Breitburn Energy Partners LP - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - 8-K - Breitburn Energy Partners LP	a8kq42015earningsrelease8-k.htm

Exhibit 99.1

Breitburn Energy Partners Reports Fourth Quarter and Full Year 2015 Results and

Provides Full Year 2016 Operational Guidance

LOS ANGELES, February 26, 2016 - Breitburn Energy Partners LP (NASDAQ:BBEP) today announced financial and operating results for the fourth quarter and full year 2015 as well as operational guidance for its expected performance in 2016.

Key Highlights


•	Annual production of 20.2 million Boe, at high-end of guidance, with average daily production of 55,288 Boe/d for the year.


•	Adjusted EBITDA, a non-GAAP financial measure, increased to $169 million in 4Q15, 8.2% higher than 3Q15, despite lower realized oil and NGL prices. 2015 Adjusted EBITDA of $636.8 million (including acquisition and integration costs of $12.6 million and restructuring costs of $5 million) was in line with guidance.


•	Pre-tax lease operating expenses were $17.74/Boe in 4Q15, 10.5% lower than 3Q15 and 18.5% lower than 4Q14. 2015 pre-tax lease operating expenses were $19.02/Boe, at low-end of guidance.


•	G&A expenses, excluding acquisition and integration costs and non-cash unit based compensation, were $2.48/Boe in 4Q15, 9.4% lower than 3Q15 and the best quarter in Breitburn’s history. 2015 G&A expenses, excluding acquisition and integration costs and non-cash unit based compensation, were $3.02/Boe, 13% lower than 2014.


•	The estimated fair value of Breitburn’s commodity hedge portfolio was approximately $666 million as of December 31, 2015.

Management Commentary

Halbert S. Washburn, Breitburn’s Chief Executive Officer, said: “We were very proactive last year in adapting to a volatile commodity price environment. We had strong operating and financial results, with production coming in at the high end of our guidance and our capital, operating, and G&A costs performing in line with or better than our guidance. We were also one of the first oil and gas companies to raise significant capital last year, and through our financing and cost cutting efforts, we were able to reduce our bank borrowings by nearly $1 billion in 2015. In light of the ongoing weakness in commodity prices, we are cutting our 2016 capital program by 60% to approximately $80 million, but because of our quality, long-lived, low-decline assets we only expect a 9% reduction to our 2016 production. With the continued hard work of our experienced team, we believe we are well-positioned to execute our operating plan successfully again this year.”

Fourth Quarter 2015 Operating and Financial Results Compared to Third Quarter 2015


•	Total production was 5,106 MBoe in the fourth quarter of 2015 compared to 5,008 MBoe in the third quarter of 2015. Average daily production was 55.5 MBoe/day in the fourth quarter of 2015 compared to 54.4 MBoe/day in the third quarter of 2015.


•	Oil production increased to 2,795 MBbl compared to 2,741 MBbl in the third quarter of 2015


•	NGL production increased to 526 MBbl compared to 485 MBbl in the third quarter of 2015


•	Natural gas production increased to 10,712 MMcf compared to 10,689 MMcf in the third quarter of 2015

•

Adjusted EBITDA was $169 million in the fourth quarter of 2015 compared to $156.3 million in the third quarter of 2015, an 8.2% increase. The increase was primarily due to higher commodity derivative instrument settlement receipts, lower operating costs, higher sales volume, and lower G&A expenses, partially offset by lower oil, natural gas and NGL sales revenue due to lower average realized commodity prices.

•

Net loss attributable to common unitholders was $902.3 million, or $4.25 per diluted common unit, in the fourth quarter of 2015, which included non-cash impairment charges of approximately $878.3 million, or $4.14 per common unit, primarily related to the impact that further deterioration in forecast future commodity prices had on our projected net revenues for certain of our oil and gas properties, compared to net loss of $1.3 billion, or $6.17 per diluted common unit, in the third quarter of 2015, which included non-cash impairment charges of approximately $1.4 billion, or $6.80 per unit.


•	Oil, NGL and natural gas sales revenues were $139.7 million in the fourth quarter of 2015 compared to $153.3 million in the third quarter of 2015, primarily due to lower realized oil and natural gas prices, partially offset by higher sales volumes.


•	Lease operating expenses, which include district expenses, processing fees, and transportation costs but exclude taxes, were $17.74 per Boe in the fourth quarter of 2015 compared to $19.83 per Boe in the third quarter of 2015. The decrease was due to lower operating costs, lower workover expenses and continued focus on lowering costs.

•

General and administrative expenses, excluding non-cash unit-based compensation costs, were $14.5 million in the fourth quarter of 2015 (including acquisition and integration costs of $1.8 million) compared to $16.9 million in the third quarter of 2015 (including acquisition and integration costs of $3.2 million). The decrease was primarily due to lower integration costs and lower employee related expenses.

•

Gains on commodity derivative instruments were $141.8 million in the fourth quarter of 2015 compared to gains of $253 million in the third quarter of 2015, primarily due to increases in oil and natural gas futures prices during the fourth quarter of 2015. Derivative instrument settlement receipts were $144.1 million in the fourth quarter of 2015 compared to receipts of $129 million in the third quarter of 2015, primarily due to lower oil prices.


•	NYMEX WTI oil spot prices averaged $41.94 per Bbl and Brent oil spot prices averaged $43.56 per Bbl in the fourth quarter of 2015 compared to $46.64 per Bbl and $50.41 per Bbl, respectively, in the third quarter of 2015. Henry Hub natural gas spot prices averaged $2.12 per Mcf in the fourth quarter of 2015 compared to $2.76 per Mcf in the third quarter of 2015.


•	Average realized crude oil, NGL, and natural gas prices, excluding the effects of commodity derivative settlements, averaged $37.31 per Bbl, $13.03 per Bbl and $2.32 per Mcf, respectively, in the fourth quarter of 2015 compared to $43.38 per Bbl, $12.44 per Bbl and $2.76 per Mcf, respectively, in the third quarter of 2015.


•	Oil, NGL and natural gas capital expenditures were approximately $36 million in the fourth quarter of 2015 compared to $46 million in the third quarter of 2015.

Full Year 2015 Results


•	Total production was 20.2 million Boe in 2015 compared to 14.1 million Boe in 2014. Production volumes increased by 6.1 million Boe, or 43%, primarily due to production from properties acquired in the QRE merger.

•

Adjusted EBITDA was $636.8 million in 2015 (including acquisition and integration costs of $12.6 million and restructuring costs of $5 million) compared to $473.8 million in 2014. The increase reflects the full year effect of the QRE merger, higher commodity derivative instrument settlement receipts and lower operating costs, partially offset by lower oil, natural gas and NGL sales revenue due to lower average realized commodity prices.


•	Net loss attributable to common unitholders was $2.6 billion, or $12.39 per diluted common unit, in 2015, which included non-cash impairment charges of approximately $2.4 billion, or $11.24 per common unit, compared to a net income of $411.3 million, or $3.02 per diluted common unit, in 2014, which included non-cash impairment charges of approximately $149 million, or $1.11 per common unit.


•	Total oil, NGL and natural gas sales were $645.3 million in 2015, a decrease of 25% from 2014 primarily due to lower commodity prices, partially offset by higher volumes from the full year effect of production from properties acquired in the QRE merger.


•	Lease operating expenses, which include district expenses, processing fees, and transportation costs but exclude taxes, were $383.8 million compared to $291.4 million in 2014, reflecting the full year effect of lease operating costs from properties acquired in the QRE merger.


•	General and administrative expenses, excluding unit-based compensation related costs but including $12.6 million in acquisition and integration costs, were $73.5 million compared to $63.6 million in 2014, which included $14 million in acquisition and integration costs. The increase was primarily due to higher payroll expense for additional personnel attributable to the QRE merger.


•	Gains on commodity derivative instruments were $438.6 million in 2015 compared to gains of $566.5 million in 2014. Derivative instrument settlement receipts were $500 million in 2015 compared to receipts of $27.8 million in 2014, primarily due to lower oil prices.


•	Average realized oil and NGL prices, excluding the effect of commodity derivative instruments, for 2015, were $44.46 per Bbl and $15.02 per Bbl, respectively, compared to NYMEX WTI oil prices of $48.49 per barrel. Average realized natural gas prices, excluding the effect of commodity derivative instruments, were $2.67 per Mcf compared to Henry Hub prices of $2.62 per Mcf.

Liquidity

As of February 25, 2016, we had approximately $1.2 billion in borrowings outstanding under our credit facility. The borrowing base at December 31, 2015 was $1.8 billion and is scheduled to be redetermined in April 2016, at which time we expect it to be significantly decreased. Although our lenders have the discretion to redetermine the borrowing base below our current outstanding borrowings, we do not expect that to occur in April 2016. If commodity prices remain depressed or further decline, we expect our borrowing base to be reduced again at the subsequent borrowing base redetermination in October 2016, which could further impact and limit our liquidity.

2015 Estimated Proved Reserves

Total estimated proved reserves as of December 31, 2015, were 239.3 MMBoe compared to total estimated proved reserves of 315.3 MMBoe as of December 31, 2014. The standardized measure of discounted future net cash flows related to our estimated proved reserves was approximately $1.3 billion as of December 31, 2015, compared to approximately $4.5 billion as of December 31, 2014. Of the total estimated proved reserves, 54% were oil, 8% were NGLs and 38% were natural gas, and 80% were classified as proved developed. Set forth below is a breakdown of Breitburn’s total estimated proved reserves among its seven operating areas:



Operating Area		% Estimated Proved Reserves
Midwest		21.5%
Ark-La-Tex		19.6%
Permian Basin		18.7%
Mid-Continent		13.5%
Rockies		10.7%
Southeast		8.5%
California		7.5%

The unweighted average first-day-of-the-month oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2015, were $50.28 per Bbl of oil for WTI NYMEX and $2.59 per MMBtu of natural gas for Henry Hub.

2016 Operational Guidance (Excludes Acquisitions, Divestitures or Financing Transactions)

Breitburn's 2016 Operational Guidance is subject to all of the cautionary statements and limitations described below and therein and under the caption “Cautionary Statement Regarding Forward-Looking Information.” Estimates for Breitburn's future production volumes are based on, among other things, assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products, and estimated future volumes may be lower due to the impact of wells being shut-in or not being repaired due to their being uneconomic at current or commodity prices. The production, transportation and marketing of oil and gas are extremely complex and are subject to disruption due to transportation and processing availability, mechanical failure, human error, weather, and numerous other factors, including the inability to obtain expected supply of CO₂. Breitburn's estimates are based on certain other assumptions, such as well performance, which may actually vary significantly from those assumed. Lease operating costs, including major maintenance costs, vary in response to changes in prices of services and materials used in the operation of our properties and the amount of maintenance activity required. Lease operating costs, including taxes, utilities and service company costs, move directionally with increases and decreases in commodity prices, and we cannot fully predict such future commodity or operating costs. Similarly, interest rates and price differentials are set by the market and are not within our control, and they can vary dramatically from time to time. Capital expenditures are based on our current expectations as to the level of capital expenditures that will be justified based upon the other assumptions set forth below as well as expectations about other operating and economic factors not set forth below. Breitburn's 2016 Operational Guidance does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved; rather it simply sets forth our best estimate today for these matters based upon our current expectations about the future based upon both stated and unstated assumptions. Actual conditions and those assumptions may, and probably will, change over the course of the year.



($ in 000s)	2016 Operational Guidance ⁽¹⁾
Total Production (MBoe):	17,000		—	19,700
Oil Production (MBbls)	9,000		—	10,500
NGL Production (MBbls)	1,750		—	1,950
Natural Gas Production (MMcfe)	37,500		—	43,500
Average Price Differential %:
WTI Oil Price Differential %	85.0	%	—	93.0%
NGL Price Differential % (of WTI)	30.0%		—	50.0%
Natural Gas Price Differential %	100.0%		—	105.0%
Oil, NGL, and Natural Gas Sales Revenue⁽²⁾	$330,000		—	$430,000
Other Revenue⁽³⁾	$25,000		—	$33,000
Lease Operating Expenses / Boe⁽⁴⁾	$18.00		—	$20.00
Other Operating Expenses⁽⁵⁾	$16,000		—	$18,000
Production / Property Taxes (% of Sales Revenue)	8.00%		—	8.50%
G&A (Excluding Unit Based Compensation)⁽⁶⁾	$56,000		—	$60,000
Adjusted EBITDA⁽⁷⁾	$490,000		—	$525,000
Cash Interest Expense⁽⁸⁾	$191,000		—	$197,000
Preferred Equity Distributions⁽⁹⁾	$16,500
Capital Expenditures⁽¹⁰⁾	$80,000



(1)	Breitburn’s 2016 Operational Guidance is based on flat $30 per barrel WTI crude oil, $30 per barrel Brent crude oil and $2.30 per Mcf natural gas prices and excludes acquisitions, divestitures or financing transactions. Operating costs and capital expenditures generally track commodity prices but they do not increase or decrease as quickly as commodity prices.
(2)	Range based on the low and high values of production and differentials as set forth above.
(3)	Primarily consists of other revenues from the East Texas Salt Water Disposal System and the Postle Field in OK.
(4)	Pre-tax lease operating expenses include processing fees, district expenses, and transportation costs.
(5)	Represents costs related to the East Texas Salt Water Disposal System.
(6)	Excludes approximately $10 million in long-term compensation and severance payments paid in cash.
(7)	Assuming the high and low ranges of production and LOE guidance (and the midpoint for the remaining guidance components), Adjusted EBITDA is expected to range between $490 million and $525 million, and is comprised of estimated net loss (before non-cash compensation and non-cash distributions paid-in-kind to holders of 8% Series B Preferred Units) between ($541) million (low end of Adjusted EBITDA) and ($500) million (high end of Adjusted EBITDA), plus unrealized losses on commodity derivative instruments of $385 million, plus DD&A of $433 million, plus interest expense between $191 million (high end of Adjusted EBITDA) and $197 million (low end of Adjusted EBITDA), plus preferred distributions to holders of 8.25% Series A Preferred Units of $16.5 million. Differences between actual and forecast prices could result in changes to unrealized gains or losses on commodity derivative instruments, DD&A, including potential impairments of long-lived assets, and ultimately, net income.
(8)	Typically, Breitburn’s borrowings under its credit facility are based on 1-month LIBOR plus an applicable spread ranging from 175 bps to 275 bps. Cash interest expense assumes a 1-month LIBOR rate of 0.50%.
(9)	Reflects cash distributions paid to holders of 8.25% Series A Cumulative Redeemable Perpetual Preferred Units and assumes that distributions owed to holders of 8% Series B Perpetual Convertible Preferred Units will be paid in kind.
(10)	Capital expenditures exclude information technology spending of $1.7 million and capitalized engineering of $4.3 million.

Impact of Derivative Instruments

Breitburn uses commodity derivative instruments to mitigate risks associated with commodity price volatility and to help maintain cash flows for operating activities, acquisitions, capital expenditures and distributions. Breitburn does not enter into derivative instruments for speculative trading purposes. Since Breitburn does not use hedge accounting to account for its derivative instruments, changes in the fair value of derivative instruments are recorded in Breitburn’s earnings during each reporting period. These non-cash changes in the fair value of derivatives do not affect Adjusted EBITDA, cash flow from operations and distributable cash flow presented.

Production, Statement of Operations, and Realized Price Information

The following table presents production, selected income statement and realized price information for the three months ended December 31, 2015 and 2014, the three months ended September 30, 2015, and the full year results for 2015 and 2014:



	Three Months Ended								Year Ended
	December 31,			September 30,			December 31,		December 31,
Thousands of dollars, except as indicated	2015			2015			2014		2015			2014
Oil sales	$	108,024		$	117,743		$	151,335	$	504,035		$	669,355
NGL sales	6,852			6,032			9,709		29,336			41,031
Natural gas sales	24,812			29,550			36,023		111,901			145,434
Gain on commodity derivative instruments	141,842			253,012			587,590		438,614			566,533
Other revenues, net	5,934			5,922			3,376		24,829			7,616
Total revenues	287,464			412,259			788,033		1,108,715			1,429,969
Lease operating expenses (a)	90,563			99,318			90,768		383,827			291,395
Production and property taxes (b)	9,033			13,249			14,084		51,174			62,071
Total lease operating expenses	99,596			112,567			104,852		435,001			353,466
Purchases and other operating costs	2,119			367			299		3,056			725
Salt water disposal costs	2,408			4,205			2,168		14,687			2,168
Change in inventory	2,116			(2,004		)	201		2,445			(678		)
Total operating costs	106,239			115,135			107,520		455,189			355,681
Lease operating expenses, pre taxes, per Boe (a)	$	17.74		$	19.83		$	21.77	$	19.02		$	20.65
Production and property taxes per Boe (b)	1.77			2.65			3.38		2.54			4.40
Total lease operating expenses per Boe	19.51			22.48			25.15		21.56			25.05
General and administrative expenses (excluding non-cash unit-based compensation)	14,508			16,916			28,116		73,537			63,562
Net (loss) income attributable to the partnership	(890,878		)	(1,327,929		)	405,173		(2,583,339		)	421,333

Basic net (loss) income per unit	$	(4.25	)	$	(6.17	)	$	2.28	$	(12.39	)	$	3.04
Diluted net (loss) income per unit	$	(4.25	)	$	(6.17	)	$	2.27	$	(12.39	)	$	3.02

Total production (MBoe) (c)	5,106			5,008			4,170		20,180			14,114
Oil (MBbl)	2,795			2,741			2,327		11,248			7,931
NGLs (MBbl)	526			485			368		1,953			1,157
Natural gas (MMcf)	10,712			10,689			8,847		41,876			30,159
Average daily production (Boe/d)	55,500			54,435			45,313		55,288			38,670
Sales volumes (MBoe) (d)	5,151			4,980			4,022		20,219			13,956
Average realized sales price (per Boe) (e) (f)	$	26.72		$	30.78		$	48.96	$	31.80		$	61.30
Oil (per Bbl) (e) (f)	37.31			43.38			69.36		44.46			86.08
NGLs (per Bbl) (e)	13.03			12.44			26.38		15.02			35.46
Natural gas (per Mcf) (e)	$	2.32		$	2.76		$	4.07	$	2.67		$	4.82



(a)	Includes district expenses, processing fees, and transportation expenses.
(b)	Includes ad valorem and severance taxes.
(c)	Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a Bbl of oil equivalent for natural gas is significantly less than the price for a Bbl of oil.
(d)	Oil sales were 2,841 MBbl, 2,713 MBbl and 2,180 MBbl for the three months ended December 31, 2015, September 30, 2015 and December 31, 2014, respectively, and 11,287 MBbl and 7,773 MBbl for the twelve months ended December 31, 2015 and 2014, respectively.
(e)	Excludes the effect of commodity derivative settlements.
(f)	Includes oil purchases.

Non-GAAP Financial Measures

This press release, including the financial tables and other supplemental information and reconciliations of certain non-generally accepted accounting principles (“non-GAAP”) measures to their nearest comparable generally accepted accounting principles (“GAAP”) measures, may be used periodically by management when discussing Breitburn’s financial results with investors and analysts, and they are also available at breitburn.com.

“Adjusted EBITDA” and “distributable cash flow” are among the non-GAAP financial measures used in this press release. These non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. Management believes that these non-GAAP financial measures enhance comparability to prior periods.

Adjusted EBITDA is presented because management believes it provides additional information relative to the performance of Breitburn’s assets, without regard to financing methods or capital structure. Distributable cash flow is used by management as a tool to measure the cash distributions we could pay to our unitholders. This financial measure indicates to investors whether or not we are generating cash flow at a level that can support our distribution rate to our unitholders. These non-GAAP financial measures may not be comparable to similarly titled measures of other publicly traded partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA or distributable cash flow in the same manner.

Adjusted EBITDA

The following table presents a reconciliation of net income (loss) and net cash flows from operating activities, our most directly comparable GAAP financial performance and liquidity measures, to Adjusted EBITDA for each of the periods indicated.



	Three Months Ended									Year Ended
	December 31,			September 30,			December 31,			December 31,
Thousands of dollars, except as indicated	2015			2015			2014			2015			2014
Reconciliation of net income (loss) to Adjusted EBITDA:
Net (loss) income attributable to the partnership	$	(890,878	)	$	(1,327,929	)	$	405,173		$	(2,583,339	)	$	421,333
Gain on commodity derivative instruments	(141,842		)	(253,012		)	(587,590		)	(438,614		)	(566,533		)
Commodity derivative instrument settlements (a) (b)	144,083			128,969			62,053			499,985			27,825
Depletion, depreciation and amortization expense	123,312			117,464			87,292			460,047			291,709
Impairment of oil and natural gas properties	878,335			1,440,167			119,566			2,377,615			149,000
Impairment of goodwill	—			—			—			95,947			—
Interest expense and other financing costs	50,319			51,915			36,110			205,718			126,470
(Gain) loss on sale of assets	(1,542		)	(7,459		)	306			(8,864		)	663
Income tax expense (benefit)	1,162			14			(457		)	1,527			(73		)
Unit-based compensation expense (c)	6,091			6,360			4,947			25,462			23,387
Restructuring costs - unit-based compensation	—			(192		)	—			1,343			—
Adjusted EBITDA	169,040			156,297			127,400			636,827			473,781
Less:
Maintenance capital (d)	$	51,000		$	52,000		$	43,714		$	200,000		$	133,079
Cash interest expense	48,374			48,654			35,651			184,007			120,470
Distributions to preferred unitholders	4,125			4,125			4,125			16,500			10,083
Distributable cash flow available to common unitholders	$	65,541		$	51,518		$	43,910		$	236,320		$	210,149

Distributable cash flow available per common unit (e) (f)	$	0.296		$	0.237		$	0.207		$	1.086		$	1.431
Common unit distribution coverage (f)	n/a			1.90x			0.83x			3.26x			0.81x

Reconciliation of net cash flows from operating activities to Adjusted EBITDA:

Net cash provided by operating activities	$	85,521		$	136,239		$	62,839		$	436,705		$	357,755
Increase (decrease) in assets net of liabilities relating to operating activities	35,665			(29,063		)	29,199			16,369			(4,057		)
Interest expense (g)	48,364			48,562			35,563			183,852			120,143
Income from equity affiliates, net	94			163			(88		)	104			(178		)
Noncontrolling interest	(202		)	(91		)	17			(326		)	17
Income taxes	(413		)	488			(130		)	258			101
Gain on marketable securities	11			—			—			(135		)	—
Adjusted EBITDA	$	169,040		$	156,297		$	127,400		$	636,827		$	473,781



(a)	Excludes premiums paid at contract inception related to those derivative contracts that settled during the applicable periods of:	$	1,682	$	1,681	$	2,141	$	6,672	$	8,494
(b)	Includes net cash settlements on derivative instruments for:
	- Oil settlements received:	123,492		112,437		55,975		431,073		18,230
	- Natural gas settlements received:	20,592		16,532		6,078		68,913		9,595
(c)	Represents non-cash long-term unit-based incentive compensation expense.
(d)	Maintenance capital is management's estimate of the investment in capital projects and obligatory spending on existing facilities and operations needed to hold production approximately flat over a multi-year period.
(e)	Based on common units outstanding (including outstanding LTIP grants) at each distribution record date within the periods.
(f)	Third quarter 2014 includes the effect of the offering of 14 million common units in October 2014. Fourth quarter 2014 includes only 41 days of QR Energy operating results, $11.7 million of acquisition and integration costs, and the effect of 71.5 million common units issued in connection with the QR Energy merger.
(g)	Excludes amortization of debt issuance costs and amortization of senior note discount/premium.

Summary of Commodity Derivative Instruments

The table below summarizes Breitburn’s commodity derivative hedge portfolio as of February 25, 2016. Please refer to the Commodity Price Protection Portfolio at breitburn.com for additional information related to our hedge portfolio.



	Year
	2016			2017			2018		2019
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Volume (Bbl/d)	17,504			14,519			1,493		1,000
Average Price ($/Bbl)	$	83.62		$	82.81		$	64.02	$	56.35
Fixed Price Swaps - ICE Brent
Volume (Bbl/d)	4,300			298			—		—
Average Price ($/Bbl)	$	95.17		$	97.50		$	—	$	—
Collars - NYMEX WTI
Volume (Bbl/d)	1,500			—			—		—
Average Floor Price ($/Bbl)	$	80.00		$	—		$	—	$	—
Average Ceiling Price ($/Bbl)	$	102.00		$	—		$	—	$	—
Collars - ICE Brent
Volume (Bbl/d)	500			—			—		—
Average Floor Price ($/Bbl)	$	90.00		$	—		$	—	$	—
Average Ceiling Price ($/Bbl)	$	101.25		$	—		$	—	$	—
Puts - NYMEX WTI
Volume (Bbl/d)	1,000			—			—		—
Average Price ($/Bbl)	$	90.00		$	—		$	—	$	—
Total:
Volume (Bbl/d)	24,804			14,817			1,493		1,000
Average Price ($/Bbl)	$	85.79		$	83.11		$	64.02	$	56.35

Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Volume (MMBtu/d)	29,000			24,000			17,500		10,000
Average Price ($/MMBtu)	$	3.91		$	3.71		$	3.10	$	3.15
Fixed Price Swaps - Henry Hub
Volume (MMBtu/d)	42,050			21,016			2,870		—
Average Price ($/MMBtu)	$	4.02		$	4.29		$	3.74	$	—
Collars - Henry Hub
Volume (MMBtu/d)	630			595			—		—
Average Floor Price ($/MMBtu)	$	4.00		$	4.00		$	—	$	—
Average Ceiling Price ($/MMBtu)	$	5.55		$	6.15		$	—	$	—
Puts - Henry Hub
Volume (MMBtu/d)	11,350			10,445			—		—
Average Price ($/MMBtu)	$	4.00		$	4.00		$	—	$	—
Deferred Premium ($/MMBtu)	$	0.66	(a)	$	0.69	(b)	$	—	$	—
Total:
Volume (MMBtu/d)	83,030			56,056			20,370		10,000
Average Price ($/MMBtu)	$	3.98		$	3.98		$	3.19	$	3.15

(a) Deferred premiums of $0.66 apply to 11,350 MMBtu/d of the 2016 volume.

(b) Deferred premiums of $0.69 apply to 10,445 MMBtu/d of the 2017 volume.

Premiums paid in 2012 related to oil and natural gas derivatives to be settled in 2016 and beyond were as follows:



	Year
Thousands of dollars	2016		2017		2018		2019
Oil	$	7,438	$	734	$	—	$	—
Natural gas	952		—		—		—

Other Information

Breitburn will host a conference call Friday, February 26, 2016, at 9:00 am (ET) to discuss Breitburn’s fourth quarter and full year 2015 results. The conference call may be accessed by calling 888-461-2024 (international callers dial 719-325-2494) or via webcast at http://ir.breitburn.com/. An archived edition of the conference call will also be available through March 4^th by calling 877-870-5176 (international callers dial 858-384-5517) and entering replay PIN 919731 or by visiting http://ir.breitburn.com/.

About Breitburn Energy Partners LP

Breitburn Energy Partners LP is a publicly traded independent oil and gas master limited partnership focused on the acquisition, development, and production of oil and gas properties throughout the United States. Breitburn’s producing and non-producing crude oil and natural gas reserves are located in Ark-La-Tex; the Midwest; the Permian Basin; the Mid-Continent; the Rockies; the Southeast; and California. See www.breitburn.com for more information.

Cautionary Statement Regarding Forward-Looking Information

This press release contains forward-looking statements relating to Breitburn's operations that are based on management’s current expectations, estimates and projections about its operations. Words and phrases such as “believes,” “expect,” “future,” “impact,” “guidance,” “will be,” “forecast” and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. These include risks relating to Breitburn's financial performance and results, availability of sufficient cash flow and other sources of liquidity to execute our business plan, prices and demand for natural gas and oil, increases in operating costs, uncertainties inherent in estimating our reserves and production, our ability to replace reserves and efficiently develop our current reserves, political and regulatory developments relating to taxes, derivatives and our oil and gas operations, risks relating to our acquisitions and the factors set forth under the heading “Risk Factors” incorporated by reference from our Annual Report on Form 10-K filed with the Securities and Exchange Commission, and if applicable, our Quarterly Reports on Form 10-Q and our Current Reports on Form 8-K. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, Breitburn undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

Contacts:

Antonio D'Amico

Vice President, Investor Relations & Government Affairs

Jessica Tang

Investor Relations Manager

(213) 225-0390

BBEP-IR

Breitburn Energy Partners LP and Subsidiaries

Consolidated Balance Sheets



	December 31,			December 31,
Thousands of dollars	2015			2014
ASSETS
Current assets
Cash	$	10,464		$	12,628
Accounts and other receivables, net	128,589			166,436
Derivative instruments	439,627			408,151
Related party receivables	2,274			2,462
Inventory	926			3,727
Prepaid expenses	6,447			7,304
Total current assets	588,327			600,708
Equity investments	6,567			6,463
Property, plant and equipment
Oil and natural gas properties	7,898,117			7,736,409
Other property, plant and equipment	188,795			60,533
	8,086,912			7,796,942
Accumulated depletion and depreciation	(4,154,030		)	(1,342,741		)
Net property, plant and equipment	3,932,882			6,454,201
Other long-term assets
Goodwill	—			92,024
Derivative instruments	226,764			319,560
Other long-term assets	117,872			165,378
Total assets	$	4,872,412		$	7,638,334
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	50,412		$	129,270
Current portion of long-term debt	154,000			105,000
Derivative instruments	4,462			5,457
Distributions payable	733			733
Current portion of asset retirement obligation	2,341			4,948
Revenue and royalties payable	35,462			40,452
Wages and salaries payable	21,654			22,322
Accrued interest payable	19,517			20,672
Production and property taxes payable	24,292			25,207
Other current liabilities	5,133			7,495
Total current liabilities	318,006			361,556
Credit facility	1,075,000			2,089,500
Senior notes, net	1,789,219			1,156,560
Other long-term debt	2,938			1,100
Total long-term debt	2,867,157			3,247,160
Deferred income taxes	3,844			2,575
Asset retirement obligation	252,037			233,463
Derivative instruments	255			2,269
Other long-term liabilities	25,218			25,135
Total liabilities	3,466,517			3,872,158
Equity
Series A preferred units, 8.0 million units issued and outstanding at December 31, 2015 and December 31, 2014	193,215			193,215
Series B preferred units, 48.8 million and 0 units issued and outstanding at December 31, 2015 and December 31, 2014, respectively	353,471			—
Common units, 213.5 million and 210.9 million units issued and outstanding at December 31, 2015 and December 31, 2014, respectively	852,114			3,566,468
Accumulated other comprehensive loss	(229		)	(392		)
Total partners' equity	1,398,571			3,759,291
Noncontrolling interest	7,324			6,885
Total equity	1,405,895			3,766,176
Total liabilities and equity	$	4,872,412		$	7,638,334

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Operations



	Three Months Ended						Year Ended
	December 31,						December 31,
Thousands of dollars, except per unit amounts	2015			2014			2015			2014

Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	139,688		$	197,067		$	645,272		$	855,820
Gain on commodity derivative instruments, net	141,842			587,590			438,614			566,533
Other revenue, net	5,934			3,376			24,829			7,616
Total revenues and other income items	287,464			788,033			1,108,715			1,429,969
Operating costs and expenses
Operating costs	106,239			107,520			455,189			355,681
Depletion, depreciation and amortization	123,312			87,292			460,047			291,709
Impairment of oil and natural gas properties	878,335			119,566			2,377,615			149,000
Impairment of goodwill	—			—			95,947			—
General and administrative expenses	20,599			33,063			98,999			86,949
Restructuring costs	(49		)	—			6,364			—
(Gain) loss on sale of assets	(1,542		)	306			(8,864		)	663
Total operating costs and expenses	1,126,894			347,747			3,485,297			884,002
Operating (loss) income	(839,430		)	440,286			(2,376,582		)	545,967
Interest expense, net of capitalized interest	51,039			36,600			203,027			126,960
Gain on interest rate swaps	(720		)	(490		)	2,691			(490		)
Other income, net	(235		)	(523		)	(814		)	(1,746		)
Total other expense	50,084			35,587			204,904			124,724
(Loss) income before taxes	(889,514		)	404,699			(2,581,486		)	421,243
Income tax expense (benefit)	1,162			(457		)	1,527			(73		)
Net (loss) income	(890,676		)	405,156			(2,583,013		)	421,316
Less: Net income (loss) attributable to noncontrolling interest	202			(17		)	326			(17		)
Net (loss) income attributable to the partnership	(890,878		)	405,173			(2,583,339		)	421,333
Less: Distributions to Series A preferred unitholders	4,125			4,125			16,500			10,083
Less: Non-cash distributions to Series B preferred unitholders	7,264			—			20,817			—
Less: Net income (loss) attributable to participating units	—			3,927			—			5,348
Less: Distributions on participating units in excess of earnings	—			—			1,731			—
Net (loss) income used to calculate basic and diluted net (loss) income per unit	$	(902,267	)	$	397,121		$	(2,622,387	)	$	405,902

Basic net (loss) income per unit	$	(4.25	)	$	2.28		$	(12.39	)	$	3.04
Diluted net (loss) income per unit	$	(4.25	)	$	2.27		$	(12.39	)	$	3.02

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Comprehensive Income



	Year Ended December 31,
Thousands of dollars, except per unit amounts	2015			2014
Net (loss) income	$	(2,583,013	)	$	421,316

Other comprehensive (loss) income, net of tax:
Change in fair value of available-for-sale securities (a)	(402		)	(189		)
Pension and post-retirement benefit actuarial gain (loss) (b)	677			(473		)
Total other comprehensive income (loss), net of tax	275			(662		)
Total comprehensive (loss) income	(2,582,738		)	420,654
Less: Comprehensive income (loss) attributable to noncontrolling interest	438			(287		)
Comprehensive (loss) income attributable to the partnership	$	(2,583,176	)	$	420,941

(a) Net of income taxes of $0.3 million and $0.1 million for the years ended December 31, 2015 and 2014, respectively.

(b) Net of income tax (benefit) expense of $(0.1) million and $0.2 million for the years ended December 31, 2015 and 2014, respectively.

Breitburn Energy Partners LP and Subsidiaries

Consolidated Statements of Cash Flows



	Year Ended December 31,
Thousands of dollars	2015			2014

Cash flows from operating activities
Net (loss) income	$	(2,583,013	)	$	421,316
Adjustments to reconcile net (loss) income to cash flow from operating activities:
Depletion, depreciation and amortization	460,047			291,709
Impairment of oil and natural gas properties	2,377,615			149,000
Impairment of goodwill	95,947			—
Unit-based compensation expense	26,805			23,387
Gain on derivative instruments	(435,923		)	(567,024		)
Derivative instrument settlement receipts	494,234			26,806
Income from equity affiliates, net	(104		)	178
Deferred income taxes	1,269			(174		)
(Gain) loss on sale of assets	(8,864		)	663
Other	16,142			6,204
Changes in assets and liabilities:
Accounts receivable and other assets	35,367			41,754
Inventory	2,801			163
Net change in related party receivables and payables	188			142
Accounts payable and other liabilities	(45,806		)	(36,369		)
Net cash provided by operating activities	436,705			357,755
Cash flows from investing activities
Property acquisitions	(18,201		)	(401,465		)
Capital expenditures	(269,350		)	(417,755		)
Other	(853		)	(18,283		)
Proceeds from sale of assets	14,547			499
Proceeds from sale of available-for-sale securities	3,875			—
Purchases of available-for-sale securities	(4,021		)	—
Net cash used in investing activities	(274,003		)	(837,004		)
Cash flows from financing activities
Proceeds from issuance of preferred units, net	337,238			193,215
Proceeds from issuance of common units, net	3,008			277,613
Distributions to preferred unitholders	(16,502		)	(9,350		)
Distributions to common unitholders	(126,188		)	(264,585		)
Proceeds from issuance of long-term debt, net	1,378,338			2,457,600
Repayments of long-term debt	(1,711,500		)	(1,785,000		)
Senior note redemption	—			(352,531		)
Change in book overdraft	11			(2,434		)
Debt issuance costs	(29,271		)	(25,109		)
Net cash (used in) provided by financing activities	(164,866		)	489,419
(Decrease) increase in cash	(2,164		)	10,170
Cash beginning of period	12,628			2,458
Cash end of period	$	10,464		$	12,628

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