Chesapeake Energy 10-K 2007
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the Fiscal Year Ended December 31, 2006
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 ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act.
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨
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 30, 2006 was approximately $11.9 billion. At February 23, 2007, there were 460,068,149 shares of our $0.01 par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2007 Annual Meeting of Shareholders are incorporated by reference in Part III.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
2006 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
We are the third largest independent producer of natural gas in the United States, and we own interests in approximately 34,600 producing oil and natural gas wells that are currently producing approximately 1.7 billion cubic feet equivalent, or bcfe, per day, 92% of which is natural gas. Our strategy is focused on discovering, developing and acquiring conventional and unconventional natural gas reserves onshore in the U.S. east of the Rocky Mountains. Our operations are located in the Mid-Continent region, which includes Oklahoma, Arkansas, southwestern Kansas and the Texas Panhandle; the Forth Worth Basin in north-central Texas; the Appalachian Basin, principally in West Virginia, eastern Kentucky, eastern Ohio 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 shale play in the U.S., including the Fort Worth Basin Barnett Shale, the Arkansas Fayetteville Shale, the Appalachian Basin Devonian Shale, the southeast Oklahoma Woodford Shale, the Delaware Basin Barnett and Woodford Shales, the Illinois Basin New Albany Shale and the Conasauga, Floyd and Chattanooga Shales in Alabama.
As of December 31, 2006, we had 9.0 trillion cubic feet equivalent, or tcfe, of proved reserves, of which 93% were natural gas and all of which were onshore. During 2006, we produced an average of 1.585 bcfe per day, a 23% increase over the 1.284 bcfe per day produced in 2005. We replaced our 578 bcfe of production with an internally estimated 2.013 tcfe of new proved reserves for a reserve replacement rate of 348%. Reserve replacement through the drillbit was 1.345 tcfe, or 233% of production (including 729 bcfe of positive performance revisions and 212 bcfe of downward revisions resulting from natural gas price declines), and reserve replacement through acquisitions was 668 bcfe, or 115% of production. As a result, our proved reserves grew by 19% during 2006, from 7.5 tcfe to 9.0 tcfe. Of our 9.0 tcfe of proved reserves, 62% were proved developed reserves.
During 2006, we led the nation in drilling activity with an average utilization of 98 operated rigs and 79 non-operated rigs. Through this drilling activity, we drilled 1,488 (1,243 net) operated wells and participated in another 1,534 (206 net) wells operated by other companies. Our success rate was 99% for operated wells and 98% for non-operated wells. In 2006, we added approximately 2,000 new employees to support our growth, which increased our total employee base to approximately 4,900 employees at December 31, 2006, and invested $771 million in leasehold (excluding leasehold acquired through corporate and asset acquisitions) and 3-D seismic data, all of which we consider the building blocks of future value creation.
From January 1, 1998 through December 31, 2006, we were one of the most active consolidators of onshore U.S. natural gas assets, having purchased approximately 6.5 tcfe of proved reserves, at a total cost of approximately $14.3 billion (including $5.1 billion for unproved leasehold, but excluding $989 million of deferred taxes established in connection with certain corporate acquisitions). Excluding the amounts allocated to unproved leasehold and deferred taxes, our acquisition cost per proved thousand cubic feet equivalent, or mcfe, was $1.41 over this time period. During 2006, we remained active in the acquisitions market. Acquisition expenditures in 2006 totaled $4.0 billion (including $2.9 billion for unproved leasehold, but excluding $180 million of deferred taxes established in connection with certain corporate acquisitions).
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.chkenergy.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 nine years, our strategy to accomplish this goal has been to focus onshore in the U.S. east of the Rockies where the company believes it can generate attractive risk adjusted returns. In building our industry-leading resource base, we have integrated an aggressive and technologically-advanced drilling program with an active property consolidation program focused on small to medium-sized corporate and property acquisitions. To date, we have built leading positions in the Mid-Continent region, the Fort Worth Barnett Shale in North Texas, the South Texas and Texas Gulf Coast regions, the Permian and Delaware Basins of West Texas and eastern New Mexico, the Fayetteville Shale in Arkansas, the Ark-La-Tex area of East Texas and northern Louisiana, the Appalachian Basin, principally in West Virginia, eastern Kentucky, eastern Ohio and southern New York, the Caney and Woodford Shales in southeastern Oklahoma, the Barnett and Woodford Shales in west Texas and the Conasauga, Floyd and Chattanooga Shales of Alabama.
Key elements of this business strategy are further explained below:
Based on our view that natural gas will be in a tight supply/demand relationship in the U.S. during at least the next few years because of the significant structural challenges to growing natural gas supply and the growing demand for this clean-burning, domestically produced fuel, we believe our focused natural gas acquisition, exploitation and exploration strategy should provide substantial value-creating growth opportunities in the years ahead. Our goal is to increase our overall production by 14% to 18% in 2007 and 10% to 14% in 2008.
We believe the following six characteristics distinguish our past performance and differentiate our future growth potential from other independent natural gas producers:
Chesapeake focuses its natural gas exploration, development and acquisition efforts in six operating areas: (i) the Mid-Continent, representing 47% of our proved reserves, (ii) the Fort Worth Basin, representing 13% of our proved reserves, (iii) the Appalachian Basin, representing 17% of our proved reserves, (iv) the Permian and Delaware Basins, representing 8% of our proved reserves, (v) the Ark-La-Tex area, representing 8% of our proved reserves, and (vi) the South Texas and Texas Gulf Coast regions, representing 7% of our proved reserves.
Chesapeakes strategy for 2007 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 secondary areas. We project that our 2007 production will be between 665 bcfe and 675 bcfe. We have budgeted $4.7 billion to $4.9 billion for drilling, acreage acquisition, seismic and related capitalized internal costs, all of which is expected to be funded with operating cash flow based on our current assumptions 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. We expect to fund future acquisitions through a combination of operating cash flow, our revolving bank credit facility and, if needed, new debt and equity issuances.
Mid-Continent. Chesapeakes Mid-Continent proved reserves of 4.226 tcfe represented 47% of our total proved reserves as of December 31, 2006, and this area produced 315 bcfe, or 55%, of our 2006 production. During 2006, we invested approximately $1.530 billion to drill 1,884 (621 net) wells in the Mid-Continent. For 2007, we anticipate spending approximately 37% of our total budget for exploration and development activities in the Mid-Continent region.
Fort Worth Barnett Shale. Chesapeakes Fort Worth Barnett Shale proved reserves represented 1.141 tcfe, or 13%, of our total proved reserves as of December 31, 2006. During 2006, the Fort Worth Barnett Shale assets produced 44 bcfe, or 7%, of our total production. During 2006, we invested approximately $428 million to drill 244 (187 net) wells in the Fort Worth Barnett Shale. For 2007, we anticipate spending approximately 26% of our total budget for exploration and development activities in the Fort Worth Barnett Shale.
Appalachian Basin. Chesapeakes Appalachian Basin proved reserves represented 1.491 tcfe, or 17%, of our total proved reserves as of December 31, 2006. During 2006, the Appalachian assets produced 45 bcfe, or 8%, of our total production. During 2006, we invested approximately $171 million to drill 319 (272 net) wells in the Appalachian Basin. For 2007, we anticipate spending approximately 7% of our total budget for exploration and development activities in the Appalachian Basin.
Permian and Delaware Basins. Chesapeakes Permian and Delaware Basins proved reserves represented 725 bcfe, or 8%, of our total proved reserves as of December 31, 2006. During 2006, the Permian assets produced 49 bcfe, or 8%, of our total production. During 2006, we invested approximately $413 million to drill 189 (92 net) wells in the Permian and Delaware Basins. For 2007, we anticipate spending approximately 13% 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 711 bcfe, or 8%, of our total proved reserves as of December 31, 2006. During 2006, the Ark-La-Tex assets produced 46 bcfe, or 8%, of our total production. During 2006, we invested approximately $381 million to drill 248 (175 net) wells in the Ark-La-Tex region. For 2007, we anticipate spending approximately 9% 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 661 bcfe, or 7%, of our total proved reserves as of December 31, 2006. During 2006, the South Texas and Texas Gulf Coast assets produced 79 bcfe, or 14%, of our total production. For 2006, we invested approximately $375 million to drill 138 (102 net) wells in the South Texas and Texas Gulf Coast regions. For 2007, we anticipate spending approximately 8% 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, 2006, we had 270 (128 net) wells in process.
At December 31, 2006, we had interests in approximately 34,600 (19,079 net) producing wells, including properties in which we held an overriding royalty interest, of which 6,500 (3,608 net) were classified as primarily oil producing wells and 28,100 (15,471 net) were classified as primarily natural gas producing wells. Chesapeake operates approximately 20,400 of its 34,600 producing wells. During 2006, we drilled 1,488 (1,243 net) wells and participated in another 1,534 (206 net) wells operated by other companies. We operate approximately 83% 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, 2006 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, 2006, our reserve estimates included 3.382 tcfe of reserves classified as proved undeveloped (PUD). Of this amount, approximately 40%, 34% and 16% (by volume) were initially classified as PUDs in 2006, 2005 and 2004, respectively, and the remaining 10% were initially classified as PUDs prior to 2004. Of our proved developed reserves, 655 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 $8.2 billion at December 31, 2006, and the $2.4 billion present value thereof, have been calculated assuming that we will expend approximately $6.2 billion to develop these reserves. We have projected to incur $2.7 billion in 2007, $1.4 billion in 2008, $0.8 billion in 2009 and $1.3 billion in 2010 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. 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 80% of our proved reserves (by volume) at year-end 2006. 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. Netherland, Sewell & Associates, Inc. evaluated 32%, Data and Consulting Services, Division of Schlumberger Technology Corporation evaluated 16%, Lee Keeling and Associates, Inc. evaluated 14%, Ryder Scott Company L.P. evaluated 10% and LaRoche Petroleum Consultants, Ltd. evaluated 8% of our estimated proved reserves by volume at December 31, 2006. The estimates prepared by the independent firms covered approximately 18,000 properties, or 40% of the 45,000 properties included in the 2006 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 20% 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.
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, 2006. 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, 2006 present value of estimated future net revenue of our proved reserves of approximately $350 million and $50 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, 2006, 2005 and 2004, 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 $1.208 billion, $671 million and $333 million in 2006, 2005 and 2004, respectively, related to properties carried as proved undeveloped locations in the prior years reserve reports. Included in our reserve reports as of December 31, 2006 are estimated future development costs of $6.2 billion related to the development of proved undeveloped reserves ($2.7 billion in 2007, $1.4 billion in 2008, $0.8 billion in 2009 and $1.3 billion in 2010 and beyond). 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.
A summary of our exploration and development, acquisition and divestiture activities in 2006 by operating area is as follows:
The following table sets forth as of December 31, 2006 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.
Chesapeakes 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 2007, approximately 80% of our natural gas production was sold under short-term contracts at market-sensitive or spot prices.
During 2006, sales to Eagle Energy Partners I, L.P. (Eagle) of $867 million accounted for 16% of our total revenues (excluding gains (losses) on derivatives). Chesapeake owns approximately 33% of Eagle. 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 2006.
Chesapeake Energy Marketing, Inc., which is our marketing subsidiary, provides marketing services, including commodity price structuring, contract administration and nomination services, for Chesapeake and its partners. This subsidiary 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.
In 2001, Chesapeake formed its 100% owned drilling rig subsidiary, Nomac Drilling Corporation (Nomac) with an investment of $26 million to build and refurbish five drilling rigs. As of December 31, 2006, Chesapeake had invested approximately $300 million to build or acquire 42 drilling rigs and to initiate the construction of 14 additional rigs. Including 24 rigs sold in 2006 and subsequently leased back to Chesapeake through 2014, the drilling rigs have depth ratings between 4,200 and 23,000 feet and range in drilling horsepower from 575 to 2,000. These drilling rigs are currently operating in Oklahoma, Texas and Appalachia. The companys drilling rig fleet should reach 81 rigs by mid-year 2007, which would rank Chesapeake as the sixth largest drilling rig contractor in the U.S. Additionally, the company has a $77 million investment in two private drilling rig contractors, DHS Drilling Company and Mountain Drilling Company, in which Chesapeakes equity ownership is approximately 45% and 49%, respectively. DHS owns 16 rigs and Mountain is operating 4 rigs and has another 4 rigs under construction or on order for delivery in 2007.
Natural Gas Gathering
Chesapeake owns and operates 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 8,000 miles of gathering lines, treating facilities and processing facilities which provide service to approximately 9,750 wells.
In 2006, Chesapeake expanded its service operations by acquiring two privately-owned oilfield trucking service companies. Our trucking business is utilized primarily to transport drilling rigs for both Chesapeake and third parties. As of December 31, 2006, our fleet includes 174 trucks which mainly service the Mid-Continent and Appalachian regions.
During the past few years Chesapeake has expanded its compression business. As of December 31, 2006, we operated 732 compressors, including wellhead and system compressors. Our compression business exists to facilitate the transportation of our natural gas production.
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 subject to regulation at the federal, state and local level, and some of the laws, rules and regulations
that govern our operations carry substantial penalties for noncompliance. This regulatory burden increases our cost of doing business and, consequently, affects 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, although very few of our oil and natural gas leases are located on federal lands. 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. 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 which 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 and Arkansas, 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 or 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 significantly adverse effect upon our capital expenditures, earnings or competitive position.
Environmental Regulation. Various federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of contaminants, and the protection of public health, natural resources, wildlife and the environment affect our exploration, development and production operations, including processing facilities. 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 requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. In addition, our operations may require us to obtain permits for, among other things,
Under state and federal 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 in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination. The Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and nonhazardous wastes. The owner and operator of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. 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 action. 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 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 regulations and requirements. These are necessary business costs in the oil and natural gas industry. Although we are not fully insured against all environmental 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 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 compliance with existing environmental 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 operations or earnings.
Chesapeake recorded income tax expense of $1.252 billion in 2006 compared to income tax expense of $545.1 million in 2005 and $289.8 million in 2004. Of the $706.9 million increase in 2006, $643.1 million was the result of the increase in net income before taxes and $63.8 million was the result of an increase in the effective tax rate. Our effective income tax rate was 38.5% in 2006 compared to 36.5% in 2005 and 36% in 2004. The increase in 2006 reflected the impact state income taxes and permanent differences had on our overall effective rate along with the effect of a Texas tax law change. In May 2006, Texas eliminated the existing franchise tax and replaced it with a new income-based margin tax. The new tax is effective for tax returns due on or after January 1, 2008 for our 2007 business activity. We recorded a $15 million liability in 2006 to reflect the impact that this change had on our liability for additional deferred income taxes at the date of enactment. We expect our effective income tax rate to be 38% in 2007.
At December 31, 2006, Chesapeake had federal income tax net operating loss (NOL) carryforwards of approximately $631.1 million. We also had approximately $3.6 million of alternative minimum tax (AMT) NOL carryforwards available as a deduction against future AMT income and approximately $15.9 million of percentage depletion carryforwards. The NOL carryforwards expire from 2011 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, 2006 and any related limitations:
As of December 31, 2006, 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.
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 oil and natural gas lease operator 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 $200 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 and we maintain a $1 million employment practice liability policy. 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 also owns or leases various field offices in the following locations:
Chesapeake had approximately 4,900 employees as of December 31, 2006, which includes 1,625 employed by our service operations companies. As a result of the CNR acquisition, approximately 135 of our employees were covered by a collective bargaining agreement with the United Steel Workers of America ("USWA") which expired effective December 1, 2006. We have continued to operate under the terms of the collective bargaining agreement while we are negotiating with the USWA. Contract negotiations began in October 2006 and are being mediated by the National Mediation Board. There have been no strikes, work stoppages, pickets or slow-downs 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.
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.
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.
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.
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.
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.
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.
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, 2006 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, 2006, we had long-term indebtedness of approximately $7.4 billion, with $178 million of outstanding borrowings drawn under our revolving bank credit facility. Our long-term indebtedness represented 40% of our total book capitalization at December 31, 2006. As of February 23, 2007, we had approximately $1.033 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 significant secured indebtedness, or issue additional series of preferred stock in order to make future acquisitions or to develop our properties. 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 acquisition, development, exploitation, exploration 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 38% of our total estimated proved reserves (by volume) at December 31, 2006 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 25% from 2007 to 2008. 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, 2006, approximately 38% 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 $2.7 billion in 2007. 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, 2006 present value is based on weighted average oil and natural gas wellhead prices of $56.25 per barrel of oil and $5.41 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. We expect acquisitions will also contribute to our future growth. 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.
As new owners, we may not effectively consolidate and integrate acquired operations, particularly when we make significant acquisitions outside our historical operating areas.
Significant acquisitions present operational and administrative challenges that may prove more difficult than anticipated. The failure to consolidate functions and integrate procedures, personnel and operations in an effective and timely manner may adversely affect our business and results of operations, at least temporarily. Significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. To the extent that we acquire properties substantially different from the properties in our primary operating areas or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as in our prior acquisitions.
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 ceiling test calculation as of December 31, 2006 indicated an impairment of our oil and natural gas properties of approximately $500 million, net of income tax. However, natural gas prices subsequent to December 31, 2006 have improved sufficiently to eliminate this calculated impairment. As a result, we were not required to record a write-down of our oil and natural gas properties under the full-cost method of accounting.
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, 2006 was an asset of approximately $344.9 billion. 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 two 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 $2.5 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 significant additional indebtedness under both of these 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 failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these 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 wastes 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, in response to studies suggesting that emissions of certain gases may be contributing to warming of the earths atmosphere, many states are beginning to consider initiatives to track and record these gases, generally referred to as greenhouse gases, with several states having already adopted regulatory initiatives and one state, California, having adopted legislation aimed at reducing emissions of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are included among the types of gases targeted by greenhouse gas initiatives and laws. This movement is in its infancy but regulatory initiatives or legislation placing restrictions on emissions of methane or carbon dioxide that may be imposed in various states of the United States could adversely affect our operations and the demand for our products.
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., Chesapeake's 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 fraud with respect to the sales prices used to calculate royalty payments and with respect to the failure of CNR to disclose post-production deductions.
Chesapeake and NiSource maintain CNR acted in good faith and paid royalties in accordance with lease terms and West Virginia law, and they intend to appeal any adverse judgment in the case. Chesapeake and NiSource have filed a joint motion for post-trial review of punitive damages to be heard on March 5, 2007. 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 effect on the company.
ITEM 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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 23, 2007, there were 1,522 holders of record of our common stock and approximately 300,000 beneficial owners.
The following table sets forth the amount of dividends per share declared on Chesapeake common stock during 2006 and 2005:
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, 2006, our coverage ratio for purposes of the debt incurrence test under the relevant indentures was 7.13 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 $1.1 billion.
The following table presents information about repurchases of our common stock during the three months ended December 31, 2006:
The following table sets forth selected consolidated financial data of Chesapeake for the years ended December 31, 2006, 2005, 2004, 2003 and 2002. 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 segments: an exploration and production segment, a marketing segment and a service operations segment which is comprised of our wholly owned drilling and trucking subsidiaries. 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 2006, 2005 and 2004 and our assets as of December 31, 2006, 2005 and 2004.
Chesapeake is the third largest independent producer of natural gas in the United States. We own interests in approximately 34,600 producing oil and natural gas wells that are currently producing approximately 1.7 bcfe per day, 92% of which is natural gas. Our strategy is focused on discovering, developing and acquiring onshore natural gas reserves 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, 2006, 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 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 shale play in the U.S., including the Forth Worth Basin Barnett Shale, the Arkansas Fayetteville Shale, the Appalachian Basin Devonian Shale, the southeast Oklahoma Woodford Shale, the Delaware Basin Barnett and Woodford Shales, the Illinois Basin New Albany Shale and the Conasauga, Floyd and Chattanooga Shales in Alabama.
Oil and natural gas production for 2006 was 578.4 bcfe, an increase of 109.8 bcfe, or 23% over the 468.6 bcfe produced in 2005. We have increased our production for 17 consecutive years and 22 consecutive quarters. During these 22 quarters, Chesapeakes U.S. production has increased 322% for an average compound quarterly growth rate of 6.8% and an average compound annual growth rate of 29.7%.
In addition to increased oil and natural gas production, the prices we received were higher in 2006 than in 2005. On a natural gas equivalent basis, weighted average prices (excluding the effect of unrealized gains or losses on derivatives) were $8.86 per mcfe in 2006 compared to $6.90 per mcfe in 2005. The increase in prices resulted in an increase in revenue of $1.135 billion, and increased production resulted in an increase in revenue of $757.2 million, for a total increase in revenue of $1.892 billion (excluding the effect of unrealized gains or losses on derivatives). In each of the operating areas where Chesapeake sells its oil and natural gas, established marketing and transportation infrastructures exist, thereby contributing to relatively high wellhead price realizations for our production.
During 2006, we led the nation in drilling activity with an average utilization of 98 operated rigs and 79 non-operated rigs. Through this drilling activity, we drilled 1,488 (1,243 net) operated wells and participated in another 1,534 (206 net) wells operated by other companies. Our success rate was 99% for operated wells and 98% for non-operated wells. To accelerate the development of our extensive prospect inventory, we have increased our current drilling activity to 132 operated rigs and we anticipate keeping our operated rig count between 130 and 140
rigs during 2007. In 2006, we added approximately 2,000 new employees to support our growth, which increased our total employee base to approximately 4,900 employees at December 31, 2006, and invested $771 million in leasehold (excluding leasehold acquired through corporate and asset acquisitions) and 3-D seismic data, all of which we consider the building blocks of future value creation.
Chesapeake began 2006 with estimated proved reserves of 7.521 tcfe and ended the year with 8.956 tcfe, an increase of 1.435 tcfe, or 19%. During 2006, we replaced 578.4 bcfe of production with an estimated 2.013 tcfe of new proved reserves, for a reserve replacement rate of 348%. Reserve replacement through the drillbit was 1.345 tcfe, or 233% of production (including 729 bcfe of positive performance revisions and 212 bcfe of downward revisions resulting from natural gas price declines between December 31, 2005 and December 31, 2006) and 67% of the total increase. Reserve replacement through the acquisition of proved reserves was 668 bcfe, or 115% of production and 33% of the total increase. Our annual decline rate on producing properties is projected to be 25% from 2007 to 2008, 16% from 2008 to 2009, 13% from 2009 to 2010, 11% from 2010 to 2011 and 10% from 2011 to 2012. Our percentage of proved undeveloped reserve additions to total proved reserve additions was approximately 38% in 2006, 36% in 2005 and 56% in 2004. Based on our current drilling schedule and budget, we expect that virtually all of the proved undeveloped reserves added in 2006 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.
Chesapeake attributes its strong drilling results and production growth during 2006 (and in this decade) to managements early recognition that oil and natural gas prices were undergoing structural change and its subsequent decision to invest aggressively in the building blocks of value creation in the E&P industrypeople, land and seismic. During the past five years, Chesapeake has significantly strengthened its technical capabilities by increasing its land, geoscience and engineering staff to approximately 1,000 employees. Today, the company has approximately 4,900 employees, of which approximately 60% work in the companys E&P operations and 40% work in the companys oilfield service operations.
Since 2000, Chesapeake has invested $6.6 billion in new leasehold and 3-D seismic acquisitions and now owns what it believes to be one of the largest inventories of onshore leasehold (10.4 million net acres) and 3-D seismic (16.3 million acres) in the U.S. On this leasehold, the company has an estimated 26,000 net drilling locations representing an approximate 10-year inventory of drilling projects.
Chesapeakes direct and indirect drilling rig investments have served as an effective hedge to higher service costs and have also provided competitive advantages in making acquisitions and in developing the companys own leasehold on a more timely and efficient basis. As of December 31, 2006, Chesapeake had invested approximately $300 million to build or acquire 42 drilling rigs and to begin the construction of 14 additional rigs. During 2006, the company entered into a sale/leaseback transaction to monetize its investment in 24 rigs in exchange for cash proceeds of approximately $244 million. These rigs are under lease to Chesapeake through 2014 at which time the company has the option to reacquire them. Including the 24 rigs sold and subsequently leased back to Chesapeake, the companys drilling rig fleet should reach 81 rigs by mid-year 2007, which would rank Chesapeake as the sixth largest drilling rig contractor in the U.S. Additionally, the company has a $77 million investment in two private drilling rig contractors, DHS Drilling Company and Mountain Drilling Company, in which Chesapeakes equity ownership is approximately 45% and 49%, respectively. DHS owns 16 rigs and Mountain is operating 4 rigs and has another 4 rigs under construction or on order for delivery in 2007.
To further hedge its exposure to oilfield service costs and achieve greater operational efficiency, in 2006 Chesapeake invested $254 million to acquire a 19.9% interest in a privately-held provider of well stimulation and high pressure pumping services with operations currently focused in Texas (principally in the Fort Worth Barnett Shale) and the Rocky Mountains. It also has expansion efforts underway in many other key regions in which Chesapeake operates.
As of December 31, 2006, the companys debt as a percentage of total capitalization (total capitalization is the sum of debt and stockholders equity) was 40% compared to 47% as of December 31, 2005. During 2006, we received net proceeds of $4.071 billion through issuances of $575 million of preferred equity, $1.8 billion of common equity and $1.8 billion principal amount of senior notes. We used the net proceeds from these offerings primarily to fund the purchase price for acquisitions and to repay outstanding indebtedness under our revolving bank credit facility. As a result of our debt transactions in 2005 and 2006, we have extended the average maturity of our long-term debt to over nine years with an average interest rate of approximately 6.5%.
We intend to continue to focus on improving the strength of our balance sheet. We believe our business strategy and operational performance will lead to an investment grade credit rating for our unsecured debt at some point in the future.
Liquidity and Capital Resources
Sources of Liquidity and Uses of Funds
Our primary source of liquidity to meet operating expenses and fund capital expenditures (other than for certain acquisitions) is cash flow from operations. Based on our current production, price and expense assumptions, we expect our drilling, land and seismic capital expenditures in 2007 to exceed our cash flow from operations. Any additional funds required will be provided through additional borrowings under our bank credit facility. Our budget for drilling, land and seismic activities during 2007 is currently between $4.7 billion and $4.9 billion. We believe this level of exploration and development will be sufficient to increase our proved oil and natural gas reserves in 2007 and increase our total production by 14% to 18% (inclusive of acquisitions completed or scheduled to close in 2007 through the filing date of this report but without regard to any additional acquisitions that may be completed in 2007). However, 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.
Cash provided by operating activities was $4.843 billion in 2006, compared to $2.407 billion in 2005 and $1.432 billion in 2004. The $2.436 billion increase from 2005 to 2006 and the $975 million increase from 2004 to 2005 were primarily due to higher realized prices and higher volumes of oil and natural gas production. We expect that 2007 production volumes will be higher than in 2006 and that cash provided by operating activities in 2007 will exceed 2006 levels. While a decline in natural gas prices in 2007 would affect the amount of cash flow that would be generated from operations, we currently have oil swaps in place covering 59% of our expected oil production in 2007 at an average NYMEX price of $71.90 per barrel of oil and natural gas swaps in place covering 48% of our expected natural gas production in 2007 at an average NYMEX price of $8.63 per mcf, along with natural gas collars covering 10% of our anticipated natural gas production for 2007 with an average NYMEX floor of $6.88 per mcf and an average NYMEX ceiling of $8.41 per mcf. Additionally, we have written call options covering 10% of our 2007 natural gas production at a weighted average price of $9.56. This level of hedging provides certainty of the cash flow we will receive for a substantial portion of our 2007 production. Depending on changes in oil and natural gas futures markets and managements view of underlying oil and natural gas supply and demand trends, however, we may increase or decrease our current hedging positions.
Based on fluctuations in natural gas and oil prices, our hedging counterparties may require us to deliver cash collateral or other assurances of performance from time to time. 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 bank credit facility or directly pledging oil and natural gas properties, rather than posting cash or letters of credit with the counterparties. As of December 31, 2006, we had outstanding collateral allocations and pledges of oil and natural gas properties, with respect to commodity price risk management transactions but were not required to post any collateral with our counterparties through letters of credit issued under our bank credit facility. As of
February 23, 2007, we had outstanding transactions with fifteen counterparties, eight of which hold collateral allocations from our bank facility or liens against certain oil and natural gas properties under our secured hedging facilities, and two of which do not require us to provide security for our risk management transactions. As of February 23, 2007, we were not required to post cash or letters of credit with the remaining five counterparties. Future collateral requirements are uncertain and will depend on the arrangements with our counterparties and highly volatile natural gas and oil prices.
A significant source of liquidity is our $2.5 billion syndicated revolving bank credit facility which matures in February 2011. At February 23, 2007, there was $1.464 billion 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 $8.370 billion and repaid $8.264 billion in 2006, we borrowed $5.682 billion and repaid $5.669 billion in 2005 and we borrowed $2.160 billion and repaid $2.101 billion in 2004 under our bank credit facility. We incurred $5.1 million, $4.7 million and $2.2 million of financing costs related to our revolving bank credit facility in 2006, 2005 and 2004, respectively, as a result of amendments to the credit facility agreement. During 2005, we repaid the remaining credit facility balance of $96.1 million assumed in our 2005 acquisition of Columbia Natural Resources, LLC.
We believe that our available cash, cash provided by operating activities and funds available under our revolving bank credit facility will be sufficient to fund our operating, debt service and general and administrative expenses, our capital expenditure budget, our short-term contractual obligations and dividend payments at current levels for the foreseeable future.
The public and institutional markets have been our principal source of long-term financing for acquisitions. We have sold debt and equity in both public and private offerings in the past, and we expect that these sources of capital will continue to be available to us in the future to finance acquisitions. Nevertheless, we caution that ready access to capital on reasonable terms and the availability of desirable acquisition targets at attractive prices are subject to many uncertainties, as explained under Risk Factors in Item 1A.
The following table reflects the proceeds from sales of securities we issued in 2006, 2005 and 2004 ($ in millions):
We qualify as a well-known seasoned issuer (WKSI), as defined in Rule 405 of the Securities Act of 1933, and therefore we may utilize automatic shelf registration to register future debt and equity issuances with the Securities and Exchange Commission. A prospectus supplement will be prepared at the time of an offering and will contain a description of the security issued, the plan of distribution and other information.
We paid dividends on our common stock of $87.0 million, $60.5 million and $38.9 million in 2006, 2005 and 2004, respectively, and we paid dividends on our preferred stock of $88.4 million, $31.5 million and $40.9 million in 2006, 2005 and 2004, respectively. We received $73.2 million, $21.6 million and $12.0 million from the exercise of employee and director stock options and warrants in 2006, 2005 and 2004, respectively. We paid
$86.2 million and $4.0 million to purchase treasury stock in 2006 and 2005. Of these amounts, $11.1 million and $4.0 million were used to fund our matching contribution to our 401(k) plans in 2006 and 2005, respectively. The remaining $75.1 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 2004.
In 2006 and 2005, we paid $86.9 million and $11.6 million to settle a portion of the derivative liabilities assumed in our 2005 acquisition of Columbia Natural Resources, LLC.
Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists increased by $70.0 million, $61.2 million and $88.3 million in 2006, 2005 and 2004, respectively. All disbursements are funded on the day they are presented to our bank using available cash on hand or draws on our revolving bank credit facility.
Historically, we have used significant funds to redeem or purchase and retire outstanding senior notes issued by Chesapeake, although we had no such transactions in 2006. The following table shows our redemption, purchases and exchanges of senior notes for 2005 and 2004 ($ in millions):
Our accounts receivable are primarily from purchasers of oil and natural gas ($617.8 million at December 31, 2006) and exploration and production companies which own interests in properties we operate ($135.3 million at December 31, 2006). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.
Cash used in investing activities increased to $8.942 billion in 2006, compared to $6.921 billion in 2005 and $3.381 billion in 2004. The following table shows our capital expenditures during these years ($ in millions):
In 2006, we expanded our service operations through a number of acquisitions. In January 2006, we acquired a privately-owned Oklahoma-based oilfield trucking service company for $47.5 million. In February 2006, we acquired 13 drilling rigs and related assets through our wholly owned subsidiary, Nomac Drilling Corporation, from Martex Drilling Company, L.L.P., a privately-owned drilling contractor with operations in East Texas and North Louisiana, for approximately $150 million. In July 2006, we acquired 15 rigs and related trucking assets from a drilling contractor in the Appalachian Basin for approximately $70 million in cash.
In February 2006, we sold our investment in publicly-traded Pioneer Drilling Company (Pioneer) common stock, realizing proceeds of $158.9 million and a gain of $117.4 million. We owned 17% of the common stock of Pioneer, which we began acquiring in 2003.
In August 2006, we invested $254 million to acquire a 19.9% interest in a privately-held provider of well stimulation and high pressure pumping services, with operations currently focused in Texas (principally in the Fort Worth Barnett Shale) and the Rocky Mountains. In September 2006, we acquired 32% of the outstanding common stock of Chaparral Energy, Inc. for $240 million in cash and 1,375,989 newly issued shares of our common stock valued at $40 million. Chaparral is a privately-held independent oil and natural gas company headquartered in Oklahoma City, Oklahoma.
During 2005 and 2006, we took several steps to improve our capital structure. These transactions enabled us to extend our average maturity of long-term debt to over nine years with an average interest rate of approximately 6.5%. Maintaining a debt-to-total-capitalization ratio below 50% and reducing debt per mcfe of proved reserves remain key goals of our business strategy.
We completed the following significant financing transactions in 2006:
First Quarter 2006
Second Quarter 2006
Third Quarter 2006
Fourth Quarter 2006
We currently have a $2.5 billion syndicated revolving bank credit facility which matures in February 2011. Commitments under the credit facility were increased from $1.25 billion to $2.0 billion in February 2006 and to $2.5 billion in September 2006. As of December 31, 2006, we had $178.0 million in outstanding borrowings under this facility and had utilized $6.2 million of the facility for various letters of credit. Borrowings under the facility are collateralized by certain producing oil and natural gas properties and bear interest at 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), at our option, plus a margin that varies from 0.875% 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 0.25% per annum. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.
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 0.65 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.5 to 1. As defined by the credit facility, our indebtedness to total capitalization ratio was 0.40 to 1 and our indebtedness to EBITDA ratio was 1.64 to 1 at December 31, 2006. 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 three secured hedging facilities maturing in 2011, each of which permits us to enter into cash-settled natural gas and oil 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 a 1% per annum exposure fee, which is assessed quarterly on the average of the daily negative fair market value amounts, 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 market values of outstanding transactions are shown below.
Two of our subsidiaries, Chesapeake Exploration Limited Partnership and Chesapeake Appalachia, L.L.C., are the borrowers under our revolving bank credit facility and Chesapeake Exploration Limited Partnership is the named party to our hedging facilities. The facilities are guaranteed by Chesapeake and all its other wholly owned subsidiaries except minor subsidiaries. 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.
In addition to outstanding revolving bank credit facility borrowings discussed above, as of December 31, 2006, senior notes represented approximately $7.2 billion of our long-term debt and consisted of the following ($ in thousands):
No scheduled principal payments are required under our senior notes until 2013, when $863.8 million is due. The holders of the 2.75% Contingent Convertible Senior Notes due 2035 may require us to repurchase all or a portion of these notes on November 15, 2015, 2020, 2025 and 2030 at 100% of the principal amount of these notes.
As of December 31, 2006 and currently, debt ratings for the senior notes are Ba2 by Moodys Investor Service (stable outlook), BB by Standard & Poors Ratings Services (positive outlook) and BB by Fitch Ratings (stable 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 with 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, 2006, we estimate that secured commercial bank indebtedness of approximately $3.3 billion could have been incurred under the most restrictive indenture covenant.
The table below summarizes our contractual obligations as of December 31, 2006 ($ in thousands):
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 every Board meeting. We believe we have sufficient internal controls to prevent unauthorized hedging. As of December 31, 2006, our oil and natural gas derivative instruments were comprised of swaps, cap-swaps, basis protection swaps, call options and collars. Item 7A-Quantitative 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 Contractual Obligations, 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.
Realized gains and losses from our oil and natural gas derivatives resulted in a net increase in oil and natural gas sales of $1.254 billion, or $2.17, per mcfe in 2006, a net decrease of $401.7 million, or $0.86, per mcfe in 2005 and a net decrease of $154.9 million, or $0.43, per mcfe in 2004. Oil and natural gas sales also include changes in the fair value of oil and natural gas derivatives that do not qualify as cash flow hedges under SFAS 133, as well as gains (losses) on ineffectiveness of instruments designated as cash flow hedges. Unrealized gains (losses) included in oil and natural gas sales in 2006, 2005 and 2004 were $495.5 million, $41.1 million and $40.9 million, respectively. Included in these unrealized gains (losses) are gains (losses) on ineffectiveness of cash flow hedges of $311.1 million in 2006, ($76.3) million in 2005 and ($8.2) million in 2004.
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 $545.9 million,
($270.7) million and ($4.4) million as of December 31, 2006, 2005 and 2004, respectively. Based upon the market prices at December 31, 2006, we expect to transfer to earnings approximately $282.5 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, 2006 and 2005 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 ($1.9) million, $4.9 million and $0.8 million in 2006, 2005 and 2004, 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 $1.6 million, $1.6 million and ($5.3) million in 2006, 2005 and 2004, 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 5, 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, 2006, Chesapeake had net income of $2.003 billion, or $4.35 per diluted common share, on total revenues of $7.326 billion. This compares to net income of $948.3 million, or $2.51 per diluted common share, on total revenues of $4.665 billion during the year ended December 31, 2005, and net income of $515.2 million, or $1.53 per diluted common share, on total revenues of $2.709 billion during the year ended December 31, 2004.
Oil and Natural Gas Sales. During 2006, oil and natural gas sales were $5.619 billion compared to $3.273 billion in 2005 and $1.936 billion in 2004. In 2006, Chesapeake produced and sold 578.4 bcfe at a weighted average price of $8.86 per mcfe, compared to 468.6 bcfe in 2005 at a weighted average price of $6.90 per mcfe, and 362.6 bcfe in 2004 at a weighted average price of $5.23 per mcfe (weighted average prices for all years discussed exclude the effect of unrealized gains or (losses) on derivatives of $495.5 million, $41.1 million and $40.9 million in 2006, 2005 and 2004, respectively). The increase in prices in 2006 resulted in an increase in revenue of $1.135 billion and increased production resulted in a $757.2 million increase, for a total increase in revenues of $1.892 billion (excluding unrealized gains or losses on oil and natural gas derivatives). The increase in production from period to period was due to the combination of production growth from drilling as well as acquisitions completed during those periods.
For 2006, we realized an average price per barrel of oil of $59.14, compared to $47.77 in 2005 and $28.33 in 2004 (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 $8.76, $6.78 and $5.29 in 2006, 2005 and 2004, respectively. Realized gains or losses from our oil and natural gas derivatives resulted in a net increase in oil and natural gas revenues of $1.254 billion or $2.17 per mcfe in 2006, a net decrease of $401.7 million or $0.86 per mcfe in 2005 and a net decrease of $154.9 million or $0.43 per mcfe in 2004.
A change in oil and natural gas prices has a significant impact on our oil and natural gas revenues and cash flows. Assuming 2006 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 $52.6 million and $50.1 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 $8.7 million and $8.2 million, respectively, without considering the effect of hedging activities.
The following table shows our production by region for 2006, 2005 and 2004: