Supplemental Information Relating to Oil and Natural Gas Producing Activities (Unaudited)

The following supplemental information relating to Compass’ oil and natural gas producing activities for Fiscal 2015, 2014 and for the period from inception to September 30, 2013 is presented in accordance with ASC 932, “Extractive Activities, Oil and Gas.”

Prior to October 31, 2014, the operating results of Compass represented the Company’s 74.4% proportionate interest. Operating results after October 31, 2014 represent 100.0% of Compass’ consolidated results. Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities:



	Fiscal 2015			Fiscal 2014		Period from inception to September 30, 2013
Proved property acquisition costs	$	95.9		$	—	$	569.5
Unproved property acquisition costs	—			—		53.9
Total property acquisition costs	95.9			—		623.4
Development	17.3			11.4		11.8
Lease acquisitions and other	1.0			0.2		—
Capitalized asset retirement costs	(0.4		)	0.1		0.1
Depletion per Boe	$	7.84		$	8.68	$	10.00
Depletion per Mcfe	$	1.31		$	1.45	$	1.67

Compass retains an independent engineering firm to provide annual year-end estimates of its future net recoverable oil and natural gas reserves. The estimated proved net recoverable reserves Compass shows below include only those quantities that it expects to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves that Compass may recover through existing wells. Proved undeveloped reserves include those reserves that Compass may recover from new wells on undrilled acreage or from existing wells on which it must make a relatively major expenditure for recompletion or secondary recovery operations. All of Compass’ reserves are located onshore in the continental United States of America.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of Compass’ oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.



	Oil (Mbbls)		Natural Gas (Mmcf)		Natural Gas Liquids (Mbbls)		Natural Gas Equivalent (Mmcfe)
Inception
Purchase of reserves in place (1)	3,940		331,592		7,353		399,350
Discoveries and extensions (2)	188		4,416		753		10,062
Revisions of previous estimates:
Changes in price	(125	)	13,116		(135	)	11,556
Other factors (3)	(296	)	(12,136	)	(1,941	)	(25,558	)
Production	(283	)	(14,570	)	(300	)	(18,068	)
September 30, 2013	3,424		322,418		5,730		377,342
Discoveries and extensions (2)	112		839		173		2,549
Revisions of previous estimates:
Changes in price	233		20,815		496		25,189
Other factors (4)	335		(13,750	)	342		(9,688	)
Production	(414	)	(20,882	)	(521	)	(26,492	)
September 30, 2014	3,690		309,440		6,220		368,900
Purchase of reserves in place	1,252		105,297		2,116		125,502
Discoveries and extensions (2)	153		44		8		1,007
Revisions of previous estimates:
Reclassification to unproved reserves (5)	(110	)	(4,954	)	(63	)	(5,993	)
Changes in price	(964	)	(51,704	)	(2,860	)	(74,651	)
Other factors	708		(1,269	)	596		6,562
Sales of reserves in place	(12	)	(2,391	)	—		(2,464	)
Production	(479	)	(24,934	)	(606	)	(31,447	)
September 30, 2015	4,238		329,529		5,411		387,416


(1)	Purchases of reserves in place include the initial contribution of conventional assets from EXCO as of February 14, 2013, and the acquisition of shallow Cotton Valley assets from an affiliate BG Group as of March 5, 2013.


(2)	New discoveries and extensions were a result of Compass’ development in the Permian basin for Fiscal 2015, Fiscal 2014 and the period from inception to September 30, 2013.

(3)

Revisions of previous estimates due to other factors were primarily due to downward adjustments in the Permian basin of 18.1 Bcfe as a result of recent performance and modifications to Compass’ development plans which extended the development beyond a five-year horizon. In addition, revisions of previous estimates due to other factors in the East Texas/North Louisiana region were 7.5 Bcfe primarily due to performance.


(4)	Revisions of previous estimates due to other factors were primarily due to downward adjustments in the East Texas/North Louisiana region of 11.5 Bcfe primarily due to recent performance.


(5)	Represents proved Undeveloped Reserves reclassified to unproved pursuant to the five year development rule established by the SEC. While these locations previously qualified as Proved Undeveloped Reserves as they directly offset a proved location, Compass’ planned capital programs do not support development at this time.

Estimated Quantities of Proved Developed and Undeveloped Reserves



	Oil (Mbbls)	Natural Gas (Mmcf)	Natural Gas Liquids (Mbbls)	Mmcfe
Proved developed:
September 30, 2015	4,085	329,485	5,403	386,409
September 30, 2014	3,356	304,628	5,145	355,634
Proved undeveloped:
September 30, 2015	153	44	8	1,007
September 30, 2014	334	4,812	1,075	13,266

Standardized measure of discounted future net cash flows (“Standardized Measure”)

Compass has summarized the Standardized Measure related to its proved oil, natural gas, and natural gas liquids (“NGL”) reserves. Compass has based the following summary on a valuation of proved reserves using discounted cash flows based on prices as prescribed by the SEC, costs and economic conditions and a 10% discount rate. The additions to proved reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, the information presented below should not be viewed as an estimate of the fair value of Compass’ oil and natural gas properties, nor should the information be considered to be indicative of any trends.



	September 30,
	2015		2014		2013
Future cash inflows	$	1,330.1	$	1,895.2	$	1,638.5
Future production costs	750.8		914.9		923.7
Future development costs	160.0		164.4		156.0
Future income taxes	—		136.2		39.3
Future net cash flows	419.3		679.7		519.5
Discount of future net cash flows at 10% per annum	191.2		333.9		217.2
Standardized measure of discounted future net cash flows	$	228.1	$	345.8	$	302.3

The reference prices at September 30, 2015, 2014 and 2013 used in the above table, were $59.21 and $99.08 and $95.04 per Bbl of oil, respectively, $3.06, $4.24 and $3.60 per Mmbtu of natural gas, respectively, and $21.50 and $43.58 and $38.64 per Bbl for NGLs, respectively. The reference prices were based on West Texas Intermediate crude oil at Cushing, Oklahoma, and natural gas at Henry Hub. These prices were further adjusted for historical differentials. The prices used for NGLs were based on the trailing 12 month average of realized prices. These prices reflect the SEC rules requiring the use of simple average of the first day of the month price for the previous 12 month period.

The following are the principal sources of change in the Standardized Measure:



	Fiscal 2015			Fiscal 2014			Period from inception to September 30, 2013
Sales and transfers of oil and natural gas produced	$	(21.5	)	$	(77.4	)	$	(46.2	)
Net changes in prices and production costs	(336.8		)	141.8			39.2
Extensions and discoveries, net of future development and production costs	1.8			3.5			8.1
Development costs during the period	12.0			10.0			7.4
Changes in estimated future development costs	28.1			(12.0		)	20.2
Revisions of previous quantity estimates	(44.9		)	24.2			(50.2		)
Sales of reserves in place	138.2			—			—
Purchase of reserves in place	(3.1		)	—			300.6
Accretion of discount before income taxes	55.3			32.3			16.1
Changes in timing and other	(12.1		)	(34.3		)	27.9
Net change in income taxes	65.4			(44.6		)	(20.8		)
Net change	$	(117.7	)	$	43.5		$	302.3

Costs not subject to amortization

The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization by the period in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within 1 to 4 years.



	Total		Fiscal 2015		Fiscal 2014		Period from inception to September 30, 2013
Property acquisition costs	$	18.9	$	—	$	—	$	18.9
Capitalized interest	1.3		—		0.7		0.6
Total	$	20.2	$	—	$	0.7	$	19.5