November 6, 2012

BreitBurn Energy Partners L.P. Reports Third Quarter Results

LOS ANGELES--(BUSINESS WIRE)-- BreitBurn Energy Partners L.P. (the "Partnership") (NASDAQ:BBEP) today announced financial and operating results for its third quarter of 2012.

Key Highlights

  • The Partnership had strong financial performance in the third quarter with record quarterly high Adjusted EBITDA of $90.1 million, which represented a 36% increase from the second quarter of 2012 and a 70% increase from the third quarter of 2011.
  • Net production in the third quarter increased 11% from the second quarter of 2012 and 29% from the third quarter or 2011.
  • The Partnership is announcing today a $14.6 million increase to its 2012 capital program, which increases the Partnership's expected total 2012 capital program to approximately $152 million.
  • On October 31, 2012, the Partnership announced an increased cash distribution for the third quarter of 2012 of $0.4650 per common unit, or an annualized rate of $1.86 per common unit, to be paid on November 14, 2012 to the record holders of common units at the close of business on November 9, 2012. This represents the Partnership's tenth consecutive quarterly distribution increase and a 7% increase over the cash distribution for the third quarter of 2011.
  • In October 2012, the Partnership completed its semi-annual borrowing base redetermination under its bank credit facility and increased its total commitments from existing lenders to $900 million, with the ability to increase total commitments to $1 billion with lender approval.
  • In September 2012 the Partnership completed the public offering of 11.5 million common units priced at $18.51 per unit and a private offering of an additional $200 million aggregate principal amount of its 7.875% senior notes due 2022. Net proceeds from the offerings were used to reduce borrowings under the Partnership's bank credit facility.

Management Commentary

Hal Washburn, CEO, said: "The Partnership delivered another quarter of consistent operating performance. We continue to work on the integration of our recently acquired properties in Texas and Wyoming while we opportunistically pursue organic growth opportunities in our legacy assets. We are pleased to announce the third increase to our 2012 capital program, which is driven by continued success identifying attractive oil drilling opportunities in our California assets. In addition, we also completed two successful financings during the quarter which position us to capitalize on acquisition opportunities as we approach year end."

Third Quarter 2012 Operating and Financial Results Compared to Second Quarter 2012

  • Total production was 2,166 MBoe in the third quarter of 2012 compared to 1,953 MBoe in the second quarter of 2012. Average daily production was 23,545 Boe/day in the third quarter of 2012 compared to 21,457 Boe/day in second quarter of 2012.
    • Oil and NGL production was 973 MBoe compared to 815 MBoe. The increase principally reflects the additional production from the acquisition of properties in the Big Horn Basin in Wyoming and the Permian Basin in Texas. NGLs represented less than 3% of total production.
    • Natural gas production was 7,161 MMcf compared to 6,824 MMcf. The increase is primarily due to production from the acquisition of properties in the Permian Basin.
  • Adjusted EBITDA, a non-GAAP measure, increased approximately 36% to a record quarterly high of $90.1 million in the third quarter of 2012 from $66.3 million in the second quarter of 2012.
  • Lease operating expenses per Boe, which include district expenses, transportation expenses and processing fees and exclude production and property taxes, decreased to $18.62 per Boe in the third quarter of 2012 from $20.03 per Boe in the second quarter of 2012.
  • General and administrative expenses on a per Boe basis, excluding non-cash unit-based compensation, decreased slightly to $3.73 per Boe in the third quarter of 2012 from $3.75 per Boe in the second quarter of 2012.
  • Oil and natural gas sales revenues were $111.7 million in the third quarter of 2012, up from $95.0 million in the second quarter of 2012. Realized gains on commodity derivative instruments were $22.5 million in the third quarter of 2012 compared to realized gains of $25.1 million in the second quarter of 2012.
  • NYMEX WTI crude oil spot prices averaged $92.17 per barrel and Brent crude oil spot prices averaged $109.63 per barrel in the third quarter of 2012 compared to $93.29 per barrel and $108.04 per barrel, respectively, in the second quarter of 2012. Henry Hub natural gas spot prices averaged $2.88 per Mcf in the third quarter of 2012 compared to $2.29 per Mcf in the second quarter of 2012.
  • Realized crude oil and NGL prices averaged $89.55 per Boe and realized natural gas prices averaged $5.89 per Mcf in the third quarter of 2012 compared to realized crude oil and NGL prices of $92.08 per Boe and realized natural gas prices of $5.74 per Mcf in the second quarter of 2012.
  • Net loss attributable to the Partnership, including the effect of unrealized losses on commodity derivative instruments, was $73.0 million, or $1.00 per diluted common unit, in the third quarter of 2012 compared to a net income of $92.5 million, or $1.29 per diluted common unit, in the second quarter of 2012.
  • Capital expenditures totaled $49.5 million in the third quarter of 2012 compared to $28.0 million in the second quarter of 2012.

Increase to 2012 Capital Program

The Partnership's 2012 crude oil and natural gas capital spending program, including projects for our properties acquired in 2012, is expected to be approximately $152 million. The Partnership had previously announced two increases to its original capital program in May and August for a total capital program of $137 million. The Partnership is increasing its capital program for a third time, by $14.6 million, to pursue attractive oil drilling opportunities in California where we receive Brent-based pricing.

Impact of Derivative Instruments

The Partnership uses commodity and interest rate derivative instruments to mitigate the risks associated with commodity price volatility and changing interest rates 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. Non-cash gains or losses do not affect Adjusted EBITDA, cash flow from operations or the Partnership's ability to pay cash distributions.

Realized gains from commodity derivative instruments were $22.5 million during the third quarter of 2012. Realized losses from interest rate derivative instruments were $0.8 million during the third quarter of 2012. Non-cash unrealized losses from commodity derivative instruments were $91.9 million and non-cash unrealized gains from interest rate derivative instruments were $0.6 million during the third quarter of 2012.

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 September 30, 2012, June 30, 2012 and September 30, 2011:

        Three Months Ended
September 30,         June 30,        

September 30,

Thousands of dollars, except as indicated 2012 2012 2011
Oil, natural gas and NGLs sales $ 111,700 $ 94,981 $ 97,356
Realized gain on commodity derivative instruments 22,496 25,063 8,092
Unrealized gain (loss) on commodity derivative instruments (91,914 ) 82,225 170,734
Other revenues, net   796     907   1,375
Total revenues $ 43,078   $ 203,176 $ 277,557
Lease operating expenses and processing fees $ 40,325 $ 39,122 $ 37,835
Production and property taxes   8,574     6,525   6,689
Total lease operating expenses $ 48,899   $ 45,647 $ 44,524
Purchases and other operating costs 293 647 329
Change in inventory   856     2,600   1,593
Total operating costs $ 50,048   $ 48,894 $ 46,446
Lease operating expenses pre taxes per Boe (a) $ 18.62 $ 20.03 $ 22.51
Production and property taxes per Boe 3.96 3.34 3.98
Total lease operating expenses per Boe   22.58     23.37   26.49
General and administrative expenses (excluding unit-based compensation)   $ 8,069   $ 7,314 $ 8,552
Net income (loss) attributable to the partnership $ (73,003 ) $ 92,506 $ 178,227
Net income (loss) per diluted limited partner unit $ (1.00 ) $ 1.29 $ 2.87
 
Total production (MBoe) 2,166 1,953 1,681
Oil and NGLs (MBoe) (b) 973 815 829
Natural gas (MMcf) 7,161 6,824 5,114
Average daily production (Boe/d)   23,545     21,457   18,273
Sales volumes (MBoe)   2,219     2,013   1,723
Average realized sales price (per Boe) (c) (d) $ 60.40 $ 59.54 $ 61.08
Oil and NGLs (per Boe) (c) (d) 89.55 92.08 81.50
Natural gas (per Mcf) (c)   5.89     5.74   6.72
 
 
(a) Includes lease operating expenses, district expenses, transportation expenses and processing fees.
(b) NGLs account for less than 3% of total production.
(c) Includes realized gain on commodity derivative instruments.
(d) Includes crude 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 is "Adjusted EBITDA." This non-GAAP financial measure should not be considered as an alternative 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. This non-GAAP financial measure 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 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
September 30,         June 30,         September 30,
Thousands of dollars 2012 2012 2011
Reconciliation of net income (loss) to Adjusted EBITDA:
 
Net income (loss) attributable to the Partnership $ (73,003 ) $ 92,506 $ 178,181
 
Unrealized (gain) loss on commodity derivative instruments 91,914 (82,225 ) (170,734 )
Depletion, depreciation and amortization expense 37,270 33,517 26,688
Interest expense and other financing costs (a) 16,174 14,872 10,342
Unrealized (gain) loss on interest rate derivatives (570 ) (613 ) 71
Loss (gain) on sale of assets 68 29 (94 )
Income taxes (647 ) 1,005 1,895
Unit-based compensation expense (b) 5,652 5,612 5,447
Net operating cash flow from acquisitions, effective date through closing date   13,227     1,595     1,078  
Adjusted EBITDA $ 90,085   $ 66,298   $ 52,874  
 
 
Three Months Ended
September 30, June 30, September 30,
Thousands of dollars 2012 2012 2011
Reconciliation of net cash flows from operating activities to Adjusted EBITDA:
 
Net cash provided by operating activities $ 65,725 $ 29,252 $ 41,267
 
Increase (decrease) in assets net of liabilities relating to operating activities (3,935 ) 21,940 1,199
Interest expense (a) (c) 15,133 13,583 9,273
Income from equity affiliates, net (47 ) (155 ) (10 )
Incentive compensation expense (d) - - (29 )
Income taxes (18 ) 100 64
Non-controlling interest - (17 ) (46 )
Net operating cash flow from acquisitions, effective date through closing date   13,227     1,595     1,078  
Adjusted EBITDA $ 90,085   $ 66,298   $ 52,874  
 
(a) Includes realized loss on interest rate derivatives.
(b) Represents non-cash long-term unit-based incentive compensation expense.
(c) Excludes amortization of debt issuance costs and amortization of senior note discount/premium.
(d) Represents cash-based incentive compensation plan expense.
 

Hedge Portfolio Summary

The table below summarizes the Partnership's commodity derivative hedge portfolio for the fourth quarter of 2012 through 2017 and includes contracts entered into through October 30, 2012. Please refer to the updated Commodity Price Protection Portfolio via our website for additional details related to our hedge portfolio.

      Year
2012         2013         2014         2015         2016         2017
Oil Positions:  
Fixed Price Swaps - NYMEX WTI
Hedged Volume (Bbl/d) 4,009 3,879 3,314 3,689 1,611 222
Average Price ($/Bbl) $ 90.90 $ 90.74 $ 93.21 $ 97.50 $ 91.50 $ 88.12
Fixed Price Swaps - IPE Brent
Hedged Volume (Bbl/d) 2,339 3,900 3,500 2,000 1,500 -
Average Price ($/Bbl) $ 105.37 $ 97.23 $ 96.86 $ 96.46 $ 93.75 $ -
Collars - NYMEX WTI
Hedged Volume (Bbl/d) 2,346 500 1,000 1,000 - -
Average Floor Price ($/Bbl) $ 110.00 $ 77.00 $ 90.00 $ 90.00 $ - $ -
Average Ceiling Price ($/Bbl) $ 145.50 $ 103.10 $ 112.00 $ 113.50 $ - $ -
Collars - IPE Brent
Hedged Volume (Bbl/d) - - - 500 500 -
Average Floor Price ($/Bbl) $ - $ - $ - $ 90.00 $ 90.00 $ -
Average Ceiling Price ($/Bbl) $ - $ - $ - $ 109.50 $ 101.25 $ -
Puts - NYMEX WTI
Hedged Volume (Bbl/d) - 500 - - - -
Average Price ($/Bbl) $ - $ 90.00 $ - $ - $ - $ -
Total:
Hedged Volume (Bbl/d) 8,694 8,779 7,814 7,189 3,611 222
Average Price ($/Bbl) $ 99.94 $ 92.80 $ 94.43 $ 95.65 $ 92.22 $ 88.12
 
Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Hedged Volume (MMBtu/d) 18,678 37,000 7,500 7,500 7,000 -
Average Price ($/MMBtu) $ 7.28 $ 6.50 $ 6.00 $ 6.00 $ 4.51 $ -
Fixed Price Swaps - Henry Hub
Hedged Volume (MMBtu/d) 16,000 19,000 36,000 40,500 13,000 -
Average Price ($/MMBtu) $ 4.88 $ 4.90 $ 4.86 $ 4.88 $ 4.18 $ -
Collars - MichCon City-Gate
Hedged Volume (MMBtu/d) 18,680 - - - - -
Average Floor Price ($/MMBtu) $ 9.00 $ - $ - $ - $ - $ -
Average Ceiling Price ($/MMBtu) $ 12.25 $ - $ - $ - $ - $ -
Puts - Henry Hub
Hedged Volume (MMBtu/d) - - 6,000 1,500 - -
Average Price ($/MMBtu) $ - $ - $ 5.00 $ 5.00 $ - $ -
Total:
Hedged Volume (MMBtu/d) 53,358 56,000 49,500 49,500 20,000 -
Average Price ($/MMBtu) $ 7.16 $ 5.96 $ 5.05 $ 5.05 $ 4.30 $ -
 
Calls - Henry Hub
Hedged Volume (MMBtu/d) - 30,000 15,000 - - -
Average Price ($/MMBtu) $ - $ 8.00 $ 9.00 $ - $ - $ -
Premium ($/MMBtu) $ - $ 0.08 $ 0.12 $ - $ - $ -
 

Other Information

The Partnership will host an investor conference call to discuss its results today at 10:00 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 888-417-8516 (international callers dial +1-719-325-2492) 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 November 20, 2012 by dialing 877-870-5176 (international callers dial +1-858-384-5517) and entering replay PIN 4036390, 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 crude oil and natural gas reserves are located in Michigan, Wyoming, California, Texas, 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," "future," "impact," "pursue," "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 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 on February 29, 2012, 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.

BBEP-IR

BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Balance Sheets
 
 
        September 30,         December 31,
Thousands 2012 2011
ASSETS
Current assets
Cash $ 4,374 $ 5,328
Accounts and other receivables, net 69,788 73,018
Derivative instruments 39,375 83,452
Related party receivables 1,916 4,245
Inventory 3,516 4,724
Prepaid expenses   3,378     2,053  
Total current assets 122,347 172,820
Equity investments 7,135 7,491
Property, plant and equipment
Oil and gas properties 2,987,032 2,583,993
Other assets   14,123     13,431  
3,001,155 2,597,424
Accumulated depletion and depreciation   (627,842 )   (524,665 )
Net property, plant and equipment 2,373,313 2,072,759
Other long-term assets
Derivative instruments 46,029 55,337
Other long-term assets 30,156 22,442
   
Total assets $ 2,578,980   $ 2,330,849  
LIABILITIES AND EQUITY
Current liabilities
Accounts payable $ 62,408 $ 33,494
Derivative instruments 5,200 8,881
Revenue and royalties payable 17,173 19,641
Salaries and wages payable 10,156 13,655
Accrued liabilities   20,423     14,218  
Total current liabilities 115,360 89,889
 
Credit facility 23,000 520,000
Senior notes, net 755,696 300,613
Deferred income taxes 2,300 2,803
Asset retirement obligation 86,499 82,397
Derivative instruments 2,016 3,084
Other long-term liabilities   4,697     4,849  
Total liabilities 989,568 1,003,635
Equity
Partners' equity 1,589,412 1,326,764
Noncontrolling interest   -     450  
Total equity 1,589,412 1,327,214
   
Total liabilities and equity $ 2,578,980   $ 2,330,849  
 
Common units outstanding 80,644 59,864
 
 
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Operations
 
        Three Months Ended         Nine Months Ended
September 30, September 30,
Thousands of dollars, except per unit amounts 2012         2011 2012         2011
 
Revenues and other income items
Oil, natural gas and natural gas liquid sales $ 111,700 $ 97,356 $ 300,688 $ 284,673
Gain (loss) on commodity derivative instruments, net (69,418 ) 178,826 1,865 119,132
Other revenue, net   796     1,375     2,848     3,416  
Total revenues and other income items 43,078 277,557 305,401 407,221
Operating costs and expenses
Operating costs 50,048 46,446 142,203 119,465
Depletion, depreciation and amortization 37,270 26,688 109,068 76,354
General and administrative expenses 13,721 13,999 40,321 38,126
Loss (gain) on sale of assets   68     (94 )   222     (40 )
Total operating costs and expenses   101,107     87,039     291,814     233,905  
 
Operating income (loss) (58,029 ) 190,518 13,587 173,316
 
Interest expense, net of capitalized interest 15,362 9,270 43,231 27,770
Loss on interest rate swaps 242 1,143 926 3,020
Other expense (income), net   17     (17 )   36     (20 )
 
Income (loss) before taxes (73,650 ) 180,122 (30,606 ) 142,546
 
Income tax expense (benefit)   (647 )   1,895     (201 )   1,509  
 
Net income (loss) (73,003 ) 178,227 (30,405 ) 141,037
 
Less: Net income attributable to noncontrolling interest - (46 ) (62 ) (148 )
       
Net income (loss) attributable to the partnership   (73,003 )   178,181     (30,467 )   140,889  
 
Basic net income (loss) per unit $ (1.00 ) $ 2.87   $ (0.44 ) $ 2.30  
Diluted net income (loss) per unit $ (1.00 ) $ 2.87   $ (0.44 ) $ 2.29  
 
 
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows
 
 
        Nine Months Ended
September 30,
Thousands of dollars 2012         2011
 
Cash flows from operating activities
Net income (loss) $ (30,405 ) $ 141,037
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation and amortization 109,068 76,354
Unit-based compensation expense 16,855 16,334
Unrealized loss (gain) on derivative instruments 61,938 (106,488 )
Income from equity affiliates, net 356 169
Deferred income taxes (503 ) 1,313
Loss (gain) on sale of assets 222 (40 )
Other 3,366 417
Changes in assets and liabilities:
Accounts receivable and other assets (10,425 ) (9,858 )
Inventory 1,208 2,638
Net change in related party receivables and payables 2,329 932
Accounts payable and other liabilities   12,267     5,976  
Net cash provided by operating activities   166,276     128,784  
Cash flows from investing activities
Capital expenditures (77,699 ) (61,264 )
Proceeds from sale of assets 863 1,118
Deposit for oil and gas properties - (14,250 )
Property acquisitions   (313,404 )   (57,380 )
Net cash used in investing activities   (390,240 )   (131,776 )
Cash flows from financing activities
Issuance of common units 370,504 99,826
Distributions (93,734 ) (75,690 )
Proceeds from issuance of long-term debt, net 1,066,885 283,500
Repayments of long-term debt (1,109,000 ) (300,500 )
Change in book overdraft (2,299 ) 141
Debt issuance costs   (9,346 )   (3,138 )
Net cash provided by financing activities   223,010     4,139  
Increase (decrease) in cash (954 ) 1,147
Cash beginning of period   5,328     3,630  
Cash end of period $ 4,374   $ 4,777  

Investor Relations Contacts:
BreitBurn Energy Partners L.P.
James G. Jackson
Executive Vice President and Chief Financial Officer
213-225-5900 x273
or
Jessica Tang
Investor Relations
213-225-5900 x210

Source: BreitBurn Energy Partners L.P.

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