Acquisitions and Divestitures of Natural Gas and Oil Properties

Divestitures of Natural Gas and Oil Properties

During the Current Quarter and the Prior Quarter, excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds of approximately $165 million and $59 million, respectively, related to divestitures of noncore natural gas and oil properties.

Under full cost accounting rules, we accounted 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 did not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves. In conjunction with certain of these transactions, affiliates of our former 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 March 31, 2013, 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 to pay future drilling and completion costs of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all leasing, drilling, completion, operations and, in certain transactions, marketing activities for the project. The carry obligations 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 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	^(c)	$	2,032	$	1,007
Niobrara	CNOOC	February 2011	33.3%	570		697		^(d)	1,267		428
Eagle Ford	CNOOC	November 2010	33.3%	1,120		1,080			2,200		—
Barnett	TOT	January 2010	25.0%	800		1,404			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			3,158		—
				$	7,100	$	9,036		$	16,136	$	1,435

____________________________________________


(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 March 31, 2013.


(c)	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.


(d)	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 Quarter and the Prior Quarter, our drilling and completion costs included the benefit of approximately $180 million and $448 million, respectively, in drilling and completion carries paid by our joint venture partners.

During the Current Quarter and the Prior Quarter, 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 $25 million and $18 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 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. 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 and the Prior Quarter were as follows:



	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012
VPP #	Natural Gas	Oil	NGL	Natural Gas	Oil	NGL
	(bcf)	(mbbl)	(mbbl)	(bcf)	(mbbl)	(mbbl)
10	4	154.0	407.7	2	97.0	217.8
9	4	56.2	148.5	5	66.6	169.3
8	18	—	—	22	—	—
7	—	—	—	—	175.0	—
6	1	6.0	—	1	6.0	—
5	2	6.0	—	2	7.6	—
4	3	14.6	—	3	16.7	—
3	2	—	—	3	—	—
2	3	—	—	3	—	—
1	4	—	—	4	—	—
	41	236.8	556.2	45	368.9	387.1

The volumes remaining to be delivered on behalf of our VPP buyers as of March 31, 2013 were as follows:



		Volume Remaining as of March 31, 2013
VPP #	Term Remaining	Natural Gas	Oil	NGL	Total
	(in months)	(bcf)	(mmbbl)	(mmbbl)	(bcfe)
10	107	65	2.1	7.1	119.6
9	95	98	1.2	3.3	125.0
8	29	146	—	—	145.8
6	82	25	0.2	—	26.0
5	46	22	0.1	—	22.9
4	45	32	0.2	—	33.4
3	76	37	—	—	37.0
2	73	28	—	—	28.2
1	117	116	—	—	116.1
		569	3.8	10.4	654.0

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.