Exhibit 99.1

  

BreitBurn Energy Partners L.P. Reports Fourth Quarter Results and Record Full Year Production and EBITDA; Provides Full Year 2014 Guidance

 

LOS ANGELES, February 27, 2014 -- BreitBurn Energy Partners L.P. (the “Partnership”) (NASDAQ:BBEP) today announced financial and operating results for the fourth quarter and full year of 2013 as well as public guidance for its expected performance in 2014, excluding any future acquisitions.

 

Key Highlights:

 

-

For the fourth quarter of 2013, net production increased 40% and Adjusted EBITDA, a non-GAAP measure, increased 50% from the fourth quarter of 2012. For the full year 2013, net production and Adjusted EBITDA increased 32% and 34%, respectively, from 2012.

-

Oil and natural gas liquid (NGL) production increased to a record quarterly high of 1.9 MMBoe, a 90% increase from the fourth quarter of 2012.

-

Annualized monthly distributions of $1.97 per unit as paid on February 14, 2014, attributable to the fourth quarter of 2013, represent a 4.8% increase over the annualized quarterly distribution of $1.88 per unit for the fourth quarter of 2012.

-

For the fourth quarter of 2013, the Partnership drilled 27 gross (25.7 net) wells and completed 9 gross (6.4 net) workovers.

-

On December 30, 2013 the Partnership completed acquisitions of oil and gas properties in the Permian Basin for approximately $302 million.

-

For the fourth quarter of 2013, increased distributable cash flow, a non-GAAP financial measure, to $55.4 million which represented a 43% increase from the fourth quarter of 2012.

 

Management Commentary

 

Halbert Washburn, CEO, said: “The Partnership had a very active 2013, completing approximately $1.2 billion in acquisitions, doubling our organic development expenditures, expanding our presence into the mid-continent, and significantly increasing our liquids reserves and production. Although we had a variety of challenges during the fourth quarter, we grew the business significantly in 2013 and are pleased to report record annual production and Adjusted EBITDA. 2013 also marked BreitBurn’s 25-year anniversary. We have a long history of operating effectively and successfully pursuing our growth-through-acquisitions strategy. Looking forward to 2014, our large portfolio of high quality assets, a robust capital program, and ample financial flexibility should serve as a strong foundation for continued growth. We are very optimistic about our prospects for 2014 and are targeting at least $600 million in new acquisitions during the year.”

 

 

Fourth Quarter 2013 Operating and Financial Results Compared to Third Quarter 2013

 

-

Total production was 3,086 MBoe in the fourth quarter of 2013 compared to 3,098 MBoe in the third quarter of 2013. Average daily production was 33.5 MBoe/day in the fourth quarter of 2013 compared to 33.7 MBoe/day in the third quarter of 2013.

o

Oil production was 1,704 MBbl compared to 1,681 MBbl in the third quarter of 2013.

o

NGL production was 205 MBbl compared to 207 MBbl in the third quarter of 2013.

o

Natural gas production was 7,060 MMcf compared to 7,258 MMcf in the third quarter of 2013.

-

Adjusted EBITDA was $109.4 million in the fourth quarter of 2013 compared to $112.1 million in the third quarter of 2013.

-

Net loss attributable to the Partnership, including the effect of derivative instruments, was $58.8 million, or $0.52 per diluted common unit, in the fourth quarter of 2013, compared to a net loss of $25.0 million, or $0.25 per diluted common unit, in the third quarter of 2013.

-

Oil, NGL and natural gas sales revenues were $193.6 million in the fourth quarter of 2013, down from $197.4 million in the third quarter of 2013, primarily reflecting lower oil realized prices and lower natural gas sales volumes, partially offset by higher oil sales volumes and slightly higher natural gas and NGL realized prices.

-

Lease operating expenses, which include district expenses, processing fees and transportation costs, were $20.56 per Boe in the fourth quarter of 2013 compared to $18.96 per Boe in the third quarter of 2013.

 

 

-

General and administrative expenses, excluding non-cash unit-based compensation, were $2.83 per Boe in the fourth quarter of 2013 compared to $3.62 per Boe in the third quarter of 2013.

-

Losses on commodity derivative instruments were $17.2 million in the fourth quarter of 2013 compared to losses of $54.8 million in the third quarter of 2013, which primarily reflected a decrease in oil futures prices during the fourth quarter of 2013. Derivative instrument settlement receipts were $4.5 million in the fourth quarter of 2013 compared to settlement payments of $6.3 million in the third quarter of 2013.

-

WTI oil spot prices averaged $97.44 per barrel and Brent oil spot prices averaged $109.22 per barrel in the fourth quarter of 2013 compared to $105.83 per barrel and $110.23 per barrel, respectively, in the third quarter of 2013. Henry Hub natural gas spot prices averaged $3.85 per Mcf in the fourth quarter of 2013 compared to $3.55 per Mcf in the third quarter of 2013.

-

Realized oil, NGL and natural gas prices excluding the effects of commodity derivative settlements, averaged $88.77 per Boe, $42.17 per Boe and $3.75 per Mcf, respectively, in the fourth quarter of 2013, compared to $100.94 per Boe, $38.11 per Boe, and $3.69 per Mcf, respectively, in the third quarter of 2013.

-

Oil and gas capital expenditures totaled $96 million in the fourth quarter of 2013 compared to $87 million in the third quarter of 2013.

-

Distributable cash flow, a non-GAAP financial measure, was $55.4 million in the fourth quarter of 2013 compared to $64.6 million in the third quarter of 2013. Distributable cash flow per common unit was $0.46 in the fourth quarter of 2013 compared to $0.64 in the third quarter of 2013.

 

Full Year 2013 Results

 

-

The Partnership completed approximately $1.2 billion in total acquisitions.

-

Total production was 10,983 MBoe in 2013, an increase of 32% from 2012 and a record high for the Partnership.

-

Adjusted EBITDA was $370.4 million, an increase of 34% from 2012 and a record high for the Partnership.

-

Net loss attributable to the Partnership was $43.7 million, or $0.43 per diluted common unit, in 2013 compared to net loss of $40.8 million, or $0.56 per diluted common unit, in 2012.

-

Total oil, NGL and natural gas sales were $660.7 million in 2013, an increase of 60% from 2012.

-

For the full year 2013, the Partnership drilled 138 gross (121.6 net) wells and completed 61 gross (54.8 net) workovers.

-

Full year lease operating expenses per Boe were $19.69, which was 3% higher than 2012.

-

Full year general and administrative expenses, excluding unit-based compensation, were $3.53 per Boe, which was 12% lower than 2012.

-

Realized oil and NGL prices, excluding the effect of commodity derivative instruments, for 2013 were $88.75 per barrel and $35.25, respectively compared to NYMEX WTI oil prices of $97.97 per barrel. Average realized natural gas prices, excluding the effect of commodity derivative instruments, were $3.82 per Mcf, compared to Henry Hub prices of $3.73 per Mcf.

-

Oil and gas capital expenditures were $295 million, an increase of 93% from 2012.

-

Distributable cash flow, a non-GAAP financial measure, was $200.3 million in 2013 compared to $153.0 million in 2012.

 

2013 Estimated Proved Reserves

 

Total estimated proved reserves as of December 31, 2013 were 214.3 MMBoe. The standardized measure of discounted future net cash flows related to our estimated proved reserves was approximately $3.2 billion. Of the total estimated proved reserves, 53% were oil, 7% were NGLs and 40% were natural gas; 81% were classified as proved developed; and 27% were located in Michigan, 20% in Oklahoma, 19% in Texas, 17% in Wyoming, 11% in California and 5% in Florida, with less than 1% in Indiana and Kentucky. As of December 31, 2012, our total estimated proved reserves were 149.4 MMBoe. 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, 2013 were $96.94 Bbl of oil for WTI NYMEX, $108.32 per Bbl of oil for ICE Brent and $3.67 per MMBtu of natural gas for Henry Hub.

 

2014 Guidance (Assuming no future 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 the Partnership'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, NGLs and gas will continue at levels that allow for economic production of these products. The production, transportation and marketing of oil, natural gas liquids 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. The Partnership's estimates are based on certain other assumptions, such as well performance, which may actually prove to vary significantly from those assumed. Operating costs, which include 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. 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. 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 guidance below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. Rather, the table 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)		FY 2014 Guidance
Total Production (MBoe):			13,600				-				14,400
Oil Production (MBbls)			7,900				-				8,400
NGL Production (MBbls)			1,125				-				1,225
Gas Production (MMcfe)			27,500				-				28,600
December 2014 Exit Rate (Boe/d)			38,400				-				40,800
Average Price Differential %:
WTI Oil Price Differential %			88.0	%			-				96.0	%
Brent Oil Price Differential %(1)			92.0	%			-				96.0	%
NGL Price Differential % (of WTI)			37.5	%			-				42.5	%
Gas Price Differential %			100.0	%			-				103.0	%
Other Revenue(2)		$	3,500				-			$	4,500
Operating Costs / Boe(3)(4)		$	18.50				-			$	20.50
Production / Property Taxes (% of oil & natural gas revenue)			6.50	%			-				7.00	%
G&A (Excl. Unit Based Compensation)		$	51,000				-			$	53,000
Cash Interest Expense(5)		$	117,000				-			$	120,000
Adjusted EBITDA(6)		$	500,000				-			$	510,000
Capital Expenditures(7)
Maintenance Capital						$	125,000
Growth Capital		$	200,000				-			$	220,000

 

	(1)	Approximately 24% of oil production is expected to be sold based on Brent pricing.
	(2)	Primarily comprised of pipeline revenues and equity earnings in affiliate.
	(3)	Operating Costs include lease operating costs, processing fees, district expense, and transportation expense.  Expected transportation expense totals approximately $6.0 million in 2014, largely attributable to our Florida production.  Excluding transportation expense, our estimated operating costs range per Boe is approximately $18.00 - $20.00.
	(4)	Operating Costs are based on flat $95 per barrel WTI oil, $105 per barrel Brent oil, and $4.00 per Mcfe natural gas price levels for 2014.  Operating costs generally move with commodity prices but do not typically increase or decrease as rapidly as commodity prices.
	(5)	The Partnership typically borrows on a 1-month LIBOR basis, plus an applicable spread.  Estimated cash interest expense assumes a 1-month LIBOR rate of 0.25%.
	(6)	Assuming the high and low range of our guidance, Adjusted EBITDA is expected to range between $500 million and $510 million, and is comprised of estimated net income (before non-cash compensation) between $131 million and $144 million, plus losses on commodity derivative instruments of $22 million, less net payments for derivative contracts settled during the period of $28 million, plus DD&A of $255 million, plus interest expense between $117 million (high end of Adjusted EBITDA) and $120 million (low end of Adjusted EBITDA).  Estimated 2014 net income is based on oil prices of $95 per barrel for WTI oil, $105 per barrel for Brent oil and $4.00 per Mcfe for natural gas.  Consequently, differences between actual and forecast prices could result in changes to gains or losses on mark to market of commodity derivative instruments, DD&A, including potential impairments of long-lived assets, and ultimately, net income.
	(7)	Total Capital Expenditures for 2014 excludes capital expense for acquisitions as well as information technology spending.  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 constant for the period.

 

 

Impact of Derivative Instruments

 

The Partnership uses commodity derivative instruments to mitigate the risks associated with commodity price volatility and to help maintain cash flows for operating activities, acquisitions, capital expenditures and distributions. The Partnership does not enter into derivative instruments for speculative trading purposes. Because the Partnership does not use hedge accounting to account for its derivative instruments, changes in the fair value of derivative instruments are recorded in earnings 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 the Partnership’s ability to pay cash distributions for the reporting periods presented.

 

Total losses from commodity derivative instruments were approximately $17.2 million for the fourth quarter of 2013, which include $4.5 million net receipts for contracts that settled during the period.

 

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, 2013 and 2012, the three months ended September 30, 2013 and the full year results for 2013 and 2012:

 

		Three Months Ended												Year Ended December 31,
		December 31,				September 30,				December 31,
Thousands of dollars, except as indicated		2013				2013				2012				2013				2012
Oil sales		$	158,456			$	162,709			$	85,639			$	530,625			$	326,130
NGL sales			8,644				7,888				845				22,558				3,858
Natural gas sales			26,504				26,816				26,695				107,482				83,879
(Loss) gain on commodity derivative instruments			(17,234	)			(54,765	)			3,715				(29,182	)			5,580
Other revenues, net			978				737				700				3,175				3,548
Total revenues		$	177,348			$	143,385			$	117,594			$	634,658			$	422,995
Lease operating expenses and processing fees (a)		$	63,439			$	58,731			$	41,769			$	216,275			$	159,289
Production and property taxes (b)			11,295				14,476				10,962				46,220				33,634
Total lease operating expenses		$	74,734			$	73,207			$	52,731			$	262,495			$	192,923
Purchases and other operating costs			440				226				267				1,321				1,577
Change in inventory			5,758				(4,931	)			578				(995	)			1,279
Total operating costs		$	80,932			$	68,502			$	53,576			$	262,821			$	195,779
Lease operating expenses, pre taxes, per Boe (a)		$	20.56			$	18.96			$	18.88			$	19.69			$	19.15
Production and property taxes per Boe (b)			3.66				4.67				4.96				4.21				4.04
Total lease operating expenses per Boe			24.22				23.63				23.84				23.90				23.19
General and administrative expenses (excluding unit-based compensation)		$	8,742			$	11,227			$	9,815			$	38,752			$	33,281
Net loss attributable to the partnership		$	(58,792	)		$	(25,011	)		$	(10,334	)		$	(43,671	)		$	(40,801	)
Total production (MBoe) (c)			3,086				3,098				2,212				10,983				8,318
Oil (MBbl)			1,704				1,681				972				5,651				3,652
NGL (MBbl)			205				207				33				640				138
Natural gas (MMcf)			7,060				7,258				7,243				28,156				27,997
Average daily production (Boe/d)			33,542				33,674				24,044				30,091				22,726
Sales volumes (MBoe) (d)			3,163				3,027				2,203				10,988				8,334
Average realized sales price (per Boe) (e) (f)		$	61.10			$	65.16			$	51.29			$	51.29			$	49.57
Oil (per Bbl) (e) (f)			88.77				100.94				88.75				88.75				92.18
NGLs (per Bbl) (e)			42.17				38.11				25.61				35.25				27.96
Natural gas (per Mcf) (e)			3.75				3.69				3.69				3.82				3.00

 

(a)  Includes lease operating expenses, district expenses, transportation expenses and processing fees.

(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 1,782 (MBbl), 1,610 (MBbl), 963 (MBbl), 5,563 (MBbl) and 3,530 (MBbl) for the three months ended December 31, 2013 September 30, 2013 and December 31, 2012 and for the twelve months ended December 31, 2013 and 2012, respectively.

(e) Excludes the effect of commodity derivative settlements.

(f) Includes oil purchases.

 

 

Non-GAAP Financial Measures

 

This press release, 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 the Partnership's financial results with investors and analysts, and they are also available on the Partnership's website under the Investor Relations tab.

 

Among the non-GAAP financial measures used are “Adjusted EBITDA” and “distributable cash flow.” 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 as management believes it provides additional information relative to the performance of the Partnership's business, such as our ability to meet our debt covenant compliance tests. 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 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,
		December 31,				September 30,				December 31,
Thousands of dollars		2013				2013				2012 (a)				2013				2012 (a)
Reconciliation of net loss to Adjusted EBITDA:
Net loss attributable to the Partnership		$	(58,792	)		$	(25,011	)		$	(10,334	)		($	43,671	)			(40,801	)
Loss (gain) on commodity derivative instruments			17,234				54,765				(3,715	)			29,182				(5,580	)
Commodity derivative instrument settlements (b) (c)			4,450				(6,323	)			22,455				8,083				87,605
Depletion, depreciation and amortization expense			62,400				59,764				40,350				216,495				137,252
Impairments			54,012				361				147				54,373				12,313
Interest expense and other financing costs			26,680				23,548				17,975				87,067				61,206
Loss on interest rate swaps (d)			-				-				175				-				1,101
Loss on sale of assets			(2,154	)			77				264				(2,015	)			486
Income tax expense (benefit)			277				24				285				905				84
Unit-based compensation expense (e)			5,270				4,889				5,329				19,955				22,184
Adjusted EBITDA		$	109,377			$	112,094			$	72,931			$	370,374			$	275,850
Less:
Maintenance capital (f)		$	29,217			$	25,782			$	16,774			$	89,267			$	63,446
Cash interest expense (g)			24,741				21,748				17,421				80,767				59,382
Distributable cash flow available to common unitholders		$	55,419			$	64,564			$	38,736			$	200,340			$	153,022
Distributable cash flow available per common unit (h)		$	0.46			$	0.64			$	0.45			$	1.88			$	1.95
Common unit distribution coverage			0.93	x			1.31	x			0.95	x			0.97	x			1.06	x
Reconciliation of net cash flows from operating activities to Adjusted EBITDA:
Net cash provided by operating activities		$	90,224			$	69,520			$	25,506			$	257,166				191,782
Increase in assets net of liabilities relating to operating activities			(5,680	)			20,663				27,655				32,105				22,492
Interest expense (d) (i)			24,654				21,721				19,885				80,617				61,807
Income from equity affiliates, net			(67	)			121				(131	)			(55	)			(487	)
Incentive compensation expense (f)			(21	)			-				(82	)			(21	)			(82	)
Income taxes			267				69				98				562				400
Non-controlling interest			-				-				-				-				(62	)
Adjusted EBITDA		$	109,377			$	112,094			$	72,931			$	370,374			$	275,850
(a) Adjusted EBITDA for the three and twelve months ended December 31, 2012 was conformed to exclude $5.1 million and $19.9 million related to "Net operating cash flow from acquisitions, effective date through closing date."
(b) Excludes premiums paid at contract inception related to those derivative  contracts that settled during the periods of:		$	1,233			$	1,233			$	517			$	4,893			$	859
(c) Includes net cash settlements on derivative instruments:
- Oil settlements received (paid) of:		$	(7,378	)		$	(17,905	)		$	4,701			$	(36,183	)		$	3,855
- Natural gas settlements received of:		$	11,828			$	11,583			$	17,754			$	44,266			$	83,750
(d) Includes settlements paid on interest rate derivatives of:		$	-			$	-			$	3,196			$	-			$	5,469
(e) Represents non-cash long-term unit-based incentive compensation expense.
(f) 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 constant for the period.
(g) Excludes $2.5 million loss on termination of interest rate swaps for the three and twelve months ended December 31, 2012.
(h) Reflects common units outstanding (including outstanding LTIP grants) at each distribution record date.
(i) Excludes amortization of debt issuance costs and amortization of senior note discount/premium.

 

 

Hedge Portfolio Summary

 

The table below summarizes the Partnership’s commodity derivative hedge portfolio as of February 26, 2014. Please refer to the updated Commodity Price Protection Portfolio via our website for additional details related to our hedge portfolio.

 

		Year
		2014				2015				2016				2017				2018
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Volume (Bbls/d)			13,814				12,689				9,211				7,971				493
Average Price ($/Bbl)		$	92.30			$	93.01			$	86.73			$	84.23			$	82.20
Fixed Price Swaps - ICE Brent
Volume (Bbls/d)			4,800				3,300				4,300				298				-
Average Price ($/Bbl)		$	98.88			$	97.73			$	95.17			$	97.50			$	-
Collars - NYMEX WTI
Volume (Bbls/d)			1,000				1,000				-				-				-
Average Floor Price ($/Bbl)		$	90.00			$	90.00			$	-			$	-			$	-
Average Ceiling Price ($/Bbl)		$	112.00			$	113.50			$	-			$	-			$	-
Collars - ICE Brent
Volume (Bbls/d)			-				500				500				-				-
Average Floor Price ($/Bbl)		$	-			$	90.00			$	90.00			$	-			$	-
Average Ceiling Price ($/Bbl)		$	-			$	109.50			$	101.25			$	-			$	-
Puts - NYMEX WTI
Volume (Bbls/d)			500				500				1,000				-				-
Average Price ($/Bbl)		$	90.00			$	90.00			$	90.00			$	-			$	-
Total:
Volume (Bbls/d)			20,114				17,989				15,011				8,269				493
Average Price ($/Bbl)		$	93.70			$	93.54			$	89.48			$	84.71			$	82.20
Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Volume (MMBtu/d)			7,500				7,500				17,000				10,000				-
Average Price ($/MMBtu)		$	6.00			$	6.00			$	4.46			$	4.48			$	-
Fixed Price Swaps - Henry Hub
Volume (MMBtu/d)			41,600				47,700				24,700				8,571				1,870
Average Price ($/MMBtu)		$	4.75			$	4.77			$	4.23			$	4.39			$	4.15
Puts - Henry Hub
Volume (MMBtu/d)			6,000				1,500				-				-				-
Average Price ($/MMBtu)		$	5.00			$	5.00			$	-			$	-			$	-
Total:
Volume (MMBtu/d)			55,100				56,700				41,700				18,571				1,870
Average Price ($/MMBtu)		$	4.95			$	4.94			$	4.32			$	4.44			$	4.15
Calls - Henry Hub
Volume (MMBtu/d)			15,000				-				-				-				-
Average Price ($/MMBtu)		$	9.00			$	-			$	-			$	-			$	-
Deferred Premium ($/MMBtu)		$	0.12			$	-			$	-			$	-			$	-

 

Premiums paid in 2012 related to oil and natural gas derivatives to be settled in 2014 and beyond are as follows:

 

		Year
Thousands of dollars		2014				2015				2016				2017				2018
Oil		$	4,479			$	4,683			$	7,438			$	734			$	-
Natural gas		$	4,015			$	1,989			$	952			$	-			$	-

 

 

Other Information

 

The Partnership will host an investor conference call to discuss its results today at 9:00 a.m. (Pacific Time). Investors may access the conference call over the Internet via the Investor Relations tab of the Partnership's website (www.breitburn.com), or via telephone by dialing 888-437-9445 (international callers dial +1-719-457-2697) a few minutes prior to register. Those listening via the Internet should go to the site 15 minutes early to register, download and install any necessary audio software. In addition, a replay of the call will be available through March 6, 2014 by dialing 877-870-5176 (international callers dial +1-858-384-5517) and entering replay PIN 7789996, or by going to the Investor Relations tab of the Partnership's website (www.breitburn.com). The Partnership will take live questions from securities analysts and institutional portfolio managers; the complete call is open to all other interested parties on a listen-only basis.

 

About BreitBurn Energy Partners L.P.

 

BreitBurn Energy Partners L.P. is a publicly traded independent oil and gas master limited partnership focused on the acquisition, exploitation, development and production of oil and gas properties. The Partnership’s producing and non-producing oil and natural gas reserves are located in Michigan, Oklahoma, Texas, Wyoming, California, Florida, Indiana and Kentucky. See www.BreitBurn.com for more information.

 

Cautionary Statement Regarding Forward-Looking Information

 

This press release contains forward-looking statements relating to the Partnership’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,” “future” 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 the Partnership’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, the Partnership 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.

 

Investor Relations Contacts:

James G. Jackson

Executive Vice President and Chief Financial Officer

(213) 225-5900 x273

or

Jessica Tang

Investor Relations

(213) 225-5900 x210

 

BBEP-IR

 

 

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Balance Sheets

 

		December 31,				December 31,
Thousands		2013				2012
ASSETS
Current assets
Cash		$	2,458			$	4,507
Accounts and other receivables, net			96,862				67,862
Derivative instruments			7,914				34,018
Related party receivables			2,604				1,413
Inventory			3,890				3,086
Prepaid expenses			3,334				2,779
Total current assets			117,062				113,665
Equity investments			6,641				7,004
Property, plant and equipment
Oil and gas properties			4,818,639				3,363,946
Other assets			21,338				14,367
			4,839,977				3,378,313
Accumulated depletion and depreciation			(924,601	)			(666,420	)
Net property, plant and equipment			3,915,376				2,711,893
Other long-term assets
Intangibles, net			11,679				-
Derivative instruments			71,319				55,210
Other long-term assets			74,205				27,722
Total assets		$	4,196,282			$	2,915,494
LIABILITIES AND EQUITY
Current liabilities
Accounts payable		$	69,809			$	42,497
Derivative instruments			24,876				5,625
Revenue and royalties payable			26,233				22,262
Wages and salaries payable			15,359				10,857
Accrued interest payable			19,690				13,002
Accrued liabilities			26,922				20,997
Total current liabilities			182,889				115,240
Credit facility			733,000				345,000
Senior notes, net			1,156,675				755,696
Deferred income taxes			2,749				2,487
Asset retirement obligation			123,769				98,480
Derivative instruments			2,560				4,393
Other long-term liabilities			4,820				4,662
Total liabilities			2,206,462				1,325,958
Partners' equity			1,989,820				1,589,536
Total liabilities and equity		$	4,196,282			$	2,915,494
Common units outstanding			119,170				84,668

 

 

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Operations

  

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
Thousands of dollars, except per unit amounts		2013				2012				2013				2012
Revenues and other income items
Oil, NGL and natural gas sales		$	193,604			$	113,179			$	660,665			$	413,867
Gain (loss) on commodity derivative instruments, net			(17,234	)			3,715				(29,182	)			5,580
Other revenue, net			978				700				3,175				3,548
Total revenues and other income items			177,348				117,594				634,658				422,995
Operating costs and expenses
Operating costs			80,933				53,576				262,822				195,779
Depletion, depreciation and amortization			62,400				40,350				216,495				137,252
Impairments			54,012				147				54,373				12,313
General and administrative expenses			14,012				15,144				58,707				55,465
(Gain) Loss on sale of assets			(2,154	)			264				(2,015	)			486
Operating (loss) income			(31,855	)			8,113				44,276				21,700
Interest expense, net of capitalized interest			26,680				17,975				87,067				61,206
Loss on interest rate swaps			-				175				-				1,101
Other expense (income), net			(20	)			12				(25	)			48
Total other expense			26,660				18,162				87,042				62,355
Loss before taxes			(58,515	)			(10,049	)			(42,766	)			(40,655	)
Income tax expense			277				285				905				84
Net loss			(58,792	)			(10,334	)			(43,671	)			(40,739	)
Less: Net income attributable to noncontrolling interest			-				-				-				(62	)
Net loss attributable to the partnership			(58,792	)			(10,334	)			(43,671	)			(40,801	)
Basic net loss per unit		$	(0.52	)		$	(0.13	)		$	(0.43	)		$	(0.56	)
Diluted net loss income per unit		$	(0.52	)		$	(0.13	)		$	(0.43	)		$	(0.56	)

 

 

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

 

		Twelve Months Ended
		December 31,
Thousands of dollars		2013				2012
Cash flows from operating activities
Net loss		$	(43,671	)		$	(40,739	)
Adjustments to reconcile net loss to cash flow from operating activities:
Depletion, depreciation and amortization			216,495				137,252
Impairments			54,373				12,313
Unit-based compensation expense			19,955				22,266
(Gain) loss on derivative instruments			29,182				(4,479	)
Derivative instrument settlements			8,083				84,615
Prepaid premiums on derivative instruments			-				(30,043	)
Settlement payments on terminated derivative instruments			-				(2,479	)
Income from equity affiliates, net			(55	)			487
Deferred income taxes			262				(316	)
(Gain) loss on sale of assets			(2,015	)			486
Other			5,163				4,472
Changes in assets and liabilities:
Accounts receivable and other assets			(29,322	)			6,759
Inventory			(804	)			1,638
Net change in related party receivables and payables			(1,191	)			2,832
Accounts payable and other liabilities			711				(3,282	)
Net cash provided by operating activities			257,166				191,782
Cash flows from investing activities
Property acquisitions			(1,175,817	)			(562,356	)
Capital expenditures			(266,308	)			(135,932	)
Other			(26,661	)			-
Proceeds from sale of assets			2,981				1,129
Net cash used in investing activities			(1,465,805	)			(697,159	)
Cash flows from financing activities
Issuance of common units			618,013				370,234
Distributions			(186,868	)			(132,420	)
Proceeds from issuance of long-term debt, net			2,276,000				1,502,885
Repayments of long-term debt			(1,487,000	)			(1,223,000	)
Change in book overdraft			2,013				(3,176	)
Debt issuance costs			(15,568	)			(9,967	)
Net cash provided by financing activities			1,206,590				504,556
Decrease in cash			(2,049	)			(821	)
Cash beginning of period			4,507				5,328
Cash end of period		$	2,458			$	4,507