BreitBurn Energy Partners L.P. (the “Partnership”) (NASDAQ:BBEP) today
announced financial and operating results for its fourth quarter and
full year 2009 and public guidance for its expected performance in 2010.
Key Highlights
The Partnership had an outstanding year operationally which
contributed to full-year 2009 results that were in-line with or
exceeded guidance. Full year 2009 production levels surpassed
expectations and totaled approximately 6.52 MMBoe.

The Partnership continued to pursue strong debt reduction efforts into
the fourth quarter and achieved its debt reduction goals for the year.
As of December 31, 2009, outstanding debt totaled $559 million,
representing $177 million in debt reduction during the year.

The Partnership’s total estimated proved reserves at year end 2009
were 111.3 MMBoe, up 7.4% from year end 2008 reserves of 103.6 MMBoe.

In early February 2010, the Partnership settled all pending litigation
with Quicksilver Resources, Inc.

In conjunction with the Quicksilver settlement, the Partnership
announced its intention to reinstate distributions at an annualized
rate of $1.50 per unit, or 37.5 cents per unit quarterly, for the
first quarter of 2010, to be paid on or before May 15, 2010.
Management Commentary
Hal Washburn, Chairman and Co-CEO, said, “Our fourth quarter and full
year 2009 results demonstrate the Partnership’s ability to deliver
results despite considerable challenges throughout the year. Our primary
goal in 2009 was to reduce our outstanding borrowings. In addition, we
focused on controlling expenses and operating successfully with a
significantly reduced capital spending program. Our dedication to these
goals has been tremendous, and we are very pleased that our full year
results met or exceeded our expectations. With our improved financial
flexibility, the recent resolution of the Quicksilver litigation, and
the reinstatement of distributions announced last month, we can focus on
cash flow generation from our portfolio of long-lived assets,
maintaining and possibly growing production slightly through the drill
bit, and executing on our growth-through-acquisition strategy.”
Fourth Quarter 2009 Operating and
Financial Results Compared to Third Quarter 2009
Total production increased slightly to 1,632 MBoe in the fourth
quarter from 1,628 MBoe in the third quarter.

Oil and NGL production was 744 MBoe compared to 743 MBoe.

Natural gas production was 5,335 MMcf compared to 5,308 MMcf.

Lease operating expenses per Boe, which include district expenses and
processing fees and exclude production/property taxes and
transportation costs, increased 10% to $19.31 per Boe in the fourth
quarter from $17.53 per Boe in the third quarter primarily as a result
of increased services and materials costs related to higher commodity
prices and increased well work activity.

General and administrative expenses, excluding unit-based
compensation, were $6.2 million, or $3.79 per Boe, in the fourth
quarter compared to $5.8 million, or $3.59 per Boe, in the third
quarter.

Adjusted EBITDA, a non-GAAP measure, was $49.0 million in the fourth
quarter, up from $48.4 million in the third quarter.

Oil and natural gas sales revenues, including realized gains and
losses on commodity derivative instruments, increased 6% to $92.5
million in the fourth quarter from $87.0 million in the third quarter.

Realized gains from commodity derivative instruments were $17.8
million in the fourth quarter as compared to $24.3 million in the
third quarter.

NYMEX WTI crude oil averaged approximately $76 per barrel and NYMEX
natural gas prices averaged approximately $4.93 per Mcf in the fourth
quarter as compared to approximately $68 per barrel and $3.44 per Mcf,
respectively, in the third quarter.

Realized crude oil and natural gas prices increased and averaged
$69.72 per Boe and $7.55 per Mcf, respectively, in the fourth quarter
as compared to $67.40 per Boe and $7.30 per Mcf, respectively, in the
third quarter.

Net loss, including the effect of unrealized losses on commodity
derivative instruments, was $39.7 million, or $0.75 per diluted
limited partner unit, in the fourth quarter as compared to a net loss
of $5.4 million, or $0.10 per diluted limited partner unit, in the
third quarter.

Oil and gas capital expenditures totaled $10.9 million in the fourth
quarter as compared to $7.3 million in the third quarter.
Full Year 2009 Results
Total production was above the high end of our guidance range at 6,517
MBoe in 2009, a decrease of 4% from 2008.

Oil and gas capital expenditures were $28.7 million, a 78% decrease
from 2008.

Full year lease operating expenses per Boe were $17.90, which was
within our guidance range of $16.25 – $18.50 per Boe.

Full year general and administrative expenses, excluding unit-based
compensation, were $23.7 million, which was within our guidance range
of $23 million – $25 million.

Adjusted EBITDA, a non-GAAP measure, was at the high end of our
guidance range at $195.0 million.

As a result of our extensive hedging portfolio, average realized crude
oil and natural gas prices for 2009 were $66.27 per Boe and $7.48 per
Mcf, compared to NYMEX WTI crude oil and NYMEX natural gas average
prices of approximately $62 per barrel and $4.16 per Mcf.
2009 Reserves
In 2009, the Partnership increased reserves by 7.7 MMBoe, which was
primarily the result of:

9.8 MMBoe of reserve increases due to economic factors

7.0 MMBoe of reserve increases due to drilling, recompletions and
workovers

1.5 MMBoe of reserve decreases due to technical revisions

1.1 MMBoe of reserve decreases due to the sale of the Lazy JL Field

6.5 MMBoe of reserve decreases due to 2009 production

BreitBurn’s total estimated proved oil and gas reserves as of December
31, 2009, were 111.3 MMBoe. The Standardized Measure of discounted (at
10%) net future cash flows from the production of these reserves is
approximately $760 million using prices and costs in effect as of the
dates such estimates were made and which are held constant throughout
the life of the properties. Estimated proved reserves were determined
using $3.87 per MMBtu for gas and $61.18 per Bbl of oil for Michigan and
California and $51.29 per Bbl of oil for Wyoming. Of the total estimated
proved reserves, 65% were natural gas and 35% were crude oil, 91% were
classified as proved developed and 68% were located in Michigan, 14% in
California, 10% in Wyoming, and 7% in Florida, with the remaining 1% in
Indiana and Kentucky.
2010 Guidance
The following guidance is subject to all 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 and gas will continue at levels
that allow for economic production of these products. The production,
transportation and marketing of oil and gas are extremely complex and
are subject to disruption due to transportation and processing
availability, mechanical failure, human error, weather, and numerous
other factors. 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 expectation 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)

 
2010 Guidance
Total Production (Mboe)

 

6,300

 

-

 

6,700

Production Mix:

Oil Production %

47%

Gas Production %

53%

Average Price Differential %:

Oil Price Differential %

87%

-

89%

Gas Price Differential %

100%

-

102%

Operating Costs / BOE(1)(2)

$19.35

-

$21.85

Production/Property Taxes (% of oil & gas revenue)

7.0%

-

7.5%

G&A (Excl. Unit Based Compensation)

$25,000

-

$27,000

Cash Interest Expense(3)

$30,000

-

$32,000

Total Capital Expenditures(4)

$72,000

-

$78,000

Adjusted EBITDA(5)

$190,000

-

$200,000

Operating Costs include lease operating costs, processing fees and
transportation expense. Expected transportation expense totals
approximately $6.7 million in 2010, largely attributable to our
Florida production. Excluding transportation expense, our estimated
operating costs range per Boe is approximately $18.32 – $20.82.

Operating Costs are based on flat $70 per barrel WTI crude oil and $5
per Mcfe natural gas price levels for 2010. Operating costs generally
move with commodity prices but do not typically increase or decrease
as rapidly as commodity prices.

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 2% and includes the impact of interest rate swaps
covering approximately $400 million of borrowings at a weighted
average swap rate of 3.17%. Our resulting estimated 2010 weighted
average LIBOR rate is 2.84%.

Total Capital Expenditures for 2010 include Maintenance and Obligatory
Capital Expenditures as well as Growth Capital Expenditures.
Maintenance and Obligatory Capital Expenditures are 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. Management estimates
that we would need to spend between $40 and $50 million in 2010 to
hold production flat.

Assuming the high and low range of our guidance, Adjusted EBITDA is
expected to range between $190 million and $200 million, and is
comprised of estimated net income between $154 million and $166
million, less unrealized gain on commodity derivative instruments of
$86 million, plus DD&A of $90 million, plus interest expense between
$30 million (high end of Adjusted EBITDA) and $32 million (low end of
Adjusted EBITDA). Estimated 2010 net income is based on oil prices of
$70 per barrel for WTI crude oil and $5 per Mcfe for natural gas.
Consequently, differences between actual and forecasted prices could
result in changes to unrealized gains or losses on commodity
derivative instruments, DD&A, including potential impairments of
long-lived assets, and ultimately, net income.
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 $17.8 million
during the fourth quarter of 2009. Realized losses from interest rate
derivative instruments were $3.4 million. Non-cash unrealized losses
from commodity derivative instruments were $54.7 million and non-cash
unrealized gains from interest rate derivative instruments were $1.8
million for the period.
Production, Income Statement and
Realized Price Information
The following table presents production, selected income statement and
realized price information for the three months ended December 31, 2009,
September 30, 2009 and December 31, 2008 and the years ended December
31, 2009 and 2008:

 
Three-Months Ended
 
Year Ended December 31,Thousands of dollars, except as indicated
December 31,2009
 
September 30,2009
 
December 31,2008
2009
 
2008
Oil, natural gas and NGL sales(a)

$

74,728

 

$

62,674

 

$

81,321

$

254,917

 

$

467,381

Realized gains (losses) on commodity derivative instruments(b)

17,771

24,356

14,949

167,683

(55,946

)

Unrealized gains (losses) on commodity derivative instruments(b)

(54,688

)

(11,637

)

346,381

(219,120

)

388,048

Other revenues, net

 

452

 

 

 

261

 

 

 

596

 

1,382

 

 

 

2,920

 

Total revenues

$

38,263

 

 

$

75,654

 

 

$

443,247

$

204,862

 

 

$

802,403

 

Lease operating expenses and processing fees

$

31,685

$

29,052

$

29,509

$

118,405

$

122,915

Production and property taxes

 

6,118

 

 

 

4,422

 

 

 

6,934

 

19,433

 

 

 

31,311

 

Total lease operating expenses

$

37,803

 

 

$

33,474

 

 

$

36,443

$

137,838

 

 

$

154,226

 

Transportation expenses

926

799

1,125

3,825

4,206

Purchases

14

18

47

72

343

Change in inventory

(518

)

(403

)

5,338

(3,337

)

3,130

Uninsured loss

 

-

 

 

 

-

 

 

 

100

 

100

 

 

 

100

 

Total operating costs

$

38,225

 

 

$

33,888

 

 

$

43,053

$

138,498

 

 

$

162,005

 

Lease operating expenses pre taxes per Boe(c)

$

19.31

$

17.53

$

17.16

$

17.90

$

17.75

Production and property taxes per Boe

3.75

2.72

4.11

2.98

4.60

Total lease operating expenses per Boe

 

23.06

 

 

 

20.25

 

 

 

21.27

 

20.88

 

 

 

22.35

 

General and administrative expenses excluding unit-based compensation

 

$

6,184

 

 

$

5,844

 

 

$

5,372

$

23,704

 

 

$

24,641

 

Net income (loss)

$

(39,693

)

$

(5,396

)

$

251,175

$

(107,257

)

$

378,424

Net income (loss) per diluted limited partnership unit

 

$

(0.75

)

 

$

(0.10

)

 

$

4.65

$

(2.03

)

 

$

6.28

 

 

Total production (MBoe)

1,632

1,628

1,689

6,517

6,809

Oil and NGL (MBoe)

744

743

767

2,990

3,078

Natural gas (MMcf)

5,335

5,308

5,530

21,161

22,384

Average daily production (Boe/d)

 

17,740

 

 

 

17,697

 

 

 

18,359

 

17,856

 

 

 

18,605

 

Sales volumes (MBoe)

 

1,642

 

 

 

1,605

 

 

 

1,759

 

6,465

 

 

 

6,857

 

Average realized sales price (per Boe)(d)(e)(f)

$

56.48

$

54.37

$

54.86

$

54.60

$

60.11

Oil and NGL (per Boe)(d)(e)(f)

69.72

67.40

62.13

66.27

72.86

Natural gas (per Mcf)(d)(e)

 

7.55

 

 

 

7.30

 

 

 

8.04

 

7.48

 

 

 

8.24

 

(a)

 

Q4 2009, Q3 2009, Q4 2008, Full Year 2009 and Full Year 2008
include $268, $258, $274, $1,039 and $1,055, respectively, of
amortization of an intangible asset related to crude oil sales
contracts.

(b)

2009 includes the effects of the early terminations of hedge
contracts monetized in January for $45,632 and in June 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)

2009 excludes the effects of the early terminations of hedge
contracts monetized in January ($32,317 of oil hedges and $13,315
of natural gas hedges) and June ($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

 

Twelve Months Ended

December 31,

December 31,
Thousands of dollars

2009

 

2008

2009

 

2008

Reconciliation of consolidated net income (loss) to Adjusted EBITDA:

 

Net income (loss) attributable to the partnership

($39,712

)

 

$

251,162

($107,290

)

$

378,236

 

Unrealized (gain) loss on commodity derivative instruments

54,688

(346,381

)

219,120

(388,048

)

Depletion, depreciation and amortization expense

25,450

115,705

106,843

179,933

Write-down of crude oil inventory

-

1,172

-

1,172

Interest expense and other financing costs(a)

7,590

10,631

31,942

31,868

Unrealized (gain) loss on interest rate derivatives

(1,757

)

15,046

(5,869

)

17,314

Gain on sale of commodity derivatives(b)

-

-

(70,587

)

-

Loss on sale of asset(c)

495

-

5,965

-

Income tax provision

(1,174

)

677

(1,528

)

1,939

Amortization of intangibles

437

792

2,771

3,131

Unit-based compensation expense(d)

 

2,933

 

 

 

2,091

 

 

13,619

 

 

 

7,481

 

Adjusted EBITDA

$

48,950

 

 

$

50,895

 

$

194,986

 

 

$

233,026

 

 

Three Months Ended

Twelve Months Ended

December 31,

December 31,
Thousands of dollars

2009

 

2008

2009

 

2008

Reconciliation of net cash from operating activities to Adjusted
EBITDA:

Net cash from operating activities

$

40,387

$

35,735

$

224,358

$

226,696

 

Increase (decrease) in assets net of liabilities relating to
operating activities

2,584

3,556

12,466

(30,942

)

Interest expense(a)(e)

6,766

9,794

28,647

29,255

Gain on sale of commodity derivatives(b)

-

-

(70,587

)

-

Write-down of crude oil inventory

-

1,172

-

1,172

Equity earnings from affiliates, net

(536

)

(426

)

(1,302

)

(1,198

)

Incentive compensation expense(f)

8

376

958

574

Incentive compensation paid

41

606

217

6,952

Income taxes

(281

)

95

262

732

Non-controlling interest

(19

)

(13

)

(33

)

(188

)

Other

 

-

 

 

 

-

 

 

-

 

 

 

(27

)

Adjusted EBITDA

$

48,950

 

 

$

50,895

 

$

194,986

 

 

$

233,026

 

(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 March 11, 2010:

 
Year
 

 
Year
 

 
Year
 

 
Year
 

 
Year

2010

2011

2012

2013

2014Gas Positions:

Fixed Price Swaps:

Hedged Volume (MMBtu/d)

43,869

25,955

19,129

27,000

-

Average Price ($/MMBtu)

$

8.20

$

7.26

$

7.10

$

6.92

$

-

Collars:

Hedged Volume (MMBtu/d)

3,405

16,016

19,129

-

-

Average Floor Price ($/MMBtu)

$

9.00

$

9.00

$

9.00

$

-

$

-

Average Ceiling Price ($/MMBtu)

$

12.79

$

11.28

$

11.89

$

-

$

-

Total:

Hedged Volume (MMBtu/d)

47,275

41,971

38,257

27,000

-

Average Price ($/MMBtu)

$

8.26

$

7.92

$

8.05

$

6.92

$

-

 
Oil Positions:

Fixed Price Swaps:

Hedged Volume (Bbls/d)

2,808

3,616

3,539

5,000

748

Average Price ($/Bbl)

$

81.35

$

71.56

$

72.30

$

79.32

$

88.65

Participating Swaps:(a)

Hedged Volume (Bbls/d)

1,993

1,439

-

-

-

Average Price ($/Bbl)

$

64.40

$

61.29

$

-

$

-

$

-

Average Part. %

55.5

%

53.2

%

-

-

-

Collars:

Hedged Volume (Bbls/d)

1,279

2,048

2,477

500

-

Average Floor Price ($/Bbl)

$

102.85

$

103.42

$

110.00

$

77.00

$

-

Average Ceiling Price ($/Bbl)

$

136.16

$

152.61

$

145.39

$

103.10

$

-

Floors:

Hedged Volume (Bbls/d)

500

-

-

-

-

Average Floor Price ($/Bbl)

$

100.00

$

-

$

-

$

-

$

-

Total:

Hedged Volume (Bbls/d)

6,580

7,103

6,016

5,500

748

Average Price ($/Bbl)

$

81.81

$

78.67

$

87.82

$

79.11

$

88.65

(a) A participating swap combines a swap and a call option with the same
strike price.
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 888-287-5530 (international callers
dial +1-719-457-2081) 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 18, 2010 by dialing
888-203-1112 (international callers dial +1-719-457-0820) and entering
replay PIN 9644200, 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. The
Partnership’s 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 Regarding
Forward-Looking Information
This press release contains forward-looking statements relating to
BreitBurn’s operations that are based on management’s current
expectations, estimates and projections about its operations. Words and
phrases such as “believes,” “future,” “impact,” “guidance,” “expect,”
“estimate,” “will,” “could,” “may be used,” “continue” 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, 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 SubsidiariesConsolidated Statements of Operations
 

 
Three Months Ended
 
Year Ended

December 31,
December 31,Thousands of dollars, except per unit amounts
 
2009
 
2008
2009
 
2008

 
Revenues and other income items:

Oil, natural gas and natural gas liquid sales

$

74,728

$

81,321

$

254,917

$

467,381

Gains (losses) on commodity derivative instruments, net

(36,917

)

361,330

(51,437

)

332,102

Other revenue, net

 

452

 

 

596

 

 

1,382

 

 

2,920

 

Total revenues and other income items

38,263

443,247

204,862

802,403

Operating costs and expenses:

Operating costs

38,225

43,053

138,498

162,005

Depletion, depreciation and amortization

25,450

115,705

106,843

179,933

General and administrative expenses

9,102

6,998

36,367

31,111

Loss on sale of assets

 

495

 

 

-

 

 

5,965

 

 

-

 

Total operating costs and expenses

 

73,272

 

 

165,756

 

 

287,673

 

 

373,049

 

 
Operating income (loss)

(35,009

)

277,491

(82,811

)

429,354

 
Interest and other financing costs, net

4,145

9,578

18,827

29,147

Loss on interest rate swaps

1,688

16,098

7,246

20,035

Other (income) expenses, net

 

25

 

 

(37

)

 

(99

)

 

(191

)

 
Income (loss) before taxes

(40,867

)

251,852

(108,785

)

380,363

 
Income tax expense (benefit)

 

(1,174

)

 

677

 

 

(1,528

)

 

1,939

 

 
Net income (loss)

(39,693

)

251,175

(107,257

)

378,424

 

Less: Net income attributable to noncontrolling interest

 

(19

)

 

(13

)

 

(33

)

 

(188

)

 
Net income (loss) attributable to the partnership

(39,712

)

251,162

(107,290

)

378,236

General Partner’s interest in net loss

 

-

 

 

-

 

 

-

 

 

(2,019

)
Net income (loss) attributable to limited partners

$

(39,712

)

$

251,162

 

$

(107,290

)

$

380,255

 

 

Basic net income (loss) per unit

$

(0.75

)

$

4.66

 

$

(2.03

)

$

6.29

 

Diluted net income (loss) per unit

$

(0.75

)

$

4.65

 

$

(2.03

)

$

6.28

 

 
BreitBurn Energy Partners L.P. and SubsidiariesConsolidated Balance Sheets
 

 
December 31,
 
December 31,Thousands
2009
2008ASSETS

Current assets:

Cash

$

5,766

$

2,546

Accounts receivable, net

65,209

47,221

Derivative instruments

57,133

76,224

Related party receivables

2,127

5,084

Inventory

5,823

1,250

Prepaid expenses

5,888

5,300

Intangibles

495

2,771

Other current assets

 

-

 

 

170

 

Total current assets

142,441

140,566

Equity investments

8,150

9,452

Property, plant and equipment

Oil and gas properties

2,058,968

2,057,531

Non-oil and gas assets

 

7,717

 

 

7,806

 

2,066,685

2,065,337

Accumulated depletion and depreciation

 

(325,596

)

 

(224,996

)

Net property, plant and equipment

1,741,089

1,840,341

Other long-term assets

Intangibles

-

495

Derivative instruments

74,759

219,003

Other long-term assets

 

4,590

 

 

6,977

 
Total assets

$

1,971,029

 

$

2,216,834

 
LIABILITIES AND PARTNERS’ EQUITY

Current liabilities:

Accounts payable

$

21,314

$

28,302

Book overdraft

-

9,871

Derivative instruments

20,057

10,192

Related party payables

13,000

-

Revenue and royalties payable

18,224

20,084

Salaries and wages payable

10,244

6,249

Accrued liabilities

 

9,051

 

 

5,292

 

Total current liabilities

91,890

79,990

 

Long-term debt

559,000

736,000

Deferred income taxes

2,492

4,282

Asset retirement obligation

36,635

30,086

Derivative instruments

50,109

10,058

Other long-term liabilities

 

2,102

 

 

2,987

 

Total liabilities

742,228

863,403

Equity:

Partners’ equity

1,228,373

1,352,892

Noncontrolling interest

 

428

 

 

539

 

Total equity

1,228,801

1,353,431

 
Total liabilities and equity

$

1,971,029

 

$

2,216,834

 

 

Limited partner units outstanding

52,784

52,636

 
BreitBurn Energy Partners L.P. and SubsidiariesConsolidated Statements of Cash Flows
 

 
Year Ended December 31,Thousands of dollars
2009
 
2008

 
Cash flows from operating activities

Net income (loss)

$

(107,257

)

$

378,424

Adjustments to reconcile net income (loss) to cash flow from
operating activities:

Depletion, depreciation and amortization

106,843

179,933

Unit-based compensation expense

12,661

6,907

Unrealized (gain) loss on derivative instruments

213,251

(370,734

)

Distributions greater than income from equity affiliates

1,302

1,198

Deferred income tax

(1,790

)

1,207

Amortization of intangibles

2,771

3,131

Loss on sale of assets

5,965

-

Other

3,294

2,643

Changes in net assets and liabilities:

Accounts receivable and other assets

(6,313

)

258

Inventory

(4,573

)

4,454

Net change in related party receivables and payables

2,957

32,688

Accounts payable and other liabilities

 

(4,753

)

 

(13,413

)

Net cash provided by operating activities

 

224,358

 

 

226,696

 
Cash flows from investing activities

Capital expenditures

(29,513

)

(131,082

)

Proceeds from sale of assets, net

23,284

-

Property acquisitions

 

-

 

 

(9,957

)

Net cash used by investing activities

 

(6,229

)

 

(141,039

)
Cash flows from financing activities

Purchase of common units

-

(336,216

)

Distributions

(28,038

)

(121,349

)

Proceeds from the issuance of long-term debt

249,975

803,002

Repayments of long-term debt

(426,975

)

(437,402

)

Book overdraft

(9,871

)

7,951

Long-term debt issuance costs

 

-

 

 

(5,026

)

Net cash used by financing activities

 

(214,909

)

 

(89,040

)
Increase (decrease) in cash

3,220

(3,383

)
Cash beginning of period

 

2,546

 

 

5,929

 
Cash end of period

$

5,766

 

$

2,546