14:30 | 09.03.2011
BreitBurn Energy Partners L.P. Reports Fourth Quarter and Full Year Results and Year End Reserves; Provides Full Year 2011 Guidance
BreitBurn Energy Partners L.P. (the “Partnership”) (NASDAQ:BBEP) today
announced financial and operating results for its fourth quarter and
full year 2010 and public guidance for its expected performance in 2011.
Key Highlights
The Partnership had an excellent year both operationally and
financially, with full-year 2010 results in-line with or exceeding
guidance.
Full-year production was at the high-end of the guidance range and
totaled 6.7MMBoe.
Full-year adjusted EBITDA, a non-GAAP measure, was well above the
guidance range at $227 million.
Lease operating costs for 2010 were below the guidance range.
General and administrative costs for the year were also below the
2010 guidance range.
In October 2010, the Partnership completed a private offering of $305
million in aggregate principal amount of 8.625% Senior Notes due 2020.
The Partnership received net proceeds of approximately $291 million,
which were primarily used to reduce borrowings under its bank credit
facility.
In February 2011, the Partnership completed a public offering of
4,945,000 common units at $21.25 per unit representing additional
limited partner interests. The Partnership received net proceeds of
approximately $100 million, which were used to further reduce
borrowings under its bank credit facility. As of February 28, 2010,
the Partnership had $122 million outstanding under the facility.
On February 11, 2011, the Partnership paid cash distributions for the
fourth quarter of 2010 at an annualized rate of $1.65 per unit, up
from an annualized rate $1.56 per unit for the third quarter of 2010.
The Partnership continues to opportunistically layer in new hedges and
has extended its price protection portfolio in 2015 at attractive
prices.
Management Commentary
Hal Washburn, CEO, said: “2010 was a very productive year for the
Partnership – we ended the year with a strong fourth quarter as well as
full-year 2010 results that exceeded expectations. Our operations teams
performed exceptionally, delivering production results at the high-end
of our guidance range while aggressively controlling operating costs.
With our inaugural Senior Notes offering launched in September and the
equity offering we closed earlier this year, we’ve increased our
financial flexibility considerably. Since announcing first quarter 2010
distributions of $1.50 per unit on an annualized basis in April 2010, we
have steadily grown distributions over three consecutive quarters by 10%
to the most recent annualized rate of $1.65 per unit which was paid in
February. With our increased liquidity and our strong hedge portfolio,
we are well-positioned in 2011 and will continue to focus on efficiently
managing our existing assets, executing our capital program, generating
cash flows, and pursuing acquisition opportunities.”
Fourth Quarter 2010 Operating and Financial
Results Compared to Third Quarter 2010
Total production decreased slightly from 1,741 MBoe in the third
quarter of 2010 to 1,700 MBoe in the fourth quarter of 2010. Average
daily production decreased from 18,927 Boe/day in the third quarter of
2010 to 18,480 Boe/day in the fourth quarter of 2010.
Oil and NGL production was 791 MBoe compared to 827 MBoe.
Natural gas production was 5,452 MMcf compared to 5,486 MMcf.
Lease operating expenses per Boe, which include district expenses and
processing fees and exclude production/property taxes and
transportation costs, increased to $17.37 per Boe in the fourth
quarter of 2010 from $16.54 per Boe in the third quarter of 2010.
General and administrative expenses, excluding non-cash unit-based
compensation, were $5.9 million, or $3.47 per Boe, in the fourth
quarter of 2010 compared to $7.2 million, or $4.13 per Boe, in the
third quarter of 2010.
Adjusted EBITDA, a non-GAAP measure, was $59.1 million in the fourth
quarter, down from $60.0 million in the third quarter of 2010.
Oil and natural gas sales revenues, including realized gains and
losses on commodity derivative instruments, were $99.8 million in the
fourth quarter of 2010, up slightly from $99.6 million in the third
quarter of 2010.
Realized gains from commodity derivative instruments were $21.7
million in the fourth quarter of 2010 compared to $22.6 million in the
third quarter of 2010.
NYMEX WTI crude oil spot prices averaged $85.16 per barrel and NYMEX
natural gas prices averaged $3.98 per Mcf in the fourth quarter of
2010 compared to $76.06 per barrel and $4.24 per Mcf, respectively, in
the third quarter of 2010.
Realized crude oil and natural gas prices averaged $78.95 per Boe and
$7.38 per Mcf, respectively, in the fourth quarter of 2010 compared to
$76.14 per Boe and $7.55 per Mcf, respectively, in the third quarter
of 2010.
Net loss, including the effect of unrealized gains on commodity
derivative instruments, was $70.9 million, or $1.25 per diluted
limited partner unit, in the fourth quarter of 2010 compared to a net
loss of $5.7 million, or $0.11 per diluted limited partner unit, in
the third quarter of 2010.
Capital expenditures totaled $16.8 million in the fourth quarter of
2010 compared to $25.6 million in the third quarter of 2010.
Full Year 2010 Results
Total production was at the high end of our guidance range at 6,699
MBoe in 2010, an increase of 3% from 2009.
Oil and gas capital expenditures were $69.5 million, an increase of
142% from 2009.
Full year lease operating expenses per Boe were $17.68, which was
below the low end of our guidance range of $18.32 – $20.82 per Boe and
1% below 2009 operating expenses per Boe.
Full year general and administrative expenses, excluding unit-based
compensation, were $24.5 million, which was below the low end of the
guidance range of $25.0 – $27.0 million.
Adjusted EBITDA, a non-GAAP measure, was above the high end of our
guidance range at $226.9 million.
Average realized crude oil and natural gas prices for 2010 were $74.31
per Boe and $7.57 per Mcf, compared to NYMEX WTI crude oil and NYMEX
natural gas average prices of $79.48 per barrel and $4.38 per Mcf.
2010 Estimated Proved Reserves Increase to
118.9 MMBoe
BreitBurn’s total estimated proved oil and gas reserves as of December
31, 2010, were 118.9 MMBoe. The Standardized Measure of discounted (at
10%) future net cash flows from the production of these reserves is
approximately $1,065 million using prices and costs in effect as of the
dates such estimates were made that are held constant throughout the
life of the properties. Estimated proved reserves were determined using
$4.38 per MMBtu for gas and $79.40 per Bbl of oil for Michigan and
California and $65.36 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, 12% in
California, 10% in Wyoming, and 8% in Florida, with the remaining 2% in
Indiana and Kentucky.
Estimates of our proved reserves were prepared by Netherland, Sewell &
Associates, Inc. and Schlumberger Data & Consulting Services,
independent petroleum engineering firms. Netherland, Sewell &
Associates, Inc. prepared reserve data for our California, Wyoming and
Florida properties, and Schlumberger Data & Consulting Services prepared
reserve data for our Michigan, Kentucky and Indiana properties.
2011 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)
2011 Guidance
Total Production (Mboe)
6,500
-
6,900
Production Mix:
Oil Production %
48%
Gas Production %
52%
Average Price Differential %:
Oil Price Differential %
89
%
-
91
%
Gas Price Differential %
100
%
-
102
%
Operating Costs / BOE(1)(2)
$18.50
-
$21.00
Production/Property Taxes (% of oil & gas revenue)
7.5
%
-
8.0
%
G&A (Excl. Unit Based Compensation)
$26,000
-
$28,000
Cash Interest Expense(3)
$36,000
-
$38,000
Total Capital Expenditures(4)
$70,000
-
$74,000
Adjusted EBITDA(5)
$195,000
-
$205,000
Operating Costs include lease operating costs, processing fees
and transportation expense. Expected transportation expense
totals approximately $6.7 million in 2011, largely attributable
to our Florida production. Excluding transportation expense, our
estimated operating costs range per Boe is approximately $17.50
– $20.00.
Operating Costs are based on flat $80 per barrel WTI crude oil
and $4.25 per Mcfe natural gas price levels for 2011. 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 1% and includes the impact of interest
rate swaps covering approximately $175 million of borrowings at
a weighted average swap rate of 2.23%.
Total Capital Expenditures for 2011 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 2011 to hold production flat.
Assuming the high and low range of our guidance, Adjusted EBITDA
is expected to range between $195 million and $205 million, and
is comprised of estimated net income between $120 million and
$132 million, less unrealized gain on commodity derivative
instruments of $63 million, plus DD&A of $100 million, plus
interest expense between $36 million (high end of Adjusted
EBITDA) and $38 million (low end of Adjusted EBITDA). Estimated
2011 net income is based on oil prices of $80 per barrel for WTI
crude oil and $4.25 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 $21.7 million
during the fourth quarter of 2010. Realized losses from interest rate
derivative instruments were $2.3 million during the fourth quarter of
2010. Non-cash unrealized losses from commodity derivative instruments
were $82.3 million and non-cash unrealized gains from interest rate
derivative instruments were $3.1 million during the fourth quarter of
2010.
Realized gains from commodity derivative instruments were $74.8 million
for the year ended December 31, 2010. Realized losses from interest rate
derivative instruments were $11.1 million for the year ended December
31, 2010. Non-cash unrealized losses from commodity derivative
instruments were $39.7 million and non-cash unrealized gains from
interest rate derivative instruments were $6.6 million for year ended
December 31, 2010.
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, 2010
and 2009, the three months ended September 30, 2010 and the years ended
December 31, 2010 and 2009:
Three Months Ended
Year Ended December 31,
December 31,
September 30,
December 31,
Thousands of dollars, except as indicated
2010
2010
2009
2010
2009
Oil, natural gas and NGL sales (a)
$
78,135
$
77,055
$
74,728
$
317,738
$
254,917
Realized gain on commodity derivative instruments (b)
21,677
22,567
17,771
74,825
167,683
Unrealized loss on commodity derivative instruments (b)
(82,307
)
(30,540
)
(54,688
)
(39,713
)
(219,120
)
Other revenues, net
660
719
452
2,498
1,382
Total revenues
$
18,165
$
69,801
$
38,263
$
355,348
$
204,862
Lease operating expenses and processing fees
$
29,536
$
28,800
$
31,685
$
118,454
$
118,405
Production and property taxes
5,626
5,081
6,118
20,510
19,433
Total lease operating expenses
$
35,162
$
33,881
$
37,803
$
138,964
$
137,838
Transportation expenses
943
1,037
926
4,058
3,825
Purchases
112
90
14
328
72
Change in inventory
(2,121
)
(1,801
)
(518
)
(825
)
(3,337
)
Uninsured loss
-
-
-
-
100
Total operating costs
$
34,096
$
33,207
$
38,225
$
142,525
$
138,498
Lease operating expenses pre taxes per Boe (c)
$
17.37
$
16.54
$
19.31
$
17.68
$
17.90
Production and property taxes per Boe
3.31
2.92
3.75
3.06
2.98
Total lease operating expenses per Boe
20.68
19.46
23.06
20.74
20.88
General and administrative expenses excluding unit-based compensation
$
5,907
$
7,193
$
6,184
$
24,478
$
23,704
Net income (loss)
$
(70,868
)
$
(5,726
)
$
(39,693
)
$
34,913
$
(107,257
)
Net income (loss) per diluted limited partnership unit
$
(1.25
)
$
(0.11
)
$
(0.75
)
$
0.61
$
(2.03
)
Total production (MBoe)
1,700
1,741
1,632
6,699
6,517
Oil and NGL (MBoe)
791
827
744
3,157
2,990
Natural gas (MMcf)
5,452
5,486
5,335
21,251
21,161
Average daily production (Boe/d)
18,480
18,927
17,740
18,354
17,856
Sales volumes (MBoe)
1,664
1,680
1,642
6,663
6,465
Average realized sales price (per Boe) (d) (e) (f)
$
59.99
$
59.32
$
56.48
$
58.94
$
54.60
Oil and NGL (per Boe) (d) (e) (f)
78.95
76.14
69.72
74.31
66.27
Natural gas (per Mcf) (d) (e)
7.38
7.55
7.55
7.57
7.48
(a) Q4 2010, Q3 2010, Q4 2009, Full Year 2010 and Full Year 2009
include $124, $124, $268, $495 and $1,040, respectively, of
amortization of an intangible asset related to crude oil sales
contracts
(b) Full Year 2009 includes the effects of the early terminations of
hedge contracts monetized in January 2009 for $45,632 and June 2009
for $24,955.
(c) Includes lease operating expenses, district expenses and
processing fees. Q4 2009 and Full Year 2009 exclude amortization of
intangible asset related to the Quicksilver Acquisition.
(d) Includes realized gains on commodity derivative instruments.
(e) Full Year 2009 excludes the effect of the early termination of
oil and natural gas hedge contracts monetized in January 2009 for
$45,632 and June 2009 for $24,955.
(f) Excludes amortization of intangible asset related to crude oil
sales contracts. 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.
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 or 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
Year Ended December 31,
December 31,
September 30,
December 31,
Thousands of dollars
2010
2010
2009
2010
2009
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss) attributable to the partnership
($70,903
)
($5,754
)
$
(39,712
)
$
34,751
$
(107,290
)
Unrealized loss on commodity derivative instruments
82,307
30,540
54,688
39,713
219,120
Depletion, depreciation and amortization expense
33,159
23,636
25,450
102,758
106,843
Interest expense and other financing costs (a)
13,116
8,090
7,590
35,639
31,942
Unrealized gain on interest rate derivatives
(3,126
)
(1,314
)
(1,757
)
(6,597
)
(5,869
)
Gain on sale of commodity derivatives (b)
-
-
-
-
(70,587
)
(Gain) loss on sale of assets (c)
(123
)
(359
)
495
14
5,965
Income taxes
(439
)
(470
)
(1,174
)
(204
)
(1,528
)
Amortization of intangibles
124
124
437
495
2,771
Unit-based compensation expense (d)
5,009
5,502
2,933
20,331
13,619
Adjusted EBITDA
$
59,124
$
59,995
$
48,950
$
226,900
$
194,986
Three Months Ended
Year Ended December 31,
December 31,
September 30,
December 31,
Thousands of dollars
2010
2010
2009
2010
2009
Reconciliation of net cash flows from operating activities to
Adjusted EBITDA:
Net cash from operating activities
$
38,722
$
62,236
$
40,387
$
182,022
$
224,358
Increase (decrease) in assets net of liabilities relating to
operating activities
9,983
(9,149
)
2,584
15,131
12,466
Interest expense (a) (e)
10,488
6,997
6,766
30,161
28,647
Gain on sale of commodity derivatives (b)
-
-
-
-
(70,587
)
Income from equity affiliates, net
(157
)
9
(536
)
(450
)
(1,302
)
Incentive compensation expense (f)
(29
)
(45
)
8
(93
)
958
Incentive compensation paid
-
11
41
91
217
Income taxes
152
(36
)
(281
)
199
262
Non-controlling interest
(35
)
(28
)
(19
)
(162
)
(33
)
Adjusted EBITDA
$
59,124
$
59,995
$
48,950
$
226,900
$
194,986
(a) Includes realized gain/loss on interest rate derivatives.
(b) Represents $45,632 and $24,955 related to the early terminations
of selected 2011 and 2012 hedge contracts monetized in January 2009
and June 2009.
(c) The year ended December 31, 2009 includes loss on sale of Lazy
JL assets of $5,541.
(d) Represents non-cash long term unit-based incentive compensation
expense.
(e) Excludes amortization of debt issuance costs and amortization of
Senior Note discount.
(f) Represents cash-based incentive compensation plan expense.
Hedge Portfolio Summary
The table below summarizes the Partnership’s commodity derivative hedge
portfolio as of March 9, 2011.
Year
2011
2012
2013
2014
2015Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)
5,019
5,039
6,480
5,000
2,000
Average Price ($/Bbl)
$
76.14
$
77.15
$
81.37
$
88.60
$
99.00
Participating Swaps: (a)
Hedged Volume (Bbls/d)
1,439
-
-
-
-
Average Price ($/Bbl)
$
61.29
$
-
$
-
$
-
$
-
Average Participation %
53.2
%
-
-
-
-
Collars:
Hedged Volume (Bbls/d)
2,048
2,477
500
1,000
1,000
Average Floor Price ($/Bbl)
$
103.42
$
110.00
$
77.00
$
90.00
$
90.00
Average Ceiling Price ($/Bbl)
$
152.61
$
145.39
$
103.10
$
112.00
$
113.50
Floors:
Hedged Volume (Bbls/d)
-
-
-
-
-
Average Floor Price ($/Bbl)
$
-
$
-
$
-
$
-
$
-
Total:
Hedged Volume (Bbls/d)
8,506
7,516
6,980
6,000
3,000
Average Price ($/Bbl)
$
80.20
$
87.97
$
81.06
$
88.83
$
96.00
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)
25,955
19,128
37,000
7,500
-
Average Price ($/MMBtu)
$
7.26
$
7.10
$
6.50
$
6.00
$
-
Collars:
Hedged Volume (MMBtu/d)
16,016
19,129
-
-
-
Average Floor Price ($/MMBtu)
$
9.00
$
9.00
$
-
$
-
$
-
Average Ceiling Price ($/MMBtu)
$
11.28
$
11.89
$
-
$
-
$
-
Total:
Hedged Volume (MMBtu/d)
41,971
38,257
37,000
7,500
-
Average Price ($/MMBtu)
$
7.92
$
8.05
$
6.50
$
6.00
$
-
(a) Participating swap combines a swap and a call option with the
same strike price.
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 866-431-5320 (international callers
dial +1-719-325-2417) 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 23, 2011 by dialing
877-870-5176 (international callers dial +1-858-384-5517) and entering
replay PIN 7571007, 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,”
“expectations,” “continue,” “anticipate,” “will remain,” “generating,”
“pursuing” 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 significant reduction in the borrowing base under our
bank credit facility, our ability to raise capital, prices and demand
for natural gas and oil, increases in operating costs, 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, 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 March 9, 2011, 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 SubsidiariesUnaudited Consolidated Statements of Operations
Three Months Ended
Year Ended
December 31,
December 31,Thousands of dollars, except per unit amounts
2010
2009
2010
2009
Revenues and other income items
Oil, natural gas and natural gas liquid sales
$
78,135
$
74,728
$
317,738
$
254,917
Gain (loss) on commodity derivative instruments, net
(60,630
)
(36,917
)
35,112
(51,437
)
Other revenue, net
660
452
2,498
1,382
Total revenues and other income items
18,165
38,263
355,348
204,862
Operating costs and expenses
Operating costs
34,096
38,225
142,525
138,498
Depletion, depreciation and amortization
33,159
25,450
102,758
106,843
General and administrative expenses
10,950
9,102
44,907
36,367
(Gain) loss on sale of assets
(123
)
495
14
5,965
Unreimbursed litigation settlement costs
1,401
-
1,401
-
Total operating costs and expenses
79,483
73,272
291,605
287,673
Operating income (loss)
(61,318
)
(35,009
)
63,743
(82,811
)
Interest and other financing costs, net
10,790
4,145
24,552
18,827
(Gain) loss on interest rate swaps
(800
)
1,688
4,490
7,246
Other expense (income), net
(1
)
25
(8
)
(99
)
Income (loss) before taxes
(71,307
)
(40,867
)
34,709
(108,785
)
Income tax benefit
(439
)
(1,174
)
(204
)
(1,528
)
Net income (loss)
(70,868
)
(39,693
)
34,913
(107,257
)
Less: Net income attributable to noncontrolling interest
(35
)
(19
)
(162
)
(33
)
Net income (loss) attributable to the partnership
(70,903
)
(39,712
)
34,751
(107,290
)
Basic net income (loss) per unit
$
(1.25
)
$
(0.75
)
$
0.61
$
(2.03
)
Diluted net income (loss) per unit
$
(1.25
)
$
(0.75
)
$
0.61
$
(2.03
)
BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Balance Sheets
December 31,
December 31,Thousands
2010
2009
ASSETS
Current assets
Cash
$
3,630
$
5,766
Accounts and other receivables, net
53,520
65,209
Derivative instruments
54,752
57,133
Related party receivables
4,345
2,127
Inventory
7,321
5,823
Prepaid expenses
6,449
5,888
Intangibles
-
495
Total current assets
130,017
142,441
Equity investments
7,700
8,150
Property, plant and equipment
Oil and gas properties
2,133,099
2,058,968
Other assets
10,832
7,717
2,143,931
2,066,685
Accumulated depletion and depreciation
(421,636
)
(325,596
)
Net property, plant and equipment
1,722,295
1,741,089
Other long-term assets
Derivative instruments
50,652
74,759
Other long-term assets
19,503
4,590
Total assets
$
1,930,167
$
1,971,029
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
$
26,808
$
21,314
Derivative instruments
37,071
20,057
Related party payables
-
13,000
Revenue and royalties payable
16,427
18,224
Salaries and wages payable
12,594
10,244
Accrued liabilities
8,417
9,051
Total current liabilities
101,317
91,890
Credit facility
228,000
559,000
Senior notes, net
300,116
-
Deferred income taxes
2,089
2,492
Asset retirement obligation
47,429
36,635
Derivative instruments
39,722
50,109
Other long-term liabilities
2,237
2,102
Total liabilities
720,910
742,228
Equity
Partners’ equity
1,208,803
1,228,373
Noncontrolling interest
454
428
Total equity
1,209,257
1,228,801
Total liabilities and equity
$
1,930,167
$
1,971,029
Limited partner units issued and outstanding
53,957
52,784
BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Statements of Cash Flows
Year Ended
December 31,Thousands of dollars
2010
2009
Cash flows from operating activities
Net income (loss)
$
34,913
$
(107,257
)
Adjustments to reconcile to cash flows from operating activities:
Depletion, depreciation and amortization
102,758
106,843
Unit based compensation expense
20,422
12,661
Unrealized loss on derivative instruments
33,116
213,251
Income from equity affiliates, net
450
1,302
Deferred income taxes
(403
)
(1,790
)
Amortization of intangibles
495
2,771
Loss on sale of assets
14
5,965
Other
3,528
3,294
Changes in net assets and liabilities
Accounts receivable and other assets
11,552
(6,313
)
Inventory
(1,498
)
(4,573
)
Net change in related party receivables and payables
(15,218
)
2,957
Accounts payable and other liabilities
(8,107
)
(4,753
)
Net cash provided by operating activities
182,022
224,358
Cash flows from investing activities
Capital expenditures
(66,947
)
(29,513
)
Proceeds from sale of assets
337
23,284
Property acquisitions
(1,676
)
-
Net cash used in investing activities
(68,286
)
(6,229
)
Cash flows from financing activities
Distributions
(65,197
)
(28,038
)
Proceeds from long-term debt
1,047,992
249,975
Repayments of long-term debt
(1,079,000
)
(426,975
)
Book overdraft
1,025
(9,871
)
Long-term debt issuance costs
(20,692
)
-
Net cash used in financing activities
(115,872
)
(214,909
)
Increase (decrease) in cash
(2,136
)
3,220
Cash beginning of period
5,766
2,546
Cash end of period
$
3,630
$
5,766
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