LOS ANGELES--(BUSINESS WIRE)--BreitBurn Energy Partners L.P. (the “Partnership”) (NASDAQ:BBEP) today announced financial and operating results for its third quarter of 2011.
Key Highlights
- The Partnership had another strong quarter of operating and financial results, with net production trending in-line with its annual guidance and EBITDA trending above the high end of its annual guidance range.
- On October 6, 2011, the Partnership completed its acquisition of gas and oil properties in the Evanston and Green River Basins in southwestern Wyoming for approximately $283 million.
- On July 28, 2011, the Partnership completed its acquisition of crude oil properties in the Greasewood Field in eastern Wyoming for approximately $57 million.
- On October 28, 2011, the Partnership announced an increased cash distribution for the third quarter of 2011 at the rate of $0.4350 per common unit, or $1.74 per common unit on an annualized basis, to be paid on November 14, 2011 to the record holders of common units at the close of business on November 9, 2011. This represents an increase of 11.5% over the cash distribution for the third quarter of 2010.
- In connection with the October 2011 scheduled borrowing base redetermination under the Partnership’s existing credit facility, the Partnership’s borrowing base was increased to $850 million from $735 million, effective October 11, 2011. As of October 31, 2011, the Partnership had $505 million outstanding under the facility.
Management Commentary
Hal Washburn, CEO, said: “Our solid performance in the third quarter continues to highlight the Partnership’s consistent and predictable business model, with Adjusted EBITDA trending above the high end of our guidance range and net production trending in-line with guidance. We are excited to have recently completed two excellent acquisitions in the Rocky Mountains, allowing us to increase our presence in the region, continue our strategy of commodity diversification, and leverage our existing operational expertise in the area. The incremental cash flow from these acquisitions supports our distribution growth strategy. Having completed these acquisitions, we were pleased to announce a distribution increase of 3% from the prior quarter, from $1.69 per unit on an annualized basis to $1.74.”
Due to increased production, expenses and EBITDA associated with the Partnership’s recent acquisitions, the Partnership notes that its full-year guidance issued near the beginning of the year (March 2, 2011)will no longer be current or applicable for fourth quarter and year-end results. The Partnership intends to issue 2012 guidance in conjunction with its fourth quarter and full-year 2011 results during the first quarter of 2012.
Third Quarter 2011 Operating and Financial Results Compared to Second Quarter 2011
-
Total production increased from 1,662 MBoe in the second quarter of
2011 to 1,681 MBoe in the third quarter of 2011 primarily as a result
of production from acquired properties. Average daily production was
18,273 Boe/day in the third quarter of 2011 compared to 18,265 Boe/day
in the second quarter of 2011.
- Oil and NGL production was 829 MBoe compared to 782 MBoe.
- Natural gas production was 5,114 MMcf compared to 5,277 MMcf.
- Adjusted EBITDA, a non-GAAP measure, was $52.9 million in the third quarter of 2011, up from $51.6 million in the second quarter of 2011. The increase was primarily due to the timing of crude oil sales in Florida which impacted oil sales revenue, partially offset by higher lease operating expenses.
- Lease operating expenses per Boe, which include district expenses and processing fees and exclude production/property taxes and transportation costs, increased to $21.66 per Boe in the third quarter of 2011 from $18.41 per Boe in the second quarter of 2011. The increase was primarily due to the intentional scheduling of maintenance activities in the third quarter to minimize costs, and to the upward pressure on the cost of services and materials due to continued strong oil prices.
- General and administrative expenses, excluding non-cash unit-based compensation, increased to $8.6 million, or $5.09 per Boe, in the third quarter of 2011 from $6.2 million, or $3.74 per Boe, in the second quarter of 2011, primarily reflecting acquisition related costs, personnel additions and higher employee related costs.
- Oil and natural gas sales revenues, including realized gains and losses on commodity derivative instruments, were $105.4 million in the third quarter of 2011, up from $93.0 million in the second quarter of 2011, primarily reflecting the timing of crude oil sales in Florida, with two sales occurring in the third quarter versus one sale in the second quarter.
- Realized gains from commodity derivative instruments were $8.1 million in the third quarter of 2011 compared to realized losses of $1.8 million in the second quarter of 2011, reflecting lower commodity prices in the third quarter.
- NYMEX WTI crude oil spot prices averaged $89.49 per barrel and NYMEX natural gas prices averaged $4.06 per Mcf in the third quarter of 2011 compared to $102.02 per barrel and $4.38 per Mcf, respectively, in the second quarter of 2011.
- Realized crude oil and natural gas liquids prices averaged $81.50 per Boe and realized natural gas prices averaged $6.72 per Mcf in the third quarter of 2011, compared to $79.48 per Boe and $6.42 per Mcf, respectively, in the second quarter of 2011.
- Net income, including the effect of unrealized gains on commodity derivative instruments, was $178.2 million, or $2.87 per diluted common unit, in the third quarter of 2011 compared to net income of $57.5 million, or $0.92 per diluted common unit, in the second quarter of 2011.
- Capital expenditures totaled $22.3 million in the third quarter of 2011 compared to $28.1 million in the second quarter of 2011.
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 $8.1 million during the third quarter of 2011. Realized losses from interest rate derivative instruments were $1.1 million during the third quarter of 2011. Non-cash unrealized gains from commodity derivative instruments were $170.7 million and non-cash unrealized losses from interest rate derivative instruments were $0.1 million during the third quarter of 2011.
Production, Statement of Operations, and Realized Price Information
The following table presents production, selected Statement of Operations and realized price information for the three months ended September 30, 2011, June 30, 2011 and September 30, 2010:
| Three Months Ended | ||||||||||||||
| September 30, | June 30, | September 30, | ||||||||||||
| Thousands of dollars, except as indicated | 2011 | 2011 | 2010 | |||||||||||
| Oil, natural gas and NGLs sales (a) | $ | 97,356 | $ | 94,742 | $ | 77,055 | ||||||||
| Realized gain (loss) on commodity derivative instruments | 8,092 | (1,751 | ) | 22,567 | ||||||||||
| Unrealized gain (loss) on commodity derivative instruments | 170,734 | 48,234 | (30,540 | ) | ||||||||||
| Other revenues, net | 1,375 | 1,143 | 719 | |||||||||||
| Total revenues | $ | 277,557 | $ | 142,368 | $ | 69,801 | ||||||||
| Lease operating expenses and processing fees | $ | 36,409 | $ | 30,595 | $ | 28,800 | ||||||||
| Production and property taxes | 6,689 | 6,195 | 5,081 | |||||||||||
| Total lease operating expenses | $ | 43,098 | $ | 36,790 | $ | 33,881 | ||||||||
| Transportation expenses | 1,426 | 1,010 | 1,037 | |||||||||||
| Purchases and other operating costs | 329 | 268 | 90 | |||||||||||
| Change in inventory | 1,593 | (1,860 | ) | (1,801 | ) | |||||||||
| Total operating costs | $ | 46,446 | $ | 36,208 | $ | 33,207 | ||||||||
| Lease operating expenses pre taxes per Boe (b) | $ | 21.66 | $ | 18.41 | $ | 16.54 | ||||||||
| Production and property taxes per Boe | 3.98 | 3.73 | 2.92 | |||||||||||
| Total lease operating expenses per Boe | 25.64 | 22.14 | 19.46 | |||||||||||
| General and administrative expenses excluding unit-based compensation | $ | 8,552 | $ | 6,221 | $ | 7,193 | ||||||||
| Net income (loss) | $ | 178,227 | $ | 57,523 | $ | (5,726 | ) | |||||||
| Net income (loss) per diluted common unit | $ | 2.87 | $ | 0.92 | $ | (0.11 | ) | |||||||
| Total production (MBoe) | 1,681 | 1,662 | 1,741 | |||||||||||
| Oil and NGLs (MBoe) | 829 | 782 | 827 | |||||||||||
| Natural gas (MMcf) | 5,114 | 5,277 | 5,486 | |||||||||||
| Average daily production (Boe/d) | 18,273 | 18,265 | 18,927 | |||||||||||
| Sales volumes (MBoe) | 1,723 | 1,621 | 1,680 | |||||||||||
| Average realized sales price (per Boe) (c) (d) | $ | 61.08 | $ | 57.29 | $ | 59.32 | ||||||||
| Oil and NGLs (per Boe) (c) (d) | 81.50 | 79.48 | 76.14 | |||||||||||
| Natural gas (per Mcf) (c) | 6.72 | 6.42 | 7.55 | |||||||||||
(a) Q3 2010 includes $124 of amortization of an intangible asset related
to crude oil sales contracts.
(b) Includes lease operating
expenses, district expenses and processing fees.
(c) Includes
realized gain (loss) on commodity derivative instruments.
(d)
Includes crude oil purchases. 2010 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 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 | |||||||||||||||
| September 30, | June 30, | September 30, | |||||||||||||
| Thousands of dollars | 2011 | 2011 | 2010 | ||||||||||||
| Reconciliation of net income (loss) to Adjusted EBITDA: | |||||||||||||||
| Net income (loss) attributable to the Partnership | $ | 178,181 | $ | 57,455 | ($5,754 | ) | |||||||||
| Unrealized (gain) loss on commodity derivative instruments | (170,734 | ) | (48,234 | ) | 30,540 | ||||||||||
| Depletion, depreciation and amortization expense | 26,688 | 25,025 | 23,636 | ||||||||||||
| Interest expense and other financing costs (a) | 10,342 | 10,145 | 8,090 | ||||||||||||
| Unrealized (gain) loss on interest rate derivatives | 71 | 1,155 | (1,314 | ) | |||||||||||
| (Gain) loss on sale of assets | (94 | ) | 40 | (359 | ) | ||||||||||
| Income taxes | 1,895 | 616 | (470 | ) | |||||||||||
| Amortization of intangibles | - | - | 124 | ||||||||||||
| Unit-based compensation expense (b) | 5,447 | 5,435 | 5,502 | ||||||||||||
| Net operating cash flow from acquisitions, effective date through closing date | 1,078 | - | - | ||||||||||||
| Adjusted EBITDA | $ | 52,874 | $ | 51,637 | $ | 59,995 | |||||||||
| Three Months Ended | |||||||||||||||
| September 30, | June 30, | September 30, | |||||||||||||
| Thousands of dollars | 2011 | 2011 | 2010 | ||||||||||||
| Reconciliation of net cash flows from operating activities to Adjusted EBITDA: | |||||||||||||||
| Net cash from operating activities | $ | 41,267 | $ | 33,118 | $ | 62,236 | |||||||||
| Increase (decrease) in assets net of liabilities relating to operating activities | 1,199 | 9,837 | (9,149 | ) | |||||||||||
| Interest expense (a) (c) | 9,273 | 8,896 | 6,997 | ||||||||||||
| Income from equity affiliates, net | (10 | ) | (262 | ) | 9 | ||||||||||
| Incentive compensation expense (d) | (29 | ) | 14 | (45 | ) | ||||||||||
| Incentive compensation paid | 78 | - | 11 | ||||||||||||
| Income taxes | 64 | 102 | (36 | ) | |||||||||||
| Non-controlling interest | (46 | ) | (68 | ) | (28 | ) | |||||||||
| Net operating cash flow from acquisitions, effective date through closing date | 1,078 | - | - | ||||||||||||
| Adjusted EBITDA | $ | 52,874 | $ | 51,637 | $ | 59,995 | |||||||||
(a) Includes realized (gain) 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.
(d) Represents cash-based incentive compensation
plan expense.
Hedge Portfolio Summary
The table below summarizes the Partnership’s commodity derivative hedge portfolio as of November 8, 2011. Please refer to the updated Commodity Price Protection Portfolio via our website for additional details related to our hedge portfolio.
In October 2011, the Partnership terminated certain crude oil fixed price swaps at NYMEX WTI prices for $33.8 million and entered into new crude oil fixed price swaps at IPE Brent prices. The new crude oil swaps were entered into to mitigate future price volatility associated with our California production. Historically WTI oil prices and Brent oil prices have fluctuated together, but they have recently diverged and management believes that Brent pricing will better correlate with local California pricing. These new positions, as well as the hedges entered into in conjunction with our recent Wyoming acquisitions, are reflected in the table below.
|
Year |
|||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2015 | |||||||||||||
| Oil Positions: | |||||||||||||||||
| Fixed Price Swaps: | |||||||||||||||||
| Hedged Volume (Bbl/d) |
5,316 |
5,039 |
6,480 |
5,000 |
2,500 |
||||||||||||
| Average Price ($/Bbl) | $ | 76.95 | $ | 96.58 | $ | 93.21 | $ | 89.41 | $ | 99.50 | |||||||
| Participating Swaps: (a) | |||||||||||||||||
| Hedged Volume (Bbl/d) |
1,377 |
- |
- |
- |
- |
||||||||||||
| Average Price ($/Bbl) | $ | 60.00 |
$ |
- |
$ |
- |
$ |
- |
$ |
- |
|||||||
|
Average Participation % |
53.1 | % |
- |
- |
- |
- |
|||||||||||
| Collars: | |||||||||||||||||
| Hedged Volume (Bbl/d) |
2,166 |
2,477 |
500 |
1,000 |
1,000 |
||||||||||||
| Average Floor Price ($/Bbl) | $ | 103.61 | $ | 110.00 | $ | 77.00 | $ | 90.00 | $ | 90.00 | |||||||
| Average Ceiling Price ($/Bbl) | $ | 153.50 | $ | 145.39 | $ | 103.10 | $ | 112.00 | $ | 113.50 | |||||||
| Total: | |||||||||||||||||
| Hedged Volume (Bbl/d) |
8,859 |
7,516 |
6,980 |
6,000 |
3,500 |
||||||||||||
| Average Price ($/Bbl) | $ | 80.84 | $ | 101.00 | $ | 92.05 | $ | 89.51 | $ | 96.79 | |||||||
| Gas Positions: | |||||||||||||||||
| Fixed Price Swaps: | |||||||||||||||||
| Hedged Volume (MMBtu/d) |
30,000 |
35,128 |
56,000 |
30,500 |
30,500 |
||||||||||||
| Average Price ($/MMBtu) | $ | 6.11 | $ | 6.09 | $ | 5.96 | $ | 5.43 | $ | 5.55 | |||||||
| Collars: | |||||||||||||||||
| Hedged Volume (MMBtu/d) |
20,000 |
19,129 |
- |
- |
- |
||||||||||||
| Average Floor Price ($/MMBtu) | $ | 9.00 | $ | 9.00 | $ |
- |
$ |
- |
$ |
- |
|||||||
| Average Ceiling Price ($/MMBtu) | $ | 12.05 | $ | 11.89 | $ |
- |
$ |
- |
$ |
- |
|||||||
| Calls: | |||||||||||||||||
| Hedged Volume (MMBtu/d) |
- |
- |
30,000 |
15,000 |
- |
||||||||||||
| Average Price ($/MMBtu) | $ |
- |
$ |
- |
$ | 8.00 | $ | 9.00 | $ |
- |
|||||||
| Total: | |||||||||||||||||
| Hedged Volume (MMBtu/d) |
50,000 |
54,257 |
86,000 |
45,500 |
30,500 |
||||||||||||
| Average Price ($/MMBtu) | $ | 7.27 | $ | 7.12 | $ | 6.67 | $ | 6.61 | $ | 5.55 | |||||||
(a) Reflects NYMEX WTI average prices for 2011 and 2015. For 2012
through 2014, an average volume of 2,346 Bbl/d is hedged at a weighted
average IPE Brent price of $99.75 per Bbl and the remaining volume is
hedged at NYMEX WTI.
(b) A participating swap combines a swap and a
call option with the same strike price.
(c) A weighted average
volume of 19,647 MMBtu/d for 2011 through 2015 is hedged at a weighted
average NYMEX Henry Hub price of $5.11 per MMBtu and the remaining
volume is hedged at Mich Con City-Gate.
(d) Reflects NYMEX Henry
Hub prices. Call options for 2013 and 2014 have a deferred premium of
$0.0815 per MMBtu and $0.1200 per MMBtu, respectively.
List of 2012-2014 NYMEX WTI Swaps Terminated and Replaced with IPE Brent Swaps:
| Period |
NYMEX |
IPE Brent |
Volume |
||||||||
| January 1, 2012 to December 31, 2012 | $ | 63.30 | $ | 105.75 | 1,939 | ||||||
| January 1, 2012 to June 30, 2012 | 79.55 | 106.20 | 600 | ||||||||
| January 1, 2012 to December 31, 2013 | 84.30 | 103.50 | 400 | ||||||||
| January 1, 2013 to December 31, 2013 | 83.60 | 92.65 | 500 | ||||||||
| January 1, 2013 to December 31, 2013 | 80.10 | 92.10 | 500 | ||||||||
| January 1, 2013 to December 31, 2013 | 80.15 | 94.25 | 500 | ||||||||
| January 1, 2013 to December 31, 2013 | 75.85 | 94.00 | 500 | ||||||||
| January 1, 2013 to December 31, 2013 | 77.85 | 100.60 | 500 | ||||||||
| January 1, 2013 to December 31, 2013 | 70.00 | 101.00 | 1,000 | ||||||||
| January 1, 2014 to December 31, 2014 | 81.05 | 89.25 | 500 | ||||||||
Other Information
The Partnership will host an investor conference call to discuss its results today at 10:00 a.m. (Pacific Time). Investors may access the conference call over the Internet via the Investor Relations tab of the Partnership's website (www.breitburn.com), or via telephone by dialing 877-718-5098(international callers dial +1-719-325-4796) 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 22, 2011 by dialing 877-870-5176 (international callers dial +1-858-384-5517) and entering replay PIN 7215054, or by going to the Investor Relations tab of the Partnership's website (www.breitburn.com). The Partnership will take live questions from securities analysts and institutional portfolio managers; the complete call is open to all other interested parties on a listen-only basis.
About BreitBurn Energy Partners L.P.
BreitBurn Energy Partners L.P. is a publicly traded independent oil and gas limited partnership focused on the acquisition, exploitation, development and production of oil and gas properties. The Partnership’s producing and non-producing crude oil and natural gas reserves are located in Michigan, Wyoming,California, Florida, Indiana, and Kentucky. See www.BreitBurn.com for more information.
Cautionary Statement Regarding Forward-Looking Information
This press release contains forward-looking statements relating to the Partnership’s operations that are based on management's current expectations, estimates and projections about its operations. Words and phrases such as “believes,” “expects,” “future,” “impact,” “guidance,” “will be” and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. These include risks relating to the Partnership’s financial performance and results, availability of sufficient cash flow and other sources of liquidity to execute our business plan, prices and demand for natural gas and oil, increases in operating costs, uncertainties inherent in estimating our reserves and production, our ability to replace reserves and efficiently develop our current reserves, political and regulatory developments relating to taxes, derivatives and our oil and gas operations, risks relating to our completed and pending acquisitions, and the factors set forth under the heading “Risk Factors” incorporated by reference from our Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 9, 2011, and if applicable, our Quarterly Reports on Form 10-Q and our Current Reports on Form 8-K. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, the Partnership undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.
BBEP-IR
| BreitBurn Energy Partners L.P. and Subsidiaries | ||||||||||
| Unaudited Consolidated Balance Sheets | ||||||||||
| September 30, | December 31, | |||||||||
| Thousands | 2011 | 2010 | ||||||||
| ASSETS | ||||||||||
| Current assets | ||||||||||
| Cash | $ | 4,777 | $ | 3,630 | ||||||
| Accounts and other receivables, net | 64,542 | 53,520 | ||||||||
| Derivative instruments | 87,824 | 54,752 | ||||||||
| Related party receivables | 3,413 | 4,345 | ||||||||
| Inventory | 4,683 | 7,321 | ||||||||
| Prepaid expenses | 6,611 | 6,449 | ||||||||
| Total current assets | 171,850 | 130,017 | ||||||||
| Equity investments | 7,531 | 7,700 | ||||||||
| Property, plant and equipment | ||||||||||
| Oil and gas properties | 2,248,035 | 2,133,099 | ||||||||
| Other assets | 11,916 | 10,832 | ||||||||
| 2,259,951 | 2,143,931 | |||||||||
| Accumulated depletion and depreciation | (494,704 | ) | (421,636 | ) | ||||||
| Net property, plant and equipment | 1,765,247 | 1,722,295 | ||||||||
| Other long-term assets | ||||||||||
| Derivative instruments | 64,418 | 50,652 | ||||||||
| Other long-term assets | 32,315 | 19,503 | ||||||||
| Total assets | $ | 2,041,361 | $ | 1,930,167 | ||||||
| LIABILITIES AND EQUITY | ||||||||||
| Current liabilities | ||||||||||
| Accounts payable | $ | 31,748 | $ | 26,808 | ||||||
| Derivative instruments | 14,630 | 37,071 | ||||||||
| Revenue and royalties payable | 17,876 | 16,427 | ||||||||
| Salaries and wages payable | 9,090 | 12,594 | ||||||||
| Accrued liabilities | 12,264 | 8,417 | ||||||||
| Total current liabilities | 85,608 | 101,317 | ||||||||
| Credit facility | 211,000 | 228,000 | ||||||||
| Senior notes, net | 300,489 | 300,116 | ||||||||
| Deferred income taxes | 3,402 | 2,089 | ||||||||
| Asset retirement obligation | 47,083 | 47,429 | ||||||||
| Derivative instruments | 2,514 | 39,722 | ||||||||
| Other long-term liabilities | 2,043 | 2,237 | ||||||||
| Total liabilities | 652,139 | 720,910 | ||||||||
| Equity | ||||||||||
| Partners' equity | 1,388,771 | 1,208,803 | ||||||||
| Noncontrolling interest | 451 | 454 | ||||||||
| Total equity | 1,389,222 | 1,209,257 | ||||||||
| Total liabilities and equity | $ | 2,041,361 | $ | 1,930,167 | ||||||
| Common units outstanding | 59,040 | 53,957 | ||||||||
| BreitBurn Energy Partners L.P. and Subsidiaries | ||||||||||||||||
| Unaudited Consolidated Statements of Operations | ||||||||||||||||
| Three Months Ended | Nine Months Ended | |||||||||||||||
| September 30, | September 30, | |||||||||||||||
| Thousands of dollars, except per unit amounts | 2011 | 2010 | 2011 | 2010 | ||||||||||||
| Revenues and other income items | ||||||||||||||||
| Oil, natural gas and natural gas liquid sales | $ | 97,356 | $ | 77,055 | $ | 284,673 | $ | 239,603 | ||||||||
| Gain (loss) on commodity derivative instruments, net | 178,826 | (7,973 | ) | 119,132 | 95,742 | |||||||||||
| Other revenue, net | 1,375 | 719 | 3,416 | 1,838 | ||||||||||||
| Total revenues and other income items | 277,557 | 69,801 | 407,221 | 337,183 | ||||||||||||
| Operating costs and expenses | ||||||||||||||||
| Operating costs | 46,446 | 33,207 | 119,465 | 108,429 | ||||||||||||
| Depletion, depreciation and amortization | 26,688 | 23,636 | 76,354 | 69,599 | ||||||||||||
| General and administrative expenses | 13,999 | 12,740 | 38,126 | 33,957 | ||||||||||||
| (Gain) loss on sale of assets | (94 | ) | (359 | ) | (40 | ) | 137 | |||||||||
| Total operating costs and expenses | 87,039 | 69,224 | 233,905 | 212,122 | ||||||||||||
| Operating income | 190,518 | 577 | 173,316 | 125,061 | ||||||||||||
| Interest expense, net of capitalized interest | 9,270 | 5,147 | 27,770 | 13,762 | ||||||||||||
| Loss on interest rate swaps | 1,143 | 1,629 | 3,020 | 5,290 | ||||||||||||
| Other income, net | (17 | ) | (3 | ) | (20 | ) | (7 | ) | ||||||||
| Income (loss) before taxes | 180,122 | (6,196 | ) | 142,546 | 106,016 | |||||||||||
| Income tax expense (benefit) | 1,895 | (470 | ) | 1,509 | 235 | |||||||||||
| Net income (loss) | 178,227 | (5,726 | ) | 141,037 | 105,781 | |||||||||||
| Less: Net income attributable to noncontrolling interest | (46 | ) | (28 | ) | (148 | ) | (127 | ) | ||||||||
| Net income (loss) attributable to the partnership | 178,181 | (5,754 | ) | 140,889 | 105,654 | |||||||||||
| Basic net income (loss) per unit | $ | 2.87 | $ | (0.11 | ) | $ | 2.30 | $ | 1.86 | |||||||
| Diluted net income (loss) per unit | $ | 2.87 | $ | (0.11 | ) | $ | 2.29 | $ | 1.86 | |||||||
| BreitBurn Energy Partners L.P. and Subsidiaries | ||||||||||
| Unaudited Consolidated Statements of Cash Flows | ||||||||||
| Nine months ended | ||||||||||
| September 30, | ||||||||||
| Thousands of dollars | 2011 | 2010 | ||||||||
| Cash flows from operating activities | ||||||||||
| Net income | $ | 141,037 | $ | 105,781 | ||||||
| Adjustments to reconcile to cash flow from operating activities: | ||||||||||
| Depletion, depreciation and amortization | 76,354 | 69,599 | ||||||||
| Unit-based compensation expense | 16,334 | 15,386 | ||||||||
| Unrealized gain on derivative instruments | (106,488 | ) | (46,065 | ) | ||||||
| Income from equity affiliates, net | 169 | 293 | ||||||||
| Deferred income taxes | 1,313 | 188 | ||||||||
| Amortization of intangibles | - | 371 | ||||||||
| (Gain) loss on sale of assets | (40 | ) | 137 | |||||||
| Other | 417 | 2,850 | ||||||||
| Changes in net assets and liabilities | ||||||||||
| Accounts receivable and other assets | (9,858 | ) | 13,315 | |||||||
| Inventory | 2,638 | 1,202 | ||||||||
| Net change in related party receivables and payables | 932 | (12,935 | ) | |||||||
| Accounts payable and other liabilities | 5,976 | (6,822 | ) | |||||||
| Net cash provided by operating activities | 128,784 | 143,300 | ||||||||
| Cash flows from investing activities | ||||||||||
| Capital expenditures | (61,264 | ) | (46,418 | ) | ||||||
| Proceeds from sale of assets | 1,118 | 225 | ||||||||
| Deposit for oil and gas properties | (14,250 | ) | - | |||||||
| Property acquisitions | (57,380 | ) | (1,550 | ) | ||||||
| Net cash used in investing activities | (131,776 | ) | (47,743 | ) | ||||||
| Cash flows from financing activities | ||||||||||
| Issuance of common units | 99,826 | - | ||||||||
| Distributions | (75,690 | ) | (43,043 | ) | ||||||
| Proceeds from issuance of long-term debt | 283,500 | 683,500 | ||||||||
| Repayments of long-term debt | (300,500 | ) | (726,500 | ) | ||||||
| Change in book overdraft | 141 | - | ||||||||
| Long-term debt issuance costs | (3,138 | ) | (11,871 | ) | ||||||
| Net cash provided by (used in) financing activities | 4,139 | (97,914 | ) | |||||||
| Increase (decrease) in cash | 1,147 | (2,357 | ) | |||||||
| Cash beginning of period | 3,630 | 5,766 | ||||||||
| Cash end of period | $ | 4,777 | $ | 3,409 | ||||||