We are the second-largest producer of natural gas in the United States. We own interests in approximately 44,100 producing natural gas and oil wells that are currently producing approximately 2.4 billion cubic feet equivalent, or bcfe, per day, 93% of which is natural gas. Our strategy is focused on discovering, acquiring and developing conventional and unconventional natural gas reserves onshore in the U.S., primarily in our “Big 6” natural gas shale plays: the Barnett Shale in the Fort Worth Basin of north-central Texas, the Haynesville and Bossier Shales in the Ark-La-Tex area of northwestern Louisiana and East Texas, the Fayetteville Shale in the Arkoma Basin of central Arkansas, the Marcellus Shale in the northern Appalachian Basin of West Virginia, Pennsylvania and New York and the Eagle Ford Shale in South Texas. We also have substantial operations in the Granite Wash Plays of western Oklahoma and the Texas Panhandle regions as well as various other plays, both conventional and unconventional, in the Mid-Continent, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the U.S.
We have been developing expertise in horizontal drilling technology since shortly after our inception in 1989 and have focused almost exclusively on developing natural gas properties in the U.S. since 2000. We were one of the first companies to recognize the potential of unconventional natural gas properties, especially shales, in the U.S. during the early part of the prior decade. During the past five years, we have grown from the eighth-largest natural gas producer in the U.S. to the second-largest natural gas producer, in large part as a result of our success in finding and developing unconventional natural gas assets. We have recently announced that we are extending our strategy to apply the horizontal drilling expertise we have gained in our natural gas shale plays to unconventional oil reservoirs. We expect to begin increasing our production of oil and natural gas liquids in 2010 in new developing unconventional oil plays, particularly in the Granite Wash and Eagle Ford.
During 2009, our estimated proved reserves grew from 12.051 trillion cubic feet equivalent, or tcfe, to 14.254 tcfe, of which 95% were natural gas, 58% were proved developed and 100% were onshore in the U.S. We replaced our 906 bcfe of production with an estimated 3.109 tcfe of new proved reserves for a reserve replacement rate of 343%. Reserve replacement through the drillbit was 3.296 tcfe, or 364% of production, including 445 bcfe of downward revisions resulting from changes to previous estimates and 952 bcfe of downward revisions resulting from lower natural gas prices using the average 12-month price in 2009 compared to the spot price as of December 31, 2008. During 2009, we acquired 33 bcfe of estimated proved reserves and divested 220 bcfe of estimated proved reserves.
Chesapeake continued the industry’s most active drilling program in 2009 and drilled 1,212 gross operated wells (885 net) and participated in another 994 gross wells operated by other companies (118 net). The company’s drilling success rate was 99% for company-operated wells and 98% for non-operated wells. Also during 2009, we invested $2.941 billion in operated wells (using an average of 104 operated rigs) and $439 million in non-operated wells (using an average of 60 non-operated rigs) for total drilling, completing and equipping costs of $3.380 billion.
During the second half of 2008 and in early 2010, we entered into joint venture arrangements that monetized a portion of our investment in five of our shale plays and provided drilling cost carries for our retained interest.
Joint venture partners include Plains Exploration & Production Company (PXP), BP America (BP), Statoil (STO) and Total S.A. (TOT).
In September of 2009, PXP accelerated the payment of its remaining joint venture carries in exchange for an approximate 12% reduction to the total amount of drilling carry obligations due to Chesapeake.
Collectively, in these four joint ventures, we received upfront cash payments of $4.8 billion and future drilling cost carries of up to $5.9 billion for total consideration of up to $10.7 billion against a cost basis of approximately $2.7 billion in the property interests we sold. Moreover, Chesapeake retained an 80% interest in the Haynesville and Bossier Shale properties, a 75% interest in the Fayetteville Shale properties, a 67.5% interest in the Marcellus Shale properties and a 75% interest in the Barnett Shale properties.
In September 2009, we formed a joint venture with Global Infrastructure Partners (GIP), a New York-based private equity fund, to own and operate natural gas midstream assets. As part of the transaction, we contributed substantially all of our midstream assets in the Barnett Shale and also the majority of our non-shale midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins to a new entity, Chesapeake Midstream Partners, L.L.C. (CMP), and GIP purchased a 50% interest in CMP for $588 million in cash.
Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118 and our main telephone number at that location is (405) 848-8000. We make available free of charge on our website at www.chk.com our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. From time to time, we also post announcements, updates and investor information on our website in addition to copies of all recent press releases. References to “us”, “we” and “our” in this report refer to Chesapeake Energy Corporation together with its subsidiaries.
Operating Areas
Chesapeake focuses its natural gas exploration, development and acquisition efforts in the eight operating areas described below.
Barnett Shale. Chesapeake’s Barnett Shale proved reserves represented 3.434 tcfe, or 24%, of our total proved reserves as of December 31, 2009. During 2009, the Barnett Shale assets produced 238 bcfe, or 26%, of our total production, and we invested approximately $1.197 billion to drill 417 (339 net) wells in the Barnett Shale. For 2010, we anticipate spending approximately $480 million, or 11% of our total budget, for exploration and development activities, net of carries, in the Barnett Shale. Total, our joint venture partner in the Barnett Shale, will pay 60% of our drilling, completion and equipping costs in the play over the next few years. Of the total $1.45 billion drilling cost carry, we expect approximately $500 million will be applied in 2010.
Fayetteville Shale. Chesapeake’s Fayetteville Shale proved reserves represented 2.167 tcfe, or 15%, of our total proved reserves as of December 31, 2009. During 2009, the Fayetteville Shale assets produced 91 bcfe, or 10%, of our total production, and we invested approximately $179 million to drill 774 (209 net) wells in the Fayetteville Shale. BP, our joint venture partner in the Fayetteville Shale, paid $601 million in carries of our drilling, completion and equipping costs on these wells in 2009. For 2010, we anticipate spending approximately $450 million, or 11% of our total budget, for exploration and development activities in the Fayetteville Shale.
Haynesville Shale (including the Bossier Shale). Chesapeake’s Haynesville Shale proved reserves represented 1.834 tcfe, or 13%, of our total proved reserves as of December 31, 2009. During 2009, the Haynesville Shale assets produced 85 bcfe, or 10%, of our total production, and we invested approximately $744 million to drill 337 (163 net) wells in the Haynesville Shale. Our joint venture partner in the Haynesville Shale, PXP, paid $390 million in carries of our drilling, completion and equipping costs on these wells in 2009 along with the $1.1 billion in September 2009 as a result of the amendment to the joint venture agreement. For 2010, we anticipate spending approximately $1.785 billion, or 42% of our total budget, for exploration and development activities in the Haynesville Shale.
Marcellus Shale. Chesapeake’s Marcellus Shale proved reserves represented 259 bcfe, or 2%, of our total proved reserves as of December 31, 2009. During 2009, the Marcellus Shale assets produced 15 bcfe, or 2%, of our total production, and we invested approximately $145 million to drill 149 (74 net) wells in the Marcellus Shale. Our joint venture partner in the Marcellus Shale, Statoil, paid $162 million in carries of our drilling, completion and equipping costs on these wells in 2009. For 2010, we anticipate spending approximately $360 million, or 8% of our total budget, for exploration and development activities, net of carries, in the Marcellus Shale. Statoil will pay 75% of our drilling, completion and equipping costs in the play over the next few years. Of the total $1.963 billion drilling cost carry remaining at December 31, 2009, we expect approximately $600 million will be applied in 2010.
Mid-Continent. Chesapeake’s Mid-Continent proved reserves of 4.098 tcfe represented 29% of our total proved reserves as of December 31, 2009. During 2009, this area produced 305 bcfe, or 34%, of our 2009 production, and we invested approximately $712 million to drill 386 (144 net) wells in the Mid-Continent. For 2010, we anticipate spending approximately $800 million, or 19% of our total budget, for exploration and development activities in the Mid-Continent region, with an increased focus on the Granite Wash and other horizontal oil and liquids-rich unconventional plays.
Permian and Delaware Basins. Chesapeake’s Permian and Delaware Basin proved reserves represented 741 bcfe, or 5%, of our total proved reserves as of December 31, 2009. During 2009, the Permian assets produced 75 bcfe, or 8%, of our total production, and we invested approximately $322 million to drill 93 (42 net) wells in the Permian and Delaware Basins. For 2010, we anticipate spending approximately $175 million, or 4% of our total budget, for exploration and development activities in the Permian and Delaware Basins, with an increased focus on various horizontal oil and liquids-rich unconventional plays.
South Texas/Gulf Coast/Ark-La-Tex (including the Eagle Ford Shale). The proved reserves of our South Texas/Texas Gulf Coast/Ark-La-Tex regions represented 565 bcfe, or 4%, of our total proved reserves as of December 31, 2009. During 2009, these assets produced 67 bcfe, or 7%, of our total production, and we invested approximately $197 million to drill 41 (25 net) wells in the South Texas/Texas Gulf Coast/Ark-La-Tex regions. For 2010, we anticipate spending approximately $200 million, or 5% of our total budget, for exploration and development activities in the South Texas/Texas Gulf Coast/Ark-La-Tex regions, especially in the Eagle Ford Shale of South Texas.
Appalachian Basin (excluding the Marcellus Shale). Chesapeake’s Appalachian Basin proved reserves represented 1.156 tcfe, or 8%, of our total proved reserves as of December 31, 2009. During 2009, the Appalachian assets produced 30 bcfe, or 3%, of our total production, and we invested approximately $44 million to drill 9 (7 net) wells in the Appalachian Basin. For 2010, we do not anticipate spending capital for exploration and development activities in the Appalachian Basin, except for our Marcellus Shale activities.
Well Data
At December 31, 2009, we had interests in approximately 44,100 (22,900 net) productive wells, including properties in which we held an overriding royalty interest, of which 36,950 (20,700 net) were classified as primarily natural gas productive wells and 7,150 (2,200 net) were classified as primarily oil productive wells. Chesapeake operates approximately 25,150 of its 44,100 productive wells. During 2009, we drilled 1,212 (885 net) wells and participated in another 994 (118 net) wells operated by other companies. We operate approximately 80% of our current daily production volumes.
Marketing, Gathering and Compression
Marketing
Chesapeake Energy Marketing, Inc., one of our wholly-owned subsidiaries, provides natural gas and oil marketing services, including commodity price structuring, contract administration and nomination services for Chesapeake, its partners and other producers. We attempt to enhance the value of our natural gas production by aggregating natural gas to be sold to natural gas marketers and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received for our production.
Our oil production is generally sold under market sensitive or spot price contracts. The revenue we receive from the sale of natural gas liquids is included in oil sales.
Our natural gas production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. By the terms of the percentage-of-proceeds contracts, we receive a percentage of the resale price received by the purchaser for sales of residue gas and natural gas liquids recovered after transportation and processing of our natural gas. These purchasers sell the residue gas and natural gas liquids based primarily on spot market prices. Under percentage-of-index contracts, the price per mmbtu we receive for our natural gas is tied to indexes published in Inside FERC or Gas Daily. Although exact percentages vary daily, as of February 2010, approximately 80% of our natural gas production was sold under short-term contracts at market-sensitive prices.
During 2009, sales to EDF Trading North America LLC (formerly Eagle Energy Partners, I, L.P.) of $571 million accounted for 10% of our total revenues (excluding gains (losses) on derivatives). In 2007, we sold our 33% limited partnership interest in Eagle Energy Partners I, L.P., which we first acquired in 2003, for proceeds of $124 million and a gain of $83 million. Management believes that the loss of this customer would not have a material adverse effect on our results of operations or our financial position. No other customer accounted for more than 10% of total revenues (excluding gains (losses) on derivatives) in 2009.
Our marketing activities constitute a reportable segment under accounting guidance for disclosure about segments of an enterprise and related information. See Note 17 of the notes to our consolidated financial statements in Item 8.
Midstream Gathering Operations
Chesapeake invests in gathering systems and processing facilities to complement our natural gas operations in regions where we have significant production and additional infrastructure is required. By doing so, we are better able to manage the value received for and the costs of, gathering, treating and processing natural gas. These systems are designed primarily to gather company production for delivery into major intrastate or interstate pipelines. In addition, our midstream business provides services to third-party customers. Chesapeake generates revenues from its gathering, treating and compression activities through fixed-rate fee structures. The company also processes a portion of its natural gas at various third-party plants.
Our midstream assets were held in various wholly-owned subsidiaries of Chesapeake until February 2008 when we transferred our non-Appalachian midstream assets to our wholly-owned subsidiary Chesapeake Midstream Development, L.P. (CMD) and its subsidiaries. In September 2009, we formed a joint venture with Global Infrastructure Partners (GIP) to own and operate natural gas midstream assets. As part of the transaction, we contributed certain natural gas gathering systems that had been held by CMD and its subsidiaries to a new entity, Chesapeake Midstream Partners, L.L.C. (CMP) and GIP purchased a 50% interest in CMP for $588 million in cash. The accounting for the joint venture is described in Note 11 of the consolidated financial statements included in this report. The assets we contributed to the joint venture were substantially all of our midstream assets in the Barnett Shale and also the majority of our non-shale midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. Together, these assets constituted approximately 57% of our total midstream assets as of September 30, 2009.
Subsidiaries of CMD continue to operate our midstream assets outside of the CMP joint venture. These include natural gas gathering assets in the Fayetteville Shale, Haynesville Shale, Marcellus Shale and other areas in Appalachia. Compared to the Barnett Shale and Mid-Continent areas where the CMP midstream assets are located, these are less developed areas and will require significant build-out capital expenditures. A source of liquidity for this business is the $250 million revolving credit facility described under Liquidity and Capital Resources in Item 7 below. The CMD systems, which are located in Oklahoma, Texas, Colorado, New Mexico, New York, Ohio, Maryland, Louisiana, Arkansas, Pennsylvania and West Virginia, consist of approximately 1,500 miles of gathering pipelines, servicing over 900 natural gas wells.
On February 16, 2010, Chesapeake Midstream Partners, L.P. (the Partnership) filed a registration statement on Form S-1 with the SEC relating to a proposed underwritten initial public offering of common units, representing limited partnership interests in the Partnership. The Partnership was formed by Chesapeake and GIP, equal indirect owners of the general partner of the Partnership, to own, operate, develop and acquire midstream assets. Upon the closing of the offering, Chesapeake and GIP will contribute CMP’s interests to the Partnership and the Partnership will continue CMP’s business. It is expected that the Partnership will succeed to CMP’s $500 million revolving credit facility, with certain amendments, and a portion of the proceeds of the offering will be used to repay the outstanding borrowings under the midstream joint venture revolving credit facility described under Liquidity and Capital Resources in Item 7 below.
Compression
Since 2003, Chesapeake has expanded its compression business. Our wholly-owned subsidiary, MidCon Compression, L.L.C., operates wellhead and system compressors to facilitate the transportation of our natural gas production. In a series of transactions in 2007, 2008 and 2009, MidCon sold a significant portion of its compressor fleet, consisting of 1,685 compressors, for $370 million and entered into a master lease agreement. These transactions were recorded as sales and operating leasebacks. During 2010, we expect to take delivery of 324 new compressors that are on order for approximately $100 million, and we intend to simultaneously enter into sale/leaseback transactions with financial counterparties as the compressors are delivered, if acceptable leasing arrangements are available to us.
Service Operations
Drilling
Securing available rigs is an integral part of the exploration process and therefore owning our own drilling company is a strategic advantage for Chesapeake. In 2001, Chesapeake formed its wholly-owned drilling subsidiary, Nomac Drilling Corporation, with an investment of $26 million to build and refurbish five drilling rigs. As of December 31, 2009, Chesapeake had invested approximately $897 million to build or acquire 98 drilling rigs. In a series of transactions in 2006, 2007 and 2008, our drilling subsidiaries sold 83 rigs for $677 million and subsequently leased back the rigs through 2018. The drilling rigs have depth ratings between 3,000 and 25,000 feet and range in drilling horsepower from 525 to 2,000. These drilling rigs are currently operating in Oklahoma, Texas, Arkansas, Louisiana and Appalachia. Chesapeake is the fourth largest drilling rig contractor in the U.S.
Trucking
In 2006, Chesapeake expanded its service operations by acquiring two privately-owned oilfield trucking service companies. We now own one of the largest oilfield and heavy haul transportation companies in the industry. Our trucking business is utilized primarily to transport drilling rigs for both Chesapeake and third parties. Through this ownership, we are better able to manage the movement of our rigs. As of December 31, 2009, our fleet included 255 trucks and 19 cranes, which mainly service the Mid-Continent, Barnett Shale and Appalachian regions.
Seasonal Nature of Business
Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can lessen seasonal demand fluctuations. World weather and resultant prices for LNG can also affect deliveries of competing LNG into this country from abroad, affecting the price of domestically produced natural gas.
Competition
We compete with both major integrated and other independent natural gas and oil companies in acquiring desirable leasehold acreage, producing properties and the equipment and expertise necessary to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than ours. The natural gas and oil industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported LNG. Competitive conditions may be affected by future legislation and regulations as the U.S. develops new energy and climate-related policies. In addition, some of our larger competitors may have a competitive advantage when responding to factors that affect demand for natural gas and oil production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities, and overall economic conditions. We believe that our technological expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively.
Hedging Activities
We utilize hedging strategies to hedge the price of a portion of our future natural gas and oil production and to manage interest rate exposure. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Regulation
General. All of our operations are conducted onshore in the United States. The U.S. natural gas and oil industry is regulated at the federal, state and local levels, and some of the laws, rules and regulations that govern our operations carry substantial penalties for noncompliance. These regulatory burdens increase our cost of doing business and, consequently, affect our profitability.
Regulation of Natural Gas and Oil Operations. Our exploration and production operations are subject to various types of regulation at the U.S. federal, state and local levels. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation include, but are not limited to:
• the location of wells;
• the method of drilling and completing wells;
• the surface use and restoration of properties upon which wells are drilled;
• the plugging and abandoning of wells;
• the disposal of fluids used or other wastes generated in connection with operations;
• the marketing, transportation and reporting of production; and
• the valuation and payment of royalties.
Our operations are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells that may be drilled in a particular area) and the unitization or pooling of natural gas and oil properties. In this regard, some states, such as Oklahoma, allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas and New Mexico rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and therefore, more difficult to fully develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from natural gas and oil 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 natural gas and oil we can produce and to limit the number of wells and the locations at which we can drill.
Chesapeake operates a number of natural gas gathering systems. The U.S. Department of Transportation and certain state agencies regulate the safety and operating aspects of the transportation and storage activities of these facilities. There is currently no price regulation of the company’s sales of oil, natural gas liquids and natural gas, although governmental agencies may elect in the future to regulate certain sales.
We do not anticipate that compliance with existing laws and regulations governing exploration, production and natural gas gathering will have a material adverse effect upon our capital expenditures, earnings or competitive position.