Description
Chesapeake Energy Corporation. Director MERRILL A JR MILLER bought 27,700 shares on 6-27-2012 at $ 18
BUSINESS OVERVIEW
Our Business
We are the second-largest producer of natural gas and a top 20 producer of oil and natural gas liquids in the U.S. We own interests in approximately 46,000 producing natural gas and oil wells that are currently producing approximately 3.0 billion cubic feet of natural gas equivalent (bcfe) per day, 87% of which is natural gas. Our strategy is focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S., primarily in the Barnett Shale in the Fort Worth Basin of north-central Texas, the Haynesville and Bossier Shales in northwestern Louisiana and East Texas, the Fayetteville Shale in the Arkoma Basin of central Arkansas and the Marcellus Shale in the northern Appalachian Basin of West Virginia and Pennsylvania. We also have substantial operations in the liquids-rich plays of the Eagle Ford Shale in South Texas, the Granite Wash, Cleveland, Tonkawa and Mississippian plays in the Anadarko Basin in western Oklahoma and the Texas Panhandle, the Niobrara Shale, Frontier and Codell plays in the Powder River and Denver Julesburg (DJ) Basins of Wyoming and Colorado and the Avalon, Bone Spring, Wolfcamp and Wolfberry plays in the Permian and Delaware Basins of West Texas and southern New Mexico, as well as various other plays, both conventional and unconventional, in the Mid-Continent, Williston Basin, Appalachian Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the U.S. We have also vertically integrated our operations and own substantial midstream, compression, drilling and oilfield service assets.
We have been developing expertise in horizontal drilling technology since shortly after our inception in 1989 and focused almost exclusively on developing natural gas properties in the U.S. from 2000 to 2008. We were one of the first companies to recognize the potential of horizontal drilling in unconventional natural gas reservoirs, especially shales, in the U.S. during the early part of the prior decade. During the past five years, we have grown from the sixth-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.
In 2010, we announced that we were extending our strategy to apply the geoscientific and horizontal drilling expertise we had developed in our unconventional natural gas plays to unconventional liquids-rich reservoirs. Our goal is to reach a balanced mix of natural gas and liquids revenue as quickly as possible through organic drilling. In 2010, we invested approximately $4.7 billion, net of divestitures, primarily in liquids-rich acreage to provide the foundation for this shift towards more profitable plays. This transition is already apparent in the mix of wells we are drilling. In 2010, approximately 30% of our drilling and completion capital expenditures were allocated to liquids-rich plays, compared to 10% in 2009 and a projected 50% in 2011 and 75% in 2012. Our production of oil and natural gas liquids was 50,397 barrels (bbls) per day during 2010, a 56% increase over the average for 2009, as a result of the increased development of our unconventional liquids-rich plays. As of December 31, 2010, the company held approximately 4.3 million net leasehold acres in unconventional liquids-rich plays.
During 2010, our estimated proved reserves grew from 14.254 trillion cubic feet of natural gas equivalent (tcfe) to 17.096 tcfe, of which 90% was natural gas, 53% was proved developed and 100% was onshore in the U.S. We replaced our 1.035 tcfe of 2010 production with an estimated 3.877 tcfe of new proved reserves for a reserve replacement rate of 375%. The 2010 proved reserve movement included 5.098 tcfe of extensions, 0.006 tcfe of downward performance revisions and 0.189 tcfe of positive revisions resulting from an increase in the twelve-month trailing average natural gas and oil prices between December 31, 2009 and December 31, 2010. During 2010, we acquired 0.089 tcfe of estimated proved reserves and divested 1.493 tcfe of estimated proved reserves.
Chesapeake continued the industry’s most active drilling program in 2010 and drilled 1,445 gross (938 net) operated wells and participated in another 1,586 gross (211 net) wells operated by other companies. The company’s drilling success rate was 98% for both company-operated and non-operated wells. Also during 2010, we invested $4.6 billion in operated wells (using an average of 131 operated rigs) and $815 million in non-operated wells (using an average of 123 non-operated rigs) for total drilling and completion costs of $5.4 billion, net of drilling and completion carries of $1.2 billion.
Daily production for 2010 averaged 2.836 bcfe, an increase of 355 million cubic feet of natural gas equivalent (mmcfe) or 14%, over the 2.481 bcfe of daily production for 2009 and consisted of 2.534 billion cubic feet of natural gas (bcf) (89% on a natural gas equivalent basis) and 50,397 bbls (11% on a natural gas equivalent basis). This was our 21st consecutive year of sequential production growth.
Information About Us
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, events, investor information and presentations 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.
Recent Developments
25/25 Plan
In January 2011, we updated our strategic and financial plan originally announced in May 2010 with our “25/25 Plan”. The 25/25 Plan details our intention to reduce our outstanding long-term indebtedness of $13.4 billion by 25% by the end of 2012 and to reduce our planned two-year net production growth rate to 25% from the previous target range of 30% to 40%. The reduction in our projected production growth rate will be achieved by various asset monetizations that we plan to execute during the next two years, including our Fayetteville Shale and Niobrara Shale divestitures described below.
Senior Notes Offering
On February 11, 2011, we issued $1.0 billion of 6.125% Senior Notes due 2021. We used the net proceeds of $977 million from the offering to repay indebtedness outstanding under our revolving bank credit facility. The offering is a part of our 2011 liability management program, which includes extending the maturity profile of our outstanding indebtedness while also retiring approximately $2.0 to $3.0 billion of our shorter-dated senior notes as part of our 25/25 Plan.
Fayetteville Shale, Frac Tech Holdings, LLC and Chaparral Energy, Inc. Asset Monetizations
On February 21, 2011, we entered into an agreement with BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Limited (NYSE: BHP; ASX: BHP), to sell all of our Fayetteville Shale assets, including approximately 487,000 net acres of leasehold and producing natural gas properties and midstream assets with approximately 420 miles of pipeline, for $4.75 billion in cash before certain deductions and standard closing adjustments. In the Fayetteville Shale, we are the second-largest producer of natural gas with current net production of approximately 415 mmcfe per day. Estimated proved reserves attributable to the Fayetteville Shale as of December 31, 2010 were 2.4 tcfe, or approximately 14% of our total proved reserves. As part of the transaction, we have agreed to provide essential services for up to one year for BHP Billiton for an agreed-upon fee. Closing of the transaction is subject to customary conditions, including filings under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and with the Committee on Foreign Investment in the United States. Closing is expected to occur in the first half of 2011. In addition, we have commenced efforts to monetize our equity investments in Frac Tech Holdings, LLC and Chaparral Energy, Inc. We own a 25.8% equity interest in Frac Tech and a 20.0% equity interest in Chaparral. These sales are subject to changes in market conditions and other factors, and there can be no assurance that we will complete either or both of these transactions on a timely basis or at all.
Niobrara Industry Participation Agreement
On February 16, 2011, we entered into an industry participation agreement with a wholly owned U.S. subsidiary of CNOOC Limited (CNOOC) to develop our Niobrara Shale play in the DJ and Powder River Basins in northeast Colorado and southeast Wyoming. Under the terms of the industry participation agreement, CNOOC acquired a 33.3% undivided interest in approximately 800,000 net acres of our leasehold. We received $570 million in cash at closing, and CNOOC has agreed to fund 66.7% of our share of drilling and completion costs until an additional $697 million has been paid, which we expect to occur by year-end 2014. In addition, CNOOC has the right to a 33.3% participation in any additional leasehold we acquire in the area at cost plus a fee.
Business Strategy
Since our inception in 1989, Chesapeake’s goal has been to create value for investors by building one of the largest onshore resource bases in the U.S. by focusing our technical and land acquisition skills on developing unconventional resource plays onshore in the U.S. From 2000 through 2008, our focus was on finding and developing natural gas resource plays. In the past two years, our focus has shifted to finding and developing plays with oil and natural gas liquids (NGL) since oil and NGLs are more highly valued in the U.S. than natural gas and technological and knowledge advances have enabled us to pursue these new plays more economically. Key elements of this business strategy are further explained below.
Grow Through the Drillbit . We believe that our most distinctive characteristic is our commitment and ability to grow production and reserves organically through the drillbit in areas with large unconventional accumulations of natural gas, oil and NGLs. We are currently utilizing 157 operated drilling rigs and 106 non-operated drilling rigs to conduct the most active drilling program in the U.S. We are active in most of the nation’s major unconventional plays, where we drill more horizontal wells than any other company in the industry. For many years, we have been actively investing large amounts of capital in leasehold, 3-D seismic information and human resources to take full advantage of our capacity to grow through the drillbit. We are one of the few large-cap independent natural gas and oil companies that have been able to consistently increase production, which we have successfully achieved for 21 consecutive years. We believe the key elements of the success and scale of our drilling programs have been our recognition earlier than most of our competitors that new horizontal drilling and completion techniques would enable development of previously uneconomic natural gas and oil reservoirs and that, as a consequence, various shale and other unconventional formations could be recognized and developed as potentially prolific reservoirs rather than just as source rocks for conventional reservoirs. In response to our early recognition of these trends, we have proactively hired thousands of new employees and have built what we believe is the largest combined inventory of onshore leasehold and 3-D seismic in the U.S. These are the building blocks of our successful large-scale drilling program and the foundation of value creation for our company.
Control Substantial Land and Drilling Location Inventories. After we identified the trends discussed above, we initiated a plan to build and maintain the largest inventory of onshore drilling opportunities in the U.S. Recognizing that better horizontal drilling and completion technologies, when applied to various new unconventional plays, would likely create a unique opportunity to capture decades worth of drilling opportunities, we embarked on an aggressive lease acquisition program, which we have referred to as the “gas shale land grab” of 2006 through 2008 and the “unconventional oil land grab” of 2009 and 2010. We believed that the winner of these land grabs would enjoy competitive advantages for decades to come as other companies would be locked out of the best new unconventional resource plays in the U.S. We believe that we have executed our land acquisition strategy with particular distinction. At December 31, 2010, we held approximately 13.2 million net acres of onshore leasehold in the U.S. and have identified approximately 38,000 drilling opportunities on this leasehold. We believe this extensive backlog of drilling, more than ten years worth at current drilling levels, provides unmistakable evidence of our future growth capabilities. We further believe that the majority of the U.S.-based land acquisition phase is now complete and are forecasting to spend significantly less on new leasehold in the coming periods as compared to recent years.
Develop Proprietary Technological Advantages . In addition to our industry-leading leasehold position, we have developed a number of proprietary technological advantages. First, we have acquired what we believe is the nation’s largest inventory of three-dimensional (3-D) seismic information. Possessing this 3-D seismic data enables us to image reservoirs of natural gas and oil that might otherwise remain undiscovered and to drill our horizontal wells more accurately inside the targeted formation and avoid various underground geohazards such as faults and karsts. In addition, we have developed an industry-leading information-gathering program that gives us insight into new plays and competitor activity. As a result of our initiatives, we now produce approximately 5% of the nation’s natural gas and oil, drill approximately 9% of its wells and participate in almost an equal number of wells drilled by others. By gathering this information on a real-time basis, then quickly assimilating and analyzing the information, we are able to react quickly to opportunities that are created through our drilling program and those of our competitors. Furthermore, we have established a unique state-of-the-art Reservoir Technology Center (RTC) in Oklahoma City. The RTC enables us to more quickly, accurately and confidentially analyze core data from wells drilled through unconventional formations on a proprietary basis, then identify new plays and leasing opportunities ahead of our competition and reduce the likelihood of investing in plays that ultimately are not commercial. It also allows us to design fracture stimulation procedures that might work most productively in the unconventional formations that we target.
Build Operating Focus and Scale . We believe one of the keys to success in the U.S. exploration and production industry is to build significant operating scale in areas that share many similar geological and operational characteristics. Achieving such scale provides many benefits, including superior geoscientific and engineering information, higher per unit revenues, lower per unit operating costs, greater rates of drilling success, higher returns from more easily integrated acquisitions and higher returns on drilling investments. By focusing most of our future activities in virtually all of the nation’s major unconventional resource plays and avoiding investing offshore and internationally, we will continue to achieve the significant benefits of focus and scale.
Focus on Low Costs and Vertical Integration . By minimizing lease operating costs and general and administrative expenses through focused activities, vertical integration and increasing scale, we have been able to deliver attractive profit margins and financial returns through all phases of the commodity price cycle. We believe our low cost structure is the result of management’s effective cost-control programs, a high-quality asset base and extensive access to oilfield services and to natural gas processing and transportation infrastructures that exist in our key operating areas. In addition, to control costs and service provider quality, we have made significant investments in our drilling rig, compression and trucking service operations and in our midstream gathering operations that create substantial benefits from vertical integration. In 2011 and 2012, we also intend to make significant investments in building our capability to hydraulically fracture our wells. As of December 31, 2010, we operated approximately 26,000 of our 46,000 wells, which delivered approximately 80% of our daily production volume. This large percentage of operated properties provides us with a high degree of operational flexibility and cost control.
Mitigate Natural Gas and Oil Price Risk . We have used and intend to continue using hedging programs to mitigate the risks inherent in developing and producing natural gas and oil reserves, commodities that are often subject to significant price volatility. We intend to use this volatility to our benefit by taking advantage of prices when they reach levels that management believes are either unsustainable for the long term or provide unusually high rates of return on our invested capital. Assuming future NYMEX natural gas settlement prices average $4.50 per mcf for 2011, and including the effect of the company’s open derivatives as of February 22, 2011, closed contracts and previously collected call premiums, the company estimates its average natural gas price will be $5.98 per mcf for 2011. This estimate does not include the effect of basis differentials and gathering costs.
Form Value-Creating Industry Participation Agreements . Since 2008, the company has entered into six significant industry participation agreements. Through these agreements, the company has collaborated with other leading energy companies to accelerate the development of the company’s properties in the Haynesville and Bossier Shales, the Fayetteville Shale, the Marcellus Shale, the Barnett Shale, the Eagle Ford Shale and the Niobrara Shale. Including the Niobrara agreement, which we entered into on February 16, 2011, we have sold leasehold and producing property assets with an original cost to us of approximately $3.4 billion to our partners for $6.5 billion of total cash consideration and $7.7 billion of drilling cost carries while retaining a majority interest in each play. The remaining drilling cost carries of approximately $4.0 billion (including the Niobrara industry participation agreement), as of December 31, 2010, will be extremely valuable in the years ahead by enabling the company to develop reserves in these unconventional plays at greatly reduced costs. We are also considering opportunities for additional industry participation agreements to develop certain of our other properties. Additionally, in 2009 we formed a joint venture with GIP for certain of our midstream assets in the Barnett Shale and Mid Continent. We and GIP have since sold a portion of the equity in this venture to the public through a master limited partnership, Chesapeake Midstream Partners, L.P.
Maintain an Entrepreneurial Culture. Chesapeake was formed in 1989 with an initial capitalization of $50,000 and fewer than ten employees. We completed our initial public offering of common stock in early 1993 and subsequent to those early corporate milestones, our management team has guided the company through various operational and industry challenges and opportunities and extremes of natural gas and oil prices to create the nation’s second-largest producer of natural gas, a top 20 producer of oil and natural gas liquids, the most active driller of new wells and an employer of approximately 10,000 people and an indirect employer of tens of thousands more. The company takes pride in its innovative and aggressive implementation of its business strategy and strives to be as entrepreneurial today as it has been in its past. We have maintained an unusually flat organizational structure as we have grown to help ensure that important information travels rapidly through the company and decisions are made and implemented quickly.
Improve our Balance Sheet. Our 2011 strategic and financial plan calls for a 25% reduction in our long-term debt while growing net natural gas and oil production by 25% by the end of 2012. We believe this reduction of our debt and continued growth in our asset base will lead to our long-term debt to reserves ratio (long-term debt net of cash divided by our estimated proved reserves) decreasing to less than $0.50 per mcfe at year-end 2012 compared to $0.73 per mcfe at year-end 2010. We believe the reduction in our debt will lower our borrowing costs, increase our financial flexibility and increase our stock market valuation. Additionally, we believe our improved credit metrics described above will lead to a more favorable debt rating by the major ratings agencies.
Operating Areas
Chesapeake focuses its exploration, development, acquisition and production efforts in the nine operating areas described below.
Mid-Continent (principally the Anadarko Basin). Chesapeake’s Mid-Continent proved reserves of 4.867 tcfe represented 28% of our total proved reserves as of December 31, 2010. During 2010, this area produced 316 bcfe, or 31%, of our 2010 production, and we invested approximately $1.1 billion to drill 596 (212 net) wells in the Mid-Continent. For 2011, we anticipate spending approximately $1.7 billion, or 33% of our total budget, for exploration and development activities in the Mid-Continent region, with a continuing focus on the Granite Wash and an increasing focus on the Tonkawa, Cleveland and Mississippian liquids-rich unconventional plays.
CEO BACKGROUND
Aubrey K. McClendon, 52, has served as Chairman of the Board and Chief Executive Officer since co-founding the Company in 1989. Mr. McClendon has also served as a director of the general partner of Chesapeake Midstream Partners, L.P. (NYSE:CHKM) since 2010. From 1982 to 1989, Mr. McClendon was an independent producer of natural gas and oil. Mr. McClendon graduated from Duke University in 1981.
As our co-founder, Chairman and CEO, Mr. McClendon sets the strategic direction of our Company with the guidance of the Board of Directors and serves as the Company’s spokesman to its shareholders and other constituencies. Mr. McClendon’s extensive knowledge of the Company and experience in the energy industry make him an invaluable asset to the Board.
Don Nickles, 63, has been a member of our Board of Directors since 2005. Senator Nickles is the founder and President of The Nickles Group, a consulting and business venture firm in Washington, D.C. Senator Nickles was elected to represent Oklahoma in the United States Senate from 1980 to 2005 where he held numerous leadership positions, including Assistant Republican Leader from 1996 to 2003 and Chairman of the Senate Budget Committee from 2003 to 2005. Senator Nickles also served on the Senate Energy and Natural Resources Committee and the Senate Finance Committee. Prior to his service in the U.S. Senate, Senator Nickles served in the Oklahoma State Senate from 1979 to 1980 and worked for Nickles Machine Corporation in Ponca City, Oklahoma, becoming Vice President and General Manager. Senator Nickles is also a director of Valero Energy Corporation (NYSE:VLO), an independent oil refiner headquartered in San Antonio, Texas and Washington Mutual Investors Fund (WMIF). Senator Nickles served in the National Guard from 1970 to 1976 and graduated from Oklahoma State University in 1971.
Senator Nickles’ 24 years of service as a U.S. Senator, including his chairmanship of the Senate Budget Committee as well as service on the Senate Energy and Natural Resources Committee and the Senate Finance Committee, have given him valuable experience and perspective on many of the major issues we face as a publicly traded energy company and insight into past and potential international, national and state energy policy and other public policy and taxation issues. Additionally, his service on Valero’s board of directors has given him valuable exposure to the downstream energy sector and domestic energy supply and demand.
Kathleen M. Eisbrenner, 51, has been a member of our Board of Directors since December 2010. Ms. Eisbrenner is the founder and has been Chief Executive Officer of Next Decade since June 2010, a company that is creating new opportunities in the integrated international liquefied natural gas (LNG) industry. Prior to organizing Next Decade, she served as the head of Houston-based Poten & Partners’ Project Development Group from March 2010 to June 2010. Poten & Partners is a global broker and commercial advisor for the energy and ocean transportation industries and a recognized leader in the crude and petroleum products, LNG, liquefied petroleum gas (LPG), fuel oil, naphtha and asphalt market sectors. From September 2007 to December 2009, Ms. Eisbrenner was Executive Vice President responsible for Royal Dutch Shell plc’s Global LNG business. From 2003 to August 2007, she was founder, President and Chief Executive Officer of Excelerate Energy, a global importer and marketer of LNG. Ms. Eisbrenner also previously served in various senior leadership positions with other energy companies in the United States, including El Paso Corporation (NYSE:EP). Ms. Eisbrenner graduated from the University of Notre Dame in 1982.
Ms. Eisbrenner has nearly 30 years of experience in the energy industry. The executive and management experience she gained as President and Chief Executive Officer of Excelerate Energy, as well as that gained as an Executive Vice President with Royal Dutch Shell plc’s Global LNG business, give her experience and insight on many of the major issues we deal with regularly, such as finance, business strategy, technology, compensation, management development, acquisitions, capital allocation, risk management, corporate governance and shareholder relations. In addition, Ms. Eisbrenner’s extensive experience in the global LNG industry provides valuable expertise regarding world-wide markets for natural gas.
Louis A. Simpson , 75, has been a member of our Board of Directors since June 2011. He has been the Chairman of SQ Advisors, LLC since January 2011. Mr. Simpson served as President and Chief Executive Officer, Capital Operations, of GEICO Corporation (a subsidiary of Berkshire Hathaway Corporation) from 1993 until his retirement on December 31, 2010. From 1985 to 1993, he served as Vice Chairman of the Board of GEICO. Mr. Simpson joined GEICO in 1979 as Senior Vice President and Chief Investment Officer. Prior to joining GEICO, Mr. Simpson was President and Chief Executive Officer of Western Asset Management, a subsidiary of the Los Angeles, California-based Western Bancorporation. Previously, Mr. Simpson was a partner at Stein Roe and Farnham, a Chicago, Illinois investment firm, and an instructor of economics at Princeton University. Mr. Simpson has also served as a director of VeriSign, Inc. (NASDAQ:VRSN) since 2005 and as a director of SAIC, Inc. (NYSE:SAI) since 2006. He was previously a director of Western Asset Funds Inc. and Western Asset Income Fund and a trustee of Western Asset Premier Bond Fund until 2006. Mr. Simpson graduated from Ohio Wesleyan University in 1958 and from Princeton University in 1960.
Mr. Simpson’s unique blend of professional experiences, accomplishments and skills is invaluable to the Company. Mr. Simpson has had a long and distinguished career as one of our nation’s most accomplished investors. His experience as Chief Executive Officer, Capital Operations, of GEICO is of substantial benefit to the Company and will help us continue to build significant intrinsic value per share. Mr. Simpson has also served as a director of numerous public companies, which allows him to bring insights into many of the major issues that we deal with regularly, such as finance, business strategy, technology, compensation, management development, acquisitions, capital allocation, risk management, corporate governance and shareholder relations.
Frank Keating, 68, has been a director of the Company since 2003. Governor Keating has been the President and Chief Executive Officer of the American Bankers Association, a large trade organization based in Washington, D.C., since January 2011. Governor Keating previously served as President and Chief Executive Officer of the American Council of Life Insurers from January 2003 to December 2010. Governor Keating became a special agent in the Federal Bureau of Investigation in 1969 and then served as Assistant District Attorney in Tulsa County, Oklahoma. In 1972, Governor Keating was elected to the Oklahoma State House of Representatives and two years later was elected to the Oklahoma State Senate. In 1981, Governor Keating was appointed as the U.S. Attorney for the Northern District of Oklahoma and in 1985, he began seven years of service in the Ronald Reagan and George H.W. Bush administrations, serving as Assistant Secretary of the Treasury, Associate Attorney General in the Justice Department and General Counsel and Acting Deputy Secretary of the Department of Housing and Urban Development. In 1994, Governor Keating was elected Oklahoma’s 25 th Governor and served two consecutive four-year terms. He was chairman of the Interstate Oil and Gas Commerce Commission during his term as governor. Governor Keating is an advisory director of Stewart Information Services Corporation (NYSE:STC), a real estate information and transaction management company located in Houston, Texas. Governor Keating graduated from Georgetown University in 1966 and from the University of Oklahoma College of Law in 1969.
Through his service as Governor, Senator, a member of the House of Representatives of Oklahoma, senior-level U.S. government appointments, and other appointments and positions, Governor Keating has valuable experience and knowledge regarding many of the major issues we face as a publicly traded energy company. He has extensive experience with national and state energy policy and other public policy matters. Governor Keating’s other board and management positions have given him exposure to different industries, approaches to governance and other key issues. Additionally, Governor Keating gained specific, first-hand knowledge of the energy industry and management of energy assets through management of his family’s oil and gas interests.
Merrill A. (“Pete”) Miller, Jr., 61, has been a director of the Company since 2007 and our Lead Independent Director since March 2010. Mr. Miller is Chairman, President and Chief Executive Officer of National Oilwell Varco, Inc. (NYSE:NOV), a supplier of oilfield services, equipment and components to the worldwide oil and natural gas industry. Mr. Miller joined NOV in 1996 as Vice President of Marketing, Drilling Systems and was promoted in 1997 to President of the company’s products and technology group. In 2000, he was named President and Chief Operating Officer, in 2001 was elected President and Chief Executive Officer and in 2002 was also elected Chairman of the Board. Mr. Miller served as President of Anadarko Drilling Company from 1995 to 1996. Prior to his service at Anadarko, Mr. Miller spent fifteen years at Helmerich & Payne International Drilling Company (NYSE:HP) in Tulsa, Oklahoma, serving in various senior management positions, including Vice President, U.S. Operations. Mr. Miller graduated from the United States Military Academy, West Point, New York in 1972. Upon graduation, he served five years in the United States Army and received his MBA from Harvard Business School in 1980. Mr. Miller serves on the Board of Directors for the Offshore Energy Center, Petroleum Equipment Suppliers Association and Spindletop International, and is a member of the National Petroleum Council.
Mr. Miller has more than 30 years of management and executive experience in the oil and gas equipment and service industry. As a result of his positions as Chairman, President and Chief Executive Officer of NOV and various other executive, financial and management positions, Mr. Miller has valuable experience in managing many of the major issues that we deal with regularly, such as finance, business strategy, technology, compensation, management development, acquisitions, capital allocation, risk management, corporate governance and shareholder relations. Additionally, in Mr. Miller’s current position with NOV, he has particularly valuable insight into issues affecting the global energy environment, including global energy supply and demand and trends affecting oilfield service costs both globally and domestically. Mr. Miller also has extensive financial and accounting expertise and is one of our Audit Committee financial experts.
MANAGEMENT DISCUSSION FROM LATEST 10K
Executive Summary
We are the second-largest producer of natural gas and a top 20 producer of oil and natural gas liquids in the U.S. We own interests in approximately 46,000 producing natural gas and oil wells that are currently producing approximately 3.0 bcfe per day, 87% of which is natural gas. Our strategy is focused on discovering and developing unconventional natural gas and oil fields onshore in the U.S., primarily in the Barnett Shale in the Fort Worth Basin of north-central Texas, the Haynesville and Bossier Shales in northwestern Louisiana and East Texas, the Fayetteville Shale in the Arkoma Basin of central Arkansas, and the Marcellus Shale in the northern Appalachian Basin of West Virginia and Pennsylvania. We also have substantial operations in the liquids-rich plays of the Eagle Ford Shale in South Texas, the Granite Wash, Cleveland, Tonkawa and Mississippian plays in the Anadarko Basin in western Oklahoma and the Texas Panhandle, the Niobrara Shale, Frontier and Codell plays in the Powder River and DJ Basins of Wyoming and Colorado and the Avalon, Bone Spring, Wolfcamp and Wolfberry plays in the Permian and Delaware Basins of West Texas and southern New Mexico, as well as various other plays, both conventional and unconventional, in the Mid-Continent, Williston Basin, Appalachian Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the U.S. We have also vertically integrated our operations and own substantial midstream, compression, drilling and oilfield service assets. As described below, we have agreed to sell our Fayetteville Shale assets in a transaction expected to close in the first half of 2011.
Chesapeake began 2010 with estimated proved reserves of 14.254 tcfe and ended the year with 17.096 tcfe, an increase of 2.842 tcfe, or 20%. During 2010, we replaced 1.035 tcfe of production with an estimated 3.877 tcfe of new proved reserves, for a reserve replacement rate of 375%. The 2010 proved reserve movement included 5.098 tcfe of extensions, 0.006 tcfe of downward performance revisions and 0.189 tcfe of positive revisions resulting from an increase in the twelve-month trailing average natural gas and oil prices between December 31, 2009 and December 31, 2010. During 2010, we acquired 0.089 tcfe of estimated proved reserves and divested 1.493 tcfe of estimated proved reserves.
Chesapeake continued the industry’s most active drilling program in 2010 and drilled 1,445 gross (938 net) operated wells and participated in another 1,586 gross (211 net) wells operated by other companies. The company’s drilling success rate was 98% for both company-operated and non-operated wells. Also during 2010, we invested $4.6 billion in operated wells (using an average of 131 operated rigs) and $815 million in non-operated wells (using an average of 123 non-operated rigs) for total drilling and completion costs of $5.4 billion, net of drilling and completion cost carries of $1.2 billion.
Our average daily production for 2010 of 2.836 bcfe consisted of 2.534 bcf (89% on a natural gas equivalent basis) and 50,397 bbls (11% on a natural gas equivalent basis) and was an increase of 355 mmcfe, or 14%, over the 2.481 bcfe of daily production for 2009. Total production for 2010 was 1,035 tcfe, an increase of 129.7 bcfe, or 14%, over 2009 total production of 905.5 bcfe. This was our 21st consecutive year of sequential production growth.
Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (13.3 million net acres) and 3-D seismic (27.9 million acres) in the U.S. This position includes the largest inventory of U.S. natural gas shale play leasehold (2.5 million net acres) as well as the largest combined leasehold position in two of the three largest new unconventional liquids-rich plays in the U.S. – the Eagle Ford Shale and the Niobrara Shale. We are currently using 157 operated rigs to further develop our inventory of approximately 37,800 net drillsites.
Implementing Our Strategy
In recognition of the value gap between oil and natural gas prices, during the past two years Chesapeake has directed a significant portion of its technological, geo-scientific, leasehold acquisition and drilling expertise to identifying, securing and commercializing new unconventional liquids-rich plays. This planned transition will result in a more balanced portfolio between natural gas and liquids. To date, we have built leasehold positions and established production in multiple unconventional liquids-rich plays on approximately 4.1 million net leasehold acres. In 2010, we invested approximately $4.7 billion, net of divestitures, primarily in liquids-rich acreage, and we allocated approximately 30% of our $5.4 billion drilling and completion capital expenditures to these plays, compared to 10% in 2009. Our production of oil and natural gas liquids was 50,397 bbls per day during 2010, a 56% increase over the average for 2009 as a result of the increased development of our unconventional liquids-rich plays. We are projecting that the portion of drilling and completion capital expenditures allocated to liquids development will reach 50% in 2011 and 75% in 2012, and we expect to increase our oil and natural gas liquids production through our drilling activities to more than 150,000 bbls per day, or 20%-25% of total production, by year-end 2012.
This shift to a greater emphasis on liquids production is a continuation of our general business strategy outlined in Item 1. Business . Our goal is to create value for investors by focusing on developing unconventional resource plays onshore in the U.S. We do so by:
•
Growing through the drillbit – We are the most active driller in the U.S., have our own fleet of 105 drilling rigs and are currently using 157 operated rigs. Our integrated marketing, gathering, compression and trucking services operations support our drilling activities so that we are able to manage the development of our leasehold efficiently and strategically.
•
Controlling substantial land and drilling location inventories and building regional scale – We have been first movers in capturing both natural gas and liquids-rich unconventional leasehold and resources. During 2010, we invested heavily in a large number of highly competitive liquids-rich unconventional plays in order to accelerate our transition to increased liquids production. We now have achieved many of our leasehold acquisition goals and are becoming a significant seller of leasehold through new industry participation agreements and the pending sale of our Fayetteville Shale assets.
•
Developing proprietary technological advantages – We support the scale of our operations with what we believe is the nation’s largest inventory of 3-D seismic information and our state-of-the-art Reservoir Technology Center, or RTC. The RTC provides us a substantial competitive advantage, enabling us among other things to more quickly, accurately and confidentially analyze core data from wells drilled through unconventional formations on a proprietary basis and then identify new plays and leasing opportunities ahead of our competition and reduce the likelihood of investing in plays that ultimately are not commercial. Our 3-D seismic data permits us to image reservoirs of natural gas and oil that might otherwise remain undiscovered and to drill our horizontal wells more accurately inside the targeted formation.
•
Focusing on low costs – We minimize lease operating costs and general and administrative expenses through focused activities, vertical integration and increasing scale. As of December 31, 2010, our operated wells accounted for approximately 80% of our daily production volume, providing us with a high degree of operational flexibility and cost control.
•
Mitigating natural gas and oil price risk – We actively seek to manage our exposure to adverse market prices for natural gas and oil through our hedging program. Hedging allows us to predict with greater certainty the effective prices we will receive for our hedged natural gas and oil production. Our realized cash hedging gains for 2010 were $2.056 billion and since January 1, 2001 have been $6.478 billion.
•
Using industry participation agreements – Through industry participation property sales, we have recouped substantially all of our lease acquisition costs in six of our significant unconventional operating areas, and we hold leasehold in new plays which we believe will be best developed through future industry participation agreements. In addition, drilling cost carries allow us to accelerate the development of new plays at a reduced cost to us. We pioneered the industry participation model of unconventional natural gas and oil development, and many other E&P companies have followed with their own industry participation agreements in the past two years.
Our strategic and financial plan for 2011-2012, announced on January 6, 2011 as our “25/25 Plan”, calls for a 25% reduction in our outstanding long-term debt while growing net natural gas and oil production by 25% by the end of 2012. We expect to achieve the reduction in debt through asset monetizations. Among the several benefits of lower debt are lower borrowing costs, and we believe improved credit metrics will lead to a more favorable debt rating by the major ratings agencies.
Our goal of a 25% reduction in debt by year-end 2012 is part of our liability management plan begun in 2010. During 2010, we issued in private placements 2.6 million shares of two series of our 5.75% Cumulative Non-Voting Convertible Preferred Stock resulting in net proceeds to us of approximately $2.562 billion. We used the net proceeds of these preferred stock offerings to redeem in whole $1.934 billion in principal amount of four series of our outstanding senior notes. Additionally, through tender offers followed by redemptions, we purchased $1.5 billion aggregate principal amount of three additional series of senior notes. We funded the purchase of the notes tendered and redeemed with proceeds from a $2.0 billion public offering of two series of senior notes. We retired all series of our outstanding senior notes that were issued under our more restrictive indentures. Excess funds from our offerings were used to repay borrowings outstanding under our corporate revolving bank credit facility.
During 2011, we plan to take steps to extend the maturity profile of our outstanding indebtedness at advantageous rates. On February 11, 2011, the company issued $1.0 billion principal amount of 6.125% Senior Notes due 2021 in a registered public offering. We applied the net proceeds of $977 million from the offering to our revolving bank credit facility balance and plan to use proceeds from asset sales to retire at least $2.0 - $3.0 billion of our shorter-dated senior notes and also to reduce borrowings under our revolving bank credit facility.
Asset monetizations were also key elements of our strategic and financial plan in 2010 and early 2011, as described below.
Other Asset Sales
In 2010, we sold non-core proved and unproved properties for proceeds of approximately $355 million. During 2010, as part of our industry participation agreements with Total, Statoil and PXP, we sold interests in additional leasehold in the Barnett, Marcellus and Haynesville Shale plays for proceeds of approximately $440 million that had an estimated original cost to us of $220 million. The cash proceeds from these transactions are reflected as a reduction of natural gas and oil properties with no gain or loss recognized.
Chesapeake Midstream Partners, L.P. IPO and Asset Sale
On August 3, 2010, Chesapeake Midstream Partners, L.P. (NYSE: CHKM), which we and GIP formed to own, operate, develop and acquire midstream assets, completed an initial public offering of common units representing limited partner interests and received net proceeds of approximately $475 million. In connection with the closing of the offering and pursuant to the terms of our contribution agreement with GIP, CHKM distributed to GIP the approximate $62 million of net proceeds from the exercise of the offering over-allotment option, and Chesapeake and GIP contributed the interests of their midstream joint venture operating subsidiary to CHKM. Chesapeake and GIP hold 42.3% and 40.0%, respectively, of all outstanding limited partner interests, and Chesapeake and GIP each have a 50% interest in the general partner of CHKM. CHKM makes quarterly distributions to its partners, and at the current annual rate of $1.35 per unit, Chesapeake receives quarterly distributions of approximately $20 million in respect of its limited partner and general partner interests. In 2010, we received cash distributions of $88 million from CHKM and its predecessor joint venture.
We account for our investment in CHKM under the equity method. During 2010, we recorded positive equity method adjustments of $89 million for our share of CHKM’s income and recorded accretion adjustments of $14 million for our share of equity in excess of cost. As a result of CHKM’s initial public offering, we recognized a $90 million gain on our investment, which represented our proportionate share of the excess of offering proceeds over the carrying value of our investment in CHKM and is reported in earnings (losses) from equity investees on our consolidated statements of operations.
On December 21, 2010, we sold our Springridge natural gas gathering system and related facilities in the Haynesville Shale to CHKM for $500 million and entered into ten-year gathering and compression agreements with CHKM. Additional information on the transaction is included in Item 1 under Marketing, Gathering and Compression - Midstream Gathering Operations.
Pending and Planned Asset Sales
Fayetteville Shale. On February 21, 2011, we entered into a purchase and sale agreement with a wholly owned subsidiary of BHP Billiton to sell all of our Fayetteville Shale assets, including approximately 487,000 net acres of leasehold and producing natural gas properties and midstream assets with approximately 420 miles of pipeline, for $4.75 billion in cash before certain deductions and standard closing adjustments. In the Fayetteville Shale, our current net production is approximately 415 mmcfe per day. Estimated proved reserves attributable to the Fayetteville Shale as of December 31, 2010 were 2.4 tcfe, or approximately 14% of our total proved reserves. As part of the transaction, we have agreed to provide essential services for up to one year for BHP Billiton’s Fayetteville Shale properties for an agreed-upon fee. Closing of the transaction is subject to customary conditions, including filings under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and with the Committee on Foreign Investment in the United States. Closing is expected to occur in the first half of 2011.
Frac Tech Holdings, LLC and Chaparral Energy, Inc. Asset Sales. We plan to sell our 25.8% equity interest in Frac Tech Holdings, LLC and our 20% equity interest in Chaparral Energy, Inc. Each of the foregoing proposed transactions is subject to changes in market conditions and other factors, and there can be no assurance that we will complete any or all of these transactions on a timely basis or at all.
Other. During 2011, the company expects to enter into additional asset monetizations, including industry participation agreements in liquids-rich plays, new VPPs, certain midstream assets sales and various other smaller planned sales.
Capital Expenditures
Our exploration, development and acquisition activities require us to make substantial capital expenditures. Our current budgeted drilling and completion capital expenditures, net of drilling and completion carries, are $5.0 - $5.4 billion in 2011 and $5.4 - $5.8 billion in 2012. We anticipate funding all or substantially all budgeted drilling and completion capital expenditures using cash flow from operations in 2011 and 2012. We plan to fund our leasehold acquisition capital expenditures, together with other capital expenditure requirements, with a combination of revolving bank credit facility borrowings and proceeds from asset monetizations. As of December 31, 2010, we had made commitments to acquire additional proved and unproved properties in various transactions during the next twelve months for approximately $350 million.
Liquidity and Capital Resources
Sources and Uses of Funds
Cash flow from operations is a significant source of liquidity we use to fund capital expenditures, pay dividends and repay debt. Cash provided by operating activities was $5.117 billion in 2010, compared to $4.356 billion in 2009 and $5.357 billion in 2008. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as impairments of assets, depreciation, depletion and amortization, deferred income taxes and changes in our derivative instruments. See the discussion below under Results of Operations .
Changes in market prices for natural gas and oil directly impact the level of our cash flow from operations. To mitigate the risk of declines in natural gas and oil prices and to provide more predictable future cash flow from operations, we have entered into various derivative instruments. Assuming future NYMEX natural gas settlement prices average $4.50 per mcf for 2011 and including the effect of the company’s open derivatives as of February 22, 2011, closed contracts and previously collected call premiums, the company estimates its average natural gas price will be $5.98 per mcf for 2011. This estimate does not include the effect of basis differentials and gathering costs. Our natural gas and oil derivatives as of December 31, 2010 are detailed in Item 7A of this report. Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and oil supply and demand trends, we may increase or decrease our current hedging positions.
Our $4.0 billion corporate revolving bank credit facility, our $300 million midstream revolving bank credit facility and cash and cash equivalents are other sources of liquidity. We use the credit facilities and cash on hand to fund daily operating activities and capital expenditures as needed. We borrowed $15.117 billion and repaid $13.303 billion in 2010, we borrowed $7.761 billion and repaid $9.758 billion in 2009, and we borrowed $13.291 billion and repaid $11.307 billion in 2008 from our revolving bank credit facilities. Our corporate facility is secured by natural gas and oil proved reserves. A significant portion of our natural gas and oil reserves are currently unencumbered and therefore available to be pledged as additional collateral if needed to respond to borrowing base and collateral redeterminations our lenders might make in the future. Accordingly, we believe our borrowing capacity under this facility will not be reduced as a result of any such future redeterminations. Our midstream facility is secured by substantially all of our wholly owned midstream assets and is not subject to periodic borrowing base redeterminations. Our revolving bank credit facilities are described below under Bank Credit Facilities .
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Business Strategy
Our business strategy is to create value for investors by building and developing one of the largest onshore natural gas and liquids resource bases in the U.S. The key elements of our business strategy, as described in Business Strategy in Item 1 of our 2011 Form 10-K, are the following: growing production and proved reserves through the drillbit; controlling substantial land and drilling location inventories and building operating focus and scale; developing proprietary technological advantages; focusing on achieving low costs through our focused activities, vertical integration and increasing scale; mitigating commodity price risk through our hedging program; entering into value-creating joint ventures; improving our balance sheet through reduction of debt; transforming the U.S. transportation fuels market and increasing demand for U.S. natural gas; and maintaining an entrepreneurial culture.
Capital Expenditures
In the Current Quarter, our capital expenditures for exploration, development and acquisition activities, net of drilling and completion carries, were $3.471 billion, including $2.503 billion for drilling and completion costs and $968 million for acquisitions of unproved properties. A disproportionately high percentage of our total budgeted 2012 capital expenditures was made early in the year, and this was the result of several factors which are discussed further below. Our current budget for 2012 includes drilling and completion capital expenditures, net of drilling and completion carries, of $7.5 – $8.0 billion and net undeveloped leasehold expenditures of $1.6 billion.
Drilling and completion costs during the Current Quarter reflected the effects of our transition to liquids-focused drilling and reduced natural gas drilling. During the 2011 fourth quarter, our rig count was as high as 172 rigs as we were rapidly ramping up our liquids-focused drilling while, at the same time, we were deliberately but more slowly ramping down drilling of natural gas wells. As of May 1, 2012, our rig count had been reduced to 154 rigs, and we expect further reductions to approximately 125 rigs in the 2012 third quarter. Our budget reflects sharp reductions in our natural gas drilling activities, from 50 rigs at the beginning of 2012 to an average of 12 rigs in the second half of 2012. The Current Quarter drilling and completion expenditures also reflected significant well completion costs for natural gas wells that had been drilled in prior periods. These completions, which we expect will represent more than 50% of all natural gas wells we complete during 2012, enabled us to hold the related leasehold according to the terms of our leases. For 2013, we are budgeting $6.5 – $7.0 billion for drilling and completion capital expenditures, net of drilling and completion carries.
Approximately 60% of our leasehold acquisition costs during the Current Quarter were focused on adding acreage in the Utica and Mississippi Lime plays to complete our leasehold acquisition strategies in connection with completed or planned joint ventures in these areas. We anticipate significantly lower leasehold spending in the remainder of 2012, and we are projecting that our 2013 net undeveloped leasehold expenditures will decline to approximately $500 million. Having captured what we believe are the most promising areas of our core plays, we have now shifted our focus to exploiting these assets.
During the Current Quarter, our capital expenditures related to our midstream, oilfield services and other assets were approximately $770 million. Our projected 2012 and 2013 capital expenditures are $2.5 –$3.5 billion and $2.0 – $2.5 billion, respectively.
Recent Asset Monetizations
An essential part of our business strategy is using the proceeds from asset monetizations to fund our capital expenditures in excess of operating cash flow and to reduce our indebtedness. Below we describe transactions completed in 2012 and the continuing benefits of our joint ventures which were completed in 2008, 2010 and 2011.
Volumetric Production Payment (VPP). In March 2012, we monetized certain of our producing assets in the Anadarko Basin Granite Wash through a ten-year VPP for proceeds of approximately $745 million. The transaction included approximately 160 bcfe of proved reserves and approximately 125 mmcfe per day of net production. Chesapeake has retained drilling rights on the properties below currently producing intervals and outside of existing producing wellbores and we also retain all production beyond the specified volumes sold in the transaction. This transaction was our tenth VPP. The cash proceeds for this transaction were reflected as a reduction of natural gas and oil properties with no gain or loss recognized. Other VPPs we completed in 2007 – 2011 are detailed in Note 8 of the condensed consolidated financial statements included in Item 1 of this report.
Cleveland Tonkawa Financial Transaction. We formed CHK Cleveland Tonkawa, L.L.C. (CHK C-T) in March 2012 to continue development of a portion of our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our corporate credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including under our indentures. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and 360 existing wells within an area of mutual interest in the Cleveland and Tonkawa plays covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 net wells to be drilled on certain of our Cleveland and Tonkawa play leasehold.
Dividends on the preferred shares are payable on a quarterly basis at a rate of 6% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, cash flow from the assets owned by CHK C-T is insufficient to fund the dividend in full in any quarter. As the managing member of CHK C-T, we may, at our sole discretion and election at any time after March 31, 2014, distribute certain excess cash of CHK C-T. If we are current in our drilling commitment at the time, any such optional distribution of excess cash is allocated 75% to the preferred shares (which is applied toward redemption of the preferred shares) and 25% to the common shares. We may also cause CHK C-T to redeem all or a portion of the CHK C-T preferred shares for cash. The preferred shares will be redeemed at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x, in each case inclusive of dividends paid at the rate of 6% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to March 31, 2019, the optional redemption valuation will increase to provide a 15% internal rate of return. As of March 31, 2012, the redemption price, and the liquidation preference, was $1,350 per preferred share. We have committed to drill, for the benefit of CHK C-T, a minimum of 37.5 net wells per six-month period through 2013 and 25 net wells per six-month period in 2014 through 2016 in the CHK C-T area of mutual interest, up to a minimum cumulative total of 300 net wells. CHK C-T is responsible for all capital and operating costs of the wells drilled for the benefit of the entity. For further discussion, see Noncontrolling Interests in Note 6 of the notes to our condensed consolidated financial statements in Item 1 of this report.
Utica East Ohio Midstream L.L.C. In March 2012, Chesapeake Midstream Development, L.P. (CMD) entered into an agreement to form Utica East Ohio Midstream L.L.C. (UEOM) with M3 Midstream L.L.C. and EV Energy Partners, L.P. to develop necessary infrastructure for the gathering and processing of natural gas and natural gas liquids in the Utica Shale play in eastern Ohio. The infrastructure complex will consist of natural gas gathering and compression facilities constructed and operated by CMD, as well as processing, NGL fractionation, loading and terminal facilities constructed and operated by M3 Midstream L.L.C. CMD made an initial cash contribution of $38 million in exchange for an ownership of approximately 59% in UEOM.
Texoma Woodford Asset Sale. In April 2012, we sold 58,400 net acres of leasehold in the Texoma Woodford play in Bryan, Carter, Johnston and Marshall counties in Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation (NYSE:XOM), for approximately $572 million in cash after certain deductions and closing costs. The properties included approximately 25 mmcfe per day of current net production.
Planned Asset Monetizations
We are pursuing a joint venture transaction in our Mississippi Lime play in northern Oklahoma and southern Kansas, where we own approximately 2.0 million net acres, and we are pursuing a 100% sale of our position in the Permian Basin in West Texas and southern New Mexico, where we own approximately 1.5 million net acres. Our Permian Basin assets represent approximately 5% of the Company’s total proved reserves and current net production. We are targeting completion of the Mississippi Lime and Permian Basin transactions during the 2012 third quarter.
In April 2012, our wholly owned service industry affiliate Chesapeake Oilfield Services, Inc. filed a registration statement with the Securities Exchange Commission (SEC) relating to the proposed initial public offering of shares of its Class A common stock. Application will be made to list the Class A common stock on the New York Stock Exchange under the symbol “COS”. There can be no assurance that we will complete this transaction, as it is subject to market conditions and other uncertainties, as well as completion of the SEC review process.
Finally, we plan to continue to seek monetizations of various non-core oil and gas assets, a portion of our midstream assets, our oilfield services assets and other miscellaneous investments.
While we expect that the proceeds from our planned asset monetizations will be sufficient to fund our planned capital expenditures, we do not have binding agreements for any of these transactions and our ability to consummate each of these transactions is subject to changes in market conditions and other factors. As a result, there can be no assurance that we will complete any of these transactions on a timely basis or at all. To the extent that proceeds from these potential transactions are inadequate to fund our planned spending, we would be required to modify our drilling program or monetize different or additional assets.
Recent Developments
On May 1, 2012, the Company announced that its Board of Directors had renegotiated the terms of the Company’s Founder Well Participation Program (FWPP) with Chairman and Chief Executive Officer Aubrey K. McClendon to provide for the early termination of the FWPP on June 30, 2014, 18 months before the end of its current term on December 31, 2015. The FWPP was approved by shareholders for a 10-year term in 2005. In conjunction with Mr. McClendon’s employment agreement with the Company, the FWPP provides Mr. McClendon a contractual right to participate and invest as a working interest owner (with up to a 2.5% working interest) in new wells drilled on the Company’s leasehold. Mr. McClendon will receive no compensation of any kind in connection with the early termination of the FWPP.
Following consultation with the Company’s Board of Directors, on April 26, 2012, Mr. McClendon separately disclosed personal financial and operational information regarding his oil and gas investments through the FWPP.
The Board of Directors is conducting an internal review of the financing arrangements between Mr. McClendon (and the entities through which he participates in the FWPP) and any third party that has had or may have a relationship with the Company in any capacity. In addition, the Board of Directors will name an independent, Non-Executive Chairman in the near future. The Board’s Nominating and Corporate Governance Committee is considering potential candidates and is soliciting input from major shareholders. Upon the appointment of a Non-Executive Chairman, Mr. McClendon will relinquish the position of Chairman and continue as Chief Executive Officer and a member of the Board. Mr. McClendon has indicated his support of the Board’s decision to name a Non-Executive Chairman and waived any rights he might have under his employment agreement as a result of no longer serving as Chairman.
From April 19 to May 3, 2012, at least ten nearly identical shareholder actions have been filed against the Company and its directors alleging, among other things, that Company proxy statements have contained material misstatements related to Mr. McClendon’s participation in the FWPP and breaches of fiduciary duties against the Board for failing to make proper disclosures in the proxy statements. Also, on April 26, 2012, a putative class action was filed against the Company and Mr. McClendon alleging violations of Sections 10(b) (and Rule 10b-5 promulgated thereunder) and 20(a) of the Securities Exchange Act of 1934 for purported misstatements concerning Mr. McClendon’s participation in the FWPP. On May 8, 2012, a derivative action was filed against the Company’s directors alleging, among other things, breaches of fiduciary duties and corporate waste related to the Company’s officers and directors’ use of the Company’s fractionally owned corporate jets. See Legal Proceedings in Part II, Item 1 for a description of these actions.
On May 2, 2012, Chesapeake and Mr. McClendon received notice from the Securities and Exchange Commission that its Fort Worth Regional Office has commenced an informal inquiry and requested that the Company and Mr. McClendon retain documents related to the FWPP and certain transactions. The SEC noted in its request that its inquiry should not be construed as an indication that any violation of the federal securities laws has occurred. The Company and Mr. McClendon intend to cooperate with the SEC in responding to its inquiry.
Liquidity and Capital Resources
Liquidity Overview
Our business strategy is to continue our reserves and production growth and transition to increased liquids production. As part of this strategy, we plan to make capital expenditures in 2012 that will significantly exceed our projected cash flow from operations. During the Current Quarter, the combination of high front-end capital expenditures and reduced cash flow as a result of low natural gas prices required that we increase our long-term debt, net of unrestricted cash, by approximately $2.4 billion to $12.6 billion to fund our capital expenditure needs. As of March 31, 2012, we had approximately $2.4 billion in cash availability compared to $3.1 billion as of December 31, 2011; however, our working capital deficit improved during the Current Quarter, and we expect this deficit to continue to decrease based on our projected capital expenditures and cash flow. For the remainder of 2012, we plan to fund capital expenditures with operating cash flow and various asset monetization transactions, potentially including joint ventures, volumetric production payments and other property and investment dispositions, including sales of a portion of our midstream and oilfield services assets. In addition, since early 2011, it has been our plan, which we call the 25/25 Plan, to reduce our net long-term debt to no more than $9.5 billion by December 31, 2012, a 25% reduction from year-end 2010, and increase our production by 25% during the two years ended December 31, 2012.
We expect that the proceeds from our 2012 closed or planned monetization transactions, which we estimate could be $11.5 – $14 billion, will be sufficient to fund our budgeted capital expenditures, meet our long-term debt reduction plans by year-end 2012 and provide additional liquidity for 2013. We do not have binding agreements for any of these monetization transactions, however, and our ability to consummate each of them is subject to changes in market conditions and other factors. As a result, there can be no assurance that we will complete any of the planned transactions on a timely basis or at all. If we are unable to consummate these transactions or if they do not generate the proceeds we are anticipating, we would be required to reduce capital spending and/or seek funds from other sources, including interim financing that would address near-term liquidity needs. Our ability to obtain capital from asset monetizations is dependent upon many factors, and they may be beyond our control. If our access to alternative asset monetizations were limited, our ability to develop and replace our reserves could be reduced.
As part of our asset monetization planning and capital expenditure budgeting process, we closely monitor the resulting effects on the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our corporate revolving bank credit facility. While asset monetizations enhance our liquidity, sales of producing natural gas and oil properties adversely affect the amount of cash flow we generate and reduce the amount and value of collateral available to secure our obligations, both of which are exacerbated by low natural gas prices. Thus the assets we select and schedule for monetization, our budgeted capital expenditures and our commodity price forecasts are carefully considered as we project our future ability to comply with the requirements of our corporate credit facility. As a result, we may delay one or more of our currently planned asset monetizations, or select other assets for monetization, in order to maintain our compliance. Continued compliance, however, is subject to all the risks that may impact our business strategy.
Through the vertical integration of our business and as operator of a substantial number of our properties under development, we retain significant control and flexibility over the development plan and the associated timing, which we believe is instrumental to our business plan and strategy. While our capital raising activities enabled us to fund our capital program in 2011 and pursue our goal of long-term debt reduction, certain recent transactions require us to meet performance obligations and we have significant other contractual cash obligations to third parties pursuant to various lease arrangements, gathering, processing, and transportation agreements, drilling commitments, leasehold maintenance arrangements, fleet utilization agreements, and investments in new ventures (see Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of this report). While our business plan assumes that we will meet these commitments in the ordinary course of business, we are required to meet our performance and payment obligations regardless of whether our business plan changes for circumstances beyond our control.
Sources of Funds
Cash flow from operations is a significant source of liquidity we use to fund capital expenditures, pay dividends and repay debt. Cash provided by operating activities was $274 million in the Current Quarter compared to $718 million in the Prior Quarter. The decline in the cash flow from operations is primarily the result of a decrease in the realized natural gas price (excluding the effect of unrealized gains or losses on derivatives) from $5.31 per mcf in the Prior Quarter to $2.35 per mcf in the Current Quarter. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, depletion and amortization, deferred income taxes, mark-to-market changes in our derivative instruments and gains or losses on the sales and impairments of fixed assets. See the discussion below under Results of Operations .
The volatility in the energy markets make it extremely difficult to predict future natural gas and oil price movements with any certainty leaving us exposed to potential reduction in our operating cash flow and therefore affecting our ability to fund our capital expenditures. While our derivative arrangements serve to mitigate a portion of the effect of price volatility on our cash flows, our forecasted natural gas production is currently not protected against downward price adjustments by derivative instruments and our use of crude oil derivatives to partially mitigate the price risk of our liquids production is subject to basis risk to the extent oil and natural gas liquids prices do not remain highly correlated. Sustained low natural gas prices, and volatile commodity prices in general, could have a material adverse effect on our financial position, results of operations and cash flows, which could adversely impact our ability to maintain compliance with financial covenants under our credit facilities and further limit our ability to fund our planned capital expenditures. In addition, sustained low commodity prices could result in a reduction in the estimated quantity of proved reserves we report and in the estimated future net cash flows expected to be generated from reserves that may require us to write down the carrying value of our natural gas and oil properties, and such amounts could be material. Our natural gas and oil derivatives as of March 31, 2012 are detailed in Item 3 of Part I of this report. Depending on changes in commodity futures markets and management’s view of underlying commodity supply and demand trends, we may increase or decrease our current derivative positions. As commodity prices dip and reach supportable low prices, however, we may take the opportunity to close out open swap positions in order to lock in substantial mark-to-market gains.
During the Current Quarter, third-party investors contributed $1.25 billion in cash to CHK C-T, in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest in 360 existing wells and up to 1,000 net wells to be drilled on certain of our Cleveland and Tonkawa play leasehold. CHK C-T is an unrestricted, non-guarantor consolidated subsidiary we formed in March 2012 to continue development of a portion of our Cleveland and Tonkawa plays covering Ellis and Roger Mills counties in western Oklahoma.
Current Quarter property divestiture proceeds of $821 million included approximately $745 million from our tenth VPP transaction. Prior Quarter property divestiture proceeds of $5.182 billion included $4.310 billion from the sale of our Fayetteville assets, $570 million at the closing of our Niobrara Shale joint venture and $302 million from other property sales.
CONF CALL
Jeffrey L. Mobley
Good morning, and thank you for joining our conference call today. With me are Aubrey McClendon, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; and from the Investor Relations Research Team, John Kilgallon and Gary Clark. I'll now turn the call over to Aubrey.
Aubrey K. McClendon
Good morning, and thank you for joining us today. As you know, we filed our 10-Q on Friday afternoon and announced the $3 billion term loan a few hours later. We knew there would be some questions in the marketplace about both items, so we wanted to provide this opportunity to address them with you.
The Goldman and Jefferies term loan provides Chesapeake with greatly enhanced financial flexibility. We firmly believe this term loan answers the most important question about Chesapeake in the marketplace today. Will we have enough financial fire power to be able to complete our pending asset sales and to finish our transition to a more liquid-focused producer, thereby generating much higher returns on capital than we've been able to deliver in the past, as primarily a natural gas producer?
We now have substantially enhanced our liquidity, and that will ensure that we can conduct our asset monetization transactions from a position of strength. We greatly appreciate the support of our financial advisors, Goldman and Jefferies and the confidence they have demonstrated in the value of our assets and our ability to achieve our asset sale objectives. We remain focused and committed on delivering the $9.5 billion to $11 billion in asset sales we have scheduled to complete during the remainder of 2012.
I would also like to address some of the confusion in the market on Friday afternoon around the filing of our 10-Q. I can assure you that management, the board, our advisors and our auditors all worked diligently to be able to file the 10-Q timely on Thursday afternoon, but we simply did not have enough time to get all the work done on time. We did file it as soon as we were able to do so on Friday afternoon, which along with closing the Goldman and Jefferies loan later that day, made it an extremely busy day for all of us.
The asset sale language in our 10-Q on Friday apparently led some readers to conclude that our Permian sale and Miss Lime JV were somehow in jeopardy. To the contrary, those transactions remain on track. We expect those transactions to close in the third quarter, and we will use the proceeds to pay off the Goldman and Jefferies loan.
The language in the 10-Q was actually referring to our decision last week to delay or even cancel VPP 11, which represents approximately $1 billion of potential sale proceeds. We had discussed this VPP on our last conference call as a key element of our second quarter financial plan as we waited on the bigger asset sale to kick in during the second half of 2012. Accordingly, our 10-Q had to address the new decision concerning the VPP.
In addition to the Permian sale and Miss Lime JV, we've identified a number of other assets that are non-core to us. And we will sell enough of those in the second half of 2012 to reach our asset sales target of $9.5 billion to $11 billion for the remainder of the year. We also plan to sell sufficient non-core assets in 2013 to make sure we are well funded next year, as we complete our natural gas to liquids transition and reach our goal of being free cash flow positive in 2014. Believe me, Chesapeake's management team is very, very focused on getting these funding gap issues behind us once and for all and as early as possible.
At some point this morning, I do hope you will take the time to calculate the value of what we will still own after our non-core asset sales. Just including our #1 and #2 positions in the Eagle Ford, Utica, Marcellus, Haynesville, Bossier, Barnett, Granite Wash, Cleveland, Tonkawa, Miss Lime and Powder River Niobrara and then adding in our midstream and service assets, we believe Chesapeake owned assets easily identifiable as being worth at least $50 billion to $60 billion against today's entire enterprise value of less than half of that. Plus, when gas prices recover in 2013 and beyond, these asset values should be significantly higher. Quite simply, we built the industry's best asset base, and we will deliver its value to our shareholders.
You might ask, how are we so sure we can do that? It's because Chesapeake's strategy is undergoing its fourth transition since the company was founded in 1989. 2012 is the year we moved from a strategy of asset capture to a strategy of asset harvest. During the past 7 years of what I call the great American unconventional resource revolution, we have positioned Chesapeake to be able to take full advantage of the effects of this revolution. As a result, today, Chesapeake is widely recognized as the world's leader in unconventional resource development. It has been exceedingly hard work, and it has sometimes made the company, its strategy and its funding of that strategy more controversial than I would have ever dreamed possible. But we will soon be leaving those days behind us. What lies ahead is actually far easier to manage, and I'm confident will be far easier to invest in as well.
In addition, it's also not been easy to make this strategy transition happen, with gas prices at 10-year lows. However, we will complete this transition despite today's low gas prices. And please remember that today's unsustainably low gas prices have created the environment for a major gas price recovery in 2013 and beyond. As a consequence of this hard work and focused execution of our business strategy during the past 7 years, I'd like to restate that Chesapeake owns the #1 and #2 position in 10 great American resource plays. We believe no other company in the industry can come close to matching the overall quality and size of Chesapeake's assets.
On the strong foundation of these 10 key plays, Chesapeake's focus going forward will be on ever more efficiently developing the assets that we already own. We set out to win a race 7 years ago to build the industry's best asset base. We now believe we have won that race and now are singularly focused on harvesting the best-in-industry returns from these best-in-industry assets.
A very visible way to see this ongoing strategy transformation is through our lease acquisition budget. For example, in 2013, it has been reduced 90% from our leasehold acquisition budget in 2010. This is an enormous change, and we are very eager to show investors in the remaining 3 quarters of 2012 how our leasehold spending is ramping down quickly.
Another way to examine our commitment to moving into harvest mode is to examine what we have done to dismantle the Chesapeake land machine. We have reduced third-party brokers dedicated to researching title and buying new leases from 3,400 at our peak to only 1,300 today, and we will be down to 650 or so by the end of 2012. That's a reduction of 80%, which will save us approximately $350 million per year. The land machine served its purpose in helping us build the best assets in the industry. But now we love what we own and now it's time to drill it all up and deliver the value to our investors.
A second proof of the company's ongoing transformation is to study our liquids production growth. In just the past 2 years, our liquids production has increased from 30,000 barrels per day to almost 4 times that at 114,000 barrels per day. By year end 2014, we expect to double this production. It will be a remarkable transformation of such a large gas company's asset base in such a short period of time and the pay off for our shareholders should be very significant.
I'll close by assuring you that there could be no CEO in America today more determined and motivated than I am to deliver the value of these companies assets to its shareholders. I do understand fully where we are and where we have been and also where we are going. And I am 100% confident that our asset harvest strategy will deliver great value to Chesapeake's investors in the quarters and years ahead.
I'll now turn the call over to Nick and let him address a few things in more detail. Nick?
Domenic J. Dell’Osso
Thanks, Aubrey. I'll start by addressing the term loan we closed last Friday afternoon. We thought it was prudent to proceed with this transaction to increase our financial flexibility through the summer months and greatly enhance our liquidity during this period of low gas prices. We're very appreciative of the support that our asset sale advisors have provided us, as we execute on our strategy and know that it will enable us to drive for the best possible results on those sales for all of our stakeholders.
I'm sure you've seen that we filed an 8-K summarizing the deal and the loan agreement this morning. It was drafted based on our existing corporate revolver, though this new agreement does not have any maintenance covenants and is pre-payable at par at any time until the end of the year. We are viewing this new loan as a bridge to asset sales and expect to use proceeds from our significant asset sales to repay this facility prior to year end. In the interim, the proceeds of the loan will be used to repay borrowings under our revolving credit facility. It should be noted that our revolving credit facility stand -- remains outstanding in full and is available to us.
As to our 10-Q filing on Friday afternoon, as Aubrey noted, it was slightly delayed, but we got the document on file as soon as it was ready. In that filing, we included additional disclosure around our asset sale considerations, that we are closely monitoring how these sales will be treated under existing covenants contained in our revolving credit facility. Given the decline in natural gas prices and resulting decrease in our projected EBITDA for the year, we felt that providing additional disclosure around this matter was appropriate. We have chosen to, at least temporarily, defer Eagle Ford VPP. Given that VPPs are declining assets, there is a relatively high amount of near-term production and cash flow associated with the property, and we chose to keep that for now.
In coming months, this transaction may make more sense, and we'll continue to revisit at what commodity prices and overall environment such a transaction would be beneficial to our stakeholders. We do not expect to have a covenant issue this year, but again thought the disclosure around our focus on this was helpful.
Remember, our only maintenance covenants are in our revolving credit facility, which is a $4 billion facility secured by a relatively small subset of our $50 billion to $60 billion asset value that Aubrey referred to earlier. These covenants are 4x debt to trailing EBITDA limitation and a 70% debt-to-capitalization ratio. We do not have maintenance financial covenants in our senior note indentures. We are very much looking forward to completing significant asset sales in the second half of the year, and we are very pleased to have incremental liquidity from Friday's term loan to add flexibility in our approach and ensure the best outcome.
Operator, we'll now open the line for questions.
|
|
Fund Letters
