Acquisitions and Divestitures

Acquisition of Bronco Drilling

In June 2011, we acquired Bronco Drilling Company, Inc., a publicly traded contract land drilling services company, for an aggregate purchase price of approximately $339 million, or $11.00 per share of Bronco common stock. The acquisition was accounted for as a business combination which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Pro forma financial information is not presented as it would not be materially different from the information presented in the consolidated statement of operations.

Asset Sales

During the Current Period and the Prior Period, we engaged in the asset sales transactions described below as well as other individually insignificant sales.

Permian Basin. In September 2012, we sold our producing assets in the Midland Basin portion of the Permian Basin to affiliates of Houston-based EnerVest, Ltd. for approximately $376 million in cash. The properties included approximately 35 mmcfe per day of current net production.

Non-Core Utica Shale. In August 2012, we sold approximately 72,000 net acres of non-core leasehold in the Utica shale play in Ohio to affiliates of EnerVest for approximately $358 million in cash.

Texoma Woodford. In April 2012, we sold approximately 60,000 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. The properties included approximately 25 mmcfe per day of current net production.

Fayetteville Shale. In March 2011, we sold all of our Fayetteville Shale assets in central Arkansas to BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Limited (NYSE:BHP; ASX:BHP), for net proceeds of approximately $4.65 billion in cash. The properties sold consisted of approximately 487,000 net acres of leasehold, net production at closing of approximately 415 million cubic feet of natural gas equivalent per day and midstream assets consisting of approximately 420 miles of pipeline. Of the total proceeds received, $350 million was allocated to our Fayetteville Shale midstream assets and a $7 million gain was recorded on the divestiture of those assets. The remainder of the proceeds was allocated to our Fayetteville Shale natural gas and oil properties.

Under full cost accounting rules, we account for the sale of natural gas and oil properties as an adjustment to capitalized costs, with no recognition of gain or loss. In conjunction with each of these transactions, affiliates of our Chief Executive Officer, Aubrey K. McClendon, sold interests in the same properties and on the same terms as those that applied to the interests sold by the Company, and the net proceeds were paid to the sellers based on their respective ownership. These interests were acquired through the FWPP, which 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 through June 2014.

Joint Ventures

As of September 30, 2012, we had entered into seven significant joint ventures with other leading energy companies pursuant to which we sold a portion of our leasehold, producing properties and other assets located in seven different resource plays and received cash of $7.1 billion and commitments for future drilling and completion cost sharing totaling $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all leasing, drilling, completion, operations and marketing activities for the project. The carry obligations paid by a joint venture partner are for a specified percentage of our drilling and completion cost obligations. In addition, a joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner. We bill our joint venture partners for their drilling carry obligations at the same time we bill them and other joint working interest owners for their share of drilling costs as they are incurred. For accounting purposes, initial cash proceeds from these joint venture transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized. The transactions are detailed below.



Primary Play	Joint Venture Partner^(a)	Joint Venture Date	Interest Sold	Cash Proceeds Received at Closing		Total Drilling Carries			Total Cash and Drilling Carry Proceeds		Drilling Carries Remaining^(b)
						($ in millions)
Utica	TOT	December 2011	25.0%	$	610	$	1,422		$	2,032	$	1,249
Niobrara	CNOOC	February 2011	33.3%	570		697			1,267		495
Eagle Ford	CNOOC	November 2010	33.3%	1,120		1,080			2,200		—
Barnett	TOT	January 2010	25.0%	800		1,404		^(c)	2,204		—
Marcellus	STO	November 2008	32.5%	1,250		2,125			3,375		—
Fayetteville	BP	September 2008	25.0%	1,100		800			1,900		—
Haynesville & Bossier	PXP	July 2008	20.0%	1,650		1,508		^(d)	3,158		—
				$	7,100	$	9,036		$	16,136	$	1,744

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(a)	Joint venture partners include Total S.A. (TOT), CNOOC Limited (CNOOC), Statoil (STO), BP America (BP) and Plains Exploration & Production Company (PXP).

(b)

As of September 30, 2012. The Utica drilling carries cover 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. The Niobrara drilling carries cover 67% of our drilling and completion costs for Niobrara wells drilled and must be used by December 2014. We expect to fully utilize these drilling carry commitments prior to expiration. See Note 4 for further discussion of the Utica drilling carries.

(c)

In conjunction with an agreement requiring us to maintain our operated rig count at no less than 12 rigs in the Barnett Shale through December 31, 2012, TOT accelerated the payment of its remaining joint venture drilling carry in exchange for an approximate 9% reduction in the total amount of drilling carry obligation owed to us at that time. As a result, in October 2011, we received $471 million in cash from TOT, which included $46 million of drilling carry obligation billed and $425 million for the remaining drilling carry obligation. In January 2012, Chesapeake and TOT agreed to reduce the minimum rig count from 12 to six rigs. In May 2012, Chesapeake and TOT agreed to further reduce the minimum rig count from six to two rigs.


(d)	In September 2009, PXP accelerated the payment of its remaining drilling carry in exchange for an approximate 12% reduction to the remaining drilling carry obligation owed to us at that time.

During the Current Period and the Prior Period, our drilling and completion costs included the benefit of approximately $655 million and $1.868 billion, respectively, in drilling and completion carries paid by our joint venture partners, CNOOC, TOT and STO.

During the Current Period, as part of our joint venture agreements with TOT and STO, we sold interests in additional leasehold we acquired in the Marcellus, Barnett and Utica shale plays to our joint venture partners for approximately $228 million. In the Prior Period, as part of our joint venture agreements with CNOOC, TOT, STO and PXP, we sold interests in additional leasehold in the Eagle Ford, Barnett, Marcellus and Haynesville and Bossier shale plays to our joint venture partners for approximately $474 million.

Volumetric Production Payments

From time to time, we have sold certain of our producing assets which are located in more mature producing regions through the sale of volumetric production payments (VPPs). A VPP is a limited-term overriding royalty interest in natural gas and oil reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. We retain drilling rights on the properties below currently producing intervals and outside of producing well bores.

As the operator of the properties from which the VPP volumes have been sold, we have the responsibility to bear the cost of producing the reserves attributable to such interests, which we include as a component of production expenses and production taxes in our condensed consolidated statements of operations in the periods such costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining the cost center ceiling for impairment purposes and in determining our standardized measure. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet and the expenses that will apply in the future will depend on the actual production expenses and taxes in effect during the periods in which such production actually occurs, which could differ materially from our current and historical costs.

We have committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.

Our VPPs consist of the following:



Date of VPP	Division	Proceeds		Proved Reserves (at time of sale)	$ / mcfe		Original Term
		($ in millions)		(bcfe)			(years)
March 2012	Anadarko Basin Granite Wash	$	744	160	$	4.68	10
May 2011	Mid-Continent	853		177	$	4.82	10
September 2010	Barnett Shale	1,150		390	$	2.93	5
February 2010	East Texas and Texas Gulf Coast	180		46	$	3.95	10
August 2009	South Texas	370		68	$	5.46	8
December 2008	Anadarko and Arkoma Basins	412		98	$	4.19	8
August 2008	Anadarko Basin	600		93	$	6.38	11
May 2008	Texas, Oklahoma and Kansas	622		94	$	6.53	11
December 2007	Kentucky and West Virginia	1,100		208	$	5.29	15
		$	6,031	1,334	$	4.52

For accounting purposes, cash proceeds from these transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized, and our proved reserves were reduced accordingly.

In September 2012, to facilitate the sales process associated with our Permian Basin divestiture packages, we purchased the remaining reserves from our Permian Basin VPP, originally entered into in June 2010, for $313 million. The reserves purchased totaled 28 bcfe and were subsequently sold to the buyers of our Permian Basin assets, including Enervest as described above. See Note 16 for further discussion of our Permian Basin asset sales subsequent to September 30, 2012.