BreitBurn Energy Partners L.P. Reports Third Quarter Results

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BreitBurn Energy Partners L.P. Reports Third Quarter Results

LOS ANGELES--(BUSINESS WIRE)-- BreitBurn Energy Partners L.P. (the "Partnership") (NAS: 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 indicated201220122011
Oil, natural gas and NGLs sales$111,700$94,981$97,356
Realized gain on commodity derivative instruments22,49625,0638,092
Unrealized gain (loss) on commodity derivative instruments(91,914)82,225170,734
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 costs293647329
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 Boe3.963.343.98
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)2,1661,9531,681
Oil and NGLs (MBoe) (b)973815829
Natural gas (MMcf)7,1616,8245,114
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)89.5592.0881.50
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 dollars201220122011
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 instruments91,914(82,225)(170,734)
Depletion, depreciation and amortization expense37,27033,51726,688
Interest expense and other financing costs (a)16,17414,87210,342
Unrealized (gain) loss on interest rate derivatives(570)(613)71
Loss (gain) on sale of assets6829(94)
Income taxes(647)1,0051,895
Unit-based compensation expense (b)5,6525,6125,447
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 dollars201220122011
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)21,9401,199
Interest expense (a) (c)15,13313,5839,273
Income from equity affiliates, net(47)(155)(10)
Incentive compensation expense (d)--(29)
Income taxes(18)10064
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)4,0093,8793,3143,6891,611222
Average Price ($/Bbl)$90.90$90.74$93.21$97.50$91.50$88.12
Fixed Price Swaps - IPE Brent
Hedged Volume (Bbl/d)
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