Acquisitions and Divestitures of Natural Gas and Oil Properties

Divestitures of 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 as the sales typically do not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves. In conjunction with certain sales, affiliates of our former Chief Executive Officer, Aubrey K. McClendon, have 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 Founder Well Participation Program, 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.

In April 2012, we sold approximately 60,000 net acres of leasehold in the Texoma Woodford play in Bryan, Carter, Johnston and Marshall counties, Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation (NYSE:XOM), for net proceeds of approximately $572 million. The properties generated approximately 25 mmcfe per day of net production at the time of sale.

During the Current Period and the Prior Period, we received proceeds of approximately $815 million and $100 million, respectively, from various other divestitures of natural gas and oil properties.

Joint Ventures

On June 28, 2013, we completed a strategic joint venture with Sinopec International Petroleum Exploration and Production Corporation (Sinopec) in which Sinopec purchased a 50% undivided interest in approximately 850,000 acres in the Mississippi Lime play in northern Oklahoma (425,000 acres net to Sinopec). The total consideration for the transaction was approximately $1.110 billion in cash, of which approximately $1.040 billion of net proceeds, or 94%, was received upon closing. Receipt of up to an additional $70 million of net proceeds is subject to customary post-closing contingencies. The assets conveyed to Sinopec produced approximately 9,600 barrels of liquids and 54 mmcf of natural gas per day during the 2013 first quarter. All future exploration and development costs in the joint venture will be shared proportionately between the parties with no drilling carries involved.

As of June 30, 2013, we had entered into eight 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 eight different resource plays and received cash of $8.1 billion and commitments by our counterparties to pay our share of future drilling and completion costs of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all drilling, completion and operations, the majority of leasing and, in certain transactions, marketing activities for the project. The carries paid by a joint venture partner are for a specified percentage of our drilling and completion costs. 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 carries 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	Initial Proceeds^(b)			Total Drilling Carries			Total Initial and Drilling Carry Proceeds		Drilling Carries Remaining^(c)
				($ in millions)
Mississippi Lime	Sinopec	June 2013	50.0%	$	1,040	^(d)	$	—		$	1,040	$	—
Utica	TOT	December 2011	25.0%	610			1,422		^(e)	2,032		836
Niobrara	CNOOC	February 2011	33.3%	570			697		^(f)	1,267		343
Eagle Ford	CNOOC	November 2010	33.3%	1,120			1,080			2,200		—
Barnett	TOT	January 2010	25.0%	800			1,403			2,203		—
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			3,158		—
				$	8,140		$	9,035		$	17,175	$	1,179

____________________________________________


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


(b)	Excludes closing and post-closing adjustments.


(c)	As of June 30, 2013.


(d)	Excludes approximately $70 million of net proceeds (or 6% of the total transaction) to be received subject to certain customary post-closing contingencies and the accrual of $17 million of transaction costs paid subsequent to June 30, 2013.


(e)	The Utica drilling carries cover 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. We expect to fully utilize these drilling carry commitments prior to expiration. See Note 4 for further discussion of the Utica drilling carries.


(f)	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.

During the Current Period and the Prior Period, our drilling and completion costs included the benefit of approximately $436 million and $518 million, respectively, in drilling and completion carries paid by our joint venture partners.

During the Current Period and the Prior Period, we sold interests in additional leasehold we acquired in the Marcellus, Barnett and Utica shale plays to our joint venture partners TOT and STO for approximately $39 million and $137 million, respectively.

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 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. For all of our VPP transactions, we have novated hedges to each of the respective VPP buyers and such hedges covered all VPP volumes sold. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores.

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. The costs that will apply in the future will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which such production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all.

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 outstanding VPPs consist of the following:



					Volume Sold
VPP #	Date of VPP	Division	Proceeds		Natural Gas	Oil	NGL	Total
			($ in millions)		(bcf)	(mmbbl)	(mmbbl)	(bcfe)
10	March 2012	Anadarko Basin Granite Wash	$	744	87	3.0	9.2	160
9	May 2011	Mid-Continent	853		138	1.7	4.8	177
8	September 2010	Barnett Shale	1,150		390	—	—	390
6	February 2010	East Texas and Texas Gulf Coast	180		44	0.3	—	46
5	August 2009	South Texas	370		67	0.2	—	68
4	December 2008	Anadarko and Arkoma Basins	412		95	0.5	—	98
3	August 2008	Anadarko Basin	600		93	—	—	93
2	May 2008	Texas, Oklahoma and Kansas	622		94	—	—	94
1	December 2007	Kentucky and West Virginia	1,100		208	—	—	208
			$	6,031	1,216	5.7	14.0	1,334

The volumes produced on behalf of our VPP buyers for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period were as follows:



	Three Months Ended June 30, 2013
VPP #	Natural Gas	Oil	NGL	Total
	(bcf)	(mbbl)	(mbbl)	(bcfe)
10	4	141.0	379.0	6.8
9	4	54.2	144.2	5.3
8	17	—	—	17.2
6	1	6.0	—	1.2
5	2	6.2	—	1.9
4	3	14.2	—	2.7
3	2	—	—	2.1
2	3	—	—	2.6
1	3	—	—	3.6
	39	221.6	523.2	43.4



	Three Months Ended June 30, 2012
VPP #	Natural Gas	Oil	NGL	Total
	(bcf)	(mbbl)	(mbbl)	(bcfe)
10	6	244.0	565.0	10.8
9	5	63.6	163.3	6.0
8	20	—	—	20.3
7	—	168.0	—	1.2
6	2	6.0	—	1.4
5	2	7.1	—	2.3
4	3	16.2	—	3.1
3	2	—	—	2.3
2	3	—	—	2.9
1	4	—	—	3.7
	47	504.9	728.3	54.0



	Six Months Ended June 30, 2013
VPP #	Natural Gas	Oil	NGL	Total
	(bcf)	(mbbl)	(mbbl)	(bcfe)
10	8	295.0	786.7	14.2
9	9	110.4	292.7	10.8
8	35	—	—	35.0
7	—	—	—	—
6	3	12.0	—	2.5
5	4	12.2	—	4.0
4	5	28.8	—	5.5
3	4	—	—	4.1
2	5	—	—	5.3
1	7	—	—	7.4
	80	458.4	1,079.4	88.8



	Six Months Ended June 30, 2012
VPP #	Natural Gas	Oil	NGL	Total
	(bcf)	(mbbl)	(mbbl)	(bcfe)
10	8	341.0	782.9	14.9
9	9	130.1	332.7	12.3
8	42	—	—	41.7
7	—	343.0	—	2.0
6	3	12.0	—	2.8
5	5	14.7	—	4.8
4	6	32.9	—	6.3
3	5	—	—	4.8
2	6	—	—	5.8
1	8	—	—	7.8
	92	873.7	1,115.6	103.2

The volumes remaining to be delivered on behalf of our VPP buyers as of June 30, 2013 were as follows:



		Volume Remaining as of June 30, 2013
VPP #	Term Remaining	Natural Gas	Oil	NGL	Total
	(in months)	(bcf)	(mmbbl)	(mmbbl)	(bcfe)
10	104	61	1.9	6.7	112.8
9	92	94	1.1	3.2	119.7
8	26	129	—	—	128.6
6	79	24	0.2	—	24.7
5	43	20	0.1	—	20.9
4	42	30	0.2	—	30.7
3	73	35	—	—	35.0
2	70	25	—	—	25.6
1	114	112	—	—	112.5
		530	3.5	9.9	610.5

For accounting purposes, cash proceeds from the sale of VPPs 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 (VPP #7), originally sold in June 2010, for $313 million. The reserves purchased totaled 28 bcfe and were subsequently sold to the buyers of our Permian Basin assets.