BERRY PETROLEUM COMPANY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)

The following discussion and analysis should be read in conjunction with the “Financial Statements” and “Notes to Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:



	Successor						Predecessor
	Year Ended December 31, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Property acquisition costs:
Proved	$	—	$	478,311	$	—	$	3,457
Unproved	—		—		—		463
Exploration costs	—		148		—		868
Development costs	130,276		555,629		22,266		577,568
Asset retirement costs	2,151		6,064		—		15,998
Total costs incurred ⁽¹⁾	$	132,427	$	1,040,152	$	22,266	$	598,354


⁽¹⁾	The total above does not reflect approximately $2 million, $6 million, $41,000 and $6 million of capitalized interest incurred for the years ended December 31, 2015, and December 31, 2014, and for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, respectively.

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:



	December 31,
	2015			2014
	(in thousands)

Oil and natural gas:
Proved properties	$	4,231,836		$	4,025,595
Unproved properties	779,225			846,464
	5,011,061			4,872,059
Less accumulated depletion and amortization	(1,596,165		)	(525,007		)
	$	3,414,896		$	4,347,052

Results of Oil and Natural Gas Producing Activities

The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below:



	Successor								Predecessor
	Year Ended December 31, 2015			Year Ended December 31, 2014		December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	575,031		$	1,298,402	$	50,324		$	1,103,245
Gains (losses) on oil and natural gas derivatives	29,175			78,784		(5,049		)	(34,711		)
	604,206			1,377,186		45,275			1,068,534
Production costs:
Lease operating expenses	245,155			364,540		15,410			295,811
Transportation expenses	52,160			41,842		2,576			46,774
Severance taxes, ad valorem taxes and California carbon allowances	70,591			97,683		2,130			57,063
	367,906			504,065		20,116			399,648
Other costs:
Exploration costs	—			—		—			24,048
Depletion and amortization	241,019			294,107		10,612			275,927
Impairment of long-lived assets	853,810			253,362		—			—
(Gains) losses on sale of assets and other, net	372			112,303		10,208			(23		)
	1,095,201			659,772		20,820			299,952
Income tax expense (benefit)	(68		)	69		—			65,280
Results of operations	$	(858,833	)	$	213,280	$	4,339		$	303,654

There is no federal tax provision included in the results above for the years ended December 31, 2015, and December 31, 2014, or for the period from December 17, 2013 through December 31, 2013, because the Company was not subject to federal income taxes during those periods. The income tax amount included in the results above for the years ended December 31, 2015 and December 31, 2014, relates to Texas margin tax expense. Limited liability companies are subject to Texas margin tax. See Note 4 for additional information about income taxes.

Proved Oil, Natural Gas and NGL Reserves

The proved reserves of oil and natural gas of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves at December 31, 2015, December 31, 2014, and December 31, 2013, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the U.S., is shown below:



	Successor
	Year Ended December 31, 2015								Year Ended December 31, 2014
	Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of year	144,410		19,992		687,037		278,908		170,903		16,459		280,117		234,048
Revisions of previous estimates	(40,348	)	(2,012	)	(270,030	)	(87,365	)	(9,256	)	(1,391	)	42,514		(3,561	)
Extensions, discoveries and other additions	793		34		4,693		1,610		20,056		379		35,552		26,360
Purchases of minerals in place	—		—		—		—		4,991		17,542		408,857		90,676
Sales of minerals in place	—		—		—		—		(28,890	)	(12,326	)	(51,065	)	(49,727	)
Production	(10,963	)	(1,061	)	(33,852	)	(17,666	)	(13,394	)	(671	)	(28,938	)	(18,888	)
End of year	93,892		16,953		387,848		175,487		144,410		19,992		687,037		278,908

Proved developed reserves	93,892		16,953		387,848		175,487		104,337		14,702		552,184		211,069
Proved undeveloped reserves	—		—		—		—		40,073		5,290		134,853		67,839
Total proved reserves	93,892		16,953		387,848		175,487		144,410		19,992		687,037		278,908



	Successor								Predecessor
	December 17, 2013 through December 31, 2013								January 1, 2013 through December 16, 2013
	Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of period	171,399		16,493		280,943		234,715		184,468		19,740		425,519		275,129
Revisions of previous estimates	—		—		—		—		(10,301	)	(3,235	)	(153,330	)	(39,092	)
Extensions, discoveries and other additions	—		—		—		—		9,360		1,595		29,756		15,913
Sales of minerals in place	—		—		—		—		(1,416	)	(847	)	(3,071	)	(2,775	)
Production	(496	)	(34	)	(826	)	(667	)	(10,712	)	(760	)	(17,931	)	(14,460	)
End of period	170,903		16,459		280,117		234,048		171,399		16,493		280,943		234,715

Proved developed reserves	113,717		7,977		202,798		155,494		114,213		8,011		203,624		156,161
Proved undeveloped reserves	57,186		8,482		77,319		78,554		57,186		8,482		77,319		78,554
Total proved reserves	170,903		16,459		280,117		234,048		171,399		16,493		280,943		234,715

The tables above include changes in estimated quantities of natural gas reserves shown in BOE using the ratio of six Mcf to one barrel.

Proved reserves decreased by approximately 103,421 MBOE to approximately 175,487 MBOE for the year ended December 31, 2015, from 278,908 MBOE for the year ended December 31, 2014. The year ended December 31, 2015, includes approximately 87,365 MBOE of negative revisions of previous estimates (71,389 MBOE due to lower commodity prices, 15,067 MBOE due to uncertainty regarding the Company’s future commitment to capital and 10,733 MBOE due to the SEC five-year development limitation on PUDs, partially offset by 9,824 MBOE of positive revisions due to asset performance). In addition, extensions and discoveries, primarily from 196 productive wells drilled during the year, contributed approximately 1,610 MBOE to the increase in proved reserves.

As a result of the uncertainty regarding the Company’s future commitment to capital, the Company reclassified all of its PUDs to unproved as of December 31, 2015. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for details regarding the Company’s going concern uncertainty.

The prices of oil, natural gas and NGL have continued to be volatile in 2016. In the future, if commodity prices continue to decline, the Company may have additional negative revisions which could have a material impact on its estimated quantities of oil, natural gas and NGL reserves. For information about potential risks that could affect the Company if lower commodity prices were to continue, see Item 1A. “Risk Factors.”

Proved reserves increased by approximately 44,860 MBOE to approximately 278,908 MBOE for the year ended December 31, 2014, from 234,048 MBOE for the year ended December 31, 2013. The year ended December 31, 2014, includes approximately 3,561 MBOE of negative revisions of previous estimates, due primarily to 3,547 MBOE of negative revisions due to asset performance and 2,910 MBOE due to the SEC five-year development limitation on PUDs, partially offset by 2,896 MBOE of positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2014, properties acquired in the exchanges with ExxonMobil and Exxon XTO increased proved reserves by approximately 90,676 MBOE and the Permian Basin Assets Sale and properties relinquished in the exchanges with ExxonMobil and Exxon XTO decreased proved reserves by approximately 49,727 MBOE. In addition, extensions and discoveries, primarily from 411 productive wells drilled during the year, contributed approximately 26,360 MBOE to the increase in proved reserves. Proved reserves decreased by approximately 667 MBOE to approximately 234,048 MBOE at December 31, 2013, from 234,715 MBOE at December 16, 2013, due to production during the successor period.

Proved reserves decreased by approximately 40,414 MBOE to approximately 234,715 MBOE at December 16, 2013, from 275,129 MBOE at December 31, 2012. The period from January 1, 2013 through December 16, 2013, includes 39,092 MBOE of negative revisions of previous estimates, due primarily to the SEC five-year development limitation on PUDs. During the period from January 1, 2013 through December 16, 2013, two sales in the Permian Basin operating area decreased proved reserves by approximately 2,775 MBOE. In addition, extensions and discoveries, primarily from 340 productive wells drilled during the period, contributed approximately 15,913 MBOE to the increase in proved reserves.

Standardized Measure of Discounted Future Net Cash Flows

Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts are not material. See Note 4 for additional information about income taxes.



	December 31,
	2015			2014			2013
	(in thousands)

Future estimated revenues	$	5,483,899		$	16,844,678		$	17,863,984
Future estimated production costs	(3,458,415		)	(7,742,035		)	(6,654,536		)
Future estimated development costs	(332,311		)	(1,132,807		)	(1,854,849		)
Future net cash flows	1,693,173			7,969,836			9,354,599
10% annual discount for estimated timing of cash flows	(697,801		)	(3,639,459		)	(4,719,267		)
Standardized measure of discounted future net cash flows	$	995,372		$	4,330,377		$	4,635,332

Representative NYMEX prices:⁽¹⁾
Oil (Bbl)	$	50.16		$	95.27		$	96.89
Natural gas (MMBtu)	2.59			4.35			3.67


⁽¹⁾	In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.

The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows:



	Successor
	December 31, 2015			December 31, 2014
	(in thousands)

Standardized measure–beginning of year	$	4,330,377		$	4,635,332
Sales and transfers of oil, natural gas and NGL produced during the period	(207,125		)	(794,337		)
Changes in estimated future development costs	431,622			68,290
Net change in sales and transfer prices and production costs related to future production	(3,203,620		)	(1,020,605		)
Extensions, discoveries and improved recovery	20,345			674,392
Purchases of minerals in place	—			548,256
Sales of minerals in place	—			(486,903		)
Previously estimated development costs incurred during the period	67,529			269,473
Net change due to revisions in quantity estimates	(544,334		)	(66,696		)
Accretion of discount	433,038			463,533
Changes in production rates and other	(332,460		)	39,642
Net decrease	(3,335,005		)	(304,955		)
Standardized measure–end of year	$	995,372		$	4,330,377



	Successor			Predecessor
	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
(in thousands)
Standardized measure–beginning of period	$	3,558,595		$	3,833,415
Sales and transfers of oil, natural gas and NGL produced during the period	(30,208		)	(703,597		)
Changes in estimated future development costs	—			20,932
Net change in sales and transfer prices and production costs related to future production	(1,272		)	(214,489		)
Extensions, discoveries and improved recovery	—			189,625
Sales of minerals in place	—			(13,279		)
Previously estimated development costs incurred during the period	—			401,791
Net change due to revisions in quantity estimates	—			(856,118		)
Accretion of discount	19,184			496,718
Income taxes	1,109,522			237,117
Changes in production rates and other	(20,489		)	166,480
Net increase (decrease)	1,076,737			(274,820		)
Standardized measure–end of period	$	4,635,332		$	3,558,595

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.