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, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31, 2012
(in thousands)
Property acquisition costs:
Proved	$	478,311	$	—	$	3,457	$	70,700
Unproved	—		—		463		10,686
Exploration costs	148		—		868		16,405
Development costs	555,629		22,266		577,568		696,095
Asset retirement costs	6,064		—		15,998		18,248
Total costs incurred ⁽¹⁾	$	1,040,152	$	22,266	$	598,354	$	812,134


⁽¹⁾	The total above does not reflect approximately $6 million, $41,000, $6 million and $18 million of capitalized interest incurred for the year ended December 31, 2014, for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, 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,
	2014			2013
	(in thousands)

Oil and natural gas:
Proved properties	$	4,025,595		$	3,397,785
Unproved properties	846,464			1,415,874
	4,872,059			4,813,659
Less accumulated depletion and amortization	(525,007		)	(10,394		)
	$	4,347,052		$	4,803,265

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, 2014		December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	1,298,402	$	50,324		$	1,103,245		$	937,261
Gains (losses) on oil and natural gas derivatives	78,784		(5,049		)	(34,711		)	64,620
	1,377,186		45,275			1,068,534			1,001,881
Production costs:
Lease operating expenses	364,540		15,410			295,811			232,266
Transportation expenses	41,842		2,576			46,774			39,531
Severance taxes, ad valorem taxes and California carbon allowances	97,683		2,130			57,063			39,374
	504,065		20,116			399,648			311,171
Other costs:
Exploration costs	—		—			24,048			21,010
Depletion and amortization	294,107		10,612			275,927			224,836
Impairment of long-lived assets	253,362		—			—			—
(Gains) losses on sale of assets and other, net	112,303		10,208			(23		)	(1,782		)
	659,772		20,820			299,952			244,064
Income tax expense	69		—			65,280			88,121
Results of operations	$	213,280	$	4,339		$	303,654		$	358,525

There is no federal tax provision included in the results above for the year ended December 31, 2014, and 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 year ended 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 SEC regulations, reserves at December 31, 2014, December 31, 2013, and December 31, 2012, 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, 2014
	Oil MBbls		Natural Gas MMcf		Total MBOE

Total proved reserves:
Beginning of year	187,362		280,117		234,048
Revisions of previous estimates	(10,647	)	42,514		(3,561	)
Extensions, discoveries and other additions	20,435		35,552		26,360
Purchases of minerals in place	22,533		408,857		90,676
Sales of minerals in place	(41,216	)	(51,065	)	(49,727	)
Production	(14,065	)	(28,938	)	(18,888	)
End of year	164,402		687,037		278,908

Proved developed reserves	119,039		552,184		211,069
Proved undeveloped reserves	45,363		134,853		67,839
Total proved reserves	164,402		687,037		278,908



	Successor						Predecessor
	December 17, 2013 through December 31, 2013						January 1, 2013 through December 16, 2013
	Oil MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		Natural Gas MMcf		Total MBOE

Total proved reserves:
Beginning of period	187,892		280,943		234,715		204,208		425,519		275,129
Revisions of previous estimates	—		—		—		(13,536	)	(153,330	)	(39,092	)
Extensions, discoveries and other additions	—		—		—		10,955		29,756		15,913
Sales of minerals in place	—		—		—		(2,263	)	(3,071	)	(2,775	)
Production	(530	)	(826	)	(667	)	(11,472	)	(17,931	)	(14,460	)
End of period	187,362		280,117		234,048		187,892		280,943		234,715

Proved developed reserves	121,694		202,798		155,494		122,224		203,624		156,161
Proved undeveloped reserves	65,668		77,319		78,554		65,668		77,319		78,554
Total proved reserves	187,362		280,117		234,048		187,892		280,943		234,715



	Predecessor
	Year Ended December 31, 2012
	Oil MBbls		Natural Gas MMcf		Total MBOE

Total proved reserves:
Beginning of year	185,880		534,279		274,926
Revisions of previous estimates	12,145		(205,845	)	(22,162	)
Extensions, discoveries and other additions	8,459		100,129		25,148
Purchases of minerals in place	8,304		16,740		11,094
Sales of minerals in place	(556	)	—		(556	)
Production	(10,024	)	(19,784	)	(13,321	)
End of year	204,208		425,519		275,129

Proved developed reserves	118,937		187,668		150,216
Proved undeveloped reserves	85,271		237,851		124,913
Total proved reserves	204,208		425,519		275,129

The tables above include changes in estimated quantities of natural gas reserves shown in BOE equivalents at a rate of six Mcf per one barrel.

Since the reserves were estimated in accordance with SEC regulations, 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, the Company had positive price revisions for the year ended December 31, 2014, even though there was a steep decline in commodity prices during the fourth quarter of 2014. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas prices decreased approximately 42% and 30%, respectively, to $53.27 per Bbl for oil and $2.89 per MMBtu for natural gas at December 31, 2014. 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 negative revisions due to asset performance and the SEC five-year development limitation on PUDs partially offset by positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2014, properties acquired in the exchanges with Exxon Mobil Corporation increased proved reserves by approximately 90,676 MBOE and the Permian Basin Assets Sale and properties relinquished in the exchanges with Exxon Mobil Corporation 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.

Proved reserves increased by approximately 203 MBOE to approximately 275,129 MBOE for the year ended December 31, 2012, from 274,926 MBOE for the year ended December 31, 2011. The year ended December 31, 2012, includes 22,162 MBOE of negative revisions of previous estimates, primarily in the Piceance Basin and East Texas due to the SEC five-year development limitation on PUDs and pricing, offset by positive revisions due to development drilling in Diatomite, McKittrick, and the Permian Basin. During the year ended December 31, 2012, the Company acquired reserves of approximately 11,094 MBOE primarily in Utah and the Permian Basin, and the sale of its Nevada Assets (see Note 2) decreased proved reserves by approximately 556 MBOE. In addition, extensions and discoveries, primarily from 467 productive wells drilled during the year, contributed approximately 25,148 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 at December 31, 2014, and December 31, 2013, 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. Prior to the LINN Energy transaction, the Company was a Subchapter C-corporation subject to federal and state income taxes. Future income tax expenses at December 31, 2012, were computed by applying the appropriate year-end statutory income tax rates to the estimated future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses gave effect to income tax deductions, credits and allowances relating to the proved oil and natural gas reserves.



	Successor						Predecessor
	December 31, 2014			December 31, 2013			December 31, 2012
(in thousands)
Future estimated revenues	$	16,844,678		$	17,863,984		$	19,738,729
Future estimated production costs	(7,742,035		)	(6,654,536		)	(5,884,891		)
Future estimated development costs	(1,132,807		)	(1,854,849		)	(2,164,780		)
Future estimated income tax expense	—			—			(3,344,024		)
Future net cash flows	7,969,836			9,354,599			8,345,034
10% annual discount for estimated timing of cash flows	(3,639,459		)	(4,719,267		)	(4,511,619		)
Standardized measure of discounted future net cash flows	$	4,330,377		$	4,635,332		$	3,833,415

Representative NYMEX prices:⁽¹⁾
Oil (Bbl)	$	95.27		$	96.89		$	90.66
Natural gas (MMBtu)	4.35			3.67			2.88


⁽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 summarizes the principal sources of change in the standardized measure of discounted future net cash flows:



	Successor
	December 31, 2014
(in thousands)
Standardized measure—beginning of year	$	4,635,332
Sales and transfers of oil, natural gas and NGL produced during the period	(794,337		)
Changes in estimated future development costs	68,290
Net change in sales and transfer prices and production costs related to future production	(1,020,605		)
Extensions, discoveries and improved recovery	674,392
Purchases of minerals in place	548,256
Sales of minerals in place	(486,903		)
Previously estimated development costs incurred during the period	269,473
Net change due to revisions in quantity estimates	(66,696		)
Accretion of discount	463,533
Changes in production rates and other	39,642
Net decrease	(304,955		)
Standardized measure—end of year	$	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



	Predecessor
	December 31, 2012
(in thousands)
Standardized measure—beginning of year	$	4,035,279
Sales and transfers of oil, natural gas and NGL produced during the period	(625,707		)
Changes in estimated future development costs	(331,498		)
Net change in sales and transfer prices and production costs related to future production	(786,022		)
Extensions, discoveries and improved recovery	124,466
Purchases of minerals in place	114,094
Sales of minerals in place	(15,283		)
Previously estimated development costs incurred during the period	497,036
Net change due to revisions in quantity estimates	743
Accretion of discount	570,505
Income taxes	323,128
Changes in production rates and other	(73,326		)
Net decrease	(201,864		)
Standardized measure—end of year	$	3,833,415

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.