BreitBurn Energy Partners L.P. Reports Third Quarter Results
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Strong Operational Performance; Key Metrics Continue to Meet or Exceed Annualized 2009 Guidance
LOS ANGELES--(BUSINESS WIRE)-- BreitBurn Energy Partners L.P. (the "Partnership") (NASDAQ: BBEP) today announced financial and operating results for its third quarter of 2009.
Key Highlights
-- Operationally, the Partnership had a very strong quarter with total
production above the high end of the 2009 guidance range despite the
sale of the Lazy JL Field in Texas, effective July 1, 2009, and
significant decreases in year-over-year capital spending.
-- The Partnership's successful debt reduction efforts continued during the
third quarter through consistent operating cash flows and the sale of
the Lazy JL Field for $23 million. As of September 30, 2009, outstanding
debt totaled $585 million.
-- As of October 31, 2009, outstanding debt was approximately $576 million,
representing $160 million in debt reduction in the first ten months of
2009.
-- The Partnership announced the successful completion of its semi-annual
borrowing base redetermination in early October, which resulted in the
reaffirmation of its borrowing base at $732 million and no modification
to any other terms of the Credit Agreement.
-- Rising commodity prices allowed the Partnership to further strengthen
its commodity price protection portfolio with the addition of new 2010,
2011, 2013, and 2014 hedges at attractive prices. The new hedges cover
approximately 1,000,000 Bbls and 8,760,000 MMBtu of expected production
during those years.
Management Commentary on Results
Hal Washburn, Chairman and Co-CEO, said, "We are pleased with the results we achieved this quarter and year-to-date, both operationally and financially. Our operations team continues to do a very good job improving the productivity of our asset base and managing costs in a volatile commodity price environment. We are particularly pleased with the ongoing improvements in our Eastern Division where the benefits of organizational changes made in the first quarter continue to have a positive impact on production even as we have reduced staffing levels in Michigan, Indiana and Kentucky below the levels in place when we acquired these properties in late 2007. Total production is trending above the high end of our guidance range and our annualized lease operating expenses and G&A costs are well within our guidance ranges for the year."
Washburn added, "In addition to our operational success, our financial flexibility continues to improve. We paid down an additional $55 million in debt during the quarter and have reduced borrowings by $160 million since year end 2008. As we move into 2010, our improved liquidity position will allow us the flexibility to accelerate capital spending to at least maintenance capital levels and eventually re-establish distributions when leverage has been reduced to acceptable levels."
Third Quarter 2009 Operating and Financial Results Compared to Second Quarter 2009
-- Total production decreased by less than 0.5% to 1,628 MBoe in the third
quarter from 1,636 MBoe (pro forma for the sale of the Lazy JL Field) in
the second quarter and is trending above the high end of our guidance
range year-to-date.
o Oil and NGL production was 743 MBoe compared to 744 MBoe (pro forma
for the sale of the Lazy JL Field).
o Natural gas production was 5,308 MMcf compared to 5,349 MMcf.
-- Lease operating expenses per Boe, which include district expenses and
processing fees and exclude production/property taxes and transportation
costs, increased 4% to $17.53 per Boe in the third quarter from $16.88
per Boe in the second quarter. Year-to-date operating costs remain well
within our guidance range of $16.25 - $18.50 per Boe.
-- General and administrative expenses, excluding unit-based compensation,
were $5.8 million, or $3.59 per Boe, in the third quarter compared to
$5.3 million, or $3.18 per Boe, in the second quarter. Year-to-date
general and administrative expenses, excluding unit-based compensation,
are trending toward the lower end of our guidance range.
-- Adjusted EBITDA, a non-GAAP measure, decreased 5% to $48.4 million in
the third quarter from $50.8 million in the second quarter.
-- Oil and natural gas sales revenues, including realized gains and losses
on commodity derivative instruments (but excluding realized gains from
hedge monetizations), increased 1% to $87.0 million in the third quarter
from $86.4 million in the second quarter.
o Realized gains from commodity derivative instruments were $24.3
million in the third quarter as compared to $51.5 million in the
second quarter. Realized gains in the second quarter included $25.0
million from the monetization of selected 2011 and 2012 hedge
contracts.
-- NYMEX WTI crude oil averaged approximately $68.14 per barrel and NYMEX
natural gas prices averaged approximately $3.44 per Mcf in the third
quarter as compared to $59.61 per barrel and $3.81 per Mcf,
respectively, in the second quarter.
-- As a result of our extensive hedging portfolio, realized crude oil and
natural gas prices increased and averaged $67.40 per Boe and $7.30 per
Mcf, respectively, in the third quarter as compared to $65.47 per Boe
and $7.09 per Mcf, respectively, in the second quarter.
-- Net loss was $5.4 million, or $0.10 per diluted limited partner unit, in
the third quarter as compared to a net loss of $108.5 million, or $2.06
per diluted limited partner unit, in the second quarter.
-- Oil and gas capital expenditures totaled $7.2 million in the third
quarter as compared to $3.3 million in the second quarter.
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 $24.3 million during the third quarter of 2009. Realized losses from interest rate derivative instruments were $3.4 million. Non-cash unrealized losses from commodity derivative instruments were $11.6 million and non-cash unrealized losses from interest rate derivative instruments were $0.4 million for the period.
In June 2009, the Partnership terminated selected crude oil and natural gas derivative instruments covering a portion of its expected production in 2011 and 2012 and replaced them with new derivative instruments for the same 2011 and 2012 volumes. Net realized proceeds of approximately $25.0 million were immediately used to reduce outstanding borrowings under the Partnership's credit facility. Realized gains from commodity derivative instruments of $51.5 million during the second quarter of 2009 included the impact of the hedge monetization.
Production, Income Statement and Realized Price Information
The following table presents production, selected income statement and realized price information for the three months ended September 30, 2009 and 2008 and the three months ended June 30, 2009:
Three-Months Ended
September 30, June 30, September 30,
Thousands of dollars, except as 2009 2009 2008
indicated
Oil, natural gas and NGL sales (a) $ 62,674 $ 59,872 $ 130,249
Realized gains (losses) on commodity 24,356 51,468 (24,123 )
derivative instruments (b)
Unrealized gains (losses) on (11,637 ) (148,727 ) 431,564
commodity derivative instruments (b)
Other revenues, net 261 393 806
Total revenues $ 75,654 $ (36,994 ) $ 538,496
Lease operating expenses and $ 29,052 $ 28,442 $ 35,611
processing fees
Production and property taxes 4,422 4,188 7,814
Total lease operating expenses $ 33,474 $ 32,630 $ 43,425
Transportation expenses 799 851 351
Purchases 18 21 118
Change in inventory (403 ) (1,498 ) (1,979 )
Total operating costs $ 33,888 $ 32,004 $ 41,915
Lease operating expenses pre taxes $ 17.53 $ 16.88 $ 20.77
per Boe (c)
Production and property taxes per 2.72 2.53 4.63
Boe
Total lease operating expenses per 20.25 19.41 25.40
Boe
General and administrative expenses $ 5,844 $ 5,255 $ 5,992
excluding unit-based compensation
Net income (loss) $ (5,396 ) $ (108,525 ) $ 454,505
Net income (loss) per diluted $ (0.10 ) $ (2.06 ) $ 8.40
limited partnership unit
Total production (MBoe) 1,628 1,654 1,689
Oil and NGL (MBoe) 743 762 762
Natural gas (MMcf) 5,308 5,349 5,564
Average daily production (Boe/d) 17,697 18,172 18,359
Sales volumes (MBoe) 1,605 1,635 1,657
Average realized sales price (per $ 54.37 $ 52.97 $ 64.17
Boe) (d) (e) (f)
Oil and NGL (per Boe) (d) (e) (f) 67.40 65.47 81.82
Natural gas (per Mcf) (d) (e) 7.30 7.09 8.38
(a) Q3 2009, Q2 2009 and Q3 2008 include $258, $258 and $273, respectively, of
amortization of an intangible asset related to crude oil sales contracts.
(b) Q2 2009 includes the effects of the early terminations of hedge contracts
monetized in June 2009 for $24,955.
(c) Includes lease operating expenses and processing fees. Excludes amortization
of intangible asset related to the Quicksilver Acquisition.
(d) Includes realized gains (losses) on commodity derivative instruments.
(e) Q2 2009 excludes the effects of the early terminations of hedge contracts
monetized in June 2009 ($6,030 of oil hedges and $18,925 of natural gas hedges).
(f) Excludes amortization of intangible asset related to crude oil sales
contracts.
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.
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 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 Nine Months Ended
September 30, September 30,
Thousands of dollars 2009 2008 2009 2008
Reconciliation of
consolidated net income
(loss) to Adjusted EBITDA:
Net income (loss)
attributable to the ($5,408 ) $ 454,454 ($67,577 ) $ 127,074
partnership
Unrealized (gain) loss on
commodity derivative 11,637 (431,564 ) 164,432 (41,667 )
instruments
Depletion, depreciation 24,130 21,477 81,393 64,228
and amortization expense
Interest expense and other 7,960 10,325 24,352 21,237
financing costs (a)
Unrealized (gain) loss on 381 1,660 (4,113 ) 2,269
interest rate derivatives
Gain on sale of commodity - - (70,587 ) -
derivatives (b)
Loss on sale of asset (c) 5,470 - 5,470 -
Income tax provision (13 ) 2,599 (354 ) 1,262
Amortization of 777 792 2,334 2,339
intangibles
Unit-based compensation 3,416 1,842 10,686 5,390
expense (d)
Adjusted EBITDA $ 48,350 $ 61,585 $ 146,036 $ 182,132
Three Months Ended Nine Months Ended
September 30, September 30,
Thousands of dollars 2009 2008 2009 2008
Reconciliation of net cash
from operating activities
to Adjusted EBITDA:
Net cash from operating $ 42,436 $ 56,326 $ 183,971 $ 190,961
activities
Increase (decrease) in
assets net of liabilities (1,293 ) (5,614 ) 9,882 (34,498 )
relating to operating
activities
Interest expense (a) (e) 7,136 9,506 21,881 19,461
Gain on sale of commodity - - (70,587 ) -
derivatives (b)
Equity earnings from (106 ) (1,256 ) (766 ) (772 )
affiliates, net
Incentive compensation (31 ) 1,384 950 198
expense (f)
Incentive compensation 7 1,006 176 6,346
paid
Income taxes 213 284 543 637
Non-controlling interest (12 ) (51 ) (14 ) (175 )
Other - - - (26 )
Adjusted EBITDA $ 48,350 $ 61,585 $ 146,036 $ 182,132
(a) Includes realized gains/losses on interest rate derivatives.
(b) Represents $24,955 and $45,632 related to the early terminations of selected
2011 and 2012 hedge contracts monetized in June 2009 and January 2009.
(c) Includes loss on sale of Lazy JL assets of $5,541.
(d) Represents non-cash long term incentive compensation expense.
(e) Excludes debt amortization.
(f) Represents cash-based incentive compensation plan expense.
Hedge Portfolio Summary
The table below summarizes the Partnership's commodity derivative hedge portfolio as of November 6, 2009:
Year Year Year Year Year Year
2009 2010 2011 2012 2013 2014
Gas Positions:
Fixed Price
Swaps:
Hedged Volume 44,723 43,869 25,955 19,129 27,000 -
(MMBtu/d)
Average Price $ 8.16 $ 8.20 $ 7.26 $ 7.10 $ 6.92 $ -
($/MMBtu)
Collars:
Hedged Volume 2,125 3,405 16,016 19,129 - -
(MMBtu/d)
Average Floor $ 9.00 $ 9.00 $ 9.00 $ 9.00 $ - $ -
Price ($/MMBtu)
Average Ceiling $ 15.40 $ 12.79 $ 11.28 $ 11.89 $ - $ -
Price ($/MMBtu)
Total:
Hedged Volume 46,848 47,275 41,971 38,257 27,000 -
(MMMBtu/d)
Average Price $ 8.20 $ 8.26 $ 7.92 $ 8.05 $ 6.92 $ -
($/MMBtu)
Oil Positions:
Fixed Price
Swaps:
Hedged Volume 2,935 2,808 2,616 2,539 3,500 748
(Bbls/d)
Average Price $ 70.18 $ 81.35 $ 66.22 $ 67.24 $ 76.79 $ 88.65
($/Bbl)
Participating
Swaps: (a)
Hedged Volume 2,410 1,993 1,439 - - -
(Bbls/d)
Average Price $ 66.48 $ 64.40 $ 61.29 $ - $ - $ -
($/Bbl)
Average 30.4 % 55.5 % 53.2 % - - -
Participation %
Collars:
Hedged Volume 514 1,279 2,048 2,477 500 -
(Bbls/d)
Average Floor $ 89.57 $ 102.85 $ 103.42 $ 110.00 $ 77.00 $ -
Price ($/Bbl)
Average Ceiling $ 59.42 $ 136.16 $ 152.61 $ 145.39 $ 103.10 $ -
Price ($/Bbl)
Floors:
Hedged Volume 500 500 - - - -
(Bbls/d)
Average Floor $ 100.00 $ 100.00 $ - $ - $ - $ -
Price ($/Bbl)
Total:
Hedged Volume 6,359 6,580 6,103 5,016 4,000 748
(Bbls/d)
Average Price $ 72.69 $ 81.81 $ 77.51 $ 88.35 $ 76.82 $ 88.65
($/Bbl)
(a) A participating swap combines a swap and a call option with the same strike price.
Interest Rate Hedge Portfolio
We had the following interest rate swaps in place at November 6, 2009, to fix a portion of floating LIBOR-base debt on our credit facility:
Notional amounts in thousands of dollars Notional Amount Fixed Rate Period Covered October 1, 2009 to January 8, 2010 $ 100,000 3.3873 % October 1, 2009 to December 20, 2010 300,000 3.6825 % January 20, 2010 to October 20, 2011 100,000 1.6200 % December 20, 2010 to October 20, 2011 200,000 2.9900 %
Conference Call
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 888-204-6674 (international callers dial +1-913-312-0399) 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 13, 2009 by dialing 888-203-1112 (international callers dial +1-719-457-0820) and entering replay PIN 7153194, 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 California-based publicly traded independent oil and gas limited partnership focused on the acquisition, exploitation, development and production of oil and gas properties. These producing and non-producing crude oil and natural gas reserves are located in Northern Michigan, the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming, the Sunniland Trend in Florida, and the New Albany Shale in Indiana and Kentucky. See www.BreitBurn.com for more information.
Cautionary Statement Relevant to 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," "future," "impact," "guidance," "ongoing improvements," "eventually," "will," "could," "may be used," "continue," "trending," 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 to execute our business plan, our level of indebtedness, a further significant reduction in the borrowing base under our bank credit facility, our ability to raise capital, prices and demand for natural gas and oil, our ability to replace reserves and efficiently develop our current reserves, the litigation instituted by Quicksilver Resources Inc. against us and the factors set forth under the heading "Risk Factors" incorporated by reference from our Annual Report on Form 10-K, 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.
BBEP-IR
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 2009 2008 2009 2008
unit amounts
Revenues and
other income
items:
Oil, natural gas
and natural gas $ 62,674 $ 130,249 $ 180,189 $ 386,060
liquid sales
Gains (losses)
on commodity 12,719 407,441 (14,520 ) (29,228 )
derivative
instruments, net
Other revenue, 261 806 930 2,324
net
Total revenues
and other income 75,654 538,496 166,599 359,156
items
Operating costs
and expenses:
Operating costs 33,888 41,915 100,273 118,952
Depletion,
depreciation and 24,130 21,477 81,393 64,228
amortization
General and
administrative 9,318 6,479 27,265 24,073
expenses
Loss on sale of 5,470 - 5,470 -
assets
Total operating
costs and 72,806 69,871 214,401 207,253
expenses
Operating income 2,848 468,625 (47,802 ) 151,903
(loss)
Interest and
other financing 4,549 9,021 14,682 19,569
costs, net
Losses on
interest rate 3,792 2,964 5,557 3,937
swaps
Other income, (84 ) (464 ) (124 ) (114 )
net
Total other 8,257 11,521 20,115 23,392
expense
Gain (loss) (5,409 ) 457,104 (67,917 ) 128,511
before taxes
Income tax
expense (13 ) 2,599 (354 ) 1,262
(benefit)
Net income (5,396 ) 454,505 (67,563 ) 127,249
(loss)
Less: Net income
attributable to (12 ) (51 ) (14 ) (175 )
noncontrolling
interest
Net income
(loss) (5,408 ) 454,454 (67,577 ) 127,074
attributable to
the partnership
General partner - - - (2,019 )
loss
Net income
(loss) $ (5,408 ) $ 454,454 $ (67,577 ) $ 129,093
attributable to
limited partners
Basic net income $ (0.10 ) $ 8.43 $ (1.28 ) $ 2.06
(loss) per unit
Diluted net
income (loss) $ (0.10 ) $ 8.40 $ (1.28 ) $ 2.06
per unit
Weighted average
number of units
used to
calculate
Basic net income 52,770,011 53,922,984 52,747,861 62,604,519
(loss) per unit
Diluted net
income (loss) 52,770,011 54,071,521 52,747,861 62,752,289
per unit
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Balance Sheets
September 30, December 31,
Thousands of dollars, except unit amounts 2009 2008
ASSETS
Current assets:
Cash $ 2,199 $ 2,546
Accounts receivable, net 38,198 47,221
Derivative instruments 63,249 76,224
Related party receivables 4,744 5,084
Inventory 4,960 1,250
Prepaid expenses 6,880 5,300
Intangibles 807 2,771
Other current assets 170 170
Total current assets 121,207 140,566
Equity investments 8,686 9,452
Property, plant and equipment
Oil and gas properties 2,046,860 2,057,531
Non-oil and gas assets 8,145 7,806
2,055,005 2,065,337
Accumulated depletion and depreciation (300,831 ) (224,996 )
Net property, plant and equipment 1,754,174 1,840,341
Other long-term assets
Intangibles 125 495
Derivative instruments 97,500 219,003
Other long-term assets 8,362 6,977
Total assets $ 1,990,054 $ 2,216,834
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 18,246 $ 28,302
Book overdraft 160 9,871
Derivative instruments 14,770 10,192
Revenue distributions payable 10,727 16,162
Salaries and wages payable 6,111 6,249
Accrued liabilities 14,559 9,214
Total current liabilities 64,573 79,990
Long-term debt 585,000 736,000
Deferred income taxes 3,385 4,282
Asset retirement obligation 35,692 30,086
Derivative instruments 31,322 10,058
Other long-term liabilities 2,120 2,987
Total liabilities 722,092 863,403
Equity:
Partners' equity 1,267,528 1,352,892
Noncontrolling interest 434 539
Total equity 1,267,962 1,353,431
Total liabilities and equity $ 1,990,054 $ 2,216,834
Common units outstanding 52,770,011 52,635,634
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows
Nine Months Ended
September 30,
Thousands of dollars 2009 2008
Cash flows from operating activities
Net income (loss) $ (67,563 ) $ 127,249
Adjustments to reconcile to cash flow from operating
activities:
Depletion, depreciation and amortization 81,393 64,228
Unit based compensation expense 9,736 5,192
Unrealized gain (loss) on derivative instruments 160,319 (39,398 )
Distributions greater than income from equity 766 772
affiliates
Deferred income tax (897 ) 625
Amortization of intangibles 2,334 2,339
Loss on sale of assets 5,470 -
Other 2,472 1,803
Changes in net assets and liabilities:
Accounts receivable and other assets 3,590 1,463
Inventory (3,710 ) (2,292 )
Net change in related party receivables and payables 340 27,614
Accounts payable and other liabilities (10,279 ) 1,366
Net cash provided by operating activities 183,971 190,961
Cash flows from investing activities
Capital expenditures (18,603 ) (86,811 )
Proceeds from sale of assets 23,034 -
Property acquisitions - (9,988 )
Net cash provided (used) by investing activities 4,431 (96,799 )
Cash flows from financing activities
Purchase of common units - (336,216 )
Distributions (28,038 ) (93,304 )
Proceeds from the issuance of long-term debt 218,475 659,093
Repayments of long-term debt (369,475 ) (321,493 )
Book overdraft (9,711 ) 7,603
Long-term debt issuance costs - (4,974 )
Net cash used by financing activities (188,749 ) (89,291 )
Increase (decrease) in cash (347 ) 4,871
Cash beginning of period 2,546 5,929
Cash end of period $ 2,199 $ 10,800
Source: BreitBurn Energy Partners L.P.
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