Chesapeake Energy 10-K 2008
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the Fiscal Year Ended December 31, 2007
Commission File No. 1-13726
Chesapeake Energy Corporation
(Exact Name of Registrant as Specified in Its Charter)
Registrants telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES x NO ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. YES ¨ NO x
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 x NO ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants 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.
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 our common stock held by non-affiliates on June 29, 2007 was approximately $12.1 billion. At February 26, 2008, there were 514,009,781 shares of our $0.01 par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2008 Annual Meeting of Shareholders are incorporated by reference in Part III.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
2007 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
We are the third largest independent producer of natural gas in the United States (first among independents). We own interests in approximately 38,500 producing oil and natural gas wells that are currently producing approximately 2.2 billion cubic feet equivalent, or bcfe, per day, 92% of which is natural gas. Our strategy is focused on discovering, acquiring and developing conventional and unconventional natural gas reserves onshore in the U.S., east of the Rocky Mountains.
Our most important operating area has historically been the Mid-Continent region of Oklahoma, Arkansas, southwestern Kansas and the Texas Panhandle. At December 31, 2007, 47% of our estimated proved oil and natural gas reserves were located in the Mid-Continent region. During the past five years, we have also built significant positions in various conventional and unconventional plays in the Fort Worth Basin in north-central Texas; the Appalachian Basin, principally in West Virginia, eastern Kentucky, eastern Ohio, Pennsylvania and southern New York; the Permian and Delaware Basins of West Texas and eastern New Mexico; the Ark-La-Tex area of East Texas and northern Louisiana; and the South Texas and Texas Gulf Coast regions. We have established a top-three position in nearly every major unconventional play onshore in the U.S. east of the Rockies, including the Barnett Shale, the Arkansas Fayetteville Shale, the Appalachian Basin Devonian and Marcellus Shales, the Arkoma and Ardmore Basin Woodford Shale in Oklahoma, the Delaware Basin Barnett and Woodford Shales in West Texas, and the Alabama Conasauga and Chattanooga Shales.
As of December 31, 2007, we had 10.879 trillion cubic feet equivalent, or tcfe, of proved reserves, of which 93% were natural gas and all of which were onshore. During 2007, we produced an average of 1.957 bcfe per day, a 23% increase over the 1.585 bcfe per day produced in 2006. We replaced our 714 bcfe of production with an internally estimated 2.637 tcfe of new proved reserves for a reserve replacement rate of 369%. Reserve replacement through the drillbit was 2.468 tcfe, or 346% of production (including 1.248 tcfe of positive performance revisions, of which 1.207 tcfe relates to infill drilling and increased density locations, and 97 bcfe of positive revisions resulting from oil and natural gas price increases between December 31, 2006 and December 31, 2007), and reserve replacement through acquisitions was 377 bcfe, or 53% of production. During 2007, we divested 208 bcfe of proved reserves. As a result, our proved reserves grew by 21% during 2007, from 9.0 tcfe to 10.9 tcfe. Of our 10.9 tcfe of proved reserves, 64% were proved developed reserves.
During 2007, Chesapeake continued the industrys most active drilling program and drilled 1,992 gross (1,695 net) operated wells and participated in another 1,679 gross (224 net) wells operated by other companies. The companys drilling success rate was 99% for company-operated wells and 97% for non-operated wells. Also during 2007, we invested $4.3 billion in operated wells (using an average of 140 operated rigs) and $708 million in non-operated wells (using an average of 105 non-operated rigs). Total costs incurred in oil and natural gas acquisition, exploration and development activities during 2007, including seismic, unproved properties, leasehold, capitalized interest and internal costs, non-cash tax basis step-up and asset retirement obligations, were $7.6 billion.
Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118 and our main telephone number at that location is (405) 848-8000. We make available free of charge on our website at www.chk.com our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. References to us, we and our in this report refer to Chesapeake Energy Corporation together with its subsidiaries.
Since our inception in 1989, Chesapeakes goal has been to create value for investors by building one of the largest onshore natural gas resource bases in the United States. For the past ten years, our strategy to accomplish this goal has been to focus onshore in the U.S. east of the Rockies, where we believe we can generate the most attractive risk adjusted returns. In building our industry-leading resource base during the period from 1998 to 2007, we integrated an aggressive and technologically-advanced drilling program with an active property consolidation program focused on small to medium-sized corporate and property acquisitions. During the past two years, we have shifted our strategy from drilling inventory capture to drilling inventory conversion. In doing so, we have de-emphasized acquisitions of proved properties while further emphasizing our industry-leading drilling program and converting our substantial backlog of drilling opportunities into proved developed producing reserves. Key elements of this business strategy are further explained below.
Grow through the Drillbit. We believe that our most distinctive characteristic is our commitment and ability to grow production and reserves through the drillbit. We are currently utilizing 138 operated drilling rigs and 77 non-operated drilling rigs to conduct the most active drilling program in the U.S. We are active in most of the unconventional plays in the U.S. east of the Rockies, where we drill more horizontal wells than any other company in the industry. For the past ten years, we have been actively investing in leasehold, 3-D seismic information and human capital to take advantage of the favorable drilling economics that exist today. We are one of the few large-cap independent oil and natural gas companies that have been able to consistently increase production, which we have successfully achieved for the past 18 consecutive years and 26 consecutive quarters. We believe the key elements of the success and scale of our drilling programs have been our recognition earlier than most of our competitors that (i) oil and natural gas prices were likely to move structurally higher for an extended period, (ii) new horizontal drilling and completion techniques would enable development of previously uneconomic natural gas reservoirs and (iii) various shale formations could be recognized and developed as potentially prolific natural gas reservoirs rather than just as sources of natural gas. In response to our early recognition of these trends, we have proactively hired thousands of new employees and have built the nations largest onshore leasehold and 3-D seismic inventories, the building blocks of a successful large-scale drilling program and the foundation of value creation in our industry.
Control Substantial Land and Drilling Location Inventories. After we identified the trends discussed above, we initiated a plan to build and maintain the largest inventory of onshore drilling opportunities in the U.S. Anticipating an increase in commodity prices and recognizing that better horizontal drilling and completion technologies when applied to various new shale plays would likely create a unique opportunity to capture decades worth of drilling opportunities, we embarked on a very aggressive lease acquisition program which we have referred to as the land grab. We believed that the winner of the land grab would enjoy a distinctive competitive advantage for decades to come as other companies would be locked out of the best new shale plays in the U.S. We believe that we have executed our land grab strategy with particular distinction. We now own approximately 13 million net acres of leasehold in the U.S. and have identified more than 36,300 drilling opportunities on this leasehold. We believe this deep backlog of drilling, more than ten years worth at current drilling levels, provides unusual confidence and transparency into our future growth capabilities.
Develop Proprietary Technological Advantages. In addition to our industry-leading leasehold position, we have developed a number of proprietary technological advantages. First, we have acquired what we believe is the nations largest inventory of three-dimensional (3-D) seismic information. Possessing this 3-D inventory enables us to image deep reservoirs of natural gas that might otherwise remain undiscovered and to drill our horizontal wells more accurately inside the targeted shale formation. In addition, we have developed an industry-leading information-gathering program that gives us proprietary insights into new plays and competitor activity. As a result of our initiatives, we now produce approximately 4% of the nations natural gas, drill 8% of its wells and participate in almost an equal number of wells drilled by others. Consequently, we believe that we receive drilling information on 20-25% of the wells drilled in areas in which we are focused. By gathering this information on a real-time basis, then quickly assimilating and analyzing the information, we are able to react
quickly to opportunities that are created through our drilling program and those of our competitors. Finally, we have recently constructed a unique state-of-the-art Reservoir Technology Center (RTC) in Oklahoma City. The RTC enables us to more quickly, accurately and confidentially analyze core data from shale wells and then design fracture stimulation procedures that are designed to work most productively in the shale formations that have been analyzed. We believe the RTC provides a very substantial competitive advantage in developing new shale plays and improving existing shale plays.
Build Regional Scale. We believe one of the keys to success in the natural gas exploration industry is to build significant operating scale in a limited number of operating areas that share many similar geological and operational characteristics. Achieving such scale provides many benefits, the most important of which are superior geoscientific and engineering information, higher per unit revenues, lower per unit operating costs, greater rates of drilling success, higher returns from more easily integrated acquisitions and higher returns on drilling investments. We first began pursuing this focused strategy in the Mid-Continent region ten years ago and we are now the largest natural gas producer, the most active driller and the most active acquirer of leasehold and producing properties in the Mid-Continent. We believe this region, which trails only the Gulf Coast and Rocky Mountains in current U.S. natural gas production, has many attractive characteristics. These characteristics include long-lived natural gas properties with predictable decline curves, multi-pay geological targets that decrease drilling risk and have resulted in a drilling success rate of approximately 98% over the past 18 years, generally lower service costs than in more competitive or more remote basins and a favorable regulatory environment with virtually no federal land ownership. We believe the other areas where we operate possess many of these same favorable characteristics, and our goal is to become or remain a top three natural gas producer in each of our operating areas.
Focus on Low Costs. By minimizing lease operating costs and general and administrative expenses through focused activities and increased scale, we have been able to deliver attractive financial returns through all phases of the commodity price cycle. We believe our low cost structure is the result of managements effective cost-control programs, a high-quality asset base, extensive and competitive services and natural gas processing and transportation infrastructures that exist in our key operating areas. In addition, to control costs and service quality, we have made significant investments in our drilling rig and trucking service operations and in our midstream gathering and compression operations. As of December 31, 2007, we operated approximately 22,400 of our 38,500 wells, which delivered approximately 85% of our daily production volume. This large percentage of operated properties provides us with a high degree of operating flexibility and cost control.
Mitigate Commodity Price Risk. We have used and intend to continue using hedging programs to seek to mitigate the risks inherent in developing and producing oil and natural gas reserves, commodities that are frequently characterized by significant price volatility. We believe this price volatility is likely to continue in the years ahead and that we can use this volatility to our benefit by taking advantage of prices when they reach levels that management believes are either unsustainable for the long-term or provide unusually high rates of return on our invested capital. As of February 21, 2008, we have oil hedges in place covering 94% and 97% of our expected oil production in 2008 and 2009, respectively, and 87% and 54% of our expected natural gas production in 2008 and 2009, respectively, thereby providing price certainty for a substantial portion of our future cash flow.
Maintain an Entrepreneurial Culture. Chesapeake was formed in 1989 with an initial capitalization of $50,000 and fewer than ten employees. Since then, our management team has guided the company through various operational and industry challenges and extremes of oil and natural gas prices to create the largest independent producer of natural gas in the U.S. with 6,400 employees currently and an enterprise value of approximately $36 billion. The company takes pride in its innovative and aggressive implementation of its business strategy and strives to be as entrepreneurial today as it has been in its past. We have maintained an unusually flat organizational structure as we have grown to help ensure that important information travels rapidly through the company and decisions are made and implemented quickly. Our chief executive officer and co-founder, Aubrey K. McClendon, has been in the oil and natural gas industry for 27 years and beneficially owns, as of February 29, 2008, approximately 28.4 million shares of our common stock.
Improve our Balance Sheet. We have made significant progress in improving our balance sheet over the past nine years. From December 31, 1998 through December 31, 2007, we increased our stockholders equity by $12.4 billion through a combination of earnings and common and preferred equity issuances. As of December 31, 2007, our debt as a percentage of total capitalization (total capitalization is the sum of debt and stockholders equity) was 47%, compared to 137% as of December 31, 1998.
We believe that demand for natural gas will continue to increase in the U.S. and around the world as a result of its favorable environmental characteristics and relative abundance, especially when compared to oil, which is in increasingly short supply, and to coal, which has many unfavorable environmental characteristics. Chesapeakes strategy for 2008 is to continue developing our natural gas assets through exploratory and developmental drilling and by selectively acquiring strategic properties in the Mid-Continent and in our other operating areas. We project that our 2008 production will be between 851 bcfe and 861 bcfe, a 19% to 21% increase over 2007 production. We have budgeted $5.9 billion to $6.5 billion for drilling, acreage acquisition, seismic and related capitalized internal costs, which is expected to be funded with operating cash flow based on our current assumptions, our 2008-2009 financial plan and borrowings under our revolving bank credit facility. Our budget is frequently adjusted based on changes in oil and natural gas prices, drilling results, drilling costs and other factors.
Chesapeake focuses its natural gas exploration, development and acquisition efforts in the six operating areas described below.
Mid-Continent. Chesapeakes Mid-Continent proved reserves of 5.122 tcfe represented 47% of our total proved reserves as of December 31, 2007, and this area produced 374 bcfe, or 52%, of our 2007 production. During 2007, we invested approximately $2.1 billion to drill 2,126 (785 net) wells in the Mid-Continent. For 2008, we anticipate spending approximately 38% of our total budget for exploration and development activities in the Mid-Continent region.
Barnett Shale. Chesapeakes Barnett Shale proved reserves represented 2.063 tcfe, or 19%, of our total proved reserves as of December 31, 2007. During 2007, the Barnett Shale assets produced 93 bcfe, or 13%, of our total production. During 2007, we invested approximately $1.3 billion to drill 512 (410 net) wells in the Barnett Shale. For 2008, we anticipate spending approximately 35% of our total budget for exploration and development activities in the Barnett Shale.
Appalachian Basin. Chesapeakes Appalachian Basin proved reserves represented 1.404 tcfe, or 13%, of our total proved reserves as of December 31, 2007. During 2007, the Appalachian assets produced 48 bcfe, or 7%, of our total production. During 2007, we invested approximately $344 million to drill 431 (374 net) wells in the Appalachian Basin. For 2008, we anticipate spending approximately 5% of our total budget for exploration and development activities in the Appalachian Basin.
Permian and Delaware Basins. Chesapeakes Permian and Delaware Basin proved reserves represented 990 bcfe, or 9%, of our total proved reserves as of December 31, 2007. During 2007, the Permian assets produced 65 bcfe, or 9%, of our total production. During 2007, we invested approximately $813 million to drill 253 (107 net) wells in the Permian and Delaware Basins. For 2008, we anticipate spending approximately 12% of our total budget for exploration and development activities in the Permian and Delaware Basins.
Ark-La-Tex. Chesapeakes Ark-La-Tex proved reserves represented 695 bcfe, or 6%, of our total proved reserves as of December 31, 2007. During 2007, the Ark-La-Tex assets produced 56 bcfe, or 8%, of our total production. During 2007, we invested approximately $556 million to drill 259 (176 net) wells in the Ark-La-Tex
region. For 2008, we anticipate spending approximately 4% of our total budget for exploration and development activities in the Ark-La-Tex area.
South Texas and Texas Gulf Coast. Chesapeakes South Texas and Texas Gulf Coast proved reserves represented 605 bcfe, or 6%, of our total proved reserves as of December 31, 2007. During 2007, the South Texas and Texas Gulf Coast assets produced 78 bcfe, or 11%, of our total production. For 2007, we invested approximately $315 million to drill 90 (67 net) wells in the South Texas and Texas Gulf Coast regions. For 2008, we anticipate spending approximately 6% of our total budget for exploration and development activities in the South Texas and Texas Gulf Coast regions.
The following table sets forth the wells we drilled during the periods indicated. In the table, gross refers to the total wells in which we had a working interest and net refers to gross wells multiplied by our working interest.
The following table shows the wells we drilled by area:
At December 31, 2007, we had 289 (132 net) wells in process.
At December 31, 2007, we had interests in approximately 38,500 (21,404 net) producing wells, including properties in which we held an overriding royalty interest, of which 6,900 (3,832 net) were classified as primarily oil producing wells and 31,600 (17,572 net) were classified as primarily natural gas producing wells. Chesapeake operates approximately 22,400 of its 38,500 producing wells. During 2007, we drilled 1,992 (1,695 net) wells and participated in another 1,679 (224 net) wells operated by other companies. We operate approximately 85% of our current daily production volumes.
Production, Sales, Prices and Expenses
The following table sets forth information regarding the production volumes, oil and natural gas sales, average sales prices received, other operating income and expenses for the periods indicated:
Oil and Natural Gas Reserves
The tables below set forth information as of December 31, 2007 with respect to our estimated proved reserves, the associated estimated future net revenue and present value (discounted at an annual rate of 10%) of estimated future net revenue before and after income tax (standardized measure) at such date. Neither the pre-tax present value of estimated future net revenue nor the after-tax standardized measure is intended to represent the current market value of the estimated oil and natural gas reserves we own.
Management uses future net revenue, which is calculated without deducting estimated future income tax expenses, and the present value thereof as one measure of the value of the companys current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While future net revenue and present value are based on prices, costs and discount factors which are consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company.
As of December 31, 2007, our reserve estimates included 3.937 tcfe of reserves classified as proved undeveloped (PUD). Of this amount, approximately 32%, 23% and 25% (by volume) were initially classified as PUDs in 2007, 2006 and 2005, respectively, and the remaining 20% were initially classified as PUDs prior to 2005. Of our proved developed reserves, 904 bcfe are non-producing, which are primarily behind pipe zones in producing wells.
The future net revenue attributable to our estimated proved undeveloped reserves of $12.8 billion at December 31, 2007, and the $4.0 billion present value thereof, have been calculated assuming that we will expend approximately $7.3 billion to develop these reserves. We have projected to incur $2.6 billion in 2008, $2.0 billion in 2009, $1.0 billion in 2010 and $1.7 billion in 2011 and beyond, although the amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, product prices and the availability of capital. Chesapeakes developmental drilling schedules are subject to revision and reprioritization throughout the year, resulting from unknowable factors such as the relative success in an individual developmental drilling prospect leading to an additional drilling opportunity, rig availability, title issues or delays, and the effect that acquisitions may have on prioritizing development drilling plans. We do not believe any of these proved undeveloped reserves are contingent upon installation of additional infrastructure and we are not subject to regulatory approval other than routine permits to drill, which we expect to obtain in the normal course of business.
Chesapeake employed third-party engineers to prepare independent reserve forecasts for approximately 79% of our proved reserves (by volume) at year-end 2007. These are not audits or reviews of internally prepared reserve reports. The estimates of the proved reserves evaluated by third-party engineers were within 99% of the companys own estimates and were used instead of our estimates for booking purposes. The estimates prepared by the independent firms covered approximately 23,000 properties, or 45% of the 50,700 properties included in the 2007 reserve reports. Because, in managements opinion, it would be cost prohibitive for third-party engineers to evaluate all of our wells, we have prepared internal reserve forecasts for approximately 21% of our proved reserves. All estimates were prepared based upon a review of production histories and other geologic, economic, ownership and engineering data we developed. The estimates are not based on any single significant assumption due to the diverse nature of the reserves and there is no significant concentration of proved reserves volume or value in any one well or field. The portion of our estimated proved reserves evaluated by each of our third-party engineering firms as of December 31, 2007 is presented below.
No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission.
Chesapeakes ownership interest used in calculating proved reserves and the associated estimated future net revenue was determined after giving effect to the assumed maximum participation by other parties to our farmout and participation agreements. The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for oil and natural gas production sold subsequent to December 31, 2007. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond Chesapeakes control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil and natural gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. A change in price of $0.10 per mcf for natural gas and $1.00 per barrel for oil would result in a change in the December 31, 2007 present value of estimated future net revenue of our proved reserves of approximately $390 million and $56 million, respectively. The estimated future net revenue used in this analysis does not include the effects of future income taxes or hedging. The foregoing uncertainties are particularly true as to proved undeveloped reserves, which are inherently less certain than proved developed reserves and which comprise a significant portion of our proved reserves.
The companys estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2007, 2006 and 2005, and the changes in quantities and standardized measure of such reserves for each of the three years then ended, are shown in Note 11 of the notes to the consolidated financial statements included in Item 8 of this report.
Development, Exploration, Acquisition and Divestiture Activities
The following table sets forth historical cost information regarding our development, exploration, acquisition and divestiture activities during the periods indicated:
Our development costs included $1.5 billion, $1.2 billion and $671 million in 2007, 2006 and 2005, respectively, related to properties carried as proved undeveloped locations in the prior years reserve reports.
A summary of our exploration and development, acquisition and divestiture activities in 2007 by operating area is as follows:
The following table sets forth as of December 31, 2007 the gross and net acres of both developed and undeveloped oil and natural gas leases which we hold. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our options to acquire additional leasehold which have not been exercised.
Chesapeake Energy Marketing, Inc., a wholly owned subsidiary of Chesapeake Energy Corporation, provides marketing services including commodity price structuring, contract administration and nomination services for Chesapeake and its partners. We attempt to enhance the value of our natural gas production by aggregating natural gas to be sold to natural gas marketers and pipelines. This aggregation allows us to attract larger, creditworthy customers that in turn assist in maximizing the prices received for our production.
Our oil production is generally sold under market sensitive or spot price contracts. The revenue we receive from the sale of natural gas liquids is included in oil sales. Our natural gas production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. By the terms of the percentage-of-proceeds contracts, we receive a percentage of the resale price received by the purchaser for sales of residue gas and natural gas liquids recovered after transportation and processing of our natural gas. These purchasers sell the residue gas and natural gas liquids based primarily on spot market prices. Under percentage-of-index contracts, the price per mmbtu we receive for our natural gas is tied to indexes published in Inside FERC or Gas Daily. Although exact percentages vary daily, as of February 2008, approximately 80% of our natural gas production was sold under short-term contracts at market-sensitive prices.
During 2007, sales to Eagle Energy Partners I, L.P. (Eagle) of $1.1 billion accounted for 15% of our total revenues (excluding gains (losses) on derivatives). In 2007, we sold our 33% limited partnership interest in Eagle Energy Partners I, L.P., which we first acquired in 2003, for proceeds of $124 million and a gain of $83 million. Management believes that the loss of this customer would not have a material adverse effect on our results of operations or our financial position. No other customer accounted for more than 10% of total revenues (excluding gains (losses) on derivatives) in 2007.
Chesapeake Energy Marketing, Inc. is a reportable segment under SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. See Note 8 of the notes to our consolidated financial statements in Item 8.
Natural Gas Gathering
Chesapeake invests in gathering and processing facilities to complement our oil and natural gas operations in regions where we have significant production. By doing so, we are better able to manage the value received for and the costs of, gathering, treating and processing natural gas through our ownership and operation of these facilities. We own and operate gathering systems in 13 states throughout the Mid-Continent and Appalachian
regions. These systems are designed primarily to gather company production for delivery into major intrastate or interstate pipelines and are comprised of approximately 8,900 miles of gathering lines, treating facilities and processing facilities which provide service to approximately 11,000 wells.
We are currently in the process of forming a private partnership to own a non-operating interest in our midstream natural gas assets outside of Appalachia, which consist primarily of natural gas gathering systems and processing assets. We anticipate raising $1 billion for a minority interest in the partnership and closing the transaction in the first half of 2008.
Securing available rigs is an integral part of the exploration process and therefore owning our own drilling company is a strategic advantage for Chesapeake. In 2001, Chesapeake formed its 100% owned drilling rig subsidiary, Nomac Drilling Corporation, with an investment of $26 million to build and refurbish five drilling rigs. As of December 31, 2007, Chesapeake had invested approximately $675 million to build or acquire 80 drilling rigs and to initiate the construction of one additional rig. During 2006 and 2007, we sold 78 rigs for $613 million and subsequently leased back the rigs through 2017. The drilling rigs have depth ratings between 3,000 and 25,000 feet and range in drilling horsepower from 350 to 2,000. These drilling rigs are currently operating in Oklahoma, Texas, Arkansas, Louisiana and Appalachia. The companys drilling rig fleet should reach 84 rigs by mid-year 2008, which would rank Chesapeake as the fifth largest drilling rig contractor in the U.S.
In 2006, Chesapeake expanded its service operations by acquiring two privately-owned oilfield trucking service companies. We now own one of the largest oilfield and heavy haul transportation companies in the industry. Our trucking business is utilized primarily to transport drilling rigs for both Chesapeake and third parties. Through this ownership we are better able to manage the movement of our rigs. As of December 31, 2007, our fleet included 178 trucks and 13 cranes which mainly service the Mid-Continent, Barnett Shale and Appalachian regions.
During the past few years Chesapeake has expanded its compression business. Our wholly-owned subsidiary, MidCon Compression, L.L.C., operates wellhead and system compressors to facilitate the transportation of our natural gas production. In a series of transactions in 2007, MidCon sold a significant portion of its compressor fleet, consisting of 1,199 compressors, for $188 million and entered into a master lease agreement. These transactions were recorded as sales and operating leasebacks. Over the next 18 months, 365 new compressors are on order for $175 million, and we intend to simultaneously enter into sale/leaseback transactions with a financial counterparty as the compressors are delivered.
We utilize hedging strategies to hedge the price of a portion of our future oil and natural gas production and to manage interest rate exposure. See Item 7A-Quantitative and Qualitative Disclosures About Market Risk.
General. All of our operations are conducted onshore in the United States. The U.S. oil and natural gas industry is regulated at the federal, state and local levels, and some of the laws, rules and regulations that govern our operations carry substantial penalties for noncompliance. These regulatory burdens increase our cost of doing business and, consequently, affect our profitability.
Regulation of Oil and Natural Gas Operations. Our exploration and production operations are subject to various types of regulation at the U.S. federal, state and local levels. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Very few of our oil and natural gas leases are located on federal lands. Other activities subject to regulation are:
Our operations are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells that may be drilled in a particular area) and the unitization or pooling of oil and natural gas properties. In this regard, some states, such as Oklahoma, allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas and New Mexico, rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to fully develop a project if the operator owns less than 100% of the leasehold. 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 certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil and natural gas we can produce and to limit the number of wells and the locations at which we can drill.
Chesapeake operates a number of natural gas gathering systems. The U.S. Department of Transportation and certain state agencies regulate the safety and operating aspects of the transportation and storage activities of these facilities. There is currently no price regulation of the companys sales of oil, natural gas liquids and natural gas, although, governmental agencies may elect in the future to regulate certain sales.
We do not anticipate that compliance with existing laws and regulations governing exploration, production and natural gas gathering will have a material adverse effect upon our capital expenditures, earnings or competitive position.
Environmental, Health and Safety Regulation. The business operations of the company and its ownership and operation of real property are subject to various federal, state and local environmental, health and safety laws and regulations pertaining to the discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees, or otherwise relating to pollution, preservation, remediation or protection of human health and safety, natural resources, wildlife or the environment. We must take into account the cost of complying with environmental regulations in planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities. In most instances, the regulatory frameworks relate to the handling of drilling and production materials, the disposal of drilling and production wastes, and the protection of water and air. In addition, our operations may require us to obtain permits for, among other things,
Under federal, state and local laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations at contaminated areas, or to perform remedial well plugging operations or response actions to reduce the risk of future contamination. Federal and state laws, including the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered responsible for response actions to address the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and persons that disposed of or arranged for the disposal of hazardous substances at the site. The Environmental Protection Agency, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such actions. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements.
Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.
We have made and will continue to make expenditures to comply with environmental, health and safety regulations and requirements. These are necessary business costs in the oil and natural gas industry. Although we are not fully insured against all environmental, health and safety risks, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental, health and safety laws and regulations, as well as claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities, including civil and criminal penalties, to Chesapeake. We believe we are in material compliance with existing environmental, health and safety regulations, and that, absent the occurrence of an extraordinary event, the effect of which cannot be predicted, any noncompliance will not have a material adverse effect on our business, financial position and results of operations.
Chesapeake recorded income tax expense of $890 million in 2007 compared to income tax expense of $1.252 billion in 2006 and $545 million in 2005. Of the $362 million decrease in 2007, $347 million was the result of the decrease in net income before taxes and $15 million was the result of a decrease in the effective tax rate. Our effective income tax rate was 38% in 2007 compared to 38.5% in 2006 and 36.5% in 2005. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences between our accounting for certain revenue or expense items and their corresponding treatment for income tax purposes. We expect our effective income tax rate to be 38.5% in 2008.
At December 31, 2007, Chesapeake had federal income tax net operating loss (NOL) carryforwards of approximately $238 million and approximately $29 million of percentage depletion carryforwards. We also had approximately $5 million of alternative minimum tax (AMT) NOL carryforwards available as a deduction against future AMT income. The NOL carryforwards expire from 2019 through 2026. The value of the remaining carryforwards depends on the ability of Chesapeake to generate taxable income. In addition, for AMT purposes, only 90% of AMT income in any given year may be offset by AMT NOLs.
The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.
In the event of an ownership change (as defined for income tax purposes), Section 382 of the Code imposes an annual limitation on the amount of a corporations taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the company multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains (as defined in the Code) inherent in the assets sold. Certain NOLs acquired through various acquisitions are also subject to limitations. The following table summarizes our net operating losses as of December 31, 2007 and any related limitations:
As of December 31, 2007, we do not believe that an ownership change has occurred. Future equity transactions by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs. Following an ownership change, the amount of Chesapeakes NOLs available for use each year will depend upon future events that cannot currently be predicted and upon interpretation of complex rules under Treasury regulations. If less than the full amount of the annual limitation is utilized in any given year, the unused portion may be carried forward and may be used in addition to successive years annual limitation.
We expect to utilize our NOL carryforwards and other tax deductions and credits to offset taxable income in the future. However, there is no assurance that the Internal Revenue Service will not challenge these carryforwards or their utilization.
In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxesan interpretation of FASB Statement No. 109. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 became effective for fiscal years beginning after December 15, 2006.
Chesapeake adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, Chesapeake recognized a $7 million liability for accrued interest associated with uncertain tax positions which was accounted for as a reduction in the January 1, 2007 balance of retained earnings, net of tax. At the date of adoption, we had approximately $142 million of unrecognized tax benefits related to alternative minimum tax (AMT) associated with uncertain tax positions. As of December 31, 2007, the amount of unrecognized tax benefits related to AMT associated with uncertain tax positions was $133 million. If these unrecognized tax benefits are disallowed and we are ultimately required to pay additional AMT liabilities, any payments can be utilized as credits against future regular tax liabilities. The uncertain tax positions identified would not have a material effect on the effective tax rate. At December 31, 2007, we had a liability of $5 million for interest related to these same uncertain tax positions. Chesapeake recognizes interest related to uncertain tax positions in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.
Chesapeake files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. With few exceptions, Chesapeake is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2004. The Internal Revenue Service (IRS) completed an examination of Chesapeakes U.S. income tax returns for 2003 and 2004 in September 2007. This examination resulted in
additional AMT liabilities of $9 million. These AMT liabilities can be utilized as credits against future regular tax liabilities. The adjustments in the examination did not result in a material change to our financial position, results of operations or cash flows.
Title to Properties
Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and natural gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Nevertheless, we are involved in title disputes from time to time which result in litigation.
Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, Chesapeake could suffer substantial losses due to 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 investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
Chesapeake maintains a $50 million control of well policy that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. There is no assurance that this insurance will be adequate to cover all losses or exposure to liability. Chesapeake also carries a $300 million comprehensive general liability umbrella policy and a $100 million pollution liability policy. We provide workers compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks.
Chesapeake owns an office complex in Oklahoma City and we are in the process of constructing additional corporate facilities in Oklahoma City and Charleston, West Virginia. We also own or lease various field offices in the following locations:
Chesapeake had approximately 6,200 employees as of December 31, 2007, which includes 2,271 employed by our service operations companies. As a result of the CNR acquisition, we assumed a collective bargaining agreement with the United Steel Workers of America (USWA) which expired effective December 1, 2006, covering approximately 135 of our field employees in West Virginia and Kentucky. We continued to operate under the terms of the collective bargaining agreement while negotiating with the USWA. Contract negotiations began in October 2006 and have been mediated by the Federal Mediation and Conciliation Service. On May 4, 2007, we presented the USWA leadership our last, best and final offer. On December 7, 2007, the USWA membership voted to reject our offer and, effective February 1, 2008 we implemented the terms of our offer with certain minor clarifications. There have been no strikes, work stoppages or slowdowns since the expiration of the contract, although no assurances can be given that such actions will not occur.
Glossary of Oil and Natural Gas Terms
The terms defined in this section are used throughout this Form 10-K.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet of natural gas equivalent.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bbtu. One billion British thermal units.
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.
Commercial Well; Commercially Productive Well. An oil and natural gas well which produces oil and natural gas in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Conventional Reserves. Oil and natural gas occurring as discrete accumulations in structural and stratigraphic traps.
Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Hole; Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Full-Cost Pool. The full-cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full-cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal Wells. Wells which are drilled at angles greater than 70 degrees from vertical.
Infill Drilling. Drilling wells between established producing wells on a lease; a drilling program to reduce the spacing between wells in order to increase production and/or recovery of in-place hydrocarbons from the lease.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
Mbtu. One thousand btus.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of natural gas equivalent.
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
Mmbtu. One million btus.
Mmcf. One million cubic feet.
Mmcfe. One million cubic feet of natural gas equivalent.
Net Acres or Net Wells. The sum of the fractional working interests owned in gross acres or gross wells.
NYMEX. New York Mercantile Exchange.
Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and gas reserves.
Present Value or PV-10. When used with respect to oil and natural gas reserves, present value or PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
Productive Well. A well that is producing oil or natural gas or that is capable of production.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production responses that increased recovery will be achieved.
Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
Proved Undeveloped Location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
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. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves may not include estimates attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Reserve Replacement. Calculated by dividing the sum of reserve additions from all sources (revisions, extensions, discoveries and other additions and acquisitions) by the actual production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table located in Note 11 of the notes to our consolidated financial statements. In calculating reserve replacement, we do not use unproved reserve quantities or proved reserve additions attributable to less than wholly owned consolidated entities or investments accounted for using the equity method. Management uses the reserve replacement ratio as an indicator of the companys ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.
Royalty Interest. An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.
Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures).
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.
Standardized Measure of Discounted Future Net Cash Flows. The discounted future net cash flows relating to proved reserves based on year-end prices, costs and statutory tax rates (adjusted for permanent differences) and a 10-percent annual discount rate.
Tcf. One trillion cubic feet.
Tcfe. One trillion cubic feet of natural gas equivalent.
Unconventional Reserves. Oil and natural gas occurring in regionally pervasive accumulations with low matrix permeability and close association with source rocks.
Undeveloped Acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Unproved Properties. Properties with no proved reserves.
VPP. A volumetric production payment represents an obligation of the purchaser of a property to deliver a specific volume of production, free and clear of all costs, to the seller of the property.
Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Oil and natural gas prices are volatile. A decline in prices could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.
Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for the oil and natural gas we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks is subject to periodic redeterminations based on prices specified by our bank group at the time of redetermination. In addition, we may have ceiling test write-downs in the future if prices fall significantly.
Historically, the markets for oil and natural gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and natural gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond our control, including:
These factors and the volatility of the energy markets 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 revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. Further, oil and natural gas prices do not necessarily move in tandem. Because approximately 93% of our reserves at December 31, 2007 were natural gas reserves, we are more affected by movements in natural gas prices.
Our level of indebtedness may limit our financial flexibility.
As of December 31, 2007, we had long-term indebtedness of approximately $10.950 billion, with $1.950 billion of outstanding borrowings drawn under our revolving bank credit facility. Our long-term indebtedness represented 47% of our total book capitalization at December 31, 2007. As of February 26, 2008, we had approximately $2.899 billion outstanding under our revolving bank credit facility.
Our level of indebtedness and preferred stock affects our operations in several ways, including the following:
We may incur additional debt, including secured indebtedness, or issue additional series of preferred stock in order to develop our properties and make future acquisitions. A higher level of indebtedness and/or additional preferred stock increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.
In addition, our bank borrowing base is subject to periodic redetermination. A lowering of our borrowing base could require us to repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral.
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 development, exploitation, exploration, acquisition and production. We face intense competition from both major and other independent oil and natural gas companies in each of the following areas:
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 and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment.
Significant capital expenditures are required to replace our reserves.
Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, our revolving bank credit facility and debt and equity issuances. 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 revenues 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. 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, debt or equity or other methods of financing on an economic basis to meet these requirements.
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 36% of our total estimated proved reserves (by volume) at December 31, 2007 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. Our reserve estimates reflect that our production rate on producing properties will decline approximately 28% from 2008 to 2009. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.
The actual quantities and present value of our proved reserves may prove to be lower than we have estimated.
This report contains estimates of our proved reserves and the estimated future net revenues from our proved reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development 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.
At December 31, 2007, approximately 36% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. These reserve estimates include the assumption that we will make significant capital expenditures to develop the reserves, including approximately $2.6 billion in 2008. You should be aware that the estimated costs may not be accurate, development may not occur as scheduled and results may not be as estimated.
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. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The December 31, 2007 present value is based on weighted average oil and natural gas wellhead prices of $90.58 per barrel of oil and $6.19 per mcf of natural gas. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
Any changes in consumption by oil and natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows.
The timing of both the production and the expenses from 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 addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and natural gas industry in general will affect the accuracy of the 10% discount factor.
Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.
Our growth during the past few years is due in large part to acquisitions of exploration and production companies, producing properties and undeveloped leasehold. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we pay to acquire oil and natural gas properties may exceed the value we realize.
We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an as is basis with limited remedies for breaches of representations and warranties. When we make entity acquisitions, we may have transferee liability that is not fully indemnified. Our acquisition of Columbia Natural Resources, LLC (CNR) in November 2005 was made subject to claims which are covered in part by the indemnification of a prior owner, NiSource Inc. NiSource and Chesapeake are co-defendants in a class action lawsuit brought by royalty owners in West
Virginia in which the jury returned a verdict in January 2007 awarding plaintiffs $404 million, consisting of $134 million in compensatory damages and $270 million in punitive damages. Although Chesapeake believes its share of damages that might ultimately be awarded in this case will not have a material adverse effect on its results of operations, financial condition or liquidity as a result of the NiSource indemnity and post-trial remedies that may be available, Chesapeake is a defendant in other cases involving acquired companies where it may have no, or only limited, indemnification rights. In any such actions we could incur significant liability.
Exploration and development drilling may not result in commercially productive reserves.
We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. 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 produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
Future price declines may result in a write-down of our asset carrying values.
We utilize the full-cost method of accounting for costs related to our oil and natural gas properties. Under this method, all such costs (for both productive and nonproductive properties) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-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 future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. The full-cost ceiling is evaluated at the end of each quarter using the prices for oil and natural gas at that date, adjusted for the impact of derivatives accounted for as cash flow hedges. A significant decline in oil and natural gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future writedown of capitalized costs and a non-cash charge against future earnings.
Our hedging activities may reduce the realized prices received for our oil and natural gas sales and require us to provide collateral for hedging liabilities.
In order to manage our exposure to price volatility in marketing our oil and natural gas, we enter into oil and natural gas price risk management arrangements for a portion of our expected production. Commodity price hedging may limit the prices we actually realize and therefore reduce oil and natural gas revenues in the future. The fair value of our oil and natural gas derivative instruments outstanding as of December 31, 2007 was a liability of approximately $369 million. In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
All but three of our commodity price risk management counterparties require us to provide assurances of performance in the event that the counterparties mark-to-market exposure to us exceeds certain levels. Most of these arrangements allow us to minimize the potential liquidity impact of significant mark-to-market fluctuations by making collateral allocations from our revolving bank credit facility or directly pledging oil and natural gas properties, rather than posting cash or letters of credit with the counterparties. Future collateral requirements are uncertain, however, and will depend on the arrangements with our counterparties and highly volatile natural gas and oil prices.
Lower oil and natural gas prices could negatively impact our ability to borrow.
Our revolving bank credit facility limits our borrowings to the lesser of the borrowing base and the total commitments (currently both are $3.5 billion). The borrowing base is determined periodically at the discretion of the banks and is based in part on oil and natural gas prices. Additionally, some of our indentures contain covenants limiting our ability to incur indebtedness in addition to that incurred under our revolving bank credit facility. These indentures limit our ability to incur additional indebtedness unless we meet one of two alternative tests. The first alternative is based on our adjusted consolidated net tangible assets (as defined in all of our indentures), which is determined using discounted future net revenues from proved oil and natural gas reserves as of the end of each year. The second alternative is based on the ratio of our adjusted consolidated EBITDA (as defined in the relevant indentures) to our adjusted consolidated interest expense over a trailing twelve-month period. Currently, we are permitted to incur additional indebtedness under both debt incurrence tests. Lower oil and natural gas prices in the future could reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness.
Oil and natural gas drilling and producing operations can be hazardous and may expose us to environmental liabilities.
Oil and natural gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, 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 risks occurs, we could sustain substantial losses as a result of:
There is inherent risk of incurring significant environmental costs and liabilities in our exploration and production operations due to our generation, handling, and disposal of materials, including wastes and petroleum hydrocarbons. We may incur joint and several, strict liability under applicable U.S. federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on, under or from our leased or owned properties, some of which have been used for oil and natural gas exploration and production activities for a number of years, often by third parties not under our control. While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be
adequate to cover casualty losses or liabilities. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.
In addition, studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, may be contributing to warming of the Earths atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases. The U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least nine states in the Northeast and five states in the West including New Mexico have developed initiatives to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The U.S. Environmental Protection Agency is separately considering whether it will regulate greenhouse gases as air pollutants under the existing federal Clean Air Act. Passage of climate control legislation or other regulatory initiatives by Congress or various states in the U.S. or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases including methane or carbon dioxide in areas in which we conduct business could have an adverse effect on our operations and demand for our products.
A portion of our oil and gas production may be subject to interruptions that could temporarily adversely affect our cash flow.
A portion of our regional oil and gas production may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or intentionally as a result of market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.
Information regarding our properties is included in Item 1 and in Note 11 of the notes to our consolidated financial statements included in Item 8 of this report.
We are involved in various disputes incidental to our business operations, including claims from royalty owners regarding volume measurements, post-production costs and prices for royalty calculations. In Tawney, et al. v. Columbia Natural Resources, Inc., Chesapeakes wholly owned subsidiary Chesapeake Appalachia, L.L.C., formerly known as Columbia Natural Resources, LLC (CNR), is a defendant in a class action lawsuit in the Circuit Court of Roane County, West Virginia filed in 2003 by royalty owners. The plaintiffs allege that CNR underpaid royalties by improperly deducting post-production costs, failing to pay royalty on total volumes of natural gas produced and not paying a fair value for the natural gas produced from their leases. The plaintiff class consists of West Virginia royalty owners receiving royalties after July 31, 1990 from CNR. Chesapeake acquired CNR in November 2005, and its seller acquired CNR in 2003 from NiSource Inc. NiSource, a co-defendant in the case, has managed the litigation and indemnified Chesapeake against underpayment claims based on the use of fixed prices for natural gas production sold under certain forward sale contracts and other claims with respect to CNRs operations prior to September 2003.
On January 27, 2007, the Circuit Court jury returned a verdict against the defendants of $404 million, consisting of $134 million in compensatory damages and $270 million in punitive damages. Most of the damages awarded by the jury relate to issues not yet addressed by the West Virginia Supreme Court of Appeals, although in June 2006 that Court ruled against the defendants on two certified questions regarding the deductibility of
post-production expenses. The jury found fraudulent conduct by the defendants with respect to the sales prices used to calculate royalty payments and with respect to the failure of CNR to disclose post-production deductions. On June 28, 2007, the Circuit Court sustained the jury verdict for punitive damages, and on September 27, 2007, it denied all post-trial motions, including defendants motion for judgment as a matter of law, or in the alternative, for a new trial. On December 5, 2007, the Circuit Court entered an order granting defendants motion to stay the judgment pending appeal conditioned upon filing an irrevocable letter of credit in the amount of $50 million. The irrevocable letter of credit was filed January 4, 2008. On January 24, 2008, the defendants filed a Petition for Appeal in the West Virginia Supreme Court of Appeals.
Chesapeake and NiSource maintain CNR acted in good faith and paid royalties in accordance with lease terms and West Virginia law. Chesapeake has established an accrual for amounts it believes will not be indemnified. Should a final nonappealable judgment be entered, Chesapeake believes its share of damages will not have a material adverse effect on its results of operations, financial condition or liquidity.
Chesapeake is subject to other legal proceedings and claims which arise in the ordinary course of business. In our opinion, the final resolution of these proceedings and claims will not have a material adverse effect on the company.
Price Range of Common Stock
Our common stock trades on the New York Stock Exchange under the symbol CHK. The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange:
At February 26, 2008, there were 1,651 holders of record of our common stock and approximately 260,000 beneficial owners.
The following table sets forth the amount of dividends per share declared on Chesapeake common stock during 2007 and 2006:
While we expect to continue to pay dividends on our common stock, the payment of future cash dividends will depend upon, among other things, our financial condition, funds from operations, the level of our capital and development expenditures, our future business prospects, contractual restrictions and any other factors considered relevant by the Board of Directors.
Several of the indentures governing our outstanding senior notes contain restrictions on our ability to declare and pay cash dividends. Under these indentures, we may not pay any cash dividends on our common or preferred stock if an event of default has occurred, if we have not met one of the two debt incurrence tests described in the indentures, or if immediately after giving effect to the dividend payment, we have paid total dividends and made other restricted payments in excess of the permitted amounts. As of December 31, 2007, our coverage ratio for purposes of the debt incurrence test under the relevant indentures was 7.46 to 1, compared to 2.25 to 1 required in our indentures. Our adjusted consolidated net tangible assets exceeded 200% of our total indebtedness, as required by the second debt incurrence test in these indentures, by more than $1.9 billion.
The following table presents information about repurchases of our common stock during the three months ended December 31, 2007:
The following table sets forth selected consolidated financial data of Chesapeake for the years ended December 31, 2007, 2006, 2005, 2004 and 2003. The data are derived from our audited consolidated financial statements revised to reflect the reclassification of certain items. In addition to changes in the annual average prices for oil and natural gas and increased production from drilling activity, significant acquisitions in recent years also impacted comparability between years. See Notes 11 and 13 of the notes to our consolidated financial statements. The table should be read in conjunction with Managements Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this report.
The following table sets forth certain information regarding the production volumes, oil and natural gas sales, average sales prices received, other operating income and expenses for the periods indicated:
We manage our business as three separate operational segments: exploration and production; marketing; and service operations, which is comprised of our wholly owned drilling and trucking operations. We refer you to Note 8 of the notes to our consolidated financial statements appearing in Item 8 of this report, which summarizes by segment our net income and capital expenditures for 2007, 2006 and 2005 and our assets as of December 31, 2007, 2006 and 2005.
We are the third largest producer of natural gas in the United States (first among independents). We own interests in approximately 38,500 producing oil and natural gas wells that are currently producing approximately 2.2 bcfe per day, 92% of which is natural gas. Our strategy is focused on discovering, acquiring and developing conventional and unconventional natural gas reserves onshore in the U.S., east of the Rocky Mountains.
Our most important operating area has historically been in various conventional plays in the Mid-Continent region of Oklahoma, Arkansas, southwestern Kansas and the Texas Panhandle. At December 31, 2007, 47% of our estimated proved oil and natural gas reserves were located in the Mid-Continent region. During the past five years, we have also built significant positions in various conventional and unconventional plays in the Fort Worth Basin in north-central Texas; the Appalachian Basin, principally in West Virginia, eastern Kentucky, eastern Ohio, Pennsylvania and southern New York; the Permian and Delaware Basins of West Texas and eastern New Mexico; the Ark-La-Tex area of East Texas and northern Louisiana; and the South Texas and Texas Gulf Coast regions. We have established a top-three position in nearly every major unconventional play onshore in the U.S. east of the Rockies, including the Barnett Shale, the Arkansas Fayetteville Shale, the Appalachian Basin Devonian and Marcellus Shales, the Arkoma and Ardmore Basins Woodford Shale in Oklahoma, the Delaware Basin Barnett and Woodford Shales in West Texas, and the Alabama Conasauga and Chattanooga Shales.
Oil and natural gas production for 2007 was 714.3 bcfe, an increase of 135.9 bcfe, or 23% over the 578.4 bcfe produced in 2006. We have increased our production for 18 consecutive years and 26 consecutive quarters. During these 26 quarters, Chesapeakes U.S. production has increased 467% for an average compound quarterly growth rate of 7% and an average compound annual growth rate of 30%.
During 2007, Chesapeake continued the industrys most active drilling program and drilled 1,992 gross (1,695 net) operated wells and participated in another 1,679 gross (224 net) wells operated by other companies. The companys drilling success rate was 99% for company-operated wells and 97% for non-operated wells. Also during 2007, we invested $4.3 billion in operated wells (using an average of 140 operated rigs) and $708 million in non-operated wells (using an average of 105 non-operated rigs). Total costs incurred in oil and natural gas acquisition, exploration and development activities during 2007, including seismic, unproved properties, leasehold, capitalized interest and internal costs, non-cash tax basis step-up and asset retirement obligations, were $7.6 billion.
Chesapeake began 2007 with estimated proved reserves of 8.956 tcfe and ended the year with 10.879 tcfe, an increase of 1.923 tcfe, or 21%. During 2007, we replaced 714 bcfe of production with an internally estimated 2.637 tcfe of new proved reserves, for a reserve replacement rate of 369%. Reserve replacement through the drillbit was 2.468 tcfe, or 346% of production and 94% of the total increase (including 1.248 tcfe of positive performance revisions and 97 bcfe of positive revisions resulting from oil and natural gas price increases between December 31, 2006 and December 31, 2007). Reserve replacement through the acquisition of proved reserves was 377 bcfe, or 53% of production and 14% of the total increase. During 2007, we divested 208 bcfe of proved
reserves. Our annual decline rate on producing properties is projected to be 28% from 2008 to 2009, 18% from 2009 to 2010, 14% from 2010 to 2011, 12% from 2011 to 2012 and 10% from 2012 to 2013. Our percentage of proved undeveloped reserve additions to total proved reserve additions was approximately 29% in 2007, 38% in 2006 and 36% in 2005. Based on our current drilling schedule and budget, we expect that virtually all of the proved undeveloped reserves added in 2007 will begin producing within the next three to five years. Generally, proved developed reserves are producing at the time they are added or will begin producing within one year.
Since 2000, Chesapeake has invested $9.4 billion in new leasehold and 3-D seismic acquisitions and now owns what we believe are the largest combined inventories of onshore leasehold (13 million net acres) and 3-D seismic (19 million acres) in the U.S. On this leasehold, the company has approximately 36,300 net drillsites representing more than a 10-year inventory of drilling projects.
As of December 31, 2007, the companys debt as a percentage of total capitalization (total capitalization is the sum of debt and stockholders equity) was 47% compared to 40% as of December 31, 2006. The average maturity of our long-term debt is almost nine years with an average interest rate of approximately 5.8%.
Liquidity and Capital Resources
2008 2009 Financial Plan
In early September 2007, we announced an enhanced financial plan designed to monetize unrecognized balance sheet value and to fully fund our planned capital expenditures through 2009 without accessing public capital markets. Since then, we have successfully implemented multiple aspects of the plan and anticipate further progress during 2008 and 2009. We believe our planned transactions described below will allow us to monetize approximately $3 billion of assets by the end of 2009.
Sale/Leasebacks. During 2007, we entered into sale/leaseback transactions involving 54 drilling rigs for net proceeds of approximately $369 million. We now operate a total of 78 rigs under sale/leaseback arrangements and anticipate similar transactions on our remaining 3 rigs during 2008, thereby completing the sale/leaseback of our entire fleet of 81 drilling rigs. Also during 2007, we completed a sale/leaseback facility for our natural gas compression assets. We received approximately $188 million for the sale/leaseback of our existing natural gas compression assets, and we will finance up to $175 million of future natural gas compression assets under the same facility.
Producing Property Sales. In December 2007, we monetized a portion of our proved reserves and production in certain Chesapeake-operated producing assets in Kentucky and West Virginia. In this transaction, we sold a volumetric production payment (VPP) to affiliates of UBS AG and DB Energy Trading LLC (a subsidiary of Deutsche Bank AG) for proceeds of approximately $1.1 billion. The VPP entitles the purchaser to receive scheduled quantities of natural gas from Chesapeakes interests in over 4,000 producing wells, free of all production costs and production taxes, over a 15-year period. The transaction included approximately 208 bcfe of proved reserves and 55 mmcfe per day of net production, or approximately 2% of our proved reserves and net production as of December 31, 2007. We have retained drilling rights on the properties below currently producing intervals and outside of existing producing wellbores. In addition, we plan to pursue monetizations of similarly mature properties in 2008 and 2009 for estimated proceeds of approximately $2.0 billion.
In the first quarter of 2008, we sold non-core oil and natural gas assets in the Rocky Mountains and in the Arkoma Basin Woodford Shale play for proceeds of approximately $250 million.
Midstream Partnership. We are currently in the process of forming a private partnership to own a non-operating interest in our midstream natural gas assets outside of Appalachia, which consist primarily of natural gas gathering systems and treating assets. We anticipate raising $1 billion in the first half of 2008 by selling a minority interest in the partnership.
Sources and Uses of Funds
Cash flow from operations is our primary source of liquidity to meet operating expenses and fund capital expenditures (other than for acquisitions outside our budgeted leasehold and property acquisitions). Cash provided by operating activities was $4.932 billion in 2007, compared to $4.843 billion in 2006 and $2.407 billion in 2005. The $89 million increase from 2006 to 2007 was primarily due to higher volumes of oil and natural gas production. The $2.436 billion increase from 2005 to 2006 was primarily due to higher realized prices and higher volumes of oil and natural gas production. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding non-cash items, such as depreciation, depletion and amortization, deferred income taxes and unrealized gains and (losses) on derivatives. Net income decreased to $1.451 billion in 2007 from $2.003 billion in 2006 compared to $948 million in 2005 and is discussed below under Results of Operations.
Changes in market prices for oil and natural gas directly impact the level of our cash flow from operations. While a decline in oil or natural gas prices would affect the amount of cash flow that would be generated from operations, we currently (as of February 21, 2008) have oil hedges in place covering 94% of our expected oil production in 2008 and 87% of our expected natural gas production in 2008, thereby providing price certainty for a substantial portion of our future cash flow. Our oil and natural gas hedges as of December 31, 2007 are detailed in Item 7A of Part II of this report. We have arrangements with our hedging counterparties that allow us to minimize the potential liquidity impact of significant mark-to-market fluctuations in the value of our oil and natural gas hedges by making collateral allocations from our bank credit facility or directly pledging oil and natural gas properties, rather than posting cash or letters of credit with the counterparties. Depending on changes in oil and natural gas futures markets and managements view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging positions.
Our bank credit facility is another source of liquidity. On November 2, 2007, we amended and restated our syndicated revolving bank credit facility to increase the borrowing base to $3.5 billion (with commitments of $3.0 billion) and extended the maturity to November 2012. We subsequently increased the commitments under the credit facility to $3.5 billion. The amendment reflects the increased scale and scope of our operations and will help accommodate timing differences between cash flow from operations, asset monetizations and planned capital expenditures. At February 26, 2008, there was $596 million of borrowing capacity available under the revolving bank credit facility. We use the facility to fund daily operating activities and acquisitions as needed. We borrowed $7.9 billion and repaid $6.2 billion in 2007, we borrowed $8.4 billion and repaid $8.3 billion in 2006, and we borrowed $5.7 billion and repaid $5.7 billion in 2005 under the bank credit facility.
In 2007, we completed two public offerings of our 2.5% Contingent Convertible Senior Notes due 2037. In the first offering, in May 2007, we issued $1.150 billion of notes and in the second offering, in August 2007, we issued $500 million of notes. Net proceeds of approximately $1.124 billion and $483 million, respectively, were used to repay outstanding borrowings under our revolving bank credit facility. The following table reflects the proceeds from sales of securities we issued in 2007, 2006 and 2005, ($ in millions):
In December 2007, we sold a portion of our proved reserves and production in certain Chesapeake-operated producing assets in Kentucky and West Virginia. In this transaction, we sold a volumetric production payment (VPP) for proceeds of $1.1 billion, net of transaction costs.
We believe our cash flow from operations, in combination with the proceeds expected from our planned producing property monetizations and other asset sales and the $1 billion increase in capacity under our bank credit facility will provide us with sufficient liquidity to execute our business strategy without accessing the public capital markets for the foreseeable future. We intend to use any cash in excess of our operating and capital expenditure needs to pay down indebtedness under our revolving bank credit facility.
Our primary use of funds is on capital expenditures for exploration, development and acquisition of oil and natural gas properties. We refer you to the table under Investing Transactions below, which sets forth the components of our oil and natural gas investing activities for 2007, 2006 and 2005. Our drilling, land and seismic capital expenditures are currently budgeted at $5.9 billion to $6.5 billion in 2008. We believe this level of exploration and development will enable us to increase our proved oil and natural gas reserves by more than 14% in 2008 and increase our total production by 19% to 21% in 2008 (inclusive of acquisitions completed or scheduled to close in 2008 through the filing date of this report but without regard to any additional acquisitions that may be completed in 2008).
We retain a significant degree of control over the timing of our capital expenditures which permits us to defer or accelerate certain capital expenditures if necessary to address any potential liquidity issues. In addition, higher drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary.
We paid dividends on our common stock of $115 million, $87 million and $60 million in 2007, 2006 and 2005, respectively. The Board of Directors increased the quarterly dividend on common stock from $0.06 to $0.0675 per share beginning with the dividend paid in July 2007. We paid dividends on our preferred stock of $95 million, $88 million and $31 million in 2007, 2006 and 2005, respectively.
In 2007, holders of our 5.0% (Series 2005) cumulative convertible preferred stock and 6.25% mandatory convertible preferred stock exchanged 4,535,880 shares and 2,156,184 shares for 19,038,891 and 17,367,823 shares of common stock, respectively, in public exchange offers. The exchange resulted in a loss on conversion of $128 million.
We received $15 million, $73 million and $21 million from the exercise of employee and director stock options in 2007, 2006 and 2005, respectively. We paid $86 million and $4 million to purchase treasury stock in 2006 and 2005, respectively. Of these amounts, $11 million and $4 million were used to fund our matching contribution to our 401(k) plans in 2006 and 2005, respectively. The remaining $75 million in 2006 was used to purchase shares of common stock to be used upon the exercise of stock options under certain stock option plans. There were no treasury stock purchases made in 2007.
In 2007, 2006 and 2005, we paid $91 million, $87 million and $12 million, respectively, to settle a portion of the derivative liabilities assumed in our 2005 acquisition of Columbia Natural Resources, LLC.
On January 1, 2006, we adopted SFAS 123(R), which requires tax benefits resulting from stock-based compensation deductions in excess of amounts reported for financial reporting purposes to be reported as cash flows from financing activities. In 2007 and 2006, we reported a tax benefit from stock-based compensation of $20 million and $88 million, respectively.
Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists decreased by $98 million, increased by $70 million and increased by $61 million in 2007, 2006 and 2005, respectively. All disbursements are funded on the day they are presented to our bank using available cash on hand or draws on our revolving bank credit facility.
Historically, we have used significant funds to redeem or purchase and retire outstanding senior notes issued by Chesapeake, although we had no such transactions in 2007 and 2006. The following table shows our redemption, purchases and exchanges of senior notes for 2005 ($ in millions):
Our accounts receivable are primarily from purchasers of oil and natural gas ($798 million at December 31, 2007) and exploration and production companies which own interests in properties we operate ($175 million at December 31, 2007). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.
Cash used in investing activities decreased to $7.922 billion in 2007, compared to $8.942 billion in 2006 and $6.921 billion in 2005. Over the past year, we have accelerated our drilling program and shifted our acquisition strategy from significant stock and asset acquisitions to targeted leasehold and property acquisitions needed for planned oil and natural gas development. Our investing activities during 2007 reflected our increasing focus on converting our resource inventory into production as well as elements of our new financial plan. The following table shows our cash used in (provided by) investing activities during 2007, 2006 and 2005 ($ in millions):
Bank Credit and Hedging Facilities
On November 2, 2007, we amended and restated our syndicated revolving bank credit facility to increase the borrowing base to $3.5 billion (with commitments of $3.0 billion) and extended the maturity to November 2012. We subsequently increased the commitments under the credit facility to $3.5 billion. As of December 31, 2007, we had $1.950 billion in outstanding borrowings under this facility and had utilized approximately $5 million of the facility for various letters of credit. Borrowings under the facility are secured by certain producing oil and natural gas properties and bear interest at our option of either (i) the greater of the reference rate of Union Bank of California, N.A., or the federal funds effective rate plus 0.50% or (ii) London Interbank Offered Rate (LIBOR), plus a margin that varies from 0.75% to 1.50% per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to a commitment fee that also varies according to our senior unsecured long-term debt ratings, from 0.125% to 0.30% per annum. Currently the commitment fee is 0.20% per annum. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals. Our subsidiaries, Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C., are the borrowers under our revolving bank credit facility and Chesapeake and all its other wholly-owned subsidiaries except minor subsidiaries are guarantors.
The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, make investments or loans and create liens. The credit facility agreement requires us to maintain an indebtedness to total capitalization ratio (as defined) not to exceed 0.70 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.75 to 1. As defined by the credit facility agreement, our indebtedness to total capitalization ratio was 0.48 to 1 and our indebtedness to EBITDA ratio was 2.16 to 1 at December 31, 2007. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million ($50 million in the case of our senior notes issued after 2004), would constitute an event of default under our senior note indentures which could in turn result in the acceleration of a significant portion of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $75 million.
We have six secured hedging facilities, each of which permits us to enter into cash-settled oil and natural gas commodity transactions, valued by the counterparty, for up to a maximum value. Outstanding transactions under each facility are collateralized by certain of our oil and natural gas properties that do not secure any of our other obligations. The hedging facilities are subject to an annual exposure fee, which is assessed quarterly based on the average of the daily negative fair value amounts of the hedges, if any, during the quarter. The hedging facilities contain the standard representations and default provisions that are typical of such agreements. The agreements also contain various restrictive provisions which govern the aggregate oil and natural gas production volumes that we are permitted to hedge under all of our agreements at any one time. The maximum permitted value of transactions under each facility and the fair value of outstanding transactions are shown below.
Our revolving bank credit facility and secured hedging facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates and commitment fees in our bank credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, the bank facility and the secured hedging facilities do not contain provisions which would trigger an acceleration of amounts due under the facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.
Senior Note Obligations
In addition to outstanding revolving bank credit facility borrowings discussed above, as of December 31, 2007, senior notes represented approximately $9.0 billion of our long-term debt and consisted of the following ($ in millions):
No scheduled principal payments are required under our senior notes until 2013, when $864 million is due. The holders of the 2.75% Contingent Convertible Senior Notes due 2035 may require us to repurchase, in cash, all or a portion of these notes on November 15, 2015, 2020, 2025 and 2030 at 100% of the principal amount of the notes. The holders of the 2.5% Contingent Convertible Senior Notes due 2037 may require us to repurchase, in cash, all or a portion of these notes on May 15, 2017, 2022, 2027 and 2032 at 100% of the principal amount of the notes.
As of December 31, 2007 and currently, debt ratings for the senior notes are Ba3 by Moodys Investor Service (negative outlook), BB by Standard & Poors Ratings Services (positive outlook) and BB by Fitch Ratings (negative outlook).
Our senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. All of our wholly-owned subsidiaries, except minor subsidiaries, fully and unconditionally guarantee the notes jointly and severally on an unsecured basis. Senior notes issued before July 2005 are governed by indentures containing covenants that limit our ability and our restricted subsidiaries ability to incur additional indebtedness; pay dividends on our capital stock or redeem, repurchase or retire our capital
stock or subordinated indebtedness; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; create restrictions on the payment of dividends or other amounts to us from our restricted subsidiaries; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. Senior notes issued after June 2005 are governed by indentures containing covenants that limit our ability and our restricted subsidiaries ability to incur certain secured indebtedness; enter into sale-leaseback transactions; and consolidate, merge or transfer assets. The debt incurrence covenants do not presently restrict our ability to borrow under or expand our secured credit facility. As of December 31, 2007, we estimate that secured commercial bank indebtedness of approximately $4.9 billion could have been incurred under the most restrictive indenture covenant.
The table below summarizes our contractual obligations as of December 31, 2007 ($ in millions):
Chesapeake has commitments to purchase the production associated with the December 31, 2007 sale of a volumetric production payment that extends over a 15 year term at market prices at the time of production and the purchased gas will be resold. The obligations are as follows:
Oil and Natural Gas Hedging Activities
Our results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Executive management is involved in all risk management activities and the Board of Directors reviews the companys hedging program at its quarterly Board meetings. We believe we have sufficient internal controls to prevent unauthorized hedging. As of December 31, 2007, our oil and natural gas derivative instruments were comprised of swaps, basis protection swaps, knockout swaps, cap-swaps, call options and collars. Item 7AQuantitative and Qualitative Disclosures About Market Risk contains a description of each of these instruments. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.
Hedging allows us to predict with greater certainty the effective prices we will receive for our hedged oil and natural gas production. We closely monitor the fair value of our hedging contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss. Commodity markets are volatile and Chesapeakes hedging activities are dynamic.
Mark-to-market positions under oil and natural gas hedging contracts fluctuate with commodity prices. As described above under Bank Credit and Hedging Facilities, we may be required to deliver cash collateral or other assurances of performance if our payment obligations to our hedging counterparties exceed levels stated in our contracts. Our realized and unrealized gains and losses on oil and natural gas derivatives during 2007, 2006 and 2005 were as follows:
Changes in the fair value of oil and natural gas derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to the hedged commodities, and locked-in gains and losses of derivative contracts are recorded in accumulated other comprehensive income and are transferred to earnings in the month of related production. These unrealized gains (losses), net of related tax effects, totaled $53 million, $546 million and ($271) million as of December 31, 2007, 2006 and 2005, respectively. Based upon the market prices at December 31, 2007, we expect to transfer to earnings approximately $127 million of the net gain included in the balance of accumulated other comprehensive income during the next 12 months. A detailed explanation of accounting for oil and natural gas derivatives under SFAS 133 appears under Application of Critical Accounting PoliciesHedging elsewhere in this Item 7.
The estimated fair values of our oil and natural gas derivative instruments as of December 31, 2007 and 2006 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.
Additional information concerning the fair value of our oil and natural gas derivative instruments, including CNR derivatives assumed, is as follows:
Interest Rate Derivatives
We use interest rate derivatives to mitigate our exposure to the volatility in interest rates. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value are recorded on the consolidated balance sheets as assets (liabilities), and the debts carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Changes in the fair value of derivative instruments not qualifying as fair value hedges are recorded currently as adjustments to interest expense.
Gains or losses from derivative transactions are reflected as adjustments to interest expense on the consolidated statements of operations. Realized gains (losses) included in interest expense were ($1) million, ($2) million and $5 million in 2007, 2006 and 2005, respectively. Pursuant to SFAS 133, certain derivatives do not
qualify for designation as fair value hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the consolidated statements of operations as unrealized gains (losses) within interest expense. Unrealized gains (losses) included in interest expense were ($40) million, $2 million and $2 million in 2007, 2006 and 2005, respectively. A detailed explanation of accounting for interest rate derivatives under SFAS 133 appears under Application of Critical Accounting PoliciesHedging elsewhere in this Item 7.
Foreign Currency Derivatives
On December 6, 2006, we issued 600 million of 6.25% Euro-denominated Senior Notes due 2017. Concurrent with the issuance of the Euro-denominated senior notes, we entered into a cross currency swap to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. A detailed explanation of accounting for foreign currency derivatives under SFAS 133 appears under Application of Critical Accounting PoliciesHedging elsewhere in this Item 7.
Results of Operations
General. For the year ended December 31, 2007, Chesapeake had net income of $1.451 billion, or $2.62 per diluted common share, on total revenues of $7.800 billion. This compares to net income of $2.003 billion, or $4.35 per diluted common share, on total revenues of $7.326 billion during the year ended December 31, 2006, and net income of $948 million, or $2.51 per diluted common share, on total revenues of $4.665 billion during the year ended December 31, 2005.
Oil and Natural Gas Sales. During 2007, oil and natural gas sales were $5.624 billion compared to $5.619 billion in 2006 and $3.273 billion in 2005. In 2007, Chesapeake produced and sold 714.3 bcfe of oil and natural gas at a weighted average price of $8.40 per mcfe, compared to 578.4 bcfe in 2006 at a weighted average price of $8.86 per mcfe, and 468.6 bcfe in 2005 at a weighted average price of $6.90 per mcfe (weighted average prices for all years discussed exclude the effect of unrealized gains or (losses) on derivatives of ($374) million, $495 million and $41 million in 2007, 2006 and 2005, respectively). The decrease in prices in 2007 resulted in a decrease in revenue of $329 million and increased production resulted in a $1.203 billion increase, for a total increase in revenues of $874 million (excluding unrealized gains or losses on oil and natural gas derivatives). The increase in production from period to period was primarily generated from the drillbit.
For 2007, we realized an average price per barrel of oil of $67.50, compared to $59.14 in 2006 and $47.77 in 2005 (weighted average prices for all years discussed exclude the effect of unrealized gains or losses on derivatives). Natural gas prices realized per mcf (excluding unrealized gains or losses on derivatives) were $8.14, $8.76 and $6.78 in 2007, 2006 and 2005, respectively. Realized gains or losses from our oil and natural gas derivatives resulted in a net increase in oil and natural gas revenues of $1.203 billion or $1.68 per mcfe in 2007, a net increase of $1.254 billion or $2.17 per mcfe in 2006 and a net decrease of $401 million or $0.86 per mcfe in 2005.
A change in oil and natural gas prices has a significant impact on our oil and natural gas revenues and cash flows. Assuming 2007 production levels, a change of $0.10 per mcf of natural gas sold would result in an increase or decrease in revenues and cash flow of approximately $65 million and $63 million, respectively, and a change of $1.00 per barrel of oil sold would result in an increase or decrease in revenues and cash flow of approximately $10 million and $9 million, respectively, without considering the effect of hedging activities.
The following table shows our production by region for 2007, 2006 and 2005:
Natural gas production represented approximately 92% of our total production volume on an equivalent basis in 2007, compared to 91% in 2006 and 90% in 2005.
Oil and Natural Gas Marketing Sales and Operating Expenses. Oil and natural gas marketing activities are substantially for third parties who are owners in Chesapeake-operated wells. Chesapeake realized $2.040 billion in oil and natural gas marketing sales to third parties in 2007, with corresponding oil and natural gas marketing expenses of $1.969 billion, for a net margin before depreciation of $71 million. This compares to sales of $1.577 billion and $1.392 billion, expenses of $1.522 billion and $1.358 billion, and margins before depreciation of $55 million and $35 million in 2006 and 2005, respectively. The net margin increase in 2007 and 2006 is primarily due to an increase in volumes and prices related to oil and natural gas marketing sales.
Service Operations Revenue and Operating Expenses. Service operations consist of third-party revenue and operating expenses related to our leased or owned drilling and oilfield trucking operations. These operations have grown as a result of assets and businesses we acquired in 2006 and 2007. Chesapeake recognized $136 million in service operations revenue in 2007 with corresponding service operations expenses of $94 million, for a net margin before depreciation of $42 million. This compares to revenue of $130 million, expenses of $68 million and a net margin before depreciation of $62 million in 2006. During 2005, service operations revenues and expenses for third parties were insignificant.
Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $640 million in 2007, compared to $490 million and $317 million in 2006 and 2005, respectively. On a unit-of-production basis, production expenses were $0.90 per mcfe in 2007 compared to $0.85 and $0.68 per mcfe in 2006 and 2005, respectively. The increase in 2007 was primarily due to higher third-party field service costs, fuel costs and personnel costs. We expect that production expenses per mcfe produced for 2008 will range from $0.90 to $1.00.
Production Taxes. Production taxes were $216 million in 2007 compared to $176 million in 2006 and $208 million in 2005. On a unit-of-production basis, production taxes were $0.30 per mcfe in 2007 compared to $0.31 per mcfe in 2006 and $0.44 per mcfe in 2005. In 2006, $2 million was accrued for certain severance tax claims and was then offset by a subsequent reversal of the cumulative $12 million accrual for such severance tax claims as a result of their dismissal. After adjusting for these items, there was an increase of $30 million in production taxes from 2006 to 2007. The $30 million increase is mostly due to an increase in production of 136 bcfe.
In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil and natural gas prices are higher. We expect production taxes for 2008 to range from $0.32 to $0.37 per mcfe produced based on a NYMEX price of $76.49 per barrel of oil and natural gas wellhead prices ranging from $7.40 to $8.40 per mcf.
General and Administrative Expense. General and administrative expenses, including stock-based compensation but excluding internal costs capitalized to our oil and natural gas properties (see Note 11 of notes to consolidated financial statements), were $243 million in 2007, $139 million in 2006 and $64 million in 2005. General and administrative expenses were $0.34, $0.24 and $0.14 per mcfe for 2007, 2006 and 2005, respectively. The increase in 2007, 2006 and 2005 was the result of the companys overall growth as well as cost and wage inflation. Included in general and administrative expenses is stock-based compensation of $58 million in 2007, $27 million in 2006 and $15 million in 2005. The increase was mainly due to a higher number of unvested restricted shares outstanding during 2007 compared to 2006 and 2005. We anticipate that general and administrative expenses for 2008 will be between $0.33 and $0.37 per mcfe produced, including stock-based compensation ranging from $0.10 to $0.12 per mcfe produced.
Our stock-based compensation for employees and non-employee directors is in the form of restricted stock. Prior to 2004, stock-based compensation awards were only in the form of stock options. Employee stock-based compensation awards generally vest over a period of four or five years. Our non-employee director awards vest over a period of three years.
Until December 31, 2005, as permitted under Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, as amended, we accounted for our stock options under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Generally, we recognized no compensation cost on grants of employee and non-employee director stock options because the exercise price was equal to the market price of our common stock on the date of grant. Effective January 1, 2006, we implemented the fair value recognition provisions of SFAS 123(R), Share-Based Payment, using the modified-prospective transition method. For all unvested options outstanding as of January 1, 2006, the previously measured but unrecognized compensation expense, based on the fair value at the original grant date, was recognized in our financial statements over the remaining vesting period. For equity-based compensation awards granted or modified subsequent to January 1, 2006, compensation expense based on the fair value on the date of grant or modification is recognized in our financial statements over the vesting period. In addition, in accordance with Financial Accounting Standards Board Staff Position No. FAS 123(R)-3, Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards, we elected to use the short-cut method to calculate the historical pool of windfall tax benefits. Results for prior periods have not been restated.
The discussion of stock-based compensation in Note 1 and Note 9 of the notes to consolidated financial statements included in Item 8 of this report provides additional detail on the accounting for and reporting of our stock options and restricted stock, as well as the effects of our adoption of SFAS 123(R).
Chesapeake follows the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $262 million, $161 million and $102 million of internal costs in 2007, 2006 and 2005, respectively, directly related to our oil and natural gas property acquisition, exploration and development efforts.
Oil and Natural Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of oil and natural gas properties was $1.835 billion, $1.359 billion and $894 million during 2007, 2006 and 2005, respectively. The average DD&A rate per mcfe, which is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented, was $2.57, $2.35 and $1.91 in 2007, 2006 and 2005, respectively. The increase in the average rate from $2.35 in 2006 to $2.57 in 2007 is primarily the result of higher drilling costs, higher costs associated with acquisitions and the recognition of the tax effect of acquisition costs in excess of tax basis acquired in certain corporate acquisitions. We expect the 2008 DD&A rate to be between $2.50 and $2.70 per mcfe produced.
Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $154 million in 2007, compared to $104 million in 2006 and $51 million in 2005. The average D&A rate per mcfe was $0.22, $0.18 and $0.11 in 2007, 2006 and 2005, respectively. The increases in 2007 and 2006 were primarily the result of higher depreciation costs resulting from the acquisition of various gathering facilities, the construction of new buildings at our corporate headquarters complex and at various field office locations and additional information technology equipment and software. In 2006, increases were also attributed to the acquisition of compression equipment and drilling rigs. The overall increase in 2007 was partially mitigated by various sale/leaseback transactions throughout 2007 related to certain of our compressors and drilling rigs. Property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 15 to 39 years, gathering facilities are depreciated over 20