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	a8kq22015earningsrelease8-k.htm

Exhibit 99.1

Breitburn Energy Partners Reports Second Quarter 2015 Results and Provides Second Half 2015 Guidance

LOS ANGELES, August 6, 2015 - Breitburn Energy Partners LP (NASDAQ:BBEP) today announced financial and operating results for the second quarter 2015 and provided second half 2015 guidance.

Key Highlights


•	Closed the $1 billion strategic investment led by EIG Global Energy Partners on April 8th, resulting in approximately $500 million of current available liquidity.


•	Reported total production of 5.0 MMBoe, in-line with Breitburn's 2015 guidance.


•	Increased Adjusted EBITDA, a non-GAAP financial measure, to $162.9 million (including costs of $1.1 million for restructuring), a 48% increase from the second quarter of 2014 and a 10% increase from the first quarter of 2015.


•	Reduced lease operating expenses to $18.72 per Boe in the second quarter of 2015, 6% lower than the first quarter of 2015 and 14% lower than the fourth quarter of 2014.


•	Reported distributable cash flow of $58.5 million, or $0.27 per common unit, and distribution coverage ratio of 2.16x based on current monthly distribution of $0.04166 per common unit, or $0.50 per common unit on an annualized basis.

•

Based on Breitburn's current commodity hedge portfolio and assuming second half 2015 guidance production rate as set forth below, Breitburn's total production is 77% hedged for the remainder of 2015, 65% in 2016, and 41% in 2017 at attractive prices. The mark-to-market value of Breitburn's commodity hedge portfolio was approximately $544 million as of June 30th and approximately $670 million as of July 31st.

Management Commentary

Halbert S. Washburn, Breitburn’s Chief Executive Officer, said: "We are very pleased to report another solid quarter with production, cost reductions, and Adjusted EBITDA in-line with our guidance for the first half of the year. We have completed the integration of the QR Energy assets and our diverse portfolio continues to perform as expected in this challenging environment. Earlier this year, we announced a number of steps to address what we thought could be an extended period of weak commodity pricing. Those steps included dramatically reducing our capital budget, implementing an aggressive program to reduce operating costs and completing a significant workforce reduction plan. In addition, in April we raised almost $1 billion in external capital and reset our borrowing base to $1.8 billion, without a scheduled redetermination until April of 2016. We also reset our common unit distribution to $0.50 per unit. As a result of these actions, we currently have approximately $500 million of available liquidity under our credit facility, are on track to reduce bank debt throughout the year and have an excellent distribution coverage ratio of 2.16 times this quarter."

Mr. Washburn continued, "In addition, we continue to evaluate the most attractive alternatives for maximizing the value of our substantial acreage position in the Midland Basin. With over 22,000 gross surface acres and approximately 360 net identified locations, we have the ability to add meaningful production and reserves to our base business over the course of the next few years. This acreage provides us with significant strategic and operating flexibility particularly in the current commodity price environment."

Second Quarter 2015 Operating and Financial Results Compared to First Quarter 2015


•	Total production was 5,015 MBoe in the second quarter of 2015 compared to 5,051 MBoe in the first quarter of 2015. Average daily production was 55.1 MBoe/day in the second quarter of 2015 compared to 56.1 MBoe/day in the first quarter of 2015.


•	Oil production decreased to 2,822 MBbl compared to 2,890 MBbl in the first quarter of 2015.


•	NGL production increased to 483 MBbl compared to 459 MBbl in the first quarter of 2015.


•	Natural gas production increased to 10,264 MMcf compared to 10,211 MMcf in the first quarter of 2015.


•	Adjusted EBITDA was $162.9 million (including $1.1 million of restructuring costs) in the second quarter of 2015 compared to $148.6 million (including $4.1 million of restructuring costs) in the first quarter of 2015, a 10% increase primarily due to higher oil sales revenue and lower lease operating and G&A expenses, partially offset by lower commodity derivative settlements.


•	Net loss attributable to common unitholders was $316.2 million, or $1.46 per diluted common unit, in the second quarter of 2015, which includes a non-cash goodwill impairment charge of $95.9 million, or $0.45 per unit, compared to net loss of

$63.0 million, or $0.29 per diluted common unit, in the first quarter of 2015, which included non-cash impairment charges of approximately $59.1 million, or $0.28 per unit.


•	Oil, NGL and natural gas sales revenues were $189.6 million in the second quarter of 2015 compared to $162.6 million in the first quarter of 2015, primarily reflecting higher realized oil and NGL prices.


•	Lease operating expenses, which include district expenses, processing fees and transportation costs but exclude taxes, were $18.72 per Boe in the second quarter of 2015 compared to $19.81 per Boe in the first quarter of 2015, a 6% decrease primarily due to cost cutting efforts, lower fuel and utility costs, and lower workover expense.


•	General and administrative expenses, excluding non-cash unit-based compensation costs, were $16.8 million in the second quarter of 2015 compared to $25.3 million in the first quarter of 2015, primarily due to cost cutting efforts (including reduction in workforce) and $1.9 million lower integration costs.

•

Losses on commodity derivative instruments were $93.4 million in the second quarter of 2015 compared to gains of $137.2 million in the first quarter of 2015, primarily due to an increase in oil and natural gas futures prices during the second quarter of 2015. Derivative instrument settlement receipts were $100.6 million in the second quarter of 2015 compared to receipts of $126.4 million in the first quarter of 2015, primarily due to higher oil prices.


•	NYMEX WTI oil spot prices averaged $57.85 per Bbl and Brent oil spot prices averaged $61.65 per Bbl in the second quarter of 2015 compared to $48.49 per Bbl and $53.98 per Bbl, respectively, in the first quarter of 2015. Henry Hub natural gas spot prices averaged $2.75 per Mcf in the second quarter of 2015 compared to $2.90 per Mcf in the first quarter of 2015.


•	Average realized crude oil, NGL and natural gas prices, excluding the effects of commodity derivative settlements, were $53.29 per Bbl, $18.35 per Bbl and $2.57 per Mcf, respectively, in the second quarter of 2015 compared to $43.62 per Bbl, $16.54 per Bbl and $3.05 per Mcf, respectively, in the first quarter of 2015.


•	Oil, NGL and natural gas capital expenditures were $58 million in the second quarter of 2015, compared to $73 million in the first quarter of 2015.


•	Distributable cash flow, a non-GAAP financial measure, was $58.5 million in the second quarter of 2015 compared to $60.7 million in the first quarter of 2015.

Second Half 2015 Guidance (Assuming No Acquisitions)

The following guidance is subject to all of the cautionary statements and limitations described below and under the caption "Cautionary Statement Regarding Forward-Looking Information." In addition, 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. 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 prove to 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. The foregoing guidance does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. Rather, the foregoing guidance 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)	Second Half 2015 Guidance ⁽¹⁾
Total Production (MBoe):	9,620		—	10,220
Oil Production (MBbls)	5,400		—	5,800
NGL Production (MBbls)	850		—	950
Natural Gas Production (MMcfe)	20,220		—	20,820
Average Price Differential %:
WTI Oil Price Differential %	89	%	—	95%
Brent Oil Price Differential %⁽²⁾	87	%	—	93%
NGL Price Differential % (of WTI)	32	%	—	38%
Natural Gas Price Differential %	100	%	—	105%
Oil, NGL, and Natural Gas Sales Revenue⁽³⁾	$317,000		—	$363,000
Realized Hedge Gains / (Losses)	$237,000
Other Revenue⁽⁴⁾	$11,000		—	$13,000
Lease Operating Expenses / Boe⁽⁵⁾	$18.75		—	$20.75
Other Operating Expenses⁽⁶⁾	$9,000		—	$10,000
Production / Property Taxes (% of Sales Revenue)	8.25	%	—	8.75%
G&A (Excl. Unit Based Compensation)	$30,000		—	$32,000
Adjusted EBITDA⁽⁷⁾	$315,000		—	$340,000
Cash Interest Expense⁽⁸⁾	$95,000		—	$98,000
Preferred Equity Distributions⁽⁹⁾	$8,250
Maintenance Capital Expenditures⁽¹⁰⁾	$103,000
Distributable Cash Flow⁽¹¹⁾	$105,000		—	$135,000
Units Outstanding⁽¹²⁾	219,000
DCF per Unit	$0.48		—	$0.62
Common Unit DCF Coverage Ratio⁽¹³⁾	1.92x		—	2.47x

(1) Breitburn’s second half 2015 guidance is based on flat $50 per barrel WTI crude oil, $55 per barrel Brent crude oil, and $3.00 per Mcf natural gas price levels for second half 2015.

(2) Approximately 15% of estimated crude oil production is expected to be sold based on Brent pricing.

(3) Range based on the low and high values of production and differentials as set forth above.

(4) Primarily consists of $9-$10 million in revenue related to the East Texas Salt Water Disposal System.

(5) Lease operating expenses include processing fees, district expenses and transportation costs.

(6) Represents costs related the East Texas Salt Water Disposal System.

(7) Assuming the high and low range of Breitburn’s second half 2015 Guidance, Adjusted EBITDA is expected to range between $315 million and $340 million, and is comprised of estimated net loss (before non-cash compensation and non-cash distributions paid-in-kind to holders of 8.0% Series B Preferred Units) between ($136) million (low end of Adjusted EBITDA) and ($108) million (high end of of Adjusted EBITDA), plus unrealized losses on commodity derivative instruments of $151 million, plus DD&A of $191 million, plus interest expense between $95 million (high end of Adjusted EBITDA) and $98 million (low end of Adjusted EBITDA), plus preferred distributions to holders of 8.25% Series A Preferred Units of $8.25 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 0.20%.

(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 8.0% Series B Perpetual Convertible Preferred Units will be paid in kind.

(10) Maintenance capital expenditures exclude information technology spending of approximately $3.2 million. Maintenance capital is defined as the estimated amount of investment in capital projects and obligatory spending on existing facilities and operations needed to hold production approximately flat over a multi-year period.

(11) Range based on (i) low end of EBITDA less high end of interest expense, maintenance capital, and preferred distributions and (ii) high end of EBITDA less the low end of interest expense, maintenance capital, and preferred distributions.

(12) Includes all common units expected to receive distributions in cash.

(13) Assumes constant annualized distribution rate of $0.50/unit.

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, distributable cash flow or Breitburn’s ability to pay cash distributions for the reporting periods 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 June 30, 2015 and 2014, and the three months ended March 31, 2015:



	Three Months Ended
	June 30,			March 31,			June 30,
Thousands of dollars, except as indicated	2015			2015			2014
Oil sales	$	154,425		$	123,843		$	173,948
NGL sales	8,861			7,591			10,675
Natural gas sales	26,350			31,189			34,428
(Loss) gain on commodity derivative instruments	(93,432		)	137,192			(127,000		)
Other revenues, net (a)	6,504			6,469			1,071
Total revenues	$	102,708		$	306,284		$	93,122
Lease operating expenses before taxes (b)	$	93,858		$	100,079		$	70,923
Production and property taxes (c)	15,348			13,544			16,001
Total lease operating expenses	109,206			113,623			86,924
Purchases and other operating costs	421			158			110
Salt water disposal costs	4,053			4,021			—
Change in inventory	2,157			176			(3,974		)
Total operating costs	$	115,837		$	117,978		$	83,060
Lease operating expenses before taxes per Boe (b)	$	18.72		$	19.81		$	21.03
Production and property taxes per Boe (c)	3.06			2.68			4.74
Total lease operating expenses per Boe	$	21.78		$	22.49		$	25.77
General and administrative expenses (excluding non-cash unit-based compensation)	$	16,778		$	25,335		$	10,322
Net loss attributable to the partnership	$	(305,707	)	$	(58,825	)	$	(104,725	)
Less: distributions to Series A preferred unitholders	4,125			4,125			1,833
Less: non-cash distributions to Series B preferred unitholders	6,408			—			—
Net loss attributable to common unitholders	$	(316,240	)	$	(62,950	)	$	(106,558	)

Total production (MBoe) (d)	5,015			5,051			3,373
Oil (MBbl)	2,822			2,890			1,901
NGLs (MBbl)	483			459			279
Natural gas (MMcf)	10,264			10,211			7,163
Average daily production (Boe/d)	55,110			56,122			37,069
Sales volumes (MBoe) (e)	5,089			4,999			3,289
Average realized sales price (per Boe) (f) (g)	$	37.24		$	32.52		$	66.59
Oil (per Bbl) (f) (g)	53.29			43.62			95.74
NGLs (per Bbl) (f)	18.35			16.54			38.26
Natural gas (per Mcf) (f)	$	2.57		$	3.05		$	4.81



(a)	Includes revenue from the East Texas Salt Water Disposal System of $4.0 million, $4.1 million and zero for the three months ended June 30, 2015, March 31, 2015 and June 30, 2014.
(b)	Includes district expenses, processing fees and transportation costs.
(c)	Includes ad valorem and severance taxes.
(d)	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.
(e)	Oil sales were 2,896 MBbl, 2,835 MBbl and 1,817 MBbl for the three months ended June 30, 2015, March 31, 2015 and June 30, 2014, respectively.
(f)	Excludes the effect of commodity derivative settlements.
(g)	Includes the per Boe effect of crude oil purchases.

Non-GAAP Financial Measures

This press release, including the financial tables and other supplemental information, including the 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 www.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, and 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 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
	June 30,			March 31,			June 30,
Thousands of dollars, except as indicated	2015			2015			2014
Reconciliation of net loss to Adjusted EBITDA:
Net loss attributable to the partnership	$	(305,707	)	$	(58,825	)	$	(104,725	)
Loss (gain) on commodity derivative instruments	93,432			(137,192		)	127,000
Commodity derivative instrument settlement receipts (payments) (a) (b)	100,576			126,357			(17,024		)
Depletion, depreciation and amortization expense	109,447			109,824			68,245
Impairments of oil and natural gas properties	—			59,113			—
Impairments of goodwill	95,947			—			—
Interest expense and other financing costs	62,007			41,477			30,208
Loss on sale of assets	122			15			334
Income tax expense (benefit)	259			92			(159		)
Unit-based compensation expense (c)	6,084			6,927			6,098
Restructuring costs - unit-based compensation	721			814			—
Adjusted EBITDA	$	162,888		$	148,602		$	109,977
Less:
Maintenance capital (d)	$	52,000		$	45,000		$	26,999
Cash interest expense	48,250			38,729			28,399
Distributions to Series A preferred unitholders (e)	4,125			4,125			1,833
Distributable cash flow available to common unitholders	$	58,513		$	60,748		$	52,746

Distributable cash flow available per common unit (f)	0.270			0.282			0.431
Common unit distribution coverage (g)	2.16x			2.26x			0.86x

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

Net cash provided by operating activities	$	73,796		$	141,149		$	74,798
Increase (decrease) in assets net of liabilities relating to operating activities	40,736			(30,968		)	7,300
Interest expense (h)	48,197			38,729			28,178
Income from equity affiliates, net	172			(325		)	(388		)
Noncontrolling interest	(126		)	93			—
Income taxes	259			(76		)	89
Gain on marketable securities	(146		)	—			—
Adjusted EBITDA	$	162,888		$	148,602		$	109,977



(a)	Excludes premiums paid at contract inception related to those derivative contracts that settled during the applicable periods of:	$	1,663	$	1,645	$	2,118
(b)	Includes net cash settlements on derivative instruments for:
	- Oil settlements received (paid):	83,265		111,879		(18,125		)
	- Natural gas settlements received:	$	17,311	$	14,478	$	1,101
(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)	Does not include paid-in-kind distributions on Series B Preferred Units.
(f)	Based on common units outstanding (including outstanding LTIP grants) at each distribution record date within the periods.
(g)	Does not include Series B Preferred Units on an as converted basis.
(h)	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 August 5, 2015. For an overview of Breitburn's commodity hedge portfolio, please refer to the Summary of Commodity Price Protection Portfolio at www.breitburn.com.



	Year
	2015				2016		2017		2018		2019
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Volume (Bbl/d)	20,043				15,504		13,519		493		—
Average Price ($/Bbl)	$	93.27			$	88.07	$	85.05	$	82.20	$	—
Fixed Price Swaps - ICE Brent
Volume (Bbl/d)	3,300				4,300		298		—		—
Average Price ($/Bbl)	$	97.73			$	95.17	$	97.50	$	—	$	—
Collars - NYMEX WTI
Volume (Bbl/d)	2,025				1,500		—		—		—
Average Floor Price ($/Bbl)	$	90.00			$	80.00	$	—	$	—	$	—
Average Ceiling Price ($/Bbl)	$	111.73			$	102.00	$	—	$	—	$	—
Collars - ICE Brent
Volume (Bbl/d)	500				500		—		—		—
Average Floor Price ($/Bbl)	$	90.00			$	90.00	$	—	$	—	$	—
Average Ceiling Price ($/Bbl)	$	109.50			$	101.25	$	—	$	—	$	—
Puts - NYMEX WTI
Volume (Bbl/d)	500				1,000		—		—		—
Average Price ($/Bbl)	$	90.00			$	90.00	$	—	$	—	$	—
Total:
Volume (Bbl/d)	26,368				22,804		13,817		493		—
Average Price ($/Bbl)	$	93.46			$	89.01	$	85.32	$	82.20	$	—

Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Volume (MMBtu/d)	16,658				25,000		20,000		7,000		4,000
Average Price ($/MMBtu)	$	4.33			$	4.03	$	3.84	$	3.23	$	3.30
Fixed Price Swaps - Henry Hub
Volume (MMBtu/d)	54,891				36,050		19,016		1,870		—
Average Price ($/MMBtu)	$	4.84			$	4.24	$	4.43	$	4.15	$	—
Collars - Henry Hub
Volume (MMBtu/d)	18,000				630		595		—		—
Average Floor Price ($/MMBtu)	$	5.00			$	4.00	$	4.00	$	—	$	—
Average Ceiling Price ($/MMBtu)	$	7.48			$	5.55	$	6.15	$	—	$	—
Puts - Henry Hub
Volume (MMBtu/d)	1,920				11,350		10,445		—		—
Average Price ($/MMBtu)	$	4.78			$	4.00	$	4.00	$	—	$	—
Deferred Premium ($/MMBtu)	$	0.64		(a)	$	0.66	$	0.69	$	—	$	—
Total:
Volume (MMBtu/d)	91,469				73,030		50,056		8,870		4,000
Average Price ($/MMBtu)	$	4.78			$	4.13	$	4.10	$	3.42	$	3.30

Basis Swaps- Henry Hub
Volume (MMBtu/d)	14,400				—		—		—		—
Average Price ($/MMBtu)	$	(0.19	)		$	—	$	—	$	—	$	—

(a) Deferred premiums of $0.64 apply to 420 MMBtu/d of the 2015 volume.

Premiums paid in 2012 related to oil and natural gas derivatives to be settled after June 30, 2015, are as follows:



	Year
Thousands of dollars	2015		2016		2017		2018		2019
Oil	$	2,361	$	7,438	$	734	$	—	$	—
Natural gas	$	1,003	$	952	$	—	$	—	$	—

Other Information

Breitburn will host a conference call Thursday, August 6, 2015, at 12:00 pm (EDT) to discuss Breitburn’s second quarter 2015 results. The conference call may be accessed by calling 888-417-8465 (international callers dial 719-325-2215) or via webcast at http://ir.breitburn.com/. An archived edition of the conference call will also be available through August 13^th by calling 877-870-5176 (international callers dial 858-384-5517) and entering replay PIN 6137597 or by visiting http://ir.breitburn.com/. Breitburn will take questions from securities analysts and institutional portfolio managers; the call is open to all other interested parties on a listen-only basis.

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 the following seven producing areas: Ark-La-Tex, Michigan/Indiana/Kentucky, the Permian Basin, the Mid-Continent, the Rockies, Florida, 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,” 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

Unaudited Consolidated Balance Sheets



	June 30,			December 31,
Thousands of dollars	2015			2014
ASSETS
Current assets
Cash	$	9,525		$	12,628
Accounts and other receivables, net	154,309			166,436
Derivative instruments	309,239			408,151
Related party receivables	297			2,462
Inventory	1,342			3,727
Prepaid expenses	7,439			7,304
Total current assets	482,151			600,708
Equity investments	6,310			6,463
Property, plant and equipment
Oil and natural gas properties	7,866,044			7,736,409
Other property, plant and equipment	140,054			60,533
	8,006,098			7,796,942
Accumulated depletion and depreciation	(1,609,796		)	(1,342,741		)
Net property, plant and equipment	6,396,302			6,454,201
Other long-term assets
Intangibles	2,044			8,336
Goodwill	—			92,024
Derivative instruments	235,554			319,560
Other long-term assets	123,182			157,042

Total assets	$	7,245,543		$	7,638,334

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	77,722		$	129,270
Current portion of long-term debt	421			105,000
Derivative instruments	5,388			5,457
Distributions payable	732			733
Current portion of asset retirement obligation	3,912			4,948
Revenue and royalties payable	46,838			40,452
Wages and salaries payable	20,146			22,322
Accrued interest payable	19,772			20,672
Production and property taxes payable	25,214			25,207
Other current liabilities	6,805			7,495
Total current liabilities	206,950			361,556

Credit facility	1,309,000			2,089,500
Senior notes, net	1,787,887			1,156,560
Other long-term debt	2,579			1,100
Total long-term debt	3,099,466			3,247,160
Deferred income taxes	2,743			2,575
Asset retirement obligation	243,243			233,463
Derivative instruments	2,082			2,269
Other long-term liabilities	24,711			25,135
Total liabilities	3,579,195			3,872,158

Equity
Series A preferred units, 8.0 million units issued and outstanding at each of June 30, 2015 and December 31, 2014	193,215			193,215
Series B preferred units, 47.2 million and 0 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively	341,700			—
Common units, 211.7 million and 210.9 million units issued and outstanding at June 30, 2015 and December 31, 2014, respectively	3,124,808			3,566,468
Accumulated other comprehensive loss	(333		)	(392		)



Total partners' equity	3,659,390		3,759,291
Noncontrolling interest	6,958		6,885
Total equity	3,666,348		3,766,176

Total liabilities and equity	$	7,245,543	$	7,638,334

Breitburn Energy Partners LP and Subsidiaries

Unaudited Consolidated Statements of Operations



	Three Months Ended						Six Months Ended
	June 30,						June 30,
Thousands of dollars, except per unit amounts	2015			2014			2015			2014

Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	189,636		$	219,051		$	352,259		$	442,607
(Loss) gain on commodity derivative instruments, net	(93,432		)	(127,000		)	43,760			(167,228		)
Other revenue, net	6,504			1,071			12,973			2,655
Total revenues and other income items	102,708			93,122			408,992			278,034
Operating costs and expenses
Operating costs	115,837			83,060			233,815			165,257
Depletion, depreciation and amortization	109,447			68,245			219,271			131,746
Impairments of oil and natural gas properties	—			—			59,113			—
Impairments of goodwill	95,947			—			95,947			—
General and administrative expenses	22,862			16,420			55,124			35,149
Restructuring costs	1,773			—			6,691			—
Loss on sale of assets	122			334			137			420
Total operating costs and expenses	345,988			168,059			670,098			332,572

Operating loss	(243,280		)	(74,937		)	(261,106		)	(54,538		)

Interest expense, net of capitalized interest	61,404			30,208			101,069			60,866
Loss on interest rate swaps	603			—			2,415			—
Other expenses (income), net	35			(261		)	(442		)	(773		)
Total other expense	62,042			29,947			103,042			60,093

Loss before taxes	(305,322		)	(104,884		)	(364,148		)	(114,631		)

Income tax expense (benefit)	259			(159		)	351			(148		)

Net loss	(305,581		)	(104,725		)	(364,499		)	(114,483		)

Less: Net income attributable to noncontrolling interest	126			—			33			—

Net loss attributable to the partnership	(305,707		)	(104,725		)	(364,532		)	(114,483		)

Less: Distributions to Series A preferred unitholders	4,125			1,833			8,250			1,833
Less: Non-cash distributions to Series B preferred unitholders	6,408			—			6,408			—

Net loss attributable to common unitholders	$	(316,240	)	$	(106,558	)	$	(379,190	)	$	(116,316	)

Basic net loss per common unit	$	(1.46	)	$	(0.89	)	$	(1.75	)	$	(0.97	)
Diluted net loss per common unit	$	(1.46	)	$	(0.89	)	$	(1.75	)	$	(0.97	)

Breitburn Energy Partners LP and Subsidiaries

Unaudited Consolidated Statements of Comprehensive Income



	Three Months Ended June 30,						Six Months Ended June 30,
Thousands of dollars, except per unit amounts	2015			2014			2015			2014
Net loss	$	(305,581	)	$	(104,725	)	$	(364,499	)	$	(114,483	)

Other comprehensive (loss) income, net of tax:
Change in fair value of available-for-sale securities (a)	(74		)	—			99			—
Total other comprehensive (loss) income	(74		)	—			99			—

Total comprehensive loss	(305,655		)	(104,725		)	(364,400		)	(114,483		)

Less: Comprehensive income attributable to noncontrolling interest	97			—			74			—

Comprehensive loss attributable to the partnership	$	(305,752	)	$	(104,725	)	$	(364,474	)	$	(114,483	)

(a) Net of income taxes benefit of less than $0.1 million and income tax expense of less than $0.1 million for the three months and six months ended June 30, 2015.

Breitburn Energy Partners LP and Subsidiaries

Unaudited Consolidated Statements of Cash Flows



	Six Months Ended June 30,
Thousands of dollars	2015			2014

Cash flows from operating activities
Net loss	$	(364,499	)	$	(114,483	)
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization	219,271			131,746
Impairment of oil and natural gas properties	59,113
Impairment of goodwill	95,947			—
Unit-based compensation expense	14,545			12,647
(Gain) loss on derivative instruments	(41,345		)	167,228
Derivative instrument settlement receipts (payments)	224,007			(30,524		)
Income from equity affiliates, net	153			281
Deferred income taxes	168			(281		)
Loss on sale of assets	137			420
Other	12,818			3,487
Changes in net assets and liabilities
Accounts receivable and other assets	8,656			2,097
Inventory	2,385			(5,347		)
Net change in related party receivables and payables	2,165			1,322
Accounts payable and other liabilities	(18,576		)	22,516
Net cash provided by operating activities	214,945			191,109
Cash flows from investing activities
Property acquisitions	(17,663		)	(2,684		)
Capital expenditures	(170,634		)	(188,758		)
Proceeds from sale of assets	—			542
Proceeds from sale of available-for-sale securities	3,480			—
Purchases of available-for-sale securities	(3,637		)	—
Other	(853		)	(5,706		)
Net cash used in investing activities	(189,307		)	(196,606		)
Cash flows from financing activities
Proceeds from issuance of preferred units, net	337,895			193,397
Proceeds from issuance of common units, net	4,925			20,273
Distributions to preferred unitholders	(8,250		)	—
Distributions to common unitholders	(81,183		)	(120,059		)
Proceeds from issuance of long-term debt, net	1,043,400			466,000
Repayments of long-term debt	(1,296,500		)	(543,500		)
Change in bank overdraft	126			(2,425		)
Debt issuance costs	(29,154		)	(1,632		)
Net cash (used in) provided by financing activities	(28,741		)	12,054
(Decrease) increase in cash	(3,103		)	6,557
Cash beginning of period	12,628			2,458
Cash end of period	$	9,525		$	9,015

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