Oil and Natural Gas Property Transactions

In the Current Quarter, CHK C-T sold all of its oil and natural gas properties to FourPoint and immediately used the consideration, plus other cash it had on hand, to repurchase and cancel all of CHK C-T’s outstanding preferred shares. In a related transaction, we sold noncore properties adjacent to the CHK C-T properties to FourPoint for approximately $90 million.

In the Prior Quarter, we exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI was the designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we were the designated operator. In conjunction with the exchange, we paid RKI approximately $450 million in cash.

During the Prior Quarter, we sold noncore leasehold interests in the Marcellus Shale to Rice Drilling B LLC, a wholly owned subsidiary of Rice Energy Inc. (NYSE:RICE), for net proceeds of $233 million.

During the Prior Quarter, we sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for net proceeds of $133 million. Operating obligations related to VPP #5 were also transferred. See Volumetric Production Payments below.

During the Current Period and the Prior Period, excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds related to divestitures of other noncore oil and natural gas properties of approximately $52 million and $335 million, respectively.

Under full cost accounting rules, we accounted for the sales of oil and natural gas properties discussed above as adjustments to capitalized costs, with no recognition of gain or loss as the sales have not involved a significant change in proved reserves or significantly altered the relationship between costs and proved reserves.

Joint Ventures

Between July 2008 and June 2013, we entered into eight significant joint ventures with other leading energy companies, including Sinopec International Petroleum Exploration and Production (Sinopec), Total S.A. (Total), CNOOC Limited, Statoil, BP America and Freeport-McMoRan Inc. (formerly known as Plains Exploration & Production Company), pursuant to which we sold portions ranging from 20% to 50% of certain leasehold, producing properties and other assets located in eight different resource plays. In return, we received aggregate cash proceeds of $8.0 billion and commitments by our joint venture partners to pay, in the aggregate, 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. Each joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner and, if applicable, pays a specified percentage of our drilling and completion costs in designated wells. As of September 30, 2015, we had utilized all drilling carries from our joint venture partners. During the Current Period and the Prior Period, our drilling and completion costs included the benefit of approximately $51 million and $535 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, Utica, Eagle Ford shales and Mid-Continent plays to our joint venture partners for approximately $30 million and $24 million, respectively.

Volumetric Production Payments

From time to time, we have sold certain of our producing assets located in more mature producing regions through the sale of VPPs. A VPP is a limited-term overriding royalty interest in oil and natural gas 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 novated to each of the respective VPP buyers hedges that 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 bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our condensed consolidated statements of operations in the periods these 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 our full cost ceiling test 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 the 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.

For accounting purposes, cash proceeds from the sale of VPPs were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and our proved reserves were reduced accordingly. We have also 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.

As of September 30, 2015, our outstanding VPPs consisted of the following:



					Volume Sold
VPP #	Date of VPP	Location	Proceeds		Oil	Natural Gas	NGL	Total
			($ in millions)		(mmbbl)	(bcf)	(mmbbl)	(bcfe)
10	March 2012	Anadarko Basin Granite Wash	$	744	3.0	87	9.2	160
9	May 2011	Mid-Continent	853		1.7	138	4.8	177
4	December 2008	Anadarko and Arkoma Basins	412		0.5	95	—	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
			$	4,331	5.2	715	14.0	830

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



	Three Months Ended September 30, 2015				Three Months Ended September 30, 2014
VPP #	Oil	Natural Gas	NGL	Total	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	76.0	2.1	253.3	4.0	98.0	2.6	314.5	5.0
9	41.4	3.6	92.9	4.3	46.1	3.8	101.5	4.7
8^(a)	—	8.9	—	8.9	—	14.8	—	14.8
6^(b)	—	—	—	—	6.0	1.1	—	1.1
5^(b)	—	—	—	—	4.2	1.2	—	1.2
4	10.5	2.0	—	2.0	11.9	2.2	—	2.3
3	—	1.6	—	1.6	—	1.8	—	1.8
2	—	1.0	—	1.0	—	1.1	—	1.1
1	—	3.2	—	3.2	—	3.4	—	3.4
	127.9	22.4	346.2	25.0	166.2	32.0	416.0	35.4

	Nine Months Ended September 30, 2015				Nine Months Ended September 30, 2014
VPP #	Oil	Natural Gas	NGL	Total	Oil	Natural Gas	NGL	Total
	(mbbl)	(bcf)	(mbbl)	(bcfe)	(mbbl)	(bcf)	(mbbl)	(bcfe)
10	237.0	6.5	798.3	12.7	310.0	8.1	989.6	15.8
9	127.5	10.8	284.8	13.2	142.6	11.7	311.9	14.4
8^(a)	—	36.5	—	36.5	—	45.7	—	45.7
6^(b)	—	—	—	—	18.0	3.3	—	3.4
5^(b)	—	—	—	—	16.5	4.6	—	4.7
4	32.2	6.1	—	6.2	36.5	6.8	—	7.0
3	—	4.9	—	4.9	—	5.5	—	5.5
2	—	3.1	—	3.1	—	5.1	—	5.1
1	—	10.0	—	10.0	—	10.4	—	10.4
	396.7	77.9	1,083.1	86.6	523.6	101.2	1,301.5	112.0

____________________________________________


(a)	VPP #8 expired in August 2015.


(b)	In 2014, we divested the properties associated with VPP #5 and VPP #6.

The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2015 were as follows:



		Volume Remaining as of September 30, 2015
VPP #	Term Remaining	Oil	Natural Gas	NGL	Total
	(in months)	(mmbbl)	(bcf)	(mmbbl)	(bcfe)
10	77	1.1	31.5	3.9	61.3
9	65	0.7	62.5	1.7	76.6
4	15	—	9.3	—	9.6
3	46	—	19.1	—	19.1
2	43	—	10.8	—	10.8
1	87	—	81.6	—	81.6
		1.8	214.8	5.6	259.0