||||
Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882 shares issued and outstanding | 2 | 2 | ||||||
Class D Common stock, $0.01 par value, 10,000,000 shares authorized and 279,999 shares issued and outstanding | 3 | 3 | ||||||
Class E Common stock, $0.01 par value, 10,000,000 shares authorized and 504,276 shares issued and outstanding | 5 | 5 | ||||||
Class F Common stock, $0.01 par value, 1 share authorized, issued, and outstanding | — | — | ||||||
Class G Common stock, $0.01 par value, 3 shares authorized, issued, and outstanding | — | — | ||||||
Additional paid in capital | 422,434 | 419,370 | ||||||
Retained earnings (accumulated deficit) | 17,186 | (47,217 | ) | |||||
Accumulated other comprehensive income, net of taxes | 23,223 | 51,846 | ||||||
|
|
|
| |||||
462,857 | 424,013 | |||||||
|
|
|
| |||||
$ | 2,007,552 | $ | 1,669,733 | |||||
|
|
|
|
The accompanying notes are an integral part of cash flows—(continued)
Supplemental disclosure of investing and financing activities
During the years ended December 31, 2009, 2008, and 2007 we entered into capital lease obligations of $111, $592, and $21 respectively, for the purchase of machinery and equipment.
During the year ended December 31, 2009, oil and natural gas property additions of $27,511 previously included in accounts payable and accrued expenses were settled and are reflected in cash used in investing activities. During the years ended December 31, 2008 and 2007, oil and natural gas property additions of $25,407 and $24,527, respectively, were recorded as increases to accounts payable and accrued expenses, and were reflected in cash used in investing activities in the periods that the payables were settled. Non-cash additions to oil and natural gas properties for 2007 also include $15,597 related to final settlement of the Calumet acquisition.
In December 2009, we exchanged the assets of the Chemicals Division of Green Country Supply for assets received from Reef Services, LLC and cash of $696. The assets received consist primarily of acid trucks and related equipment and have an estimated fair value of approximately $2,950. This transaction is considered a non-monetary exchange accounted for at fair value. Non-cash additions to property and equipment for 2008 include $1,707 related to final settlement of the Green Country Supply acquisition.
During the years ended December 31, 2009, 2008, and 2007, we recorded an asset and related liability of $1,322, $707, and $266, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and natural gas properties.
Interest of $836, $1,370, and $1,613 was capitalized during the years ended December 31, 2009, 2008, and 2007, respectively, related to unproved oil and natural gas leaseholds. Interest of $0, $214, and $70 was capitalized during the years ended December 31, 2009, 2008, and 2007, respectively, primarily related to the construction of our office building.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of operations
Year ended December 31, | ||||||||||||
(in thousands) | 2012 | 2011 | 2010 | |||||||||
Revenues: | ||||||||||||
Oil and natural gas sales | �� | $ | 509,503 | $ | 530,041 | $ | 408,561 | |||||
Gain (loss) from oil and natural gas hedging activities | 46,746 | (27,452 | ) | (29,393 | ) | |||||||
Other revenues | — | 4,070 | 4,127 | |||||||||
|
|
|
|
|
| |||||||
Total revenues | 556,249 | 506,659 | 383,295 | |||||||||
Costs and expenses: | ||||||||||||
Lease operating | 130,960 | 121,420 | 106,127 | |||||||||
Production taxes | 32,003 | 34,321 | 26,495 | |||||||||
Depreciation, depletion and amortization | 169,307 | 146,083 | 109,503 | |||||||||
Loss on impairment of other assets | 2,000 | — | 4,150 | |||||||||
General and administrative | 49,812 | 42,056 | 29,915 | |||||||||
Other expenses | — | 3,448 | 3,148 | |||||||||
|
|
|
|
|
| |||||||
Total costs and expenses | 384,082 | 347,328 | 279,338 | |||||||||
Operating income | 172,167 | 159,331 | 103,957 | |||||||||
Non-operating income (expense): | ||||||||||||
Interest expense | (98,402 | ) | (96,720 | ) | (81,370 | ) | ||||||
Non-hedge derivative gains | 49,685 | 34,408 | 38,595 | |||||||||
Loss on extinguishment of debt | (21,714 | ) | (20,592 | ) | (2,241 | ) | ||||||
Financing costs | — | — | (1,812 | ) | ||||||||
Other income | 504 | 1,545 | 387 | |||||||||
|
|
|
|
|
| |||||||
Net non-operating expense | (69,927 | ) | (81,359 | ) | (46,441 | ) | ||||||
Income before income taxes | 102,240 | 77,972 | 57,516 | |||||||||
Income tax expense | 37,837 | 35,924 | 23,803 | |||||||||
|
|
|
|
|
| |||||||
Net income | $ | 64,403 | $ | 42,048 | $ | 33,713 | ||||||
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of comprehensive income
Year ended December 31, | ||||||||||||
(in thousands) | 2012 | 2011 | 2010 | |||||||||
Net income | $ | 64,403 | $ | 42,048 | $ | 33,713 | ||||||
Other comprehensive income (loss) | ||||||||||||
Reclassification adjustment for hedge (gains) losses included in net income | (46,746 | ) | 27,452 | 28,733 | ||||||||
Unrealized loss on hedges | — | — | (1,034 | ) | ||||||||
Income tax expense (benefit) related to other comprehensive income (loss) | 18,123 | (10,580 | ) | (10,343 | ) | |||||||
|
|
|
|
|
| |||||||
Other comprehensive income (loss), net of tax | (28,623 | ) | 16,872 | 17,356 | ||||||||
|
|
|
|
|
| |||||||
Comprehensive income | $ | 35,780 | $ | 58,920 | $ | 51,069 | ||||||
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of stockholders’ equity
(dollars in thousands) | Common stock | Additional paid in capital | Retained earnings (accumulated deficit) | Accumulated other comprehensive income | Total | |||||||||||||||||||
Shares | Amount | |||||||||||||||||||||||
Balance at January 1, 2010 | 877,000 | 9 | 100,918 | (122,978 | ) | 17,618 | (4,433 | ) | ||||||||||||||||
Common stock issuance for cash | 475,043 | 5 | 313,226 | — | — | 313,231 | ||||||||||||||||||
Restricted stock issuances | 51,346 | — | — | — | — | — | ||||||||||||||||||
Stock-based compensation | — | — | 3,690 | — | — | 3,690 | ||||||||||||||||||
Net income | — | — | — | 33,713 | — | 33,713 | ||||||||||||||||||
Other comprehensive income, net | ||||||||||||||||||||||||
Unrealized loss on hedges, net of taxes of $386 | — | — | — | — | (648 | ) | (648 | ) | ||||||||||||||||
Reclassification adjustment for hedge losses included in net income, net of taxes of $10,729 | — | — | — | — | 18,004 | 18,004 | ||||||||||||||||||
|
| |||||||||||||||||||||||
Total comprehensive income | 51,069 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Balance at December 31, 2010 | 1,403,389 | 14 | 417,834 | (89,265 | ) | 34,974 | 363,557 | |||||||||||||||||
Restricted stock issuances | 17,642 | — | — | — | — | — | ||||||||||||||||||
Restricted stock forfeitures | (2,295 | ) | — | — | — | — | — | |||||||||||||||||
Restricted stock repurchased | (528 | ) | — | — | — | — | — | |||||||||||||||||
Stock-based compensation | — | — | 4,137 | — | — | 4,137 | ||||||||||||||||||
Modification of Time Vesting awards to liability plan | — | — | (2,640 | ) | — | — | (2,640 | ) | ||||||||||||||||
Time Vesting awards settled in restricted stock | — | — | 39 | — | — | 39 | ||||||||||||||||||
Net income | — | — | — | 42,048 | — | 42,048 | ||||||||||||||||||
Other comprehensive income, net | ||||||||||||||||||||||||
Reclassification adjustment for hedge losses included in net income, net of taxes of $10,580 | — | — | — | — | 16,872 | 16,872 | ||||||||||||||||||
|
| |||||||||||||||||||||||
Total comprehensive income | 58,920 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Balance at December 31, 2011 | 1,418,208 | 14 | 419,370 | (47,217 | ) | 51,846 | 424,013 | |||||||||||||||||
Restricted stock issuances | 17,494 | — | — | — | — | — | ||||||||||||||||||
Restricted stock forfeitures | (14,199 | ) | — | — | — | — | — | |||||||||||||||||
Restricted stock repurchased | (1,469 | ) | — | — | — | — | — | |||||||||||||||||
Stock-based compensation | — | — | 2,463 | — | — | 2,463 | ||||||||||||||||||
Time Vesting awards settled in restricted stock | — | — | 601 | — | — | 601 | ||||||||||||||||||
Net income | — | — | — | 64,403 | — | 64,403 | ||||||||||||||||||
Other comprehensive income, net | ||||||||||||||||||||||||
Reclassification adjustment for hedge gains included in net income, net of taxes of $18,123 | — | — | — | — | (28,623 | ) | (28,623 | ) | ||||||||||||||||
|
| |||||||||||||||||||||||
Total comprehensive income | 35,780 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Balance at December 31, 2012 | 1,420,034 | $ | 14 | $ | 422,434 | $ | 17,186 | $ | 23,223 | $ | 462,857 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Consolidated statements of cash flows
Year ended December 31, | ||||||||||||
(in thousands) | 2012 | 2011 | 2010 | |||||||||
Cash flows from operating activities | ||||||||||||
Net income | $ | 64,403 | $ | 42,048 | $ | 33,713 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||||||
Depreciation, depletion, & amortization | 169,307 | 146,083 | 109,503 | |||||||||
Loss on impairment of other assets | 2,000 | — | 4,150 | |||||||||
Deferred income taxes | 37,719 | 35,745 | 23,724 | |||||||||
Unrealized loss (gain) on ineffective portion of hedges and reclassification adjustments | (46,746 | ) | 27,452 | 23,889 | ||||||||
Non-hedge derivative gains | (49,685 | ) | (34,408 | ) | (38,595 | ) | ||||||
Loss on extinguishment of debt | 21,714 | 20,592 | 2,241 | |||||||||
Net gain on sale of assets | (149 | ) | (1,284 | ) | (184 | ) | ||||||
Other | 2,864 | 3,057 | 2,211 | |||||||||
Change in assets and liabilities | ||||||||||||
Accounts receivable | (12,502 | ) | (4,762 | ) | (6,463 | ) | ||||||
Inventories | (2,304 | ) | 328 | (785 | ) | |||||||
Prepaid expenses and other assets | 2,360 | 1,583 | 5,141 | |||||||||
Accounts payable and accrued liabilities | 3,988 | 16,519 | 9,452 | |||||||||
Revenue distribution payable | (2,648 | ) | 3,577 | (1,450 | ) | |||||||
Stock-based compensation | 1,679 | 3,086 | 1,155 | |||||||||
|
|
|
|
|
| |||||||
Net cash provided by operating activities | 192,000 | 259,616 | 167,702 | |||||||||
Cash flows from investing activities | ||||||||||||
Purchase of property and equipment and oil and natural gas properties | (506,787 | ) | (339,863 | ) | (310,125 | ) | ||||||
Proceeds from asset dispositions | 46,246 | 38,356 | 445 | |||||||||
Settlement of non-hedge derivative instruments | 37,274 | (23,491 | ) | 45,490 | ||||||||
Other | 21 | — | 18 | |||||||||
|
|
|
|
|
| |||||||
Net cash used in investing activities | (423,246 | ) | (324,998 | ) | (264,172 | ) | ||||||
Cash flows from financing activities | ||||||||||||
Proceeds from long-term debt | 208,561 | 21,724 | 209,533 | |||||||||
Repayment of long-term debt | (183,482 | ) | (24,785 | ) | (717,561 | ) | ||||||
Proceeds from Senior Notes | 556,750 | 400,000 | 293,016 | |||||||||
Repayment of Senior Notes | (325,000 | ) | (325,000 | ) | — | |||||||
Proceeds from equity issuance | — | — | 313,231 | |||||||||
Principal payments under capital lease obligations | (10 | ) | (120 | ) | (249 | ) | ||||||
Payment of debt issuance costs and other financing fees | (14,516 | ) | (11,858 | ) | (19,806 | ) | ||||||
Payment of debt extinguishment costs | (15,827 | ) | (15,101 | ) | — | |||||||
|
|
|
|
|
| |||||||
Net cash provided by financing activities | 226,476 | 44,860 | 78,164 | |||||||||
|
|
|
|
|
| |||||||
Net decrease in cash and cash equivalents | (4,770 | ) | (20,522 | ) | (18,306 | ) | ||||||
Cash and cash equivalents at beginning of period | 34,589 | 55,111 | 73,417 | |||||||||
|
|
|
|
|
| |||||||
Cash and cash equivalents at end of period | $ | 29,819 | $ | 34,589 | $ | 55,111 | ||||||
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(Dollarsdollars in thousands, unless otherwise noted)
Note 1: Nature of operations and summary of significant accounting policies
Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) isare involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, Montana, Kansas, and Wyoming.Kansas.
A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.
Principles of consolidation
The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and natural gas reserves, valuation allowances associated with deferred income taxes, asset retirement obligations, fair value of derivative instruments, and others, and are subject to change.
Reclassifications
Certain reclassifications have been made to prior period financial statements to conform to current period presentation.
Cash and cash equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2009,2012, cash with a recorded balance totaling $70,787$27,732 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.
Accounts receivable
We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. Interest accrues beginning on the day after the due date of the receivable. Accounts receivable past due 90 days or more and still accruing interest at December 31, 2009 and 2008 were $687 and $1,124, respectively. We determine our allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
We write off accounts receivable when they are determined to be uncollectible. Bad debt expense (recovery) for the years ended December 31, 2009, 2008,2012, 2011, and 20072010 was $317, $351,$731, $179, and ($11),$17, respectively. When the account is determined to be uncollectible, all interest previously accrued but not collected is reversed against the allowance for doubtful accounts. Accounts receivable consisted of the following at December 31:
2009 | 2008 | |||||||
Joint interests | $ | 11,986 | $ | 21,136 | ||||
Accrued oil and natural gas sales | 33,600 | 27,432 | ||||||
Hedge settlements | 5,977 | 15,315 | ||||||
Other | 1,204 | 1,671 | ||||||
Allowance for doubtful accounts | (817 | ) | (617 | ) | ||||
$ | 51,950 | $ | 64,937 | |||||
Production tax benefit asset
During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15,000. Our expected return on the investment was the receipt of $2 of tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments were accounted for as a production tax benefit asset and were netted against tax credits realized in other income using the effective yield method over the expected recovery period. As of December 31, 2009 and 2008, the carrying value of the production tax benefit asset was $19 and $13,685, respectively. Oklahoma production tax credits of $13,544, $711, and $745 were included in other income in the consolidated statements of operations for the years ended December 31, 2009, 2008, and 2007, respectively.
2012 | 2011 | |||||||
Joint interests | $ | 19,282 | $ | 16,926 | ||||
Accrued oil and natural gas sales | 50,814 | 47,667 | ||||||
Derivative settlements | 8,013 | 449 | ||||||
Other | 472 | 380 | ||||||
Allowance for doubtful accounts | (1,274 | ) | (634 | ) | ||||
|
|
|
| |||||
$ | 77,307 | $ | 64,788 | |||||
|
|
|
|
Inventories
Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas productionproduct inventories, and inventoryequipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory, if necessary. The provision for excess or obsolete inventory for the years ended December 31, 2009, 2008,2012, 2011, and 20072010 was $274, $615,$0, $602, and $136$810, respectively. Inventories consisted of the following at December 31:
2009 | 2008 | 2012 | 2011 | |||||||||||||
Equipment inventory | $ | 6,673 | $ | 10,484 | $ | 8,047 | $ | 6,164 | ||||||||
Oil and natural gas product | 2,642 | 3,467 | 3,175 | 3,793 | ||||||||||||
Inventory for resale | 2,356 | 4,184 | ||||||||||||||
Inventory valuation allowance | (1,120 | ) | (846 | ) | (712 | ) | (1,316 | ) | ||||||||
|
| |||||||||||||||
$ | 10,551 | $ | 17,289 | $ | 10,510 | $ | 8,641 | |||||||||
|
|
Property and equipment
Property and equipment are capitalized and stated at cost, while maintenance and repairs are expensed currently.
Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives are as follows:
Furniture and fixtures | 10 years | |||
Automobiles and trucks | 5 years | |||
Machinery and equipment | 10 | |||
Office and computer equipment | 5 | |||
Building and improvements | 10 |
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
Oil and natural gas properties
We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, capitalized interest on qualified projects and other internal costs directly attributable to these activities.
Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment. Depreciation, depletion and amortization expense of oil and natural gas properties was $92,561, $91,316 and $78,717 for the years ended December 31, 2009, 2008, and 2007, respectively.
In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the fourth quarter of 2008, we recorded a ceiling test impairmentproperties not being amortized.
Our estimates of oil and natural gas propertiesreserves as of $281,393 as a result of a decline inDecember 31, 2012, 2011, and 2010 were prepared using an average price for oil and natural gas prices atbased upon the measurement date. The impairment was calculated based on December 31, 2008 spot pricesfirst day of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. Based on these year-end prices,each month for the effect of derivative contracts accounted forprior twelve months as cash flow hedges increased the full cost ceiling by $192,108, thereby reducing the ceiling test write downrequired by the same amount.
DuringSEC’sModernization of Oil and Gas Reporting and the first quarterguidance of 2009, natural gas prices declined significantly as comparedthe Financial Accounting Standard Board (“FASB”) relating to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oilOil and $3.63 per Mcf of natural gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to the PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oilGas Reserve Estimation and natural gas properties of $240,790 during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169,013, thereby reducing the ceiling test write down by the same amount.
Disclosures. As of December 31, 2009,2012, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, by $294,173, and no additional ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $61.18$94.71 per Bbl of oil and $3.87$2.76 per Mcf of gas for the year ended December 31, 2009. The effect of derivative contracts accounted for as cash flow hedges, based on these year-end prices, increased the full cost ceiling by $25,468. The qualifying cash flow hedges as of December 31, 2009, which consisted of commodity price swaps, covered 3,741 MBbls of oil production for the period from January 2010 through December 2011. See Note 4 for a further discussion of hedging activity.2012.
A decline in oil and natural gas prices subsequent to December 31, 20092012 could result in additional ceiling test write downswrite-downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.
Assets Held for Sale
In the fourth quarter of 2012, the Company finalized a plan to dispose of certain of the company’s owned drilling rigs by sale. The accounting for these assets is in accordance with ASC 360-10, Property, Plant and Equipment. Under this guidance, the assets are carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less. In determining fair value for the assets, management performed internal estimates of the value of the assets based on prices that would be received to sell each rig in an orderly transaction between market participants. As a result of determining fair value on the assets held for sale, an impairment loss was recorded for the year ended December 31, 2012 on certain of the assets held for sale in the amount of $1,500 which was included in the Loss on impairment of other assets in the Statements of Operations.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
In December 2008, the SEC issued its Modernization of Oil and Gas Reporting, which revises reserves requirements for oil and natural gas companies. The most significant amendments to the requirements include the following:
economic producibility of reserves and discounted cash flows is now estimated using an average price for oil and natural gas based upon the first day of each month for the prior twelve months rather than prices on the last day of the reporting period;
proved reserves may be estimated through the use of new technologies if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes;
reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years;
additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process and the internal controls used to assure the objectivity of the reserves estimate; and
probable and possible reserves may be disclosed separately on a voluntary basis.
In January 2010, the Financial Accounting Standards Board also issued guidance regardingOil and Gas Reserve Estimation and Disclosuresto provide consistency with the new SEC rules. The new guidance amends existing standards to align the reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules.
We adopted the new SEC reserves requirements and GAAP reserves guidance as a change in accounting principle that is inseparable from a change in estimate, and applied the guidance prospectively effective December 31, 2009. See Note 16 for a discussion of the impact of these changes on our reserves.
Funds held in escrow
We have funds held in escrow that are restricted as to withdrawal or usage. The restricted amounts consisted of the following at December 31:
2009 | 2008 | |||||
Escrows from acquisitions | $ | — | $ | 692 | ||
Plugging and abandonment escrow | 1,672 | 1,658 | ||||
$ | 1,672 | $ | 2,350 | |||
We are entitled to make quarterly withdrawals from the plugging escrow account equal to one-half of the interest earnings for the period and as reimbursement for actual plugging and abandonment expenses incurred on the North Burbank Unit, provided that written documentation has been provided. The balance is not intended to reflect our total future financial obligation for the plugging and abandonment of these wells.
Impairment of long-lived assets
Impairment losses are recorded on property and equipment used in operations and other long lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
WeIn 2012, we recognized $1,500 of impairment losses on certain of our owned drilling rigs classified as assets held for sale due to the expectation that these particular drilling rigs could not be sold at a 66.67% interest in Oklahoma Ethanol LLC, a joint venture to construct and operate an ethanol production plant in Blackwell, Oklahoma. Oklahoma Ethanol LLC retained a financial advisor to arrange project financing to fund construction costs and for related start-up working capital. Because financing did not close by September 15, 2008, the minority owner, Oklahoma Sustainable Energy LLC, is no longer able to participateprice that would exceed their carrying values in the joint venture, and we now own 100%current market climate. We estimated the fair value of Oklahoma Ethanol LLC. The City of Blackwell was also unable to obtain financing for the railroad upgrades and storage facilitiesdrilling rigs using prices that would be necessaryreceived to supportsell each rig in an orderly transaction between market participants. Also in 2012, we recognized $500 of additional impairment losses primarily related to drill pipe.
We owned an interest in the Levelland/Hockley County ethanol production.plant in Levelland, Texas, and we own a pipeline constructed for the sole purpose of supplying natural gas to the ethanol plant. During the thirdfourth quarter of 2008,2010, we determined that weany future cash flows generated by either the ethanol plant or by our pipeline, which supplies gas to the ethanol plant, would probably not be unlikelysufficient to obtain equity capital or new project financing for an ethanol plant.allow us to recover our investment in these assets. We accordingly recorded an impairment charge of $2,900,$4,150, which was the amount ofincluded our $2,042 investment in the ethanol plant.
Chaparral Energy, Inc.plant and subsidiaries
Notes to consolidated financial statements—(Continued)
(Dollars in thousands, unless otherwise noted)
the $2,108 carrying value of our pipeline assets.
Deferred income taxes
Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.
Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.
If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 20092012 and 2008,2011, we have not recorded a liability or accrued interest or penalties related to uncertain tax positions.
The taxTax years 1998 through 2009beginning with 1999 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.
Revenue recognitionChaparral Energy, Inc. and subsidiaries
Oil revenue is recognized when the product is deliveredNotes to the purchaser and natural gas revenue when delivered to the gas purchaser’s sales meter. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products or services are recognized at the time of delivery of materials or performance of service.consolidated financial statements
Gas balancing(dollars in thousands, unless otherwise noted)
In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its rateable portion of the gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. To the extent future reserves exist to enable the other owners to sell more than their rateable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production. At December 31, 2009 and 2008, our aggregate imbalance due to under production is approximately 3,024 MMcf and 3,194 MMcf, respectively. As of December 31, 2009, and 2008, our aggregate imbalance due to over production was approximately 1,818 MMcf and 1,840 MMcf, respectively, and a liability for gas imbalances of $1,486 and $1,346, respectively, was included in accounts payable and accrued liabilities.
Derivative transactions
We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative and the resulting designation.
Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in non-hedge derivative gains (losses) in the statement of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the statement of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.
If the derivative qualifies and is designated as a cash flow hedge, the effective portion of changes in the fair value of the derivative is recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value, as measured using the dollar offset method, is immediately recognized in lossgain (loss) from oil and natural gas hedging activities in the statement of operations. Cash flows associated with hedges are reported as operating activities in the statement of cash flows unless the hedges contain a significant financing element, in which case they are reported as financing activities.
If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting is discontinued and the gain or loss reported in accumulated other comprehensive income (loss) (“AOCI”) is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting is discontinued. The gain or loss associated with the discontinued hedges remains in accumulated other comprehensive income (loss)AOCI and is reclassified into income as the hedged transactions occur.
Chaparral Energy, Inc. Effective April 1, 2010, we have elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and subsidiaries
Notes to consolidated financial statements—(Continued)
(Dollars in thousands, unless otherwise noted)
In March 2008, the FASB issued new authoritative guidance regarding“Disclosures about Derivative Instruments and Hedging Activities”which is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. This guidance addresses concerns that the existing disclosure requirements do not provide adequate information about how derivative and hedging activities affect an entity’s financial position, financial performance, and cash flows. Accordingly, it requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. We adopted these disclosure requirements beginning January 1, 2009, and their adoption did not have an impact on our financial position or results of operations.discontinue hedge accounting prospectively.
We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See Note 45 for additional information regarding our derivative transactions.
Fair value measurements
In September 2006, the Financial Accounting Standards Board (“FASB”) issued new authoritative guidance which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.
As permitted by the FASB’s one-year deferral, we adopted the new fair value guidance for our financial assets and financial liabilities measured at fair value on January 1, 2008, and we adopted the new guidance for our nonfinancial assets and nonfinancial liabilities measured at fair value on a non-recurring basis on January 1, 2009. With the exception of incorporating the impact of nonperformance risk on derivative instruments, we did not change our method of calculating the fair value of assets or liabilities. The primary impact from adoption was additional disclosures.
Assets and liabilities recorded at fair value in the balance sheet are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and assets acquired through a non-monetary exchange transaction.
In February 2007, the FASB issued guidanceSee Note 5 for additional information regarding “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits companies to choose to measure certain financial instruments and other items at fair value. Unrealized gains and losses on any items for which we elect theour fair value measurement option would be reported in earnings. This guidance was effective for fiscal years beginning after November 15, 2007. We adopted the new guidance on January 1, 2008, and its adoption did not have an impact on our financial position or results of operations as we made no elections to report selected financial assets and liabilities at fair value.
In October 2008, the FASB provided additional guidance regarding “Estimating the Fair Value of a Financial Asset in a Market That Is Not Active.” This guidance clarifies how management’s internal assumptions should be considered in measuring fair value when observable data are not present. In addition, observable market information from an inactive market should be considered to determine fair value, and it is inappropriate to conclude that all market activity represents forced liquidations or distressed sales or to conclude that any transaction price can determine fair value. The use of broker quotes and pricing services should also be considered to assess the relevance of observable and unobservable data. When valuing financial assets and liabilities, significant judgment is required. This guidance was effective upon issuance and has been considered in conjunction with our 2009 and 2008 financial results. There was no material impact on our financial position or results of operations for the years ended December 31, 2009 or 2008.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
In April 2009, the FASB provided additional application guidance regarding “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” requiring “Interim Disclosures about Fair Value of Financial Instruments,”and clarifying“Recognition and Presentation of Other-Than-Temporary Impairments.” This guidance is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted this guidance for the period ending March 31, 2009, which resulted in additional disclosures, but did not have an impact on our financial position or results of operations.
In August 2009, the FASB issued new authoritative guidance regarding “Measuring Liabilities at Fair Value,” which is effective for the first reporting period (including interim periods) beginning after issuance. The new guidance provides additional clarification regarding how fair value should be measured when a quoted price in an active market for the identical liability is not available. We adopted the new guidance on October 1, 2009, and its adoption did not have an impact on our financial position or results of operations.
Asset retirement obligations
We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 56 for additional information regarding our asset retirement obligations.
Earnings (loss) per share
Basic earnings (loss) per share is computed by dividing net income (loss) attributable to all classes of common shareholders by the weighted average number of shares of all classes of common stock outstanding during the applicable period. Diluted earnings (loss) per share is determined in the same manner as basic earnings (loss) per share except that the number of shares is increased to assume exercise of potentially dilutive securities outstanding during the periods presented. There were no potentially dilutive securities outstanding during the periods presented.
Comprehensive income (loss)
Comprehensive income (loss) consists of net income (loss) and the unrealized gain or loss for the effective portion of derivative instruments classified as cash flow hedges. Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss).
Environmental liabilities
We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 20092012 and 2008,2011, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows.
Merger costs and termination feeSale of common stock
On October 9, 2009,April 12, 2010, we entered intoclosed the sale of an aggregate of 475,043 shares of our common stock to CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”). Proceeds from the sale were $313,231, net of fees and other expenses of $11,769, and were used to repay the amounts owing under our Seventh Restated Credit Agreement (our “prior credit facility”).
Revenue recognition
Oil revenue is recognized when the product is delivered to the purchaser and Plannatural gas revenue when delivered to the gas purchaser’s sales meter. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of Reorganization with United Refining Energy Corp. (“United”) under which we would merge with United, a publicly held Special Purpose Acquisition Company, in a reverse merger. The merger was to be accounted for as a reverse recapitalization, whereby we would beproducts or services are recognized at the continuing entity for financial reporting purposes and would be deemed, for accounting purposes, to betime of delivery of materials or performance of service.
Gas balancing
In certain instances, the acquirer of United. On December 11, 2009, United announced that the merger did not receive the stockholder vote required for approval, and the Agreement and Plan of Reorganization was terminated. As a result, costs of $2,169 associated with the merger were expensed.
On July 14, 2008, we entered into an Agreement and Plan of Merger (“Merger Agreement”) with Edge Petroleum Corporation (“Edge”), whereby Edge would merge with and into our wholly owned subsidiary, Chaparral Exploration, L.L.C. During the fourth quarter of 2008, the parties concluded that it was highly unlikely that allowners of the closing conditions set forthnatural gas produced from a well will select different purchasers for their respective ownership interest in the Merger Agreement wouldwells. If one purchaser takes more than its rateable portion of the gas, the owners selling to that purchaser will be met,required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, thereforeaccordingly, have recognized revenue on all production delivered to our purchasers. To the merger would not be consummated on or priorextent future reserves exist to enable the other owners to sell more than their rateable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production. As of December 31, 2008, the date on which either party could, subject2012 and 2011, our aggregate imbalance due to the termsunder production was approximately 2,690 MMcf and 2,860 MMcf , respectively. As of the Merger Agreement, terminate the Merger Agreement unilaterally. AsDecember 31, 2012 and 2011, our aggregate imbalance due to over production was approximately 1,658 MMcf and 1,802 MMcf, respectively, and a result, weliability for gas imbalances of $1,984 and Edge executed a Merger Termination Agreement on December 16, 2008,$1,819, respectively, was included in accounts payable and costs of $1,400 associated with the merger were expensed.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
On July 14, 2008, we entered into a Stock Purchase Agreement with Magnetar Financial LLC (“Magnetar”), which provided for Magnetar and its affiliates to purchase 1.5 million shares of our Series B convertible preferred stock for an aggregate purchase price of $150,000. On December 16, 2008, we executed a Termination and Settlement Agreement (the “Magnetar Termination Agreement”) with Edge and Magnetar, which terminated the Stock Purchase Agreement. Pursuant to the Magnetar Termination Agreement, Magnetar paid a total of $5,000, of which $1,500 was paid to Edge at our direction to reimburse Edge for certain expenses, and $3,500 was paid to us and recorded as a termination fee.
Discontinued operationsStock-based compensation
Certain amountsOur stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.
The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.
The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.
We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.
The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been reclassified to presentsignificantly impacted.
The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the operations of Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary, as discontinued operations. Unless otherwise indicated, information presentedstock-based compensation cost could be different from what we have recorded in the notes to the financial statements relates only to our continuing operations. current period.
See Note 28 for additional information relating to discontinued operations.
Recent accounting pronouncements
In January 2010, the FASB issued new authoritative guidance regarding “Improving Disclosures about Fair Value Measurements and Disclosures” that requires additional disclosure of transfers in and out of Level 1 and 2 measurements and the reasons for the transfers, and a gross presentation of activity within the Level 3 roll forward. The guidance also includes clarifications to existing disclosure requirements on the level of disaggregation and disclosures regarding inputs and valuation techniques. The guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We will adopt the guidance on January 1, 2010, except for requirements regarding the gross presentation of Level 3 roll forward information, which we will adopt on January 1, 2011. Because this guidance only requires additional disclosures, it is not expected to have a significant impact on our financial statements.
In June 2009, the FASB issued new authoritative guidance regarding the “FASB Accounting Standards Codification,” which became the source of authoritative GAAP for nongovernmental entities effective for financial statements issued for interim and annual periods ending after September 15, 2009. We adopted the new guidance on July 1, 2009. The guidance did not have an impact on our financial position or results of operations, but it did affect the way we reference GAAP in our consolidated financial statements and accounting policies.
In December 2007, the FASB issued new authoritative guidance regarding “Business Combinations” which is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. This guidance establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. This guidance also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. We adopted this guidance effective January 1, 2009. The guidance will apply prospectively to future business combinations, and did not have an effect on our reported financial position or results of operations.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
Note 2: Discontinued operationsRecently adopted and issued accounting pronouncements
On April 16, 2007, we acquired allIn May 2011, the FASB issued authoritative guidance that clarifies the application of the outstanding shares of common stock of Green Country Supply, Inc. (“GCS”) for an aggregate cash purchase price of approximately $23,606. The purchase price was paid in cash and financed through our line of credit. GCS provided oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and natural gas operators primarily in Oklahoma, Texas, and Wyoming. As a result of the acquisition, GCS became a wholly-owned subsidiary and the results of operations have been included in the consolidated statement of operations since April 16, 2007.
During the second quarter of 2009, we committed to a plan to sell the assets of GCS, and on May 14, 2009, we entered into an agreement to sell the assets of the Electric Submersible Pumps (“ESP”) division of GCS to Global Oilfield Services, Inc. (“Global”) for a cash price of approximately $24,650 after working capital adjustments as provided in the agreement. We paid off notes payable attributed to certain assets sold to Global in the amount of $1,605, and recorded a pre-tax gain associated with the sale of $9,081.
On December 11, 2009, we entered into an agreement with Reef Services, LLC (“Reef”) under which we exchanged the assets of the Chemicals division of GCS for the assets of the Reef Acid Division and cash of $696. The assets received consist primarily of acid trucks and related equipment and have an estimated fair value of approximately $2,950. This transaction is considered a non-monetary exchange accountedmeasurement and disclosure requirements and changes particular principles or requirements for atmeasuring fair value. We paid off notes payable attributed to certain assets sold to Reef in the amount of $253,This guidance is effective for interim and recorded a pre-tax gain associated with the exchange of $1,368.
The operating results of GCS have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below.
Year ended December 31, | April 16, 2007 through December 31, | |||||||||||
2009 | 2008 | 2007 | ||||||||||
Revenues | $ | 11,142 | $ | 33,821 | $ | 20,611 | ||||||
Operating expenses | (10,983 | ) | (31,450 | ) | (18,852 | ) | ||||||
Gain on sale | 10,449 | — | — | |||||||||
Income before income taxes | 10,608 | 2,371 | 1,759 | |||||||||
Income tax provision | 3,959 | 915 | 641 | |||||||||
Income from discontinued operations | $ | 6,649 | $ | 1,456 | $ | 1,118 | ||||||
annual periods beginning after December 15, 2011, and we adopted it on January 1, 2012. There werewas no assets held for sale or liabilities associated with discontinued operations as of December 31, 2009. At December 31, 2008, the assets and liabilities of GCS are classified as assets held for sale and liabilities associated with discontinued operations, respectively,significant impact on our consolidated balance sheet.financial statements other than additional disclosures.
In June 2011, the FASB issued new authoritative guidance that requires entities that report other comprehensive income to present the components of net income and comprehensive income in either one continuous financial statement or two consecutive financial statements. It does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we applied it retrospectively beginning on January 1, 2012. We have elected to present the components of net income and comprehensive income in two consecutive financial statements.
In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance is effective for calendar years beginning after December 15, 2013, once the fee is instituted. We are currently assessing the impact that this fee and the adoption of the related authoritative guidance will have on our financial statements.
In December 2011, the FASB issued authoritative guidance requiring entities to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning on or after January 1, 2013. We will adopt the requirements with the preparation of our Form 10-Q for the quarter ending March 31, 2013, which will require additional footnote disclosures for our derivative instruments and are not expected to have a material effect on our consolidated financial statements.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
Note 2: Supplemental disclosures to the consolidated statements of cash flows
Supplemental disclosures to the consolidated statements of cash flows are presented below:
Year ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Net cash provided by operating activities included: | ||||||||||||
Cash payments for interest | $ | 103,350 | $ | 85,222 | $ | 67,529 | ||||||
Interest capitalized | (4,437 | ) | (2,379 | ) | (2,036 | ) | ||||||
|
|
|
|
|
| |||||||
Cash payments for interest, net of amounts capitalized | $ | 98,913 | $ | 82,843 | $ | 65,493 | ||||||
|
|
|
|
|
| |||||||
Cash (receipts) payments for income taxes | $ | 255 | $ | 179 | $ | (21 | ) | |||||
Non-cash investing activities included: | ||||||||||||
Asset retirement costs capitalized | $ | 1,079 | $ | 2,522 | $ | 1,488 | ||||||
Oil and natural gas properties acquired through increase (decrease) in accounts payable and accrued liabilities | $ | 24,280 | $ | (14,667 | ) | $ | 25,773 | |||||
Non-cash financing activities included: | ||||||||||||
Modification of Time Vesting equity awards to liability plan | $ | — | $ | 2,640 | $ | — |
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 3: Property and equipment
Major classes of property and equipment consist of the following at December 31:
2009 | 2008 | 2012 | 2011 | |||||||||||
Furniture and fixtures | $ | 1,960 | $ | 1,701 | $ | 2,327 | $ | 2,115 | ||||||
Automobiles and trucks | 12,095 | 12,249 | 13,618 | 12,966 | ||||||||||
Machinery and equipment | 42,522 | 38,982 | 52,326 | 59,190 | ||||||||||
Office and computer equipment | 7,594 | 7,464 | 10,603 | 8,823 | ||||||||||
Building and improvements | 21,741 | 21,453 | 26,051 | 22,758 | ||||||||||
|
| |||||||||||||
85,912 | 81,849 | 104,925 | 105,852 | |||||||||||
Less accumulated depreciation and amortization | 29,198 | 20,664 | 46,080 | 45,500 | ||||||||||
|
| |||||||||||||
56,714 | 61,185 | 58,845 | 60,352 | |||||||||||
Work in progress | — | 9 | ||||||||||||
Land | 5,483 | 5,731 | 6,756 | 5,359 | ||||||||||
|
| |||||||||||||
$ | 62,197 | $ | 66,925 | $ | 65,601 | $ | 65,711 | |||||||
|
|
Property and equipment leased under capital leases, which are included in the above amounts, consist of the following at December 31:
2009 | 2008 | 2012 | 2011 | |||||||||||
Office and computer equipment | $ | 1,926 | $ | 1,926 | $ | 1,926 | $ | 1,926 | ||||||
Machinery and equipment | 642 | 531 | 642 | 642 | ||||||||||
|
| |||||||||||||
2,568 | 2,457 | 2,568 | 2,568 | |||||||||||
Less accumulated depreciation and amortization | 1,929 | 1,756 | 2,241 | 2,175 | ||||||||||
|
| |||||||||||||
$ | 639 | $ | 701 | $ | 327 | $ | 393 | |||||||
|
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 4: Long-term debt
As of the dates indicated, long-term debt consists of the following:
December 31, | ||||||||
2012 | 2011 | |||||||
8.875% Senior Notes due 2017, net of discount of $0 and $1,658, respectively | $ | — | $ | 323,342 | ||||
9.875% Senior Notes due 2020, net of discount of $5,969 and $6,441, respectively | 294,031 | 293,559 | ||||||
8.25% Senior Notes due 2021 | 400,000 | 400,000 | ||||||
7.625% Senior Notes due 2022, including premium of $6,631 and $0, respectively | 556,631 | — | ||||||
Senior secured revolving credit facility | 25,000 | — | ||||||
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due January 2013 through December 2028; collateralized by real property | 12,596 | 12,116 | ||||||
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.00% to 6.99%, due January 2013 through October 2017; collateralized by automobiles, machinery and equipment | 5,144 | 5,546 | ||||||
Capital lease obligations | — | 10 | ||||||
|
|
|
| |||||
1,293,402 | 1,034,573 | |||||||
Less current maturities | 3,746 | 3,078 | ||||||
|
|
|
| |||||
$ | 1,289,656 | $ | 1,031,495 | |||||
|
|
|
|
On March 27, 2013, we committed to borrow an additional $20,000 under our senior secured revolving credit facility and will receive the funds on April 1, 2013.
Maturities of long-term debt and capital leases, excluding premiums or discounts on our Senior Notes, are as follows as of December 31, 2012:
2013 | $ | 3,746 | ||
2014 | 2,098 | |||
2015 | 1,473 | |||
2016 | 732 | |||
2017 | 25,646 | |||
2018 and thereafter | 1,259,045 | |||
|
| |||
$ | 1,292,740 | |||
|
|
Senior Notes
On May 2, 2012, we issued $400,000 aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the May 2, 2012 7.625% Senior Notes issuance to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. Interest is payable on the 7.625% Senior Notes semi-annually on May 15 and November 15 each year beginning November 15, 2012. On or after May 15, 2017, we may, at our option, redeem the 7.625% Senior Notes at the following redemption prices plus accrued and unpaid interest: 103.813% after May 15, 2017; 102.542% after May 15, 2018; 101.271% after May 15, 2019; and 100% after May 15, 2020. Prior to May 15, 2015, we may redeem up to 35% of the 7.625% Senior Notes with the net proceeds of one or more equity offerings at a redemption price of 107.625%, plus accrued and unpaid interest. The initial $400,000 of 7.625% Senior Notes were exchanged for registered notes effective September 28, 2012.
On November 15, 2012, we issued an additional $150,000 aggregate principal amount of 7.625% Senior Notes under the same indenture covering the issuance on May 2, 2102 (the “Add-on Notes”). The net proceeds from the additional 7.625% Senior Notes issuance were used to repay the outstanding balance of the indebtedness under our senior secured revolving credit facility and for general corporate purposes. In connection with the sale of the Add-on Notes, we entered into a registration rights agreement in which we agree to file a registration statement with the SEC related to an offer to exchange the Add-on Notes for an issue of registered notes within 270 days of the closing date (the “Target Registration Date”). If we fail to complete the exchange
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
offer by the Target Registration Date, we will be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the Target Registration Date. After the first 90 days, the rate increases an additional 0.25% for each additional 90-day period, up to a maximum of 1.0% per annum.
In connection with the issuance of the May 2, 2012 7.625% Senior Notes, we capitalized approximately $8,778 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. In connection with the issuance of the November 15, 2012 Add-on Notes, we recorded a premium of $6,750 and capitalized $3,485 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. Amortization of $119 was netted against interest expense during the year ended December 31, 2012 related to the premium and amortization of $419 was charged to interest expense during the year ended December 31, 2012 related to the issuance costs. Unamortized issuance costs of $11,844 were included in “Other assets” as of December 31, 2012.
During 2012, we recorded a $21,714 loss associated with the refinancing of our 8.875% Senior Notes, including $15,827 in repurchase or redemption-related fees and a $5,887 write-off of deferred financing costs and unaccreted discount.
On February 22, 2011, we issued $400,000 aggregate principal amount of 8.25% senior notes maturing on September 1, 2021. The net proceeds, after underwriting and issuance costs, were used to consummate a tender offer for all of our 8.5% senior notes due 2015, to redeem the 8.5% senior notes not purchased in the tender offer, and for general corporate purposes. Interest is payable on the 8.25% senior notes semi-annually on March 1 and September 1 each year beginning September 1, 2011. On or after September 1, 2016, we may, at our option, redeem the notes at the following redemption prices plus accrued and unpaid interest: 104.125% after September 1, 2016, 102.750% after September 1, 2017, 101.375% after September 1, 2018, and 100% after September 1, 2019. Prior to March 1, 2014, we may redeem up to 35% of the notes with the net proceeds of one or more equity offerings at a redemption price of 108.250%, plus accrued and unpaid interest.
In connection with the issuance of the 8.25% Senior Notes, we capitalized $8,785 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. Unamortized issuance costs of $7,750 and $8,329 were included in “Other assets” as of December 31, 2012 and 2011, respectively. Amortization of $579 and $456 was charged to interest expense during the year ended December 31, 2012 and 2011, respectively.
During the year ended December 31, 2011, we recorded a $20,592 loss associated with the refinancing of our 8.5% senior notes due 2015, including $15,101 in repurchase or redemption-related fees and a $5,491 write-off of deferred financing costs.
On September 16, 2010, we issued $300,000 of 9.875% senior notes due 2020 at a price of 97.672% of the principal amount. The net proceeds, after underwriting and issuance costs, were used to pay down the outstanding indebtedness under our revolving line of credit and for working capital. Interest is payable on the senior notes semi-annually on April 1 and October 1 each year beginning April 1, 2011. The notes mature on October 1, 2020. On or after October 1, 2015, we may, at our option, redeem the notes at the following redemption prices plus accrued and unpaid interest: 104.938% after October 1, 2015, 103.292% after October 1, 2016, 101.646% after October 1, 2017, and 100% after October 1, 2018 and thereafter. Prior to October 1, 2013, we may redeem up to 35% of the notes with the net proceeds of one or more equity offerings at a redemption price of 109.875%, plus accrued and unpaid interest.
In connection with the issuance of the 9.875% senior notes, we recorded a discount of $6,984 and capitalized $6,796 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. Unamortized issuance costs of $5,816 and $6,275 were included in “Other assets” as of December 31, 2012 and 2011, respectively. Accretion of $472, $424, and $119 was charged to interest expense during the years ended December 31, 2012, 2011, and 2010, respectively, related to the discount, and amortization of $459, $409, and $112 was charged to interest expense during the years ended December 31, 2012, 2011, and 2010, respectively, related to the issuance costs.
On January 18, 2007, we issued $325,000 of 8.875% senior notes due 2017 at a price of 99.178% of the principal amount. The net proceeds, after underwriting and issuance costs, were used to reduce outstanding indebtedness under our revolving line of credit and for working capital. Interest on the notes is payable semi-annually on February 1 and August 1 each year beginning August 1, 2007, and the notes mature on February 1, 2017. These notes were repurchased or redeemed upon issuance of the 7.625% Senior Notes maturing on November 15, 2022 issued May 2, 2012.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
In connection with the issuance of the 8.875% senior notes, we recorded a discount of $2,671 and capitalized $7,316 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. Unamortized issuance costs of $0 and $4,552 were included in “Other assets” as of December 31, 2012 and 2011, respectively. Accretion of $86, $243, and $222 was charged to interest expense during the years ended December 31, 2012, 2011, and 2010, respectively, related to the discount, and amortization of $237, $669, and $609 was charged to interest expense during the years ended December 31, 2012, 2011, and 2010, respectively, related to the issuance costs.
The indentures governing our 9.875% senior notes due 2020, and our 8.25% senior notes due 2021, and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”) contain certain covenants which limit our ability to:
incur or guarantee additional indebtedness, or issue preferred stock;
pay dividends on our capital stock or redeem, repurchase, or retire our capital stock or subordinated debt;
make investments;
incur liens on assets;
create restrictions on the ability of our restricted subsidiaries to pay dividends, make loans, or transfer property to us;
engage in transactions with affiliates;
sell assets, including capital stock of our subsidiaries;
consolidate, merge or transfer assets; and
enter into other lines of business.
If we experience a change of control (as defined in the indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell to us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.
Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries except for Oklahoma Ethanol, LLC and Chaparral Biofuels, LLC.
Senior secured revolving credit facility
In April 2010, we entered into an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under our senior secured revolving credit facility, to repay the amounts owing under our Seventh Restated Credit Agreement. During the year ended December 31, 2010, we wrote off deferred financing costs associated with the refinancing of our Seventh Restated Credit Agreement of $2,241, and we recorded deferred financing costs associated with the closing of our senior secured revolving credit facility of $10,909. The Eighth Amendment to our senior secured revolving credit facility, effective April 30, 2012, amended our Asset Sale Covenant to permit the sale of certain oil and natural gas properties located in southern Oklahoma and increased our permitted ratio of Consolidated Net Debt to Consolidated EBITDAX. The Ninth Amendment to our senior secured revolving credit facility, effective May 24, 2012, amended the calculation of Consolidated EBITDAX to permit the exclusion of our reasonable and customary fees related to the refinancing of our 8.875% Senior Notes. The Tenth Amendment to our senior secured revolving credit facility, effective November 1, 2012, increased our borrowing base from $375,000 to $500,000; increased the Aggregate Maximum Credit Amount from $450,000 to $750,000 and the maximum Aggregate Maximum Credit Amount (after giving effect to any exercise of the accordion option on the terms and conditions set forth in the senior secured revolving credit facility) to $850,000; extended the maturity date to November 1, 2017; reduced the applicable margins added to the Adjusted LIBO Rate for the purposes of determining the interest rate (i) on Eurodollar loans to a margin ranging from 1.50% to 2.50% and (ii) on ABR loans to a margin ranging from 0.50% to 1.50%, each depending on the utilization percentage of the conforming borrowing base; reduced commitment fees to 0.375% if less than 50% of the borrowing base is utilized; reaffirmed the borrowing base through May 1, 2013 and permitted the offering of the Add-on Notes without triggering the automatic 25% reduction of the borrowing base.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Amounts borrowed under our senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). The entire balance outstanding at December 31, 2012 was subject to the Eurodollar rate.
The Eurodollar rate is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our senior secured revolving credit facility, plus a margin that varies depending on our utilization percentage. During 2012, the margin varied from 1.50% to 2.75%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.
Interest on loans subject to the ABR is computed as the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in our senior secured revolving credit facility, plus 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%, plus a margin that varies depending on our utilization percentage. During 2012, the margin varied from 0.50% to 1.75%.
Commitment fees of 0.375% to 0.50% accrue on the unused portion of the borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.
Our senior secured revolving credit facility contains restrictive covenants that may limit our ability, among other things, to:
incur additional indebtedness;
create or incur additional liens on our oil and natural gas properties;
pay dividends in cash or other property, redeem our capital stock or prepay certain indebtedness;
make investments in or loans to others;
change our line of business;
enter into operating leases;
merge or consolidate with another person, or lease or sell all or substantially all of our assets;
sell, farm-out or otherwise transfer property containing proved reserves;
enter into transactions with affiliates;
issue preferred stock;
enter into negative pledge agreements or agreements restricting the ability of our subsidiaries to pay dividends;
enter into or terminate certain swap agreements;
amend our organizational documents; and
amend, modify or waive under our permitted bond documents (i) any covenants that would make the terms materially more onerous to us or (ii) certain other provisions.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Our senior secured revolving credit facility, as amended, also has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than 4.50 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter.
The First Amendment to our senior secured revolving credit facility, dated July 26, 2010, modified the definition of Consolidated EBITDAX to (1) permit cash proceeds received from the monetization of derivatives to be included in the calculation of Consolidated EBITDAX, to the extent that such monetizations, in any period between scheduled redeterminations, do not exceed 5% of the borrowing base then in effect, and (2) permit the exclusion from the calculation of Consolidated EBITDAX of up to $4,500 in one-time cash expenses associated with our financing transactions that were incurred and paid during the second quarter of 2010.
The Fourth Amendment to our senior secured revolving credit facility, effective April 1, 2011, amended the definition of Consolidated EBITDAX to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.
We believe we were in compliance with all covenants under our senior secured revolving credit facility as of December 31, 2012.
Our senior secured revolving credit facility also specifies events of default, including non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, and change of control, among others. In addition, bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under our senior secured revolving credit facility. An acceleration of our indebtedness under our senior secured revolving credit facility could in turn result in an event of default under the indentures for our Senior Notes, which in turn could result in the acceleration of the Senior Notes.
If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 30 days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Note 5: Derivative activities and financial instrumentsfair value measurements
Derivative activitiesOverview
Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. See Note 1 for additional information regarding our accounting policies for derivative transactions and fair value measurements.
For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. Our collars have not been designated as hedges. Therefore,A three-way collar contract consists of a standard collar contract plus a put option contract sold by us with a price below the changes in fair value and settlementfloor price of these derivative contracts are recognized as non-hedge derivative gains (losses).the collar. This can haveadditional put option requires us to make a significant impact on our results of operations duepayment to the volatilitycounterparty if the market price is below the additional put option price. If the market price is greater than the additional put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the underlying commodity prices.standard collar and the additional put option price if the market price falls below the additional put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while defraying the associated cost with the sale of the additional put option.
We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. We do not designate these instruments as hedges; therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
In anticipationDecember 2011, we amended our senior secured revolving credit facility to provide greater flexibility when hedging our anticipated production. The terms of the Calumet acquisition in October 2006, we entered into additional commodity swapsamendment allow us to provide protection againstprotect a decline in the priceportion of oil. We do not believe that these instruments qualify as hedges. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).
As part of the Calumet acquisition, we assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges. These derivative positions were recorded at fair value in the purchase price allocation as a liability of $838. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlyingliquids production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment tofrom price volatility using crude oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the price assumed in the original fair value calculation.
The change in fair value of the acquired cash flow hedges from the date of acquisition is recorded as a component of accumulated other comprehensive income (loss). In addition, the hedge instruments are deemed to contain a significant financing element, and all cash flows associated with these positions are reported as a financing activity in the consolidated statement of cash flows for the periods in which settlement occurs. All of these positions were settled as of December 31, 2008.
derivatives. Our outstanding derivative instruments as of December 31, 20092012 are summarized below:
Oil derivatives | ||||||||||
Swaps | Collars | |||||||||
Volume MBbl | Weighted average fixed price to be received | Volume MBbl | Weighted average range | |||||||
2010 | 2,387 | $ | 67.69 | 240 | $ | 110.00 - $168.55 | ||||
2011 | 2,095 | 68.40 | 204 | 110.00 - 152.71 | ||||||
4,482 | 444 | |||||||||
Oil derivatives | ||||||||||||||||||||||||
Swaps | Three-way collars | |||||||||||||||||||||||
Volume MBbls | Weighted average fixed price per Bbl | |||||||||||||||||||||||
Weighted average fixed price per Bbl | Volume MBbls | Additional put option | Put | Call | ||||||||||||||||||||
2013 | 1,020 | $ | 96.78 | 3,710 | $ | 77.88 | $ | 99.94 | $ | 114.26 | ||||||||||||||
2014 | — | — | 1,320 | 75.91 | 92.54 | 103.08 | ||||||||||||||||||
|
|
|
| |||||||||||||||||||||
1,020 | 5,030 | |||||||||||||||||||||||
|
|
|
|
Natural gas derivatives | Natural gas basis protection swaps | ||||||||||||||
Swaps | Collars | ||||||||||||||
Volume BBtu | Weighted average fixed price to be received | Volume BBtu | Weighted average range | Volume BBtu | Weighted average fixed price to be paid | ||||||||||
2010 | 12,900 | $ | 7.39 | 3,360 | $ | 10.00 - $11.53 | 16,600 | $ | 0.81 | ||||||
2011 | 10,800 | 7.34 | — | 12,990 | 0.74 | ||||||||||
23,700 | 3,360 | 29,590 | |||||||||||||
Natural gas swaps | Natural gas basis protection swaps | |||||||||||||||
Volume BBtu | Weighted average fixed price per MMBtu | Volume BBtu | Weighted average fixed price per MMBtu | |||||||||||||
2013 | 16,800 | $ | 4.31 | 16,400 | $ | 0.20 | ||||||||||
2014 | 8,400 | 3.95 | 14,090 | 0.23 | ||||||||||||
|
|
|
| |||||||||||||
25,200 | 30,490 | |||||||||||||||
|
|
|
|
Discontinuance of cash flow hedge accounting
Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, all gains and losses from changes in the fair value of our derivative contracts subsequent to March 31, 2010 are recognized immediately in “Non-hedge derivative gains” in the consolidated statements of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Prior to March 31, 2010, a portion of the change in fair value was deferred through other comprehensive income. As of December 31, 2012, AOCI consists of deferred net gains of $37,134 ($23,223 net of tax) that will be recognized as gains from oil and natural gas hedging activities through December 2013 as the hedged production is sold.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Derivative activities
Gains and losses associated with cash flow hedges are summarized below.
Year ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Amount of loss recognized in AOCI (effective portion) | ||||||||||||
Oil swaps | $ | — | $ | — | $ | (1,034 | ) | |||||
Income taxes | — | — | 386 | |||||||||
|
|
|
|
|
| |||||||
$ | — | $ | — | $ | (648 | ) | ||||||
|
|
|
|
|
| |||||||
Amount of gain (loss) reclassified from AOCI in income (effective portion)(1) | ||||||||||||
Oil swaps | $ | 46,746 | $ | (27,452 | ) | $ | (30,243 | ) | ||||
Natural gas swaps | — | 1,510 | ||||||||||
Income taxes | (18,123 | ) | 10,580 | 10,729 | ||||||||
|
|
|
|
|
| |||||||
$ | 28,623 | $ | (16,872 | ) | $ | (18,004 | ) | |||||
|
|
|
|
|
| |||||||
Loss on oil swaps recognized in income (ineffective portion)(1) | $ | — | $ | — | $ | (660 | ) | |||||
|
|
|
|
|
|
(1) | Included in “Gain (loss) from oil and natural gas hedging activities” in our consolidated statements of operations. |
“Gain (loss) from oil and natural gas hedging activities,” which is a component of total revenues in the consolidated statements of operations, consists of the reclassification of hedge gains (losses) on discontinued oil hedges into income and is comprised of the following:
Year ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Oil hedges | ||||||||||||
Reclassification adjustment for hedge gains (losses) included in net income | $ | 46,746 | $ | (27,452 | ) | $ | (30,243 | ) | ||||
Loss on ineffective portion of derivatives qualifying for hedge accounting | — | — | (660 | ) | ||||||||
Natural gas hedges | ||||||||||||
Reclassification adjustment for hedge gains included in net income | — | — | 1,510 | |||||||||
|
|
|
|
|
| |||||||
$ | 46,746 | $ | (27,452 | ) | $ | (29,393 | ) | |||||
|
|
|
|
|
|
During 2010, we received proceeds of $7,097 on the early settlement of certain oil and natural gas derivative contracts with original settlement dates from April 2010 through December 2012. The proceeds from early settlement are recorded as a component of “Non-hedge derivative gains” in the consolidated statements of operations.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
“Non-hedge derivative gains” in the consolidated statements of operations are comprised of the following:
Year ended December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Change in fair value of commodity price swaps | $ | (8,440 | ) | $ | 50,004 | $ | 8,610 | |||||
Change in fair value of costless collars | 21,182 | 3,540 | (24,846 | ) | ||||||||
Change in fair value of natural gas basis differential contracts | (331 | ) | 4,355 | 9,341 | ||||||||
Receipts from (payments on) settlement of commodity price swaps | 28,716 | (16,801 | ) | 27,332 | ||||||||
Receipts from settlement of costless collars | 10,229 | 1,250 | 28,268 | |||||||||
Payments on settlement of natural gas basis differential contracts | (1,671 | ) | (7,940 | ) | (10,110 | ) | ||||||
|
|
|
|
|
| |||||||
$ | 49,685 | $ | 34,408 | $ | 38,595 | |||||||
|
|
|
|
|
|
Fair value of derivative instruments
All derivative financial instruments are recorded on the balance sheet at fair value. TheWe estimate the fair value of swaps is generally determinedour derivative instruments using a combined income and market valuation methodology. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price.price, and are discounted at the LIBOR swap rate. The fair value of collars is determined using an option pricing model which takes into account market volatility market prices, and contract parameters. Derivativeas well as the inputs described above. All derivative instruments are discounted further using a rate that incorporates our nonperformance risk for derivative liabilities and our counterparties’ creditnonperformance risk for derivative assets.
Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility, and we believe the credit risks associated with all As of these institutions are acceptable. We did not post collateral under any of these contracts as they are secured under our revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our revolving credit facility. The aggregate fair value of our derivative liabilities was $83,713 at December 31, 2009.
Chaparral Energy, Inc.2012 and subsidiaries
Notes to consolidated financial statements—(Continued)
(Dollars in thousands, unless otherwise noted)
2011, the rate reflecting our nonperformance risk was 1.50% and 1.75%, respectively, and the weighted-average rate reflecting our counterparties’ nonperformance risk was approximately 0.32% and 3.38%, respectively.
The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.
As of December 31, 2009 | As of December 31, 2008 | As of December 31, 2012 | As of December 31, 2011 | ||||||||||||||||||||||||||||||||||||||||||
Assets | Liabilities | Net Value | Assets | Liabilities | Net Value | Assets | Liabilities | Net value | Assets | Liabilities | Net value | ||||||||||||||||||||||||||||||||||
Derivatives designated as cash flow hedges: | |||||||||||||||||||||||||||||||||||||||||||||
Oil swaps | $ | 172 | $ | (54,883 | ) | $ | (54,711 | ) | $ | 116,311 | $ | (5,631 | ) | $ | 110,680 | ||||||||||||||||||||||||||||||
Derivatives not designated as hedging instruments: | |||||||||||||||||||||||||||||||||||||||||||||
Natural gas swaps | 30,366 | (26 | ) | 30,340 | 14,043 | (731 | ) | 13,312 | $ | 13,642 | $ | (1,487 | ) | $ | 12,155 | $ | 30,124 | $ | — | $ | 30,124 | ||||||||||||||||||||||||
Oil swaps | — | (13,840 | ) | (13,840 | ) | 2,424 | (1,688 | ) | 736 | 4,957 | (1,339 | ) | 3,618 | 3,832 | (9,744 | ) | (5,912 | ) | |||||||||||||||||||||||||||
Natural gas collars | 14,065 | — | 14,065 | 21,682 | — | 21,682 | |||||||||||||||||||||||||||||||||||||||
Oil collars | 12,290 | — | 12,290 | 57,716 | — | 57,716 | 27,411 | (1,180 | ) | 26,231 | 6,296 | (1,247 | ) | 5,049 | |||||||||||||||||||||||||||||||
Natural gas basis differential swaps | — | (14,964 | ) | (14,964 | ) | 2,093 | (475 | ) | 1,618 | — | (1,599 | ) | (1,599 | ) | — | (1,268 | ) | (1,268 | ) | ||||||||||||||||||||||||||
Total non-hedge instruments | 56,721 | (28,830 | ) | 27,891 | 97,958 | (2,894 | ) | 95,064 | |||||||||||||||||||||||||||||||||||||
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
Total derivative instruments | 56,893 | (83,713 | ) | (26,820 | ) | 214,269 | (8,525 | ) | 205,744 | 46,010 | (5,605 | ) | 40,405 | 40,252 | (12,259 | ) | 27,993 | ||||||||||||||||||||||||||||
Less: | |||||||||||||||||||||||||||||||||||||||||||||
Netting adjustments (1) | 32,873 | (32,873 | ) | — | 5,137 | (5,137 | ) | — | 2,977 | (2,977 | ) | — | 10,627 | (10,627 | ) | — | |||||||||||||||||||||||||||||
Current portion asset (liability) | 18,226 | (20,677 | ) | (2,451 | ) | 51,412 | — | 51,412 | 42,516 | (436 | ) | 42,080 | 12,840 | (1,505 | ) | 11,335 | |||||||||||||||||||||||||||||
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
$ | 5,794 | $ | (30,163 | ) | $ | (24,369 | ) | $ | 157,720 | $ | (3,388 | ) | $ | 154,332 | $ | 517 | $ | (2,192 | ) | $ | (1,675 | ) | $ | 16,785 | $ | (127 | ) | $ | 16,658 | ||||||||||||||||
|
|
|
|
|
|
(1) | Amounts represent the impact of |
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (loss) (“AOCI”), which is later transferred to earnings when the hedged transaction occurs. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged, and is included in gain (loss) from oil and natural gas hedging activities in the consolidated statements of operations. If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting is discontinued and the gain or loss reported in AOCI is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting is discontinued. The gain or loss associated with the discontinued hedges remains in AOCI and is reclassified into income as the hedged transactions occur.
Gains and losses associated with cash flow hedges are summarized below:
Year ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Amount of gain (loss) recognized in AOCI (effective portion) | ||||||||||||
Oil swaps | $ | (84,284 | ) | $ | 171,095 | $ | (136,242 | ) | ||||
Natural gas swaps | — | (1,495 | ) | 1,682 | ||||||||
Income taxes | 32,601 | (65,602 | ) | 52,048 | ||||||||
$ | (51,683 | ) | $ | 103,998 | $ | (82,512 | ) | |||||
Amount of gain (loss) reclassified from AOCI in income (effective portion)(1) | ||||||||||||
Oil swaps | $ | 13,289 | $ | (76,921 | ) | $ | (25,963 | ) | ||||
Natural gas swaps | 7,638 | (7,837 | ) | 5,384 | ||||||||
Income taxes | (8,095 | ) | 32,784 | 7,960 | ||||||||
$ | 12,832 | $ | (51,974 | ) | $ | (12,619 | ) | |||||
Amount of gain (loss) recognized in income (ineffective portion)(1) | ||||||||||||
Oil swaps | $ | (1,524 | ) | $ | 11,520 | $ | (9,201 | ) | ||||
Natural gas swaps | — | (3,179 | ) | 1,640 | ||||||||
$ | (1,524 | ) | $ | 8,341 | $ | (7,561 | ) | |||||
During the fourth quarter of 2008, we determined that our natural gas swaps are no longer expected to be highly effective, primarily due to the increased volatility in the basis differentials between the contract price and the indexed price at the point of sale. As a result, we discontinued hedge accounting and applied mark-to-market accounting treatment to all outstanding natural gas swaps. The change in fair value related to these instruments, after hedge accounting was discontinued, is recorded immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. In the past, a portion of the change in fair value would have been deferred through other comprehensive income (loss), and the ineffective portion would have been included in gain (loss) from oil and natural gas hedging activities, which is a component of revenue.
In addition, during the fourth quarter of 2008, we early settled oil and natural gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32,589. During the first quarter of 2009, we early settled additional natural gas swaps with original settlement dates from May through October of 2009 for proceeds of $9,522. During the second quarter of 2009, we early settled additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102,352. Certain swaps that were early settled had previously been accounted for as cash flow hedges. As of December 31, 2009 and 2008, accumulated other comprehensive income included $83,442 and $23,662, respectively, of deferred gains related to discontinued cash flow hedges that will be recognized as a gain from oil and natural gas hedging activities when the hedged production is sold.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)
(Dollars in thousands, unless otherwise noted)
Gains of $22,153 associated with derivatives for which hedge accounting had previously been discontinuedDerivative settlements outstanding were reclassified into earnings during the year endedas follows at December 31, 2009 as the hedged production was sold. There were no gains or losses associated with the discontinuance of hedge accounting treatment during the years ended December 31, 2008 and 2007. Gain (loss) from oil and natural gas hedging activities, which is a component of total revenues in the consolidated statements of operations, is comprised of the following:31:
Year ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
Oil derivatives | ||||||||||||
Reclassification adjustment for hedge gains (losses) included in net loss | $ | 13,289 | $ | (76,921 | ) | $ | (25,963 | ) | ||||
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting | (1,524 | ) | 11,520 | (9,201 | ) | |||||||
Natural gas derivatives | ||||||||||||
Reclassification adjustment for hedge gains (losses) included in net loss | 7,638 | (7,837 | ) | 5,384 | ||||||||
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting | — | (3,179 | ) | 1,640 | ||||||||
$ | 19,403 | $ | (76,417 | ) | $ | (28,140 | ) | |||||
Based upon market prices at December 31, 2009 and assuming no future change in the market, we expect to reclassify $16,146 of losses in accumulated other comprehensive income to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of December 31, 2009 are expected to be settled by December 2011.
The changes in fair value and settlement of derivative contracts that do not qualify or have not been designated as hedges are recognized as non-hedge derivative gains (losses). All non-hedge derivative contracts outstanding at December 31, 2009 are expected to be settled by December 2011. Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following:
Year ended December 31, | |||||||||||
2009 | 2008 | 2007 | |||||||||
Change in fair value of non-qualified commodity price swaps | $ | (79,480 | ) | $ | 9,077 | $ | (24,416 | ) | |||
Change in fair value of non-designated costless collars | (53,044 | ) | 79,398 | — | |||||||
Change in fair value of natural gas basis differential contracts | (16,582 | ) | 1,079 | 1,385 | |||||||
Receipts from (payments on) settlement of non-qualified commodity price swaps | 116,445 | 20,290 | — | ||||||||
Receipts from (payments on) settlement of non-designated costless collars | 49,019 | 11,127 | — | ||||||||
Receipts from (payments on) settlement of natural gas basis differential contracts | (5,189 | ) | 5,970 | (750 | ) | ||||||
$ | 11,169 | $ | 126,941 | $ | (23,781 | ) | |||||
Derivative settlements receivable of $5,977 and $15,315 were included in accounts receivable at December 31, 2009 and 2008, respectively. Derivative settlements payable of $1,739 and $0 were included in accounts payable and accrued liabilities at December 31, 2009 and 2008, respectively.
2012 | 2011 | |||||||
Derivative settlements receivable included in accounts receivable | $ | 8,013 | $ | 449 | ||||
Derivative settlements payable included in accounts payable and accrued liabilities | $ | 41 | $ | 5,042 |
We have no Level 1 assets or liabilities as of December 31, 2009.2012 or 2011. Our derivative contracts classified as Level 2 are valued using NYMEX forward commodity price curves and quotations provided by price index developers such as Platts and Oil Price Information Service.Platts. In certain less liquid markets, forward prices are not as readily available. In these circumstances, commodity swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. Due to unavailability of observable volatility data input, the fair value measurement of all our collars has been categorized as Level 3.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)
(Dollars in thousands, unless otherwise noted)
The fair value hierarchy for our financial assets and liabilities is shown by the following table:
As of December 31, 2009 | As of December 31, 2008 | As of December 31, 2012 | As of December 31, 2011 | ||||||||||||||||||||||||||||||||||||||||||||
Derivative assets | Derivative liabilities | Net assets (liabilities) | Derivative assets | Derivative liabilities | Net assets (liabilities) | Derivative assets | Derivative liabilities | Net assets (liabilities) | Derivative assets | Derivative liabilities | Net assets (liabilities) | ||||||||||||||||||||||||||||||||||||
Significant other observable inputs (Level 2) | $ | 30,538 | $ | (83,713 | ) | $ | (53,175 | ) | $ | 134,666 | $ | (8,525 | ) | $ | 126,141 | $ | 18,599 | $ | (4,425 | ) | $ | 14,174 | $ | 33,956 | $ | (11,012 | ) | $ | 22,944 | ||||||||||||||||||
Significant unobservable inputs (Level 3) | 26,355 | — | 26,355 | 79,603 | — | 79,603 | 27,411 | (1,180 | ) | 26,231 | 6,296 | (1,247 | ) | 5,049 | |||||||||||||||||||||||||||||||||
Netting adjustments (1) | (32,873 | ) | 32,873 | — | (5,137 | ) | 5,137 | — | (2,977 | ) | 2,977 | — | (10,627 | ) | 10,627 | — | |||||||||||||||||||||||||||||||
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||
$ | 24,020 | $ | (50,840 | ) | $ | (26,820 | ) | $ | 209,132 | $ | (3,388 | ) | $ | 205,744 | $ | 43,033 | $ | (2,628 | ) | $ | 40,405 | $ | 29,625 | $ | (1,632 | ) | $ | 27,993 | |||||||||||||||||||
|
|
|
|
|
|
(1) | Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. |
Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at December 31 were:
Year ended December 31, | ||||||||
Net derivative assets (liabilities) | 2009 | 2008 | ||||||
Beginning balance | $ | 79,603 | $ | 172 | ||||
Total realized and unrealized gains (losses) included in non-hedge derivative gains (losses) | (3,939 | ) | 92,250 | |||||
Purchases, issuances, and settlements | (49,309 | ) | (12,819 | ) | ||||
Ending balance | 26,355 | 79,603 | ||||||
The amount of total gains (losses) for the period included in non-hedge derivative gains (losses) attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date | $ | (1,777 | ) | $ | 79,498 | |||
For the year ended December 31, | ||||||||
Net derivative assets | 2012 | 2011 | ||||||
Beginning balance | $ | 5,049 | $ | 1,509 | ||||
Realized and unrealized gains included in “Non-hedge derivative gains” | 31,411 | 4,790 | ||||||
Settlements received | (10,229 | ) | (1,250 | ) | ||||
|
|
|
| |||||
Ending balance | $ | 26,231 | $ | 5,049 | ||||
|
|
|
| |||||
Gains relating to assets still held at the reporting date included in “Non-hedge derivative gains” for the period | $ | 21,534 | $ | 5,049 | ||||
|
|
|
|
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements
(dollars in thousands, unless otherwise noted)
Fair value of other financial instruments
The carrying values of items comprising current assets and current liabilities other than derivatives, approximate fair values due to the short-term maturities of these instruments. The carrying value for long-term debt at December 31, 20092012 and 20082011 approximates fair value because substantially all debt carries variablethe rates are comparable to those at which we could currently borrow under similar terms. The carrying value and estimated market rates. Based on market prices,value of our Senior Notes at December 31, 2009, the fair value of the 8 1/2% Senior Notes2012 and 8 7/8% Senior Notes, which2011 were carried at $325,000 and $322,877, respectively, was $281,125 and $281,125, respectively. Based on market prices, at December 31, 2008, the fair value of the 8 1/2% Senior Notes and 8 7/8% Senior Notes, which were carried at $325,000 and $322,675, respectively, was $73,125 and $73,125, respectively.as follows:
December 31, 2012 | December 31, 2011 | |||||||||||||||
Carrying value | Estimated fair value | Carrying value | Estimated fair value | |||||||||||||
8.875% Senior Notes due 2017 | $ | — | $ | — | $ | 323,342 | $ | 326,625 | ||||||||
9.875% Senior Notes due 2020 | 294,031 | 341,250 | 293,559 | 322,500 | ||||||||||||
8.25% Senior Notes due 2021 | 400,000 | 434,000 | 400,000 | 402,400 | ||||||||||||
7.625% Senior Notes due 2022 | 556,631 | 574,750 | — | — | ||||||||||||
|
|
|
|
|
|
|
| |||||||||
$ | 1,250,662 | $ | 1,350,000 | $ | 1,016,901 | $ | 1,051,525 | |||||||||
|
|
|
|
|
|
|
|
Fair value amounts have been estimated using availablebased on quoted market information.prices. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements—(Continued)statements
(Dollarsdollars in thousands, unless otherwise noted)
Concentrations of credit risk
Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. We do not require collateral or other security to support the derivative instruments subject to credit risk, however, counterparties to our derivative instrumentscontracts have been executed with the institutions that are affiliates of our lenders.lenders, and we believe the credit risks associated with all of these institutions are acceptable. At December 31, 2009,2012, we had significant commodity derivative net asset balances outstanding with the following counterparties:
Counterparty | Fair Value(1) | ||
Credit Agricole Corporate and Investment Bank | $ | 14,010 | |
Bank of Oklahoma, N.A | 9,659 | ||
Other | 151 | ||
$ | 23,820 | ||