Attached files
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| 8-K - COPANO ENERGY, L.L.C. FORM 8-K - Copano Energy, L.L.C. | form8-k.htm |
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Exhibit 99.1
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News Release
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Contacts:
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Carl A. Luna, SVP and CFO
Copano Energy, L.L.C.
713-621-9547
Jack Lascar / jlascar@drg-l.com
Anne Pearson/ apearson@drg-l.com
DRG&L/ 713-529-6600
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FOR IMMEDIATE RELEASE
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Copano Energy Reports Second Quarter 2012 Results
Issues 2013 Guidance
HOUSTON, August 8, 2012 — Copano Energy, L.L.C. (NASDAQ: CPNO) today announced its financial results for the three months ended June 30, 2012.
Second Quarter 2012 Highlights:
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Total distributable cash flow of $39.5 million, a 5% increase from second quarter 2011
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Total segment gross margin of $72.9 million, a 12% increase from the prior year period
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Adjusted EBITDA of $58.3 million, a 7% increase from the prior year period
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Volumes gathered from the Eagle Ford Shale play averaged 490,000 MMBtu/d, a 277% increase from the prior year period
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Texas segment NGL production of over 50,000 Bbls/d, an 86% increase from second quarter 2011
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2013 Guidance:
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Adjusted EBITDA forecasted to range from $300 million to $330 million
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Total Distributable Cash Flow forecasted to range from $220 million to $240 million
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Common unit distribution growth rate target of 7% to 9%
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“Continued strong volume growth from the Eagle Ford Shale and increased volumes at our Saint Jo plant, combined with improving asset performance, led to increased financial results during the second quarter,” said R. Bruce Northcutt, Copano’s President and Chief Executive Officer. “Our results also benefited from our strategy of transitioning to a more fee-based business, which has reduced the impact of the lower commodity price environment.
“We are pleased with our progress on capital projects and look forward to achieving the full benefits of our Eagle Ford strategy, which will drive cash flow and distribution growth in 2013. At the same time, we have begun to focus on new long-term growth opportunities to create additional value for Copano unitholders,” Northcutt added.
Second Quarter Financial Results
Total distributable cash flow increased 5% from a year ago, to $39.5 million for the second quarter of 2012, and 19% from the first quarter of 2012. The increase from the prior-year period was primarily due to:
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increased throughput from the Eagle Ford Shale, north Barnett Shale Combo and Woodford Shale plays,
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volumes processed at the Lake Charles plant in Louisiana, and
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lower maintenance capital expenditures.
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These benefits were partially offset by lower natural gas liquids (NGL) prices and higher interest and operating expenses.
Second-quarter 2012 total distributable cash flow represents 93% coverage of the second-quarter distribution of $0.575 per unit, based on common units outstanding on the distribution record date.
Revenue for the second quarter of 2012 decreased 8% from the second quarter of 2011 to $317.3 million, and 6% from the first quarter of 2012. Total segment gross margin increased 12% from both the second quarter of 2011 and first quarter of 2012 to $72.9 million. Adjusted EBITDA increased 7% from the second quarter of 2011, to $58.3 million and 16% from first quarter of 2012. Net income to common was $12.2 million for the second quarter of 2012, compared to net loss of $17.4 million for the second quarter of 2011.
Corporate and other activities, which include Copano’s commodity risk management efforts, contributed a gain of $3.4 million for the second quarter of 2012 compared to a loss of $10.3 million for the second quarter of 2011 and a loss of $5.1 million for the first quarter of 2012.
Total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures at the end of this news release. Please read “Use of Non-GAAP Financial Measures” beginning on page 6 of this news release.
2
Second Quarter Operating Results by Segment
Texas
Segment gross margin for Texas increased 6% from the second quarter of 2011 to $49.1 million, and increased 8% from the first quarter of 2012. The increase from the prior year was primarily a result of volume growth from the Eagle Ford Shale and north Barnett Shale Combo plays, partially offset by lower NGL prices and a decline in lean gas volumes, which were displaced by rich gas volumes at the Houston Central complex. Also, the Lake Charles plant, which contributed $2.5 million to Texas gross margin for the second quarter of 2012, did not operate during the prior-year period.
During the second quarter of 2012, the Texas segment provided gathering and processing services for an average of 924,465 MMBtu/d of natural gas, an increase of 39% from the second quarter of 2011. The Texas segment gathered an average of 566,388 MMBtu/d of natural gas, an increase of 28% over the second quarter of 2011, primarily due to increased volumes from the Eagle Ford Shale and north Barnett Shale Combo plays. Volumes processed at Copano’s plants and third-party plants in Texas averaged 834,846 MMBtu/d during the second quarter of 2012, an increase of 42% over the second quarter of 2011 primarily due to increased volumes from the north Barnett Shale Combo play and at the Lake Charles plant. Second-quarter NGL production averaged 50,146 Bbls/d at Copano-owned plants and third-party plants, an increase of 86% from the second quarter of 2011 and 42% from the first quarter of 2012, reflecting a substantial increase in the NGL content of volumes at the Houston Central complex, and increased volumes at the Saint Jo plant in the north Barnett Shale Combo play and the Lake Charles plant in Louisiana.
Eagle Ford Gathering, Copano’s unconsolidated joint venture with Kinder Morgan, has been in full service since December 2011 and provided gathering services for an average of 252,912 MMBtu/d during the second quarter of 2012. Texas segment gross margin results do not include the financial results and volumes associated with Copano’s interest in Eagle Ford Gathering, which is accounted for under the equity method of accounting and shown in Copano’s financial statements under “Equity in (earnings) loss from unconsolidated affiliates.” For the second quarter of 2012, equity earnings and distributions from Eagle Ford Gathering totaled $9.8 million and $4.8 million, respectively.
Oklahoma
Segment gross margin for Oklahoma was $20.2 million for the second quarter of 2012, a decrease of 30% compared to the second quarter of last year and 17% from the first quarter of 2012. The year-over-year decrease resulted primarily from a decrease of 39% in realized margins on service throughput compared to the second quarter of 2011 ($0.68 per MMBtu in 2012 compared to $1.11 per MMBtu in 2011) due to lower NGL and natural gas prices. This decrease was partially offset by an increase in service throughput attributable to lean gas volume growth from the Woodford Shale play.
3
The Oklahoma segment gathered an average of 324,915 MMBtu/d of natural gas, an increase of 14% compared to the second quarter of 2011, due primarily to lean gas from the Woodford Shale area, which increased 46% compared to the second quarter of 2011. Volumes processed at wholly-owned and third-party plants in Oklahoma were flat compared to the second quarter of 2011, averaging 158,016 MMBtu/d. Second quarter NGL production at Copano-owned plants and third-party plants averaged 17,028 Bbls/d, a decrease of 2% from the second quarter of 2011.
Rocky Mountains
Segment gross margin for the Rocky Mountains segment totaled $0.2 million in the second quarter of 2012 compared to $0.8 million for the second quarter of 2011 and $0.4 million for the first quarter of 2012. Rocky Mountains segment gross margin results do not include the financial results and volumes associated with Copano’s interest in Bighorn Gas Gathering and Fort Union Gas Gathering, which are accounted for under the equity method of accounting and shown in Copano’s financial statements under “Equity in (earnings) loss from unconsolidated affiliates.”
Average pipeline throughput for Bighorn and Fort Union on a combined basis increased 40% to 747,009 MMBtu/d in the second quarter of 2012 as compared to 533,329 MMBtu/d in the second quarter of 2011. The volume increase is due primarily to producers increasing volumes on Fort Union to access downstream markets; however, because Fort Union has firm volume commitments, the increase did not have a material impact on Copano’s equity earnings or distributions. For the second quarter of 2012, combined equity earnings for Bighorn and Fort Union totaled $2.6 million, compared to $0.6 million for the same period in 2011. Combined distributions from Bighorn and Fort Union totaled $7.3 million in the second quarter of 2012, compared to $6.3 million in the second quarter of last year.
Cash Distributions
On July 11, 2012, Copano announced its second quarter 2012 cash distribution of $0.575 per unit, or $2.30 per unit on an annualized basis, for all of its outstanding common units. This distribution is unchanged from the first quarter of 2012 and will be paid on August 9, 2012 to common unitholders of record at the close of business on July 31, 2012.
4
2013 Guidance
Copano announced today its forecast for certain financial items for 2013, as outlined in the table below:
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($ in millions)
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Calendar 2013
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Adjusted EBITDA
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$300 to $330 | ||
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Total distributable cash flow
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$220 to $240
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| Common unit distribution growth rate target (1) | 7% to 9% | ||
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Quarterly common unit distribution coverage target
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100% to 115%
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Fee-based margin (2)
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55% to 60%
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Capital expenditures:
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Expansion
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$250 to $300 | ||
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Maintenance
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$13 to $18 | ||
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___________________________
(1) Based on annualized fourth quarter 2013 declared distribution
(2) Represents fee-based component of our total segment gross margin and our share of gross margin from our unconsolidated affiliates
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The above forecasted amounts are based on various assumptions, which include an average natural gas price of $3.80 per MMBtu, weighted-average Mont Belvieu and Conway NGL prices of $33.16 per barrel and $29.34 per barrel, respectively, and an average NYMEX crude price of $90.34 per barrel. Additionally, for the third and fourth quarters of 2013, Copano assumes no conversion of its preferred units then outstanding and payment of cash rather than in-kind preferred unit distributions.
Additional assumptions include, among others, timely and on-budget completion of Copano’s announced expansion capital projects, forecasted operational volumes from existing operations and expansion capital projects, Copano’s existing contract portfolio and outstanding commodity hedge portfolio, receipt of volume deficiency payments under certain contracts, consistent operations at third-party facilities and timely completion of expansions at third-party facilities that impact Copano’s operations, estimated interest rates, and budgeted operations and maintenance and general and administrative costs. Management will issue updated 2013 guidance in subsequent earnings announcements only if revised expectations fall outside the ranges set forth above.
Management does not develop detailed forecasts for certain items, including GAAP revenues, depreciation, amortization and non-cash changes in derivatives, and therefore is unable to provide forecasted net income, a comparable GAAP measure, for the period presented.
5
With respect to the third and fourth quarters of 2012, management expects to continue to provide quarterly gross margin trends and any material updates to full-year 2012 capital expenditures and expense guidance.
Conference Call Information
Copano will hold a conference call on August 9, 2012 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) to discuss its second quarter 2012 financial results. To participate in the call, dial (480) 629-9645 and ask for the Copano call at least 10 minutes prior to the start time, or access it live over the internet at www.copano.com on the “Investor Overview” page of the “Investor Relations” section of Copano’s website.
A replay of the audio webcast will be available shortly after the call on Copano’s website. A telephonic replay will be available through August 16, 2012 by calling (303) 590-3030 and using the pass code 4551423#.
Use of Non-GAAP Financial Measures
This news release and the accompanying schedules include non-generally accepted accounting principles, or non-GAAP, financial measures of total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP. Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Copano’s non-GAAP financial measures may not be comparable to similarly titled measures of other companies, who may not calculate their measures in the same manner.
Copano’s management team uses non-GAAP financial measures to evaluate its core profitability and to assess the financial performance of its assets. Subject to the limitations expressed above, Copano believes that investors and other market participants benefit from access to the various financial measures that its management uses in evaluating its performance because it allows them to independently evaluate Copano’s performance with the same information used by management.
Copano Energy, L.L.C. is a midstream natural gas company with operations in Texas, Oklahoma, Wyoming and Louisiana. More information is available at http://www.copano.com.
6
This press release includes “forward-looking statements,” as defined by the Securities and Exchange Commission. Statements that address activities or events that Copano believes will or may occur in the future are forward-looking statements. These statements include, but are not limited to, statements about future producer activity and Copano’s total distributable cash flow and distribution coverage. These statements are based on management’s experience and perception of historical trends, current conditions, expected future developments and other factors management believes are reasonable. Important factors that could cause actual results to differ materially from those in forward-looking statements include the following risks and uncertainties, many of which are beyond Copano’s control: the volatility of prices and market demand for natural gas and natural gas liquids; Copano’s ability to continue to obtain new sources of natural gas supply and retain its key customers; the impact on volumes and resulting cash flow of technological, economic and other uncertainties inherent in estimating future production; producers’ ability to drill and successfully complete and attach new natural gas supplies; the NGL content of new gas supplies; Copano’s ability to access or construct new processing, fractionation and transportation capacity; the availability of downstream transportation and other facilities for natural gas and NGLs; mechanical failures and other operational risks affecting the performance of Copano’s processing plants and other facilities, higher construction costs or project delays due to inflation, limited availability of required resources, or the effects of environmental, legal or other uncertainties; general economic conditions; the effects of government regulations and policies; and other financial, operational and legal risks and uncertainties detailed from time to time in Copano’s quarterly and annual reports filed with the Securities and Exchange Commission.
–financial statements follow –
7
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months Ended
June 30,
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Six Months Ended
June 30,
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2012
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2011
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2012
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2011
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(In thousands, except per unit information)
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Revenue:
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Natural gas sales
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$ | 69,993 | $ | 123,928 | $ | 156,205 | $ | 227,723 | ||||||||
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Natural gas liquids sales
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188,780 | 180,758 | 383,967 | 329,759 | ||||||||||||
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Transportation, compression and processing fees
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43,241 | 27,898 | 83,080 | 52,369 | ||||||||||||
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Condensate and other
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15,289 | 13,472 | 31,279 | 26,130 | ||||||||||||
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Total revenue
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317,303 | 346,056 | 654,531 | 635,981 | ||||||||||||
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Costs and expenses:
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Cost of natural gas and natural gas liquids (1)
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238,482 | 274,398 | 504,433 | 498,128 | ||||||||||||
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Transportation (1)
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5,971 | 6,362 | 12,420 | 12,211 | ||||||||||||
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Operations and maintenance
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18,287 | 15,763 | 36,929 | 30,862 | ||||||||||||
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Depreciation and amortization
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19,062 | 17,363 | 38,150 | 34,232 | ||||||||||||
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Impairment
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- | - | 28,744 | - | ||||||||||||
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General and administrative
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10,298 | 11,901 | 25,242 | 24,499 | ||||||||||||
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Taxes other than income
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2,110 | 1,397 | 3,476 | 2,527 | ||||||||||||
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Equity in (earnings) loss from unconsolidated affiliates
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(12,437 | ) | (1,306 | ) | 102,291 | (3,008 | ) | |||||||||
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Total costs and expenses
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281,773 | 325,878 | 751,685 | 599,451 | ||||||||||||
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Operating income (loss)
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35,530 | 20,178 | (97,154 | ) | 36,530 | |||||||||||
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Other income (expense):
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Interest and other income
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521 | 8 | 559 | 15 | ||||||||||||
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Loss on refinancing of unsecured debt
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- | (18,233 | ) | - | (18,233 | ) | ||||||||||
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Interest and other financing costs
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(14,602 | ) | (11,454 | ) | (29,026 | ) | (23,370 | ) | ||||||||
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Income (loss) before income taxes
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21,449 | (9,501 | ) | (125,621 | ) | (5,058 | ) | |||||||||
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Provision for income taxes
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(331 | ) | 140 | (932 | ) | (771 | ) | |||||||||
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Net income (loss)
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21,118 | (9,361 | ) | (126,553 | ) | (5,829 | ) | |||||||||
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Preferred unit distributions
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(8,915 | ) | (8,076 | ) | (17,613 | ) | (15,956 | ) | ||||||||
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Net income (loss) to common units
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$ | 12,203 | $ | (17,437 | ) | $ | (144,166 | ) | $ | (21,785 | ) | |||||
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Basic net income (loss) per common unit:
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Net income (loss) per common unit
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$ | 0.17 | $ | (0.26 | ) | $ | (2.00 | ) | $ | (0.33 | ) | |||||
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Weighted average number of common units
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72,300 | 66,143 | 72,228 | 66,065 | ||||||||||||
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Diluted net income (loss) per common unit:
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Net income (loss) per common unit
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$ | 0.14 | $ | (0.26 | ) | $ | (2.00 | ) | $ | (0.33 | ) | |||||
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Weighted average number of common units
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85,176 | 66,143 | 72,228 | 66,065 | ||||||||||||
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Distributions declared per common unit
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$ | 0.575 | $ | 0.575 | $ | 1.150 | $ | 1.150 | ||||||||
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(1) Exclusive of operations and maintenance, depreciation and amortization and impairment shown separately below.
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8
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
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Six Months Ended June 30,
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2012
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2011
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Cash Flows From Operating Activities:
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(In thousands)
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Net loss
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$ | (126,553 | ) | $ | (5,829 | ) | ||
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Adjustments to reconcile net loss to net cash provided by operating activities:
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Depreciation and amortization
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38,150 | 34,232 | ||||||
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Impairment
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28,744 | - | ||||||
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Amortization of debt issue costs
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1,978 | 1,949 | ||||||
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Equity in loss (income) from unconsolidated affiliates
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102,291 | (3,008 | ) | |||||
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Distributions from unconsolidated affiliates
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20,618 | 12,323 | ||||||
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Loss on refinancing of unsecured debt
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- | 18,233 | ||||||
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Non-cash gain on risk management activities, net
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(6,021 | ) | (1,536 | ) | ||||
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Equity-based compensation
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2,314 | 5,340 | ||||||
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Deferred tax provision
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185 | 168 | ||||||
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Other non-cash items
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346 | (10 | ) | |||||
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Changes in assets and liabilities, net of acquisitions:
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Accounts receivable
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24,756 | (15,637 | ) | |||||
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Prepayments and other current assets
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2,733 | 2,110 | ||||||
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Risk management activities
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6,105 | 5,455 | ||||||
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Accounts payable
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(45,705 | ) | 21,498 | |||||
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Other current liabilities
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3,621 | 718 | ||||||
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Net cash provided by operating activities
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53,562 | 76,006 | ||||||
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Cash Flows From Investing Activities:
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Additions to property, plant and equipment
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(142,465 | ) | (98,289 | ) | ||||
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Additions to intangible assets
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(2,740 | ) | (4,140 | ) | ||||
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Acquisitions
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- | (16,084 | ) | |||||
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Investments in unconsolidated affiliates
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(34,165 | ) | (65,027 | ) | ||||
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Distributions from unconsolidated affiliates
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1,896 | 1,249 | ||||||
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Escrow cash
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- | 6 | ||||||
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Proceeds from sale of assets
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178 | 141 | ||||||
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Other
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3,366 | (185 | ) | |||||
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Net cash used in investing activities
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(173,930 | ) | (182,329 | ) | ||||
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Cash Flows From Financing Activities:
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Proceeds from long-term debt
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330,375 | 605,000 | ||||||
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Repayment of long-term debt
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(317,000 | ) | (392,665 | ) | ||||
| Payments of premiums and expenses on unsecured debt | (14,572 | ) | ||||||
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Deferred financing costs
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(3,434 | ) | (15,670 | ) | ||||
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Distributions to unitholders
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(84,150 | ) | (76,571 | ) | ||||
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Proceeds from public offering of common units, net of underwriting discounts
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and commissions of $7,590
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188,083 | - | ||||||
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Equity offering costs
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(360 | ) | (4 | ) | ||||
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Proceeds from option exercises
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888 | 2,431 | ||||||
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Net cash provided by financing activities
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114,402 | 107,949 | ||||||
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Net (decrease) increase in cash and cash equivalents
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(5,966 | ) | 1,626 | |||||
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Cash and cash equivalents, beginning of year
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56,962 | 59,930 | ||||||
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Cash and cash equivalents, end of period
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$ | 50,996 | $ | 61,556 | ||||
9
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED BALANCE SHEETS
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June 30,
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December 31,
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2012
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2011
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(In thousands, except unit information)
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ASSETS
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Current assets:
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Cash and cash equivalents
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$ | 50,996 | $ | 56,962 | ||||
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Accounts receivable, net
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95,105 | 119,193 | ||||||
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Risk management assets
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21,995 | 4,322 | ||||||
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Prepayments and other current assets
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2,381 | 5,114 | ||||||
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Total current assets
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170,477 | 185,591 | ||||||
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Property, plant and equipment, net
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1,238,893 | 1,103,699 | ||||||
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Intangible assets, net
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160,391 | 192,425 | ||||||
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Investments in unconsolidated affiliates
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453,380 | 544,687 | ||||||
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Escrow cash
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1,848 | 1,848 | ||||||
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Risk management assets
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10,445 | 6,452 | ||||||
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Other assets, net
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27,851 | 29,895 | ||||||
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Total assets
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$ | 2,063,285 | $ | 2,064,597 | ||||
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LIABILITIES AND MEMBERS' CAPITAL
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Current liabilities:
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Accounts payable
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$ | 120,632 | $ | 155,921 | ||||
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Accrued capital expenditures
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19,712 | 7,033 | ||||||
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Accrued interest
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10,951 | 8,686 | ||||||
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Accrued tax liability
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729 | 1,182 | ||||||
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Risk management liabilities
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1,833 | 3,565 | ||||||
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Other current liabilities
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15,953 | 15,007 | ||||||
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Total current liabilities
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169,810 | 191,394 | ||||||
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Long term debt (includes $3,263 and $0 bond premium as of June 30, 2012
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and December 31, 2011, respectively)
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1,007,788 | 994,525 | ||||||
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Deferred tax liability
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2,385 | 2,199 | ||||||
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Other noncurrent liabilities
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5,105 | 4,581 | ||||||
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Commitments and contingencies
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Members’ capital:
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Series A convertible preferred units, no par value, 12,275,579 units and
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11,684,074 units issued and outstanding as of June 30, 2012 and
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December 31, 2011, respectively
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285,168 | 285,168 | ||||||
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Common units, no par value, 72,365,674 units and 66,341,458 units issued and
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outstanding as of June 30, 2012 and December 31, 2011, respectively
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1,353,504 | 1,164,853 | ||||||
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Paid in capital
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67,034 | 62,277 | ||||||
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Accumulated deficit
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(834,712 | ) | (624,121 | ) | ||||
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Accumulated other comprehensive income (loss)
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7,203 | (16,279 | ) | |||||
| 878,197 | 871,898 | |||||||
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Total liabilities and members’ capital
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$ | 2,063,285 | $ | 2,064,597 | ||||
10
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED RESULTS OF OPERATIONS
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Three Months Ended
June 30,
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Six Months Ended
June 30,
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2012
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2011
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2012
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2011
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($ In thousands)
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Total segment gross margin(1)
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$ | 72,850 | $ | 65,296 | $ | 137,678 | $ | 125,642 | ||||||||
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Operations and maintenance expenses
|
18,287 | 15,763 | 36,929 | 30,862 | ||||||||||||
|
Depreciation and amortization
|
19,062 | 17,363 | 38,150 | 34,232 | ||||||||||||
|
Impairment
|
- | - | 28,744 | - | ||||||||||||
|
General and administrative expenses
|
10,298 | 11,901 | 25,242 | 24,499 | ||||||||||||
|
Taxes other than income
|
2,110 | 1,397 | 3,476 | 2,527 | ||||||||||||
|
Equity in (earnings) loss from unconsolidated affiliates(2)(3)
|
(12,437 | ) | (1,306 | ) | 102,291 | (3,008 | ) | |||||||||
|
Operating income (loss)
|
35,530 | 20,178 | (97,154 | ) | 36,530 | |||||||||||
|
Loss on refinancing of unsecured debt
|
- | (18,233 | ) | - | (18,233 | ) | ||||||||||
|
Interest and other financing costs, net
|
(14,081 | ) | (11,446 | ) | (28,467 | ) | (23,355 | ) | ||||||||
|
Provision for income taxes
|
(331 | ) | 140 | (932 | ) | (771 | ) | |||||||||
|
Net income (loss)
|
21,118 | (9,361 | ) | (126,553 | ) | (5,829 | ) | |||||||||
|
Preferred unit distributions
|
(8,915 | ) | (8,076 | ) | (17,613 | ) | (15,956 | ) | ||||||||
|
Net income (loss) to common units
|
$ | 12,203 | $ | (17,437 | ) | $ | (144,166 | ) | $ | (21,785 | ) | |||||
|
Basic net income (loss) per common unit
|
$ | 0.17 | $ | (0.26 | ) | $ | (2.00 | ) | $ | (0.33 | ) | |||||
|
Weighted average number of common units - basic
|
72,300 | 66,143 | 72,228 | 66,065 | ||||||||||||
|
Diluted net income (loss) per common unit
|
$ | 0.14 | $ | (0.26 | ) | $ | (2.00 | ) | $ | (0.33 | ) | |||||
|
Weighted average number of common units - diluted
|
85,176 | 66,143 | 72,228 | 66,065 | ||||||||||||
|
Total segment gross margin:
|
||||||||||||||||
|
Texas
|
$ | 49,101 | $ | 46,134 | $ | 94,442 | $ | 91,145 | ||||||||
|
Oklahoma
|
20,171 | 28,665 | 44,370 | 51,747 | ||||||||||||
|
Rocky Mountains(4)
|
187 | 771 | 545 | 1,813 | ||||||||||||
|
Segment gross margin
|
69,459 | 75,570 | 139,357 | 144,705 | ||||||||||||
|
Corporate and other(5)
|
3,391 | (10,274 | ) | (1,679 | ) | (19,063 | ) | |||||||||
|
Total segment gross margin(1)
|
$ | 72,850 | $ | 65,296 | $ | 137,678 | $ | 125,642 | ||||||||
|
Segment gross margin per unit:
|
||||||||||||||||
|
Texas:
|
||||||||||||||||
|
Service throughput ($/MMBtu)
|
$ | 0.58 | $ | 0.76 | $ | 0.56 | $ | 0.76 | ||||||||
|
Oklahoma:
|
||||||||||||||||
|
Service throughput ($/MMBtu)
|
$ | 0.68 | $ | 1.11 | $ | 0.76 | $ | 1.03 | ||||||||
|
Volumes:
|
||||||||||||||||
|
Texas: (6)
|
||||||||||||||||
|
Service throughput (MMBtu/d)(7)
|
924,465 | 665,040 | 934,257 | 660,741 | ||||||||||||
|
Pipeline throughput (MMBtu/d)
|
566,388 | 444,186 | 565,949 | 422,429 | ||||||||||||
|
Plant inlet volumes (MMBtu/d)
|
834,846 | 588,533 | 834,004 | 574,794 | ||||||||||||
|
NGLs produced (Bbls/d)
|
50,146 | 26,913 | 42,745 | 25,080 | ||||||||||||
|
Oklahoma:(8)
|
||||||||||||||||
|
Service throughput (MMBtu/d)(7)
|
324,915 | 283,870 | 321,600 | 280,293 | ||||||||||||
|
Plant inlet volumes (MMBtu/d)
|
158,106 | 157,424 | 157,579 | 156,856 | ||||||||||||
|
NGLs produced (Bbls/d)
|
17,028 | 17,331 | 16,994 | 17,067 | ||||||||||||
11
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED RESULTS OF OPERATIONS
|
Capital Expenditures:
|
|
|
|
|
||||||||||||
|
Maintenance capital expenditures
|
$ | 3,798 | $ | 5,555 | $ | 6,241 | $ | 7,601 | ||||||||
|
Expansion capital expenditures
|
115,562 | 69,382 | 163,925 | 120,901 | ||||||||||||
|
Total capital expenditures
|
$ | 119,360 | $ | 74,937 | $ | 170,166 | $ | 128,502 | ||||||||
|
Operations and maintenance expenses:
|
||||||||||||||||
|
Texas
|
$ | 11,275 | $ | 8,908 | $ | 21,893 | $ | 17,733 | ||||||||
|
Oklahoma
|
6,962 | 6,794 | 14,943 | 13,013 | ||||||||||||
|
Rocky Mountains
|
50 | 61 | 93 | 116 | ||||||||||||
|
Total operations and maintenance expenses
|
$ | 18,287 | $ | 15,763 | $ | 36,929 | $ | 30,862 | ||||||||
|
|
|
|
(1)
|
Total segment gross margin is a non-GAAP financial measure. Please read “Unaudited Non-GAAP Financial Measures” for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.
|
|
|
(2)
|
During the three months ended March 31, 2012, Copano recorded a $120 million non-cash impairment charge relating to its investments in Bighorn and Fort Union.
|
|
|
(3)
|
The following table summarizes the results and volumes associated with our unconsolidated affiliates ($ in thousands):
|
|
Three Months Ended June 30,
|
|||||||||||||||||
|
2012
|
2011
|
||||||||||||||||
|
Volume
|
Equity (Earnings)/Loss
|
Volume
|
Equity (Earnings)/Loss
|
||||||||||||||
|
Eagle Ford Gathering
|
$ | (9,846 | ) | $ | 8 | ||||||||||||
|
Pipeline throughput
|
(MMBtu/d)
|
252,912 | — | ||||||||||||||
|
NGLs produced(a)
|
(Bbls/d)
|
10,169 | — | ||||||||||||||
|
Liberty Pipeline Group
|
(Bbls/d)
|
22,379 | 139 | — | 1 | ||||||||||||
|
Webb Duval(b)
|
(MMBtu/d)
|
63,199 | (47 | ) | 48,045 | (18 | ) | ||||||||||
|
Southern Dome
|
(13 | ) | (669 | ) | |||||||||||||
|
Plant inlet
|
(MMBtu/d)
|
7,352 | 11,730 | ||||||||||||||
|
NGLs produced
|
(Bbls/d)
|
249 | 432 | ||||||||||||||
|
Bighorn and Fort Union(c)
|
(MMBtu/d)
|
747,009 | (2,574 | ) | 533,329 | (615 | ) | ||||||||||
|
Six Months Ended June 30,
|
|||||||||||||||||
|
2012
|
2011
|
||||||||||||||||
|
Volume
|
Equity (Earnings)/Loss
|
Volume
|
Equity (Earnings)/Loss
|
||||||||||||||
|
Eagle Ford Gathering
|
$ | (11,908 | ) | $ | 38 | ||||||||||||
|
Pipeline throughput
|
(MMBtu/d)
|
229,991 | — | ||||||||||||||
|
NGLs produced(a)
|
(Bbls/d)
|
10,040 | — | ||||||||||||||
|
Liberty Pipeline Group
|
(Bbls/d)
|
17,690 | 274 | — | 1 | ||||||||||||
|
Webb Duval(b)
|
(MMBtu/d)
|
62,567 | (190 | ) | 48,744 | 184 | |||||||||||
|
Southern Dome
|
(401 | ) | (1,371 | ) | |||||||||||||
|
Plant inlet
|
(MMBtu/d)
|
8,684 | 11,457 | ||||||||||||||
|
NGLs produced
|
(Bbls/d)
|
306 | 413 | ||||||||||||||
|
Bighorn and Fort Union(c)
|
(MMBtu/d)
|
767,188 | 114,711 | 557,059 | (1,834 | ) | |||||||||||
|
____________________________________
|
|||||||||||||||||
|
(a) Net of NGLs produced at our Houston Central complex.
|
|||||||||||||||||
|
(b) Net of intercompany volumes.
|
|||||||||||||||||
|
(c) Changes in pipeline throughput at Fort Union did not have a material impact on gross margin because Fort Union received payments for additional volumes under long-term contractual commitments in each of the periods indicated.
|
|||||||||||||||||
|
|
(4)
|
Rocky Mountains segment gross margin includes results from producer services, including volumes purchased for resale, volumes gathered under firm capacity gathering agreements with Fort Union, volumes transported using Copano’s firm capacity agreements with Wyoming Interstate Gas Company and compressor rental services provided to Bighorn.
|
|
|
(5)
|
Corporate and other includes results attributable to Copano’s commodity risk management activities.
|
|
|
(6)
|
Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Texas segment at all plants, including plants owned by the Texas segment and plants owned by third parties.
|
|
|
(7)
|
“Service throughput” means the volume of natural gas delivered to Copano’s 100%-owned processing plants by third-party pipelines plus Copano’s “pipeline throughput,” which is the volume of natural gas transported or gathered through Copano’s pipelines.
|
|
|
(8)
|
Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including plants owned by the Oklahoma segment and plants owned by third parties.
|
12
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED NON-GAAP FINANCIAL MEASURES
|
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|||||||||||||||
|
|
|
|||||||||||||||
|
2012
|
2011
|
2012
|
2011
|
|||||||||||||
|
Reconciliation of total segment gross margin to operating income (loss):
|
(In thousands)
|
|||||||||||||||
|
Operating income (loss)
|
$ | 35,530 | $ | 20,178 | $ | (97,154 | ) | $ | 36,530 | |||||||
|
Add: Operations and maintenance expenses
|
18,287 | 15,763 | 36,929 | 30,862 | ||||||||||||
|
Depreciation and amortization
|
19,062 | 17,363 | 38,150 | 34,232 | ||||||||||||
|
Impairment
|
- | - | 28,744 | - | ||||||||||||
|
General and administrative expenses
|
10,298 | 11,901 | 25,242 | 24,499 | ||||||||||||
|
Taxes other than income
|
2,110 | 1,397 | 3,476 | 2,527 | ||||||||||||
|
Equity in (earnings) loss from unconsolidated affiliates
|
(12,437 | ) | (1,306 | ) | 102,291 | (3,008 | ) | |||||||||
|
Total segment gross margin
|
$ | 72,850 | $ | 65,296 | $ | 137,678 | $ | 125,642 | ||||||||
|
Reconciliation of EBITDA, adjusted EBITDA and total distributable
|
||||||||||||||||
|
cash flow to net income (loss):
|
||||||||||||||||
|
Net income (loss)
|
$ | 21,118 | $ | (9,361 | ) | $ | (126,553 | ) | $ | (5,829 | ) | |||||
|
Add: Depreciation and amortization
|
19,062 | 17,363 | 38,150 | 34,232 | ||||||||||||
|
Interest and other financing costs
|
14,602 | 11,454 | 29,026 | 23,370 | ||||||||||||
|
Provision for income taxes
|
331 | (140 | ) | 932 | 771 | |||||||||||
|
EBITDA
|
55,113 | 19,316 | (58,445 | ) | 52,544 | |||||||||||
|
Add: Amortization of commodity derivative options
|
5,039 | 7,357 | 10,078 | 14,627 | ||||||||||||
|
Distributions from unconsolidated affiliates
|
12,185 | 7,099 | 22,514 | 13,572 | ||||||||||||
|
Loss on refinancing of unsecured debt
|
- | 18,233 | - | 18,233 | ||||||||||||
|
Equity-based compensation
|
1,121 | 4,109 | 4,352 | 7,091 | ||||||||||||
|
Equity in (earnings) loss from unconsolidated affiliates
|
(12,437 | ) | (1,306 | ) | 102,291 | (3,008 | ) | |||||||||
|
Unrealized (gain) loss from commodity risk management activities
|
(4,980 | ) | 180 | (4,401 | ) | (363 | ) | |||||||||
|
Impairment
|
- | - | 28,744 | - | ||||||||||||
|
Other non-cash operating items
|
2,252 | (572 | ) | 3,485 | (848 | ) | ||||||||||
|
Adjusted EBITDA
|
58,293 | 54,416 | 108,618 | 101,848 | ||||||||||||
|
Less: Interest expense
|
(14,548 | ) | (10,988 | ) | (28,781 | ) | (22,594 | ) | ||||||||
|
Current income tax expense and other
|
(418 | ) | (293 | ) | (747 | ) | (624 | ) | ||||||||
|
Maintenance capital expenditures
|
(3,798 | ) | (5,555 | ) | (6,241 | ) | (7,601 | ) | ||||||||
|
Total distributable cash flow (1)
|
$ | 39,529 | $ | 37,580 | $ | 72,849 | $ | 71,029 | ||||||||
|
Actual quarterly distribution
|
$ | 42,336 | $ | 38,687 | ||||||||||||
|
Total distributable cash flow coverage
|
93 | % | 97 | % | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Prior to any retained cash reserves established by Copano's Board of Directors.
|
||||||||||
13