Attached files
| file | filename |
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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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Copano Energy, L.L.C.
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Contacts:
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Carl A. Luna, SVP and CFO
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Copano Energy, L.L.C.
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713-621-9547
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FOR IMMEDIATE RELEASE
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Jack Lascar / jlascar@drg-l.com
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Anne Pearson/ apearson@drg-l.com
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DRG&L/ 713-529-6600
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COPANO ENERGY REPORTS FIRST QUARTER 2011 RESULTS
Operating Segment Gross Margin improves 8% over Fourth Quarter
HOUSTON, May 5, 2011 — Copano Energy, L.L.C. (NASDAQ: CPNO) today announced its financial results for the three months ended March 31, 2011.
“Our operating segment gross margin improved 8% from the fourth quarter despite the impact of severe winter weather in Oklahoma and Texas as well as an unscheduled outage at our Saint Jo plant in north Texas during February,” said R. Bruce Northcutt, Copano Energy’s President and Chief Executive Officer. “Due to lower strike prices on our 2011 hedges, the contribution from our hedging program was significantly less compared to the fourth quarter but was almost offset by strong margins in our Texas segment, driven by higher commodity prices, and volume growth from the Eagle Ford Shale play.”
“We remain on track with our Eagle Ford build-out and expect it to be a significant contributor to improving our operating segment gross margin as projects are completed and come on-line later this year,” Northcutt added.
First Quarter Financial Results
Total distributable cash flow for the first quarter of 2011 increased 8% to $33.4 million from $30.9 million for the first quarter of 2010 but it decreased 11% from $37.5 million in the fourth quarter of 2010. First quarter 2011 total distributable cash flow represents 87% coverage of the first quarter distribution of $0.575 per unit, based on common units outstanding on the distribution record date.
Revenue for the first quarter of 2011 increased 9% to $289.9 million compared to $266.7 million for the first quarter of 2010 and increased 11% compared to $260.7 million in the fourth quarter of 2010. Operating segment gross margin increased 32% to $69.1 million compared to $52.5 million for the first quarter of 2010 and increased 8% compared to $64.2 million in the fourth quarter of 2010. Total segment gross margin increased 18% to $60.3 million for the first quarter of 2011 compared to $51.1 million for the first quarter of 2010, but decreased 2% compared to $61.5 million for the fourth quarter of 2010.
Page 1 of 12
Adjusted EBITDA for the first quarter of 2011 was $39.5 million compared to $35.7 million for the first quarter of 2010 and $43.8 million for the fourth quarter of 2010. Adjusted EBITDA includes non-cash amortization expense relating to the option component of Copano’s risk management portfolio of $7.3 million for the first quarter of 2011, $8.0 million for the first quarter of 2010 and $8.2 million for the fourth quarter of 2010.
Net income was $3.5 million for the first quarter of 2011 compared to net loss of $1.3 million for the first quarter of 2010. Net income for the first quarter of 2011 is prior to deducting in-kind distributions on Copano’s Series A convertible preferred units issued in July 2010.
Net loss to common units after deducting $7.9 million of in-kind preferred unit distributions totaled $4.3 million, or $0.07 per unit on a diluted basis, for the first quarter of 2011 compared to net loss to common units of $1.3 million, or $0.02 per unit on a diluted basis, for the first quarter of 2010. Weighted average diluted units outstanding totaled 66.0 million for the first quarter of 2011 as compared to 58.2 million for the same period in 2010.
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.
First Quarter Operating Results by Segment
Copano manages its business in three geographical operating segments: Texas, which provides midstream natural gas services in Texas and also includes a processing plant in southwest Louisiana; Oklahoma, which provides midstream natural gas services in central and east Oklahoma; and the Rocky Mountains, which provides midstream natural gas services to producers in Wyoming’s Powder River Basin and includes managing member interests in Bighorn Gas Gathering, L.L.C. (Bighorn) of 51% and in Fort Union Gas Gathering, L.L.C. (Fort Union) of 37.04%.
Texas
Segment gross margin for Texas increased to $45.0 million for the first quarter of 2011 compared to $27.2 million for the first quarter of 2010 and $38.5 million for the fourth quarter of 2010, increases of 66% and 17%, respectively. The 66% year-over-year increase resulted primarily from (i) a 46% increase in realized margins on service throughput compared to the first quarter of 2010 ($0.76 per MMBtu in 2011 compared to $0.52 per MMBtu in 2010) reflecting higher NGL prices, (ii) the impact of Copano’s fractionation facilities, which were placed in service in May 2010 and (iii) an increase of pipeline throughput associated with fee-based contracts in the Eagle Ford Shale and the north Barnett Shale Combo plays.
Page 2 of 12
During the first quarter of 2011, weighted-average NGL prices on the Mt. Belvieu index, based on Copano’s product mix for the period, were $51.22 per barrel compared to $47.66 per barrel during the first quarter of 2010, an increase of 7%. During the first quarter of 2011, natural gas prices on the Houston Ship Channel index averaged $4.06 per MMBtu compared to $5.36 per MMBtu during the first quarter of 2010, a decrease of 24%.
During the first quarter of 2011, the Texas segment provided gathering, transportation and processing services for an average of 654,996 MMBtu/d of natural gas compared to 582,958 MMBtu/d for the first quarter of 2010, an increase of 12%. The Texas segment gathered an average of 399,033 MMBtu/d of natural gas, an increase of 26% over last year’s first quarter, primarily due to increased volumes from the Eagle Ford Shale and north Barnett Shale Combo plays. Processed volumes increased 23% to an average of 560,903 MMBtu/d of natural gas at Copano’s plants and third-party plants. NGL production increased 51% to an average of 23,228 Bbls/d at Copano’s plants and third-party plants, reflecting increased volumes behind Copano’s Houston Central plant, driven by a 70,000 MMBtu/d increase in Eagle Ford Shale volumes, and behind the Saint Jo plant in the north Barnett Shale Combo play.
Oklahoma
Segment gross margin for Oklahoma decreased 5% to $23.1 million for the first quarter of 2011 compared to $24.3 million for the first quarter of 2010 and decreased 6% from $24.5 million for the fourth quarter of 2010. The year-over-year decrease resulted primarily from a 12% decrease in realized margins on service throughput compared to the first quarter of 2010 ($0.95 per MMBtu in 2011 compared to $1.08 per MMBtu in 2010), primarily reflecting lower natural gas prices. During the first quarter of 2011, weighted-average NGL prices on the Conway index, based on Copano’s product mix for the period, were $46.36 per barrel compared to $44.44 per barrel during the first quarter of 2010, an increase of 4%. During the first quarter of 2011, natural gas prices on the CenterPoint East index averaged $3.93 per MMBtu compared to $5.22 per MMBtu during the first quarter of 2010, a decrease of 25%.
The Oklahoma segment gathered an average of 269,550 MMBtu/d of natural gas, processed an average of 147,710 MMBtu/d of natural gas and produced an average of 16,037 Bbls/d of NGLs at its own plants and third-party plants during the first quarter of 2011. Compared to the first quarter of 2010, this represents an 8% increase in service throughput, a 3% decrease in plant inlet volumes and a 5% increase in NGL production. The increase in service throughput is primarily attributable to increased drilling and production of lean gas in the Woodford Shale area near Copano’s Cyclone Mountain system, offset by normal production declines in rich gas areas.
Page 3 of 12
Rocky Mountains
Segment gross margin for Rocky Mountains totaled $1.0 million in the first quarter of 2011 compared to $1.1 million for the first and fourth quarters of 2010. The Rocky Mountains segment gross margin results do not include the financial results and volumes associated with Copano’s interests in Bighorn and Fort Union, which are accounted for under the equity method of accounting and are shown in Copano’s financial statements under “Equity in earnings from unconsolidated affiliates.” Average pipeline throughput for Bighorn and Fort Union on a combined basis decreased 38% to 581,051 MMBtu/d in the first quarter of 2011 as compared to 931,319 MMBtu/d in the first quarter of 2010. The volume decline is primarily due to certain Fort Union shippers diverting gas volumes to TransCanada’s Bison Pipeline upon its start up in January 2011. However, Fort Union also received payments based on an additional 288,966 MMBtu/d in long-term contractually committed volumes for the three months ended March 31, 2011.
Corporate and Other
Corporate and other gross margin includes Copano’s commodity risk management activities. These activities contributed a loss of $8.8 million for the first quarter of 2011 compared to a loss of $2.6 million for the fourth quarter of 2010 and a loss of $1.4 million for the first quarter of 2010. The loss for the first quarter of 2011 included $7.3 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio and $2.1 million of net cash settlements paid for expired commodity derivative instruments offset by $0.6 million of unrealized gain on undesignated economic hedges. The first quarter 2010 loss included $8.0 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio and $0.4 million of unrealized mark-to-market losses on undesignated economic hedges offset by $7.0 million of net cash settlements received for expired commodity derivative instruments.
Cash Distributions
On April 13, 2011, Copano announced its first quarter 2011 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 fourth quarter of 2010 and will be paid on May 12, 2011 to common unitholders of record at the close of business on April 29, 2011.
Page 4 of 12
Conference Call Information
Copano will hold a conference call to discuss its first quarter 2011 financial results on May 6, 2011 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time). To participate in the call, dial (480) 629-9723 and ask for the Copano call 10 minutes prior to the start time, or access it live over the internet at www.copanoenergy.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 May 13, 2011 by calling (303) 590-3030 and using the pass code 4430941#.
Use of Non-GAAP Financial Measures
This news release and the accompanying schedules include the 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), income (loss) from continuing operations, cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Copano uses non-GAAP financial measures to measure its core profitability, liquidity position and to assess the financial performance of its assets. Copano believes that investors benefit from access to the same financial measures that its management uses in evaluating Copano’s core profitability, liquidity position and financial performance.
Houston-based Copano Energy, L.L.C. is a midstream natural gas company with operations in Texas, Oklahoma, Wyoming and Louisiana. Its assets include approximately 6,400 miles of active natural gas gathering and transmission pipelines, 260 miles of NGL pipelines and nine natural gas processing plants, with more than one billion cubic feet per day of combined processing capacity and 22,000 barrels per day of fractionation capacity. For more information, please visit www.copanoenergy.com.
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 the forward-looking statements include, without limitation, the
Page 5 of 12
following risks and uncertainties, many of which are beyond Copano’s control: The volatility of prices and market demand for natural gas and NGLs; 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 and producers’ ability to drill and successfully complete and attach new natural gas supplies and the availability of downstream transportation systems and other facilities for natural gas and NGLs; 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 filings with the Securities and Exchange Commission.
– financial statements to follow –
Page 6 of 12
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months Ended March 31,
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2011
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2010
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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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$ | 103,795 | $ | 120,216 | ||||
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Natural gas liquids sales
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149,001 | 119,318 | ||||||
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Transportation, compression and processing fees
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24,471 | 13,114 | ||||||
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Condensate and other
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12,658 | 14,018 | ||||||
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Total revenue
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289,925 | 266,666 | ||||||
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Costs and expenses:
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Cost of natural gas and natural gas liquids(1)
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223,730 | 209,865 | ||||||
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Transportation (1)
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5,849 | 5,676 | ||||||
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Operations and maintenance
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15,099 | 12,103 | ||||||
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Depreciation and amortization
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16,869 | 15,201 | ||||||
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General and administrative
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12,598 | 10,542 | ||||||
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Taxes other than income
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1,130 | 1,162 | ||||||
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Equity in earnings from unconsolidated affiliates
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(1,702 | ) | (1,795 | ) | ||||
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Total costs and expenses
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273,573 | 252,754 | ||||||
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Operating income
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16,352 | 13,912 | ||||||
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Other income (expense):
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Interest and other income
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7 | 7 | ||||||
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Interest and other financing costs
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(11,916 | ) | (14,945 | ) | ||||
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Income (loss) before income taxes
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4,443 | (1,026 | ) | |||||
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Provision for income taxes
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(911 | ) | (234 | ) | ||||
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Net income (loss)
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3,532 | (1,260 | ) | |||||
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Preferred unit distributions
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(7,880 | ) | - | |||||
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Net loss to common units
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$ | (4,348 | ) | $ | (1,260 | ) | ||
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Basic and diluted net loss per common unit
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$ | (0.07 | ) | $ | (0.02 | ) | ||
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Weighted average number of common units
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65,985 | 58,206 | ||||||
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Distributions declared per common unit
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$ | 0.575 | $ | 0.575 | ||||
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(1) Exclusive of operations and maintenance and depreciation and amortization shown separately below.
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Page 7 of 12
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
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Three Months Ended March 31,
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2011
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2010
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Cash Flows From Operating Activities:
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(In thousands)
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Net income (loss)
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$
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3,532
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$
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(1,260)
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Adjustments to reconcile net income (loss) to net cash provided by operating activities:
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Depreciation and amortization
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16,869
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15,201
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Amortization of debt issue costs
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982
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895
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Equity in earnings from unconsolidated affiliates
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(1,702)
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(1,795)
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Distributions from unconsolidated affiliates
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5,531
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5,765
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Non-cash (loss) gain on risk management activities, net
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(1,216)
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533
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Equity-based compensation
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2,473
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2,703
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Deferred tax provision
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602
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27
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Other non-cash items
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55
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(301)
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Changes in assets and liabilities:
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Accounts receivable
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(696)
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2,124
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Prepayments and other current assets
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930
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1,167
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Risk management activities
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(1,917)
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597
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Accounts payable
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2,519
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2,063
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Other current liabilities
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569
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|
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1,445
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Net cash provided by operating activities
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28,531
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29,164
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Cash Flows From Investing Activities:
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Additions to property, plant and equipment
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(40,009)
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(19,162)
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Additions to intangible assets
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(1,307)
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(263)
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Investments in unconsolidated affiliates
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(26,800)
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(435)
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Distributions from unconsolidated affiliates
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942
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972
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Proceeds from sale of assets
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159
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259
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Other
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(155)
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188
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Net cash used in investing activities
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(67,170)
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(18,441)
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Cash Flows From Financing Activities:
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Proceeds from long-term debt
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85,000
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35,000
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Repayment of long-term debt
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-
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(170,000)
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Deferred financing costs
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(114)
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-
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Distributions to unitholders
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(37,928)
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(31,457)
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Proceeds from public offering of common units, net of underwriting discounts
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and commissions of $7,223
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-
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164,786
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Equity offering costs
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-
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(272)
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Proceeds from option exercises
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1,139
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676
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Net cash provided by (used in) financing activities
|
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48,097
|
|
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(1,267)
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|
|
|
|
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Net increase in cash and cash equivalents
|
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9,458
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9,456
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Cash and cash equivalents, beginning of year
|
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59,930
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44,692
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Cash and cash equivalents, end of period
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$
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69,388
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$
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54,148
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Page 8 of 12
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED BALANCE SHEETS
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March 31,
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December 31,
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2011
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2010
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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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$ | 69,388 | $ | 59,930 | ||||
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Accounts receivable, net
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97,528 | 96,662 | ||||||
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Risk management assets
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3,875 | 7,836 | ||||||
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Prepayments and other current assets
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4,249 | 5,179 | ||||||
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Total current assets
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175,040 | 169,607 | ||||||
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Property, plant and equipment, net
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950,195 | 912,157 | ||||||
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Intangible assets, net
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186,994 | 188,585 | ||||||
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Investments in unconsolidated affiliates
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626,122 | 604,304 | ||||||
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Escrow cash
|
1,850 | 1,856 | ||||||
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Risk management assets
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12,256 | 11,943 | ||||||
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Other assets, net
|
18,322 | 18,541 | ||||||
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Total assets
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$ | 1,970,779 | $ | 1,906,993 | ||||
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LIABILITIES AND MEMBERS' CAPITAL
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Current liabilities:
|
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Accounts payable
|
$ | 133,837 | $ | 117,706 | ||||
|
Accrued interest
|
8,790 | 10,621 | ||||||
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Accrued tax liability
|
1,222 | 913 | ||||||
|
Risk management liabilities
|
10,638 | 9,357 | ||||||
|
Other current liabilities
|
15,275 | 14,495 | ||||||
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Total current liabilities
|
169,762 | 153,092 | ||||||
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|
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Long term debt (includes $524 and $546 bond premium as of March 31, 2011
|
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and December 31, 2010, respectively)
|
677,714 | 592,736 | ||||||
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Deferred tax provision
|
2,485 | 1,883 | ||||||
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Risk management and other noncurrent liabilities
|
3,673 | 4,525 | ||||||
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|
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Commitments and contingencies (Note 9)
|
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|
Members’ capital:
|
||||||||
|
Series A convertible preferred units, no par value, 10,849,826 units and
|
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|
10,585,197 units issued and outstanding as of March 31, 2011 and
|
||||||||
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December 31, 2010, respectively
|
285,172 | 285,172 | ||||||
|
Common units, no par value, 66,043,613 units and 65,915,173 units issued and
|
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outstanding as of March 31, 2011 and December 31, 2010, respectively
|
1,162,791 | 1,161,652 | ||||||
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Paid in capital
|
55,162 | 51,743 | ||||||
|
Accumulated deficit
|
(348,357 | ) | (313,454 | ) | ||||
|
Accumulated other comprehensive loss
|
(37,623 | ) | (30,356 | ) | ||||
|
|
1,117,145 | 1,154,757 | ||||||
|
Total liabilities and members’ capital
|
$ | 1,970,779 | $ | 1,906,993 | ||||
Page 9 of 12
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
OPERATING STATISTICS
(Unaudited)
|
Three Months Ended March 31,
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2011
|
2010
|
|||||||
|
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|
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($ In thousands)
|
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Total segment gross margin(1)
|
$ | 60,346 | $ | 51,125 | ||||
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Operations and maintenance expenses
|
15,099 | 12,103 | ||||||
|
Depreciation and amortization
|
16,869 | 15,201 | ||||||
|
General and administrative expenses
|
12,598 | 10,542 | ||||||
|
Taxes other than income
|
1,130 | 1,162 | ||||||
|
Equity in earnings from unconsolidated affiliates(2)(3)(4)
|
(1,702 | ) | (1,795 | ) | ||||
|
Operating income
|
16,352 | 13,912 | ||||||
|
Interest and other financing costs, net
|
(11,909 | ) | (14,938 | ) | ||||
|
Provision for income taxes
|
(911 | ) | (234 | ) | ||||
|
Net income (loss)
|
3,532 | (1,260 | ) | |||||
|
Preferred unit distributions
|
(7,880 | ) | - | |||||
|
Net loss to common units
|
$ | (4,348 | ) | $ | (1,260 | ) | ||
|
Total segment gross margin:
|
||||||||
|
Texas
|
$ | 45,011 | $ | 27,165 | ||||
|
Oklahoma
|
23,082 | 24,275 | ||||||
|
Rocky Mountains(5)
|
1,042 | 1,103 | ||||||
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Segment gross margin
|
69,135 | 52,543 | ||||||
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Corporate and other(6)
|
(8,789 | ) | (1,418 | ) | ||||
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Total segment gross margin(1)
|
$ | 60,346 | $ | 51,125 | ||||
|
Segment gross margin per unit:
|
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|
Texas:
|
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|
Service throughput ($/MMBtu)
|
$ | 0.76 | $ | 0.52 | ||||
|
Oklahoma:
|
||||||||
|
Service throughput ($/MMBtu)
|
$ | 0.95 | $ | 1.08 | ||||
|
Volumes:
|
||||||||
|
Texas: (7)
|
||||||||
|
Service throughput (MMBtu/d)(8)
|
654,996 | 582,958 | ||||||
|
Pipeline throughput (MMBtu/d)
|
399,033 | 316,937 | ||||||
|
Plant inlet volumes (MMBtu/d)
|
560,903 | 457,233 | ||||||
|
NGLs produced (Bbls/d)
|
23,228 | 15,339 | ||||||
|
Oklahoma:(9)
|
||||||||
|
Service throughput (MMBtu/d)(8)
|
269,550 | 248,784 | ||||||
|
Plant inlet volumes (MMBtu/d)
|
147,710 | 152,190 | ||||||
|
NGLs produced (Bbls/d)
|
16,037 | 15,334 | ||||||
|
Capital Expenditures:
|
||||||||
|
Maintenance capital expenditures
|
$ | 2,046 | $ | 1,431 | ||||
|
Expansion capital expenditures
|
51,520 | 20,406 | ||||||
|
Total capital expenditures
|
$ | 53,566 | $ | 21,837 | ||||
|
Operations and maintenance expenses:
|
||||||||
|
Texas
|
$ | 8,825 | $ | 6,569 | ||||
|
Oklahoma
|
6,219 | 5,433 | ||||||
|
Rocky Mountains
|
55 | 101 | ||||||
|
Total operations and maintenance expenses
|
$ | 15,099 | $ | 12,103 | ||||
|
|
|
|
(1)
|
Total segment gross margin is a non-GAAP financial measure. Please read “— Non-GAAP Financial Measures” for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.
|
|
|
(2)
|
Includes results and volumes associated with our interests in Bighorn and Fort Union. Combined volumes gathered by Bighorn and Fort Union were 581,051 MMBtu/d and 931,319 MMBtu/d for the three months ended March 31, 2011 and 2010, respectively. The volume decline is primarily due to certain Fort Union shippers diverting gas volumes to TransCanada’s Bison Pipeline upon its start up in January 2011. In addition, Fort Union also received payments based on an additional 288,966 MMBtu/d in long-term contractually committed volumes for the three months ended March 31, 2011.
|
|
|
(3)
|
Includes results and volumes associated with our interest in Southern Dome, LLC (“Southern Dome”). For the three months ended March 31, 2011, plant inlet volumes for Southern Dome averaged 11,182 MMBtu/d and NGLs produced averaged 393 Bbls/d. For the three months ended March 31, 2010, plant inlet volumes for Southern Dome averaged 14,130 MMBtu/d and NGLs produced averaged 499 Bbls/d.
|
|
|
(4)
|
Includes results and volumes associated with our interest in Webb/Duval Gatherers (“Webb Duval”). Gross volumes transported by Webb Duval, net of intercompany volumes, were 49,450 MMBtu/d and 60,091 MMBtu/d for the three months ended March 31, 2011 and 2010, respectively.
|
Page 10 of 12
|
|
(5)
|
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 our firm capacity agreements with Wyoming Interstate Gas Company and compressor rental services provided to Bighorn. Excludes results and volumes associated with our interests in Bighorn and Fort Union.
|
|
|
(6)
|
Corporate and other includes results attributable to our commodity risk management activities.
|
|
|
(7)
|
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. Plant inlet volumes averaged 543,151 MMBtu/d and NGLs produced averaged 22,122 Bbls/d for the three months ended March 31, 2011 for plants owned by the Texas segment. Plant inlet volumes averaged 450,417 MMBtu/d and NGLs produced averaged 14,852 Bbls/d for the three months ended March 31, 2010 for plants owned by the Texas segment.
|
|
|
(8)
|
“Service throughput” means the volume of natural gas delivered to our wholly owned processing plants by third-party pipelines plus our “pipeline throughput,” which is the volume of natural gas transported or gathered through our pipelines.
|
|
|
(9)
|
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. For the three months ended March 31, 2011, plant inlet volumes averaged 114,646 MMBtu/d and NGLs produced averaged 13,181 Bbls/d for plants owned by the Oklahoma segment. For the three months ended March 31, 2010, plant inlet volumes averaged 117,602 MMBtu/d and NGLs produced averaged 12,468 Bbls/d for plants owned by the Oklahoma segment.
|
Page 11 of 12
Non-GAAP Financial Measures
The following table presents a reconciliation of the non-GAAP financial measures of (i) total [Missing Graphic Reference]segment gross margin (which consists of the sum of individual segment gross margins and the results of risk management activities, which are included in corporate and other) to the GAAP financial measure of operating income (loss), (ii) EBITDA and adjusted EBITDA to the GAAP financial measures of net income (loss) and cash flows from operating activities and (iii) total distributable cash flow to the GAAP financial measure of net income (loss), for each of the periods indicated (in thousands).
|
|
Three Months Ended March 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Reconciliation of total segment gross margin to operating income:
|
|
|
||||||
|
Operating income
|
$ | 16,352 | $ | 13,912 | ||||
|
Add: Operations and maintenance expenses
|
15,099 | 12,103 | ||||||
|
Depreciation and amortization
|
16,869 | 15,201 | ||||||
|
General and administrative expenses
|
12,598 | 10,542 | ||||||
|
Taxes other than income
|
1,130 | 1,162 | ||||||
|
Equity in earnings from unconsolidated affiliates
|
(1,702 | ) | (1,795 | ) | ||||
|
Total segment gross margin
|
$ | 60,346 | $ | 51,125 | ||||
|
Reconciliation of EBITDA and adjusted EBITDA to net income (loss):
|
||||||||
|
Net income (loss)
|
$ | 3,532 | $ | (1,260 | ) | |||
|
Add: Depreciation and amortization
|
16,869 | 15,201 | ||||||
|
Interest and other financing costs
|
11,916 | 14,945 | ||||||
|
Provision for income taxes
|
911 | 234 | ||||||
|
EBITDA
|
33,228 | 29,120 | ||||||
|
Add: Amortization of difference between the carried investment and
|
||||||||
|
the underlying equity in net assets of equity investments
|
4,421 | 4,645 | ||||||
|
Copano’s share of depreciation and amortization included
|
||||||||
|
in equity in earnings from unconsolidated affiliates
|
1,647 | 1,537 | ||||||
|
Copano’s share of interest and other financing costs incurred by our equity method investments
|
177 | 371 | ||||||
|
Adjusted EBITDA
|
$ | 39,473 | $ | 35,673 | ||||
|
|
||||||||
|
Reconciliation of EBITDA and adjusted EBITDA to cash flows from operating activities:
|
||||||||
|
Cash flow provided by operating activities
|
$ | 28,531 | $ | 29,164 | ||||
|
Add: Cash paid for interest and other financing costs
|
10,934 | 14,050 | ||||||
|
Equity in earnings from unconsolidated affiliates
|
1,702 | 1,795 | ||||||
|
Distributions from unconsolidated affiliates
|
(5,531 | ) | (5,765 | ) | ||||
|
Risk management activities
|
1,917 | (597 | ) | |||||
|
Changes in working capital and other
|
(4,325 | ) | (9,527 | ) | ||||
|
EBITDA
|
33,228 | 29,120 | ||||||
|
Add: Amortization of difference between the carried investment and
|
||||||||
|
the underlying equity in net assets of equity investments
|
4,421 | 4,645 | ||||||
|
Copano’s share of depreciation and amortization included
|
||||||||
|
in equity in earnings from unconsolidated affiliates
|
1,647 | 1,537 | ||||||
|
Copano’s share of interest and other financing costs incurred by our equity method investments
|
177 | 371 | ||||||
|
Adjusted EBITDA
|
$ | 39,473 | $ | 35,673 | ||||
|
Reconciliation of net income (loss) to total distributable cash flow:
|
||||||||
|
Net income (loss)
|
$ | 3,532 | $ | (1,260 | ) | |||
|
Add: Depreciation and amortization
|
16,869 | 15,201 | ||||||
|
Amortization of commodity derivative options
|
7,270 | 7,978 | ||||||
|
Amortization of debt issue costs
|
982 | 895 | ||||||
|
Equity-based compensation
|
2,982 | 2,715 | ||||||
|
Distributions from unconsolidated affiliates
|
6,472 | 6,737 | ||||||
|
Unrealized (gain) loss associated with line fill contributions and gas imbalances
|
(219 | ) | 1,582 | |||||
|
Unrealized (gain) loss on derivative activity
|
(1,216 | ) | 533 | |||||
|
Deferred taxes and other
|
525 | (301 | ) | |||||
|
Less: Equity in earnings from unconsolidated affiliates
|
(1,702 | ) | (1,795 | ) | ||||
|
Maintenance capital expenditures
|
(2,046 | ) | (1,431 | ) | ||||
|
Total distributable cash flow (1)
|
$ | 33,449 | $ | 30,854 | ||||
|
|
||||||||
|
Actual quarterly distribution (“AQD”)
|
$ | 38,538 | $ | 38,134 | ||||
|
Total distributable cash flow coverage of AQD
|
87 | % | 81 | % | ||||
|
|
||||||||
|
|
||||||||
|
(1) Prior to any retained cash reserves established by Copano’s Board of Directors.
|
||||||||
Page 12 of 12