| Exhibit 99.1 |
| Copano Energy, L.L.C. | News Release |
| |
| | Contacts: | Matt Assiff, Senior VP & CFO |
| | | Copano Energy, L.L.C. |
FOR IMMEDIATE RELEASE | | 713-621-9547 |
| | | |
| | | Jack Lascar / jlascar@drg-e.com |
| | | Anne Pearson/ apearson@drg-e.com |
| | | DRG&E / 713-529-6600 |
COPANO ENERGY REPORTS SECOND QUARTER 2009 RESULTS
HOUSTON, August 5, 2009 — Copano Energy, L.L.C. (NASDAQ: CPNO) today announced its financial results for the three and six months ended June 30, 2009.
“We are pleased with our second quarter 2009 results in light of the challenging comparison with the prior year period when quarterly average crude oil and natural gas liquids prices reached record levels,” said John Eckel, Copano Energy’s Chairman and Chief Executive Officer. “During the second quarter 2009, processed gas volumes for Copano and its unconsolidated affiliates grew by 2% sequentially from the prior quarter. Unprocessed gas volumes fell 5% partly reflecting seasonal factors, and overall volumes fell 3%. As a result of increased unit margins, segment gross margin for our operating segments increased 17% from the first quarter of 2009. The results also reflect the progress of our continuing cost control efforts,” Mr. Eckel added.
Second Quarter Financial Results
Revenue for the second quarter of 2009 decreased 60% to $202.9 million compared with $501.3 million for the second quarter of 2008. Total segment gross margin decreased 26% to $53.4 million for the second quarter of 2009, from $72.1 million for the same period a year ago.
Adjusted EBITDA for the second quarter of 2009 decreased 32% to $39.0 million compared with $57.4 million for the second quarter of 2008. Adjusted EBITDA is earnings before interest, taxes, depreciation and amortization, adjusted to include Copano’s share of depreciation, amortization and interest costs attributable to its unconsolidated affiliates. Non-cash charges incurred during the second quarter of 2009 that were not added back in determining adjusted EBITDA include amortization expense of $9.3 million related to the option component of Copano’s risk management portfolio.
Total distributable cash flow for the second quarter of 2009, which includes amortization expense related to the option component of Copano’s risk management portfolio, totaled $32.9 million compared to $49.0 million for the second quarter of 2008. Second quarter 2009 total distributable cash
flow represents 103% coverage of the second quarter 2009 distribution of $0.575 per unit. During the second quarter of 2009, Copano did not repurchase any of its unsecured notes whereas in the prior two quarters, Copano recognized gains of $3.9 million and $15.3 million, respectively, from unsecured note repurchases.
Net income decreased by 74% to $6.0 million, or $0.10 per unit on a diluted basis, for the second quarter of 2009 compared to net income of $23.2 million, or $0.40 per unit on a diluted basis, for the second quarter of 2008. The major drivers of Copano’s net income for the second quarter of 2009 compared to the second quarter of 2008 included:
| · | a decrease in total segment gross margin of $18.7 million consisting of a $46.9 million decrease in operating segment gross margins primarily reflecting average NGL price declines of 59% in the Conway index and 57% in the Mt. Belvieu index and lower overall service throughput volumes, offset by an increase of $28.2 million from Copano’s commodity risk management activities; |
| · | a decrease of $2.7 million in equity in earnings of unconsolidated affiliates; and |
| · | an increase in depreciation and amortization expenses of $1.0 million primarily related to expanded operations in north Texas; |
offset by:
| · | a decrease of $4.1 million in interest expense as a result of (i) a decrease of noncash mark-to-market charges on interest rate swaps of $5.4 million offset by (ii) an increase in interest expense of $1.3 million as a result of increased average outstanding borrowings slightly offset by lower average interest rates between the periods; and |
| · | a decrease in general and administrative expenses of $1.6 million primarily related to successful cost reduction efforts, including reduced employee compensation expense and third-party service provider fees. |
Weighted average diluted units decreased slightly to 57.9 million for the second quarter of 2009 compared with 58.0 million for the same period in 2008.
Segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow are non-GAAP financial measures that are defined and reconciled to the most directly comparable GAAP measures at the end of this news release.
Second Quarter Operating Results by Segment
Copano manages its business in three geographical operating segments: Oklahoma, Texas and the Rocky Mountains.
Oklahoma
The Oklahoma segment provides midstream natural gas services in central and east Oklahoma and owns a crude oil pipeline located in south Oklahoma and north Texas.
During the second quarter of 2009, segment gross margin for the Oklahoma segment decreased 61% to $18.6 million compared to $47.9 million for the second quarter of 2008. The decrease resulted primarily from a 67% decline in realized margins on service throughput from the second quarter of 2008 ($0.76 per MMBtu in 2009 compared with $2.30 per MMBtu in 2008), reflecting lower NGL and natural gas prices. During the second quarter of 2009, NGL prices based on Conway index prices and Copano’s weighted average product production mix averaged $25.57 per barrel compared with $62.27 per barrel during the second quarter of 2008, a decrease of $36.70, or 59%. During the second quarter of 2009, natural gas prices based on CenterPoint East index prices averaged $2.70 per MMBtu compared with $9.26 per MMBtu during the second quarter of 2008, a decrease of $6.56, or 71%.
The decrease in segment gross margin for the Oklahoma segment was partially offset by increased service throughput and processing volumes. The Oklahoma segment gathered an average of 267,576 MMBtu/d of natural gas, processed an average of 166,846 MMBtu/d of natural gas and produced an average of 15,981 Bbls/d of NGLs at its plants and third-party plants during the second quarter of 2009, representing increases of 17%, 7% and 3%, respectively, compared with the second quarter of 2008. During the second quarter of 2008, the Oklahoma segment gathered an average of 228,941 MMBtu/d of natural gas, processed an average of 155,430 MMBtu/d of natural gas and produced an average of 15,465 Bbls/d of NGLs.
Texas
The Texas segment provides midstream natural gas services in Texas and also owns a processing plant in southwest Louisiana.
Segment gross margin for the Texas segment decreased approximately 42% in the second quarter of 2009 to $23.3 million compared to $40.5 million for the second quarter of 2008. The decrease resulted primarily from a 36% decline in realized margins on service throughput from the second quarter of 2008 ($0.41 per MMBtu in 2009 compared with $0.64 per MMBtu in 2008), reflecting lower NGL prices. During the second quarter of 2009, NGL prices based on Mt. Belvieu index prices and Copano’s weighted average product production mix averaged $30.09 per barrel compared with $69.42 per barrel during the second quarter of 2008, a decrease of $39.33, or 57%.
The decrease in segment gross margin for the Texas segment was also attributable to decreased service throughput and processing volumes. During the second quarter of 2009, the Texas segment
provided gathering, transportation and processing services for an average of 630,674 MMBtu/d of natural gas compared with 700,545 MMBtu/d for the second quarter of 2008. The Texas segment gathered an average of 290,005 MMBtu/d of natural gas and processed an average of 559,597 MMBtu/d of natural gas during the second quarter of 2009 representing decreases of 8% and 11%, respectively, as compared with the second quarter of 2008. The Texas segment produced an average of 18,425 Bbls/d of NGLs at its plants and third-party plants during the second quarter of 2009, an increase of 4% as compared with the second quarter of 2008. During the second quarter of 2008, the Texas segment gathered an average of 313,523 MMBtu/d of natural gas, processed an average of 629,334 MMBtu/d of natural gas and produced an average of 17,721 Bbls/d of NGLs.
Rocky Mountains
The Rocky Mountains segment provides services to producers in Wyoming’s Powder River Basin and owns managing member interests in Bighorn of 51% and in Fort Union of 37.04%.
Segment gross margin for the Rocky Mountains segment was $0.7 million for the second quarter of 2009 compared with $1.2 million for the same period in 2008. Producer services throughput, which represents volumes purchased for resale, volumes gathered using firm capacity gathering agreements with Fort Union and volumes transported under firm capacity transportation agreements with Wyoming Interstate Gas Company (WIC), or using additional capacity that Copano obtains on WIC, averaged 166,022 MMBtu/d for the second quarter of 2009, as compared to 229,513 MMBtu/d for the same period in 2008. The decrease in segment gross margin was the result of lower volumes and unit margins primarily due to a continuing softened pricing environment in the Rocky Mountains creating disincentives for producers to continue drilling programs or to initiate de-watering programs on wells previously drilled. The Rocky Mountains segment 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 under “Equity in earnings from unconsolidated affiliates.” Average pipeline throughput for Bighorn and Fort Union on a combined basis increased 4% in the second quarter of 2009 as compared with the second quarter of 2008. For the second quarter of 2009, average pipeline throughput for Bighorn and Fort Union totaled 185,622 MMBtu/d and 795,072 MMBtu/d, respectively, as compared to 217,373 MMBtu/d and 727,688 MMBtu/d, respectively, for the second quarter of 2008.
Corporate and Other
Corporate and other gross margin includes Copano’s commodity risk management activities. These activities produced a gain of $10.8 million for the second quarter of 2009 compared to a loss of $17.5 million for the second quarter of 2008. The gain for the second quarter of 2009 included
$20.8 million of net cash settlements received for expired commodity derivative instruments offset by $0.7 million of unrealized mark-to-market losses on undesignated economic hedges and $9.3 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio. The second quarter 2008 loss included $6.7 million of net cash settlements paid for expired commodity derivative instruments, $8.5 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio and $2.3 million of unrealized mark-to-market losses on undesignated economic hedges.
Year-to-Date Financial Results
Revenue for the first six months of 2009 decreased 54% to $419.3 million compared to $903.0 million for the same period of last year. Total segment gross margin decreased 21% to $106.0 million for the six months ended June 30, 2009 from $133.4 million for the same period in 2008. For the six months ended June 30, 2009, total segment gross margin included a net gain of $26.9 million related to Copano’s risk management activities, comprised of $45.9 million of net cash settlements received on expired commodity derivative instruments offset by $18.5 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio and $0.5 million of unrealized mark-to-market losses on undesignated economic hedges. Total segment gross margin for the six months ended June 30, 2008 included a net loss of $35.3 million related to Copano’s risk management activities comprised of $12.5 million of net cash settlements paid on expired commodity derivative instruments, $16.0 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio and $6.8 million of unrealized mark-to-market losses on undesignated economic hedges.
Adjusted EBITDA decreased 23% to $79.5 million for the first six months of 2009 compared to $103.2 million for the same period of last year. Total distributable cash flow decreased 25% to $68.0 million for the six months ended June 30, 2009 compared to $90.5 million for the same period of 2008.
Net income decreased by 68% to $11.9 million, or $0.21 per unit on a diluted basis, for the six months ended June 30, 2009 compared to net income of $37.7 million, or $0.65 per unit on a diluted basis, for the six months ended June 30, 2008. The major drivers of net income for 2009 compared to 2008 included:
| · | a decrease in total segment gross margin of $27.4 million consisting of a $89.6 million decrease in operating segment gross margins primarily reflecting average NGL price declines of 58% in the Conway index and 57% in the Mt. Belvieu index and lower overall service throughput volumes, offset by an increase of $62.2 million from commodity risk management activities; |
| · | an increase in operations, maintenance, depreciation and amortization expenses of $3.6 million primarily related to expanded operations in north Texas; and |
| · | a decrease of $1.6 million in equity in earnings of unconsolidated affiliates; |
offset by:
| · | a gain of $3.9 million related to the repurchase and retirement of $18.2 million aggregate principal amount of 7.75% senior unsecured notes due 2018 at market prices averaging 78% of the face amount of the notes; and |
| · | a decrease in general and administrative expenses of $2.7 million primarily related to successful cost reduction efforts, including reduced employee compensation expense and third-party service provider fees |
| · | a decrease of $1.0 million in interest expense as a result of (i) a decrease of noncash mark-to-market charges on interest rate swaps of $5.4 million offset by (ii) an increase in interest expense of $4.4 million as a result of increased average outstanding borrowings slightly offset by lower average interest rates between the periods. |
Weighted average diluted units decreased slightly to 57.9 million for the six months ended June 30, 2009 as compared to 58.0 million units for the six months ended June 30, 2008.
Cash Distributions
On July 15, 2009, Copano announced a second quarter 2009 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 equal to Copano’s distribution of $0.575 per unit for the first quarter of 2009 and is payable on August 13, 2009 to common unitholders of record at the close of business on August 3, 2009.
Conference Call Information
Copano will hold a conference call to discuss its second quarter 2009 financial results and recent developments on Thursday, August 6, 2009 at 10:00 a.m. Eastern Daylight Time (9:00 a.m. Central Daylight Time). To participate in the call, dial (480) 629-9722 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. Additionally, a telephonic replay will be available through August 13, 2009 by calling (303) 590-3030 and using the pass code 4106205#.
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 segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow. 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, operating income, cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Copano uses non-GAAP financial measures as measures of its core profitability or to assess the financial performance of its assets. Copano believes that investors benefit from having access to the same financial measures that its management uses in evaluating Copano’s liquidity position or financial performance.
Copano defines segment gross margin as an operating segment’s revenue minus cost of sales. Cost of sales includes the following: cost of natural gas and NGLs purchased, cost of crude oil purchased and costs for transportation of volumes. Total segment gross margin is the sum of the operating segment gross margins and the results of Copano’s risk management activities that are included in Corporate and other. Copano views total segment gross margin as an important performance measure of the core profitability of its operations. Segment gross margin allows Copano’s senior management to compare volume and price performance of the segments and to more easily identify operational or other issues within a segment. The GAAP measure most directly comparable to total segment gross margin is operating income.
Copano defines EBITDA as net income (loss) plus interest and other financing costs, provision for income taxes and depreciation, amortization and impairment expense. Because a portion of Copano’s net income (loss) is attributable to equity in earnings (loss) from its unconsolidated affiliates, including Bighorn, Fort Union, Webb/Duval Gatherers (Webb Duval) and Southern Dome, LLC (Southern Dome), Copano calculates adjusted EBITDA to reflect the depreciation, amortization and impairment expense and interest and other financing costs embedded in the equity in earnings (loss) from unconsolidated affiliates. Specifically, Copano determines adjusted EBITDA by adding to EBITDA (i) the amortization expense attributable to the difference between Copano’s carried investment in each unconsolidated affiliate and the underlying equity in its net assets, (ii) the portion of each unconsolidated affiliate’s depreciation and amortization expense which is proportional to Copano’s ownership interest in that unconsolidated affiliate and (iii) the portion of each unconsolidated affiliate’s interest and other financing costs which is proportional to Copano’s ownership interest in that unconsolidated affiliate. External users of Copano’s financial statements such as investors, commercial
banks and research analysts use EBITDA or adjusted EBITDA, and Copano’s management uses adjusted EBITDA as a supplemental financial measure to assess:
| · | the financial performance of Copano’s assets without regard to financing methods, capital structure or historical cost basis; |
| · | the ability of Copano’s assets to generate cash sufficient to pay interest costs and support indebtedness; |
| · | Copano’s operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and |
| · | the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
EBITDA is also a financial measure that, with certain negotiated adjustments, is reported to Copano’s lenders and is used to compute financial covenants under its revolving credit facility. Neither EBITDA nor adjusted EBITDA should be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of liquidity or financial performance presented in accordance with GAAP. Copano’s EBITDA or adjusted EBITDA may not be comparable to EBITDA, adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate EBITDA or adjusted EBITDA in the same manner as Copano does. Copano has reconciled EBITDA and adjusted EBITDA to net income and cash flows from operating activities.
Copano defines total distributable cash flow as net income plus: (i) depreciation, amortization and impairment expense (including amortization expense relating to the option component of Copano’s risk management portfolio); (ii) cash distributions received from investments in unconsolidated affiliates and equity losses from such unconsolidated affiliates; (iii) provision for deferred income taxes; (iv) the subtraction of maintenance capital expenditures; (v) the subtraction of equity in earnings from unconsolidated affiliates; and (vi) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period, such as equity-based compensation, mark-to-market changes in derivative instruments, and Copano’s line fill contributions to third-party pipelines and gas imbalances. Maintenance capital expenditures are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of Copano’s assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.
Total distributable cash flow is a significant performance metric used by senior management to compare basic cash flows generated by Copano (prior to the establishment of any retained cash reserves by its Board of Directors) to the cash distributions Copano expects to pay its unitholders, and it also correlates with the metrics of Copano’s existing debt covenants. Using total distributable cash flow, management
can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Total distributable cash flow is also an important non-GAAP financial measure for unitholders because it serves as an indicator of Copano’s success in providing a cash return on investment— specifically, whether or not Copano is generating cash flow at a level that can sustain or support an increase in quarterly distribution rates. Total distributable cash flow is also used by industry analysts with respect to publicly traded partnerships and limited liability companies because the market value of such an entities’ equity securities is significantly influenced by the amount of cash they can distribute to unitholders. The GAAP measure most directly comparable to total distributable cash flow is net income.
Although Copano has previously reported both distributable cash flow and total distributable cash flow, Copano has determined that total distributable cash flow is a better measure of the rate at which cash available for distribution is generated by Copano’s operations than distributable cash flow, which does not add back the amortization expense relating to the option component of Copano’s risk management portfolio. Total distributable cash flow should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.
Houston-based Copano Energy, L.L.C. is a midstream natural gas company with operations in Oklahoma, Texas, Wyoming and Louisiana.
This news release may include “forward-looking statements” as defined by the Securities and Exchange Commission. These statements reflect certain assumptions based on management’s experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances. These statements include, but are not limited to, statements with respect to future distributions. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond Copano’s control, which may cause Copano’s actual results to differ materially from those implied or expressed by the forward-looking statements. These risks include an inability to obtain new sources of natural gas supplies, the loss of key producers that supply natural gas to Copano, key customers reducing the volume of natural gas and NGLs they purchase from Copano, a decline in the price and market demand for natural gas and NGLs, the incurrence of significant costs and liabilities in the future resulting from Copano’s failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment and other factors detailed in Copano’s Securities and Exchange Commission filings.
– financial statements to follow –
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
| | | Three Months Ended June 30, | | | Six Months Ended June 30, | |
| | | | | | | | | | | | | |
| | | (In thousands, except per unit information) | |
| Revenue: | | | | | | | | | | | | |
Natural gas sales | | $ | 64,517 | | | $ | 235,000 | | | $ | 159,496 | | | $ | 415,887 | |
Natural gas liquids sales | | | 91,463 | | | | 179,031 | | | | 172,294 | | | | 333,112 | |
Crude oil sales | | | 22,730 | | | | 57,183 | | | | 38,068 | | | | 98,365 | |
Transportation, compression and processing fees | | | 13,913 | | | | 16,442 | | | | 28,912 | | | | 29,124 | |
Condensate and other | | | 10,290 | | | | 13,622 | | | | 20,559 | | | | 26,538 | |
Total revenue | | | 202,913 | | | | 501,278 | | | | 419,329 | | | | 903,026 | |
| | | | | | | | | | | | | | | | | |
| Costs and expenses: | | | | | | | | | | | | | | | | |
Cost of natural gas and natural gas liquids (1) | | | 122,415 | | | | 369,766 | | | | 265,873 | | | | 667,234 | |
Cost of crude oil purchases (1) | | | 21,340 | | | | 56,021 | | | | 35,768 | | | | 95,863 | |
Transportation (1) | | | 5,744 | | | | 3,416 | | | | 11,728 | | | | 6,537 | |
Operations and maintenance | | | 13,028 | | | | 13,065 | | | | 25,850 | | | | 24,895 | |
Depreciation and amortization | | | 13,835 | | | | 12,767 | | | | 27,000 | | | | 24,337 | |
General and administrative | | | 9,321 | | | | 10,936 | | | | 20,046 | | | | 22,786 | |
Taxes other than income | | | 727 | | | | 729 | | | | 1,513 | | | | 1,470 | |
Equity in earnings from unconsolidated affiliates | | | (2,099 | ) | | | (4,788 | ) | | | (3,583 | ) | | | (5,184 | ) |
Total costs and expenses | | | 184,311 | | | | 461,912 | | | | 384,195 | | | | 837,938 | |
| | | | | | | | | | | | | | | | | |
Operating income | | | 18,602 | | | | 39,366 | | | | 35,134 | | | | 65,088 | |
| | | | | | | | | | | | | | | | | |
Interest and other income | | | 8 | | | | 278 | | | | 54 | | | | 734 | |
Gain on retirement of unsecured debt | | | — | | | | — | | | | 3,939 | | | | — | |
Interest and other financing costs | | | (12,001 | ) | | | (16,077 | ) | | | (26,449 | ) | | | (27,469 | ) |
Income before income taxes | | | 6,609 | | | | 23,567 | | | | 12,678 | | | | 38,353 | |
Provision for income taxes | | | (571 | ) | | | (365 | ) | | | (735 | ) | | | (649 | ) |
Net income | | $ | 6,038 | | | $ | 23,202 | | | $ | 11,943 | | | $ | 37,704 | |
| | | | | | | | | | | | | | | | | |
| Basic net income per common unit: | | | | | | | | | | | | | | | | |
Net income | | $ | 0.11 | | | $ | 0.49 | | | $ | 0.22 | | | $ | 0.79 | |
Weighted average number of common units | | | 54,356 | | | | 47,672 | | | | 54,185 | | | | 47,524 | |
| | | | | | | | | | | | | | | | | |
| Diluted net income per common unit: | | | | | | | | | | | | | | | | |
Net income | | $ | 0.10 | | | $ | 0.40 | | | $ | 0.21 | | | $ | 0.65 | |
Weighted average number of common units | | | 57,946 | | | | 58,010 | | | | 57,933 | | | | 57,967 | |
________________________
(1) Exclusive of operations and maintenance and depreciation and amortization shown separately below.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | Six Months Ended June 30, | |
| | | | | | | |
| | | (In thousands) | |
| Cash Flows From Operating Activities: | | | | | | |
Net income | | $ | 11,943 | | | $ | 37,704 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | |
Depreciation and amortization | | | 27,000 | | | | 24,337 | |
Amortization of debt issue costs | | | 2,165 | | | | 1,619 | |
Equity in earnings from unconsolidated affiliates | | | (3,583 | ) | | | (5,184 | ) |
Distributions from unconsolidated affiliates | | | 11,439 | | | | 11,718 | |
Gain on retirement of unsecured debt | | | (3,939 | ) | | | — | |
| Noncash (gain) loss on risk management portfolio, net | | | (1,636 | ) | | | 10,000 | |
Equity-based compensation | | | 4,317 | | | | 1,808 | |
Deferred tax provision | | | 373 | | | | 253 | |
Other noncash items | | | 296 | | | | (85 | ) |
| Changes in assets and liabilities: | | | | | | | | |
Accounts receivable | | | 24,805 | | | | (44,258 | ) |
Prepayments and other current assets | | | 2,080 | | | | 753 | |
Risk management activities | | | 18,479 | | | | (26,320 | ) |
Accounts payable | | | (12,338 | ) | | | 62,605 | |
Other current liabilities | | | (1,773 | ) | | | 3,035 | |
Net cash provided by operating activities | | | 79,628 | | | | 77,985 | |
| | | | | | | | | |
| Cash Flows From Investing Activities: | | | | | | | | |
Additions to property, plant and equipment | | | (37,380 | ) | | | (76,995 | ) |
Additions to intangible assets | | | (698 | ) | | | (3,849 | ) |
Acquisitions | | | (2,840 | ) | | | (77 | ) |
Investment in unconsolidated affiliates | | | (2,774 | ) | | | (18,809 | ) |
Distributions from unconsolidated affiliates | | | 2,788 | | | | 877 | |
Other | | | (995 | ) | | | (2,701 | ) |
Net cash used in investing activities | | | (41,899 | ) | | | (101,554 | ) |
| | | | | | | | | |
| Cash Flows From Financing Activities: | | | | | | | | |
Proceeds from long-term debt | | | 50,000 | | | | 364,000 | |
Repayment of long-term debt | | | — | | | | (314,000 | ) |
Retirement of unsecured debt | | | (14,286 | ) | | | — | |
Deferred financing costs | | | — | | | | (6,350 | ) |
Distributions to unitholders | | | (62,505 | ) | | | (49,585 | ) |
Capital contributions from pre-IPO investors | | | — | | | | 4,103 | |
Equity offering costs | | | — | | | | (47 | ) |
| Proceeds from option exercises | | | 61 | | | | 524 | |
Net cash used in financing activities | | | (26,730 | ) | | | (1,355 | ) |
| | | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 10,999 | | | | (24,924 | ) |
Cash and cash equivalents, beginning of year | | | 63,684 | | | | 72,665 | |
Cash and cash equivalents, end of period | | $ | 74,683 | | | $ | 47,741 | |
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | |
| | | | | |
| | (In thousands, except unit information) |
| ASSETS | | |
| Current assets: | | |
| Cash and cash equivalents | $ | 74,683 | | | $ | 63,684 | |
| Accounts receivable, net | | 71,644 | | | | 96,028 | |
| Risk management assets | | 44,270 | | | | 76,440 | |
| Prepayments and other current assets | | 2,924 | | | | 5,004 | |
| Total current assets | | 193,521 | | | | 241,156 | |
| | | | | | | | |
| Property, plant and equipment, net | | 833,198 | | | | 823,574 | |
| Intangible assets, net | | 193,779 | | | | 198,974 | |
| Investment in unconsolidated affiliates | | 631,741 | | | | 640,598 | |
| Escrow cash | | 1,858 | | | | 1,858 | |
| Risk management assets | | 37,138 | | | | 82,892 | |
| Other assets, net | | 23,004 | | | | 24,613 | |
| Total assets | $ | 1,914,239 | | | $ | 2,013,665 | |
| | | | | | | | |
| LIABILITIES AND MEMBERS’ CAPITAL | | | | | | | |
| Current liabilities: | | | | | | | |
| Accounts payable | $ | 88,092 | | | $ | 103,849 | |
| Accrued interest | | 11,380 | | | | 11,904 | |
| Accrued tax liability | | 356 | | | | 784 | |
| Risk management liabilities | | 7,774 | | | | 6,272 | |
| Other current liabilities | | 8,479 | | | | 16,787 | |
| Total current liabilities | | 116,081 | | | | 139,596 | |
| | | | | | | | |
| Long-term debt (includes $666 and $704 bond premium as of June 30, 2009 and December 31, 2008, respectively) | | 852,856 | | | | 821,119 | |
| Deferred tax provision | | 2,091 | | | | 1,718 | |
| Risk management and other noncurrent liabilities | | 12,882 | | | | 13,274 | |
| | | | | | | | |
| Members’ capital: | | | | | | | |
| Common units, no par value, 54,520,170 and 53,965,288 units issued and outstanding as of June 30, 2009 and December 31, 2008, respectively | | 878,901 | | | | 865,343 | |
| Class C units, no par value, 0 units and 394,853 units issued and outstanding as of June 30, 2009 and December 31, 2008, respectively | | — | | | | 13,497 | |
| Class D units, no par value, 3,245,817 units issued and outstanding as of June 30, 2009 and December 31, 2008 | | 112,454 | | | | 112,454 | |
| Paid-in capital | | 38,907 | | | | 33,734 | |
| Accumulated deficit | | (105,900 | ) | | | (54,696 | ) |
| Accumulated other comprehensive income | | 5,967 | | | | 67,626 | |
| | | 930,329 | | | | 1,037,958 | |
| Total liabilities and members’ capital | $ | 1,914,239 | | | $ | 2,013,665 | |
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
OPERATING STATISTICS
(Unaudited)
| | | Three Months Ended June 30, | | | Six Months Ended June 30, | |
| | | | | | | | | | | | | |
| | | ($ in thousands) | |
Total segment gross margin(1) | | $ | 53,414 | | | $ | 72,075 | | | $ | 105,960 | | | $ | 133,392 | |
| Operations and maintenance expenses | | | 13,028 | | | | 13,065 | | | | 25,850 | | | | 24,895 | |
| Depreciation and amortization | | | 13,835 | | | | 12,767 | | | | 27,000 | | | | 24,337 | |
| General and administrative expenses | | | 9,321 | | | | 10,936 | | | | 20,046 | | | | 22,786 | |
| Taxes other than income | | | 727 | | | | 729 | | | | 1,513 | | | | 1,470 | |
| Equity in earnings from unconsolidated affiliates | | | (2,099 | ) | | | (4,788 | ) | | | (3,583 | ) | | | (5,184 | ) |
| Operating income | | | 18,602 | | | | 39,366 | | | | 35,134 | | | | 65,088 | |
| Gain on retirement of unsecured debt | | | — | | | | — | | | | 3,939 | | | | — | |
| Interest and other financing costs, net | | | (11,993 | ) | | | (15,799 | ) | | | (26,395 | ) | | | (26,735 | ) |
| Provision for income taxes | | | (571 | ) | | | (365 | ) | | | (735 | ) | | | (649 | ) |
| Net income | | $ | 6,038 | | | $ | 23,202 | | | $ | 11,943 | | | $ | 37,704 | |
| Total segment gross margin: | | | | | | | | | | | | | | | | |
| Oklahoma | | $ | 18,626 | | | $ | 47,852 | | | $ | 33,697 | | | $ | 84,422 | |
| Texas | | | 23,320 | | | | 40,499 | | | | 43,900 | | | | 82,075 | |
| Rocky Mountains | | | 711 | | | | 1,218 | | | | 1,510 | | | | 2,181 | |
| Segment gross margin | | | 42,657 | | | | 89,569 | | | | 79,107 | | | | 168,678 | |
Corporate and other(2) | | | 10,757 | | | | (17,494 | ) | | | 26,853 | | | | (35,286 | ) |
Total segment gross margin(1) | | $ | 53,414 | | | $ | 72,075 | | | $ | 105,960 | | | $ | 133,392 | |
| Segment gross margin per unit: | | | | | | | | | | | | | | | | |
| Oklahoma: | | | | | | | | | | | | | | | | |
Service throughput ($/MMBtu)(3) | | $ | 0.76 | | | $ | 2.30 | | | $ | 0.69 | | | $ | 2.06 | |
| Texas: | | | | | | | | | | | | | | | | |
Service throughput ($/MMBtu) (4) | | $ | 0.41 | | | $ | 0.64 | | | $ | 0.38 | | | $ | 0.65 | |
| Rocky Mountains: | | | | | | | | | | | | | | | | |
Producer services throughput ($/MMBtu) (5) | | $ | 0.04 | | | $ | 0.06 | | | $ | 0.05 | | | $ | 0.05 | |
| | | | | | | | | | | | | | | | | |
| Volumes: | | | | | | | | | | | | | | | | |
Oklahoma:(3) (6) | | | | | | | | | | | | | | | | |
| Service throughput (MMBtu/d) | | | 267,576 | | | | 228,941 | | | | 269,389 | | | | 225,474 | |
| Plant inlet throughput (MMBtu/d) | | | 166,846 | | | | 155,430 | | | | 163,532 | | | | 153,020 | |
| NGLs produced (Bbls/d) | | | 15,981 | | | | 15,465 | | | | 15,647 | | | | 15,004 | |
| Crude oil service volumes (Bbls/d) | | | 4,314 | | | | 5,074 | | | | 4,360 | | | | 4,854 | |
Texas: (4) (7) | | | | | | | | | | | | | | | | |
| Service throughput (MMBtu/d) | | | 630,674 | | | | 700,545 | | | | 637,565 | | | | 697,844 | |
| Pipeline throughput (MMBtu/d) | | | 290,005 | | | | 313,523 | | | | 296,932 | | | | 320,761 | |
| Plant inlet volumes (MMBtu/d) | | | 559,597 | | | | 629,334 | | | | 558,900 | | | | 617,034 | |
| NGLs produced (Bbls/d) | | | 18,425 | | | | 17,721 | | | | 17,667 | | | | 17,902 | |
| Rocky Mountains: | | | | | | | | | | | | | | | | |
Producer services throughput (MMBtu/d)(5) | | | 166,022 | | | | 229,513 | | | | 173,661 | | | | 228,117 | |
| | | | | | | | | | | | | | | | | |
| Capital Expenditures: | | | | | | | | | | | | | | | | |
| Maintenance capital expenditures | | $ | 3,895 | | | $ | 3,094 | | | $ | 6,046 | | | $ | 6,153 | |
| Expansion capital expenditures | | | 14,301 | | | | 52,044 | | | | 24,836 | | | | 82,665 | |
| Total capital expenditures | | $ | 18,196 | | | $ | 55,138 | | | $ | 30,882 | | | $ | 88,818 | |
| Operations and maintenance expenses: | | | | | | | | | | | | | | | | |
| Oklahoma | | $ | 5,746 | | | $ | 6,100 | | | $ | 11,512 | | | $ | 12,026 | |
| Texas | | | 7,280 | | | | 7,017 | | | | 14,334 | | | | 12,869 | |
| Rocky Mountains | | | 2 | | | | (52 | ) | | | 4 | | | | — | |
| Total operations and maintenance expenses | | $ | 13,028 | | | $ | 13,065 | | | $ | 25,850 | | | $ | 24,895 | |
________________________
| | (1) | Total segment gross margin is a non-GAAP financial measure. For a reconciliation of total segment gross margin to its most directly comparable GAAP measure, please read “Non-GAAP Financial Measures.” |
| | (2) | Corporate and other includes results attributable to Copano’s commodity risk management activities. |
| | (3) | Excludes volumes associated with Copano’s interest in Southern Dome. For the three months ended June 30, 2009, plant inlet volumes for Southern Dome averaged 15,412 MMBtu/d and NGLs produced averaged 578 Bbls/d. For the three months ended June 30, 2008, plant inlet volumes for Southern Dome averaged 9,116 MMBtu/d and NGLs produced averaged 325 Bbls/d. For the six months ended June 30, 2009, plant inlet volumes for Southern Dome averaged 13,023 MMBtu/d and NGLs produced averaged 473 Bbls/d. For the six months ended June 30, 2008, plant inlet volumes for Southern Dome averaged 9,970 MMBtu/d and NGLs produced averaged 386 Bbls/d |
| | (4) | Excludes volumes associated with Copano’s interest in Webb Duval. Gross volumes transported by Webb Duval, net of intercompany volumes, were 84,452 MMBtu/d and 94,022 MMBtu/d for the three months ended June 30, 2009 and 2008, respectively. Gross volumes transported by Webb Duval, net of intercompany volumes, were 86,584 MMBtu/d and 87,580 MMBtu/d for the six months ended June 30, 2009 and 2008, respectively. |
| | (5) | Producers services throughput consists of volumes purchased for resale, volumes gathered under firm capacity gathering agreements with Fort Union and volumes transported using firm capacity agreements with WIC. Excludes results and volumes associated with Copano’s interests in Bighorn and Fort Union. Volumes gathered by Bighorn were 185,622 MMBtu/d and 217,373 MMBtu/d for the three months ended June 30, 2009 and 2008, respectively. Volumes gathered by Fort Union were 795,072 MMBtu/d and 727,688 MMBtu/d for the three months ended June 30, 2009 and 2008, respectively. Volumes gathered by Bighorn were 193,654 MMBtu/d and 217,699 MMBtu/d for the six months ended June 30, 2009 and 2008, respectively. Volumes gathered by Fort Union were 799,621 MMBtu/d and 701,498 MMBtu/d for the six months ended June 30, 2009 and 2008, respectively. |
| | (6) | 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 June 30, 2009, plant inlet volumes averaged 128,390 MMBtu/d and NGLs produced averaged 12,956 Bbls/d for plants owned by the Oklahoma segment. For the three months ended June 30, 2008, plant inlet volumes averaged 114,720 MMBtu/d and NGLs produced averaged 11,986 Bbls/d for plants owned by the Oklahoma segment. For the six months ended June 30, 2009, plant inlet volumes averaged 125,661 MMBtu/d and NGLs produced averaged 12,747 Bbls/d for plants owned by the Oklahoma segment. For the six months ended June 30, 2008, plant inlet volumes averaged 106,995 MMBtu/d and NGLs produced averaged 10,990 Bbls/d for plants owned by the Oklahoma segment. |
| | (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 539,946 MMBtu/d and NGLs produced averaged 16,759 Bbls/d for the three months ended June 30, 2009 for plants owned by the Texas segment. Plant inlet volumes averaged 607,339 MMBtu/d and NGLs produced averaged 15,961 Bbls/d for the three months ended June 30, 2008 for plants owned by the Texas segment. Plant inlet volumes averaged 537,528 MMBtu/d and NGLs produced averaged 15,920 Bbls/d for the six months ended June 30, 2009 for plants owned by the Texas segment. Plant inlet volumes averaged 594,195 MMBtu/d and NGLs produced averaged 16,168 Bbls/d for the six months ended June 30, 2008 for plants owned by the Texas segment. |
Non-GAAP Financial Measures
The following table presents a reconciliation of the non-GAAP financial measures of (i) total 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, (ii) EBITDA and adjusted EBITDA to the GAAP financial measures of net income and cash flows from operating activities and (iii) total distributable cash flow to the GAAP financial measure of net income, for each of the periods indicated (in thousands).
| | | Three Months Ended June 30, | | | Six Months Ended June 30, | |
| | | | | | | | | | | | | |
| Reconciliation of total segment gross margin to operating income: | | | | | | | | | | | | |
| Operating income | | $ | 18,602 | | | $ | 39,366 | | | $ | 35,134 | | | $ | 65,088 | |
| Add: Operations and maintenance expenses | | | 13,028 | | | | 13,065 | | | | 25,850 | | | | 24,895 | |
| Depreciation and amortization | | | 13,835 | | | | 12,767 | | | | 27,000 | | | | 24,337 | |
| General and administrative expenses | | | 9,321 | | | | 10,936 | | | | 20,046 | | | | 22,786 | |
| Taxes other than income | | | 727 | | | | 729 | | | | 1,513 | | | | 1,470 | |
| Equity in earnings from unconsolidated affiliates | | | (2,099 | ) | | | (4,788 | ) | | | (3,583 | ) | | | (5,184 | ) |
| Total segment gross margin | | $ | 53,414 | | | $ | 72,075 | | | $ | 105,960 | | | $ | 133,392 | |
| | | | | | | | | | | | | | | | | |
| Reconciliation of EBITDA and adjusted EBITDA to net income: | | | | | | | | | | | | | | | | |
| Net income | | $ | 6,038 | | | $ | 23,202 | | | $ | 11,943 | | | $ | 37,704 | |
| Add: Depreciation and amortization | | | 13,835 | | | | 12,767 | | | | 27,000 | | | | 24,337 | |
| Interest and other financing costs | | | 12,001 | | | | 16,077 | | | | 26,449 | | | | 27,469 | |
Provision for income taxes | | | 571 | | | | 365 | | | | 735 | | | | 649 | |
| EBITDA | | | 32,445 | | | | 52,411 | | | | 66,127 | | | | 90,159 | |
| Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments | | | 4,785 | | | | 4,602 | | | | 9,603 | | | | 9,201 | |
| Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates | | | 1,776 | | | | 1,319 | | | | 3,333 | | | | 2,588 | |
| % of equity method investment interest and other financing costs | | | (30 | ) | | | (944 | ) | | | 478 | | | | 1,226 | |
| Adjusted EBITDA | | $ | 38,976 | | | $ | 57,388 | | | $ | 79,541 | | | $ | 103,174 | |
| | | | | | | | | | | | | | | | | |
| Reconciliation of EBITDA and adjusted EBITDA to cash flows from operating activities: | | | | | | | | | | | | | | | | |
| Cash flow provided by operating activities | | $ | 44,230 | | | $ | 58,807 | | | $ | 79,628 | | | $ | 77,985 | |
| Add: Cash paid for interest and other financing costs | | | 11,106 | | | | 15,226 | | | | 24,284 | | | | 25,850 | |
| Equity in earnings from unconsolidated affiliates | | | 2,099 | | | | 4,788 | | | | 3,583 | | | | 5,184 | |
| Distributions from unconsolidated affiliates | | | (6,068 | ) | | | (7,442 | ) | | | (11,439 | ) | | | (11,718 | ) |
| Risk management activities | | | (9,291 | ) | | | 8,145 | | | | (18,479 | ) | | | 26,320 | |
| Decrease in working capital and other | | | (9,631 | ) | | | (27,113 | ) | | | (11,450 | ) | | | (33,462 | ) |
| EBITDA | | | 32,445 | | | | 52,411 | | | | 66,127 | | | | 90,159 | |
| Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments | | | 4,785 | | | | 4,602 | | | | 9,603 | | | | 9,201 | |
| Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates | | | 1,776 | | | | 1,319 | | | | 3,333 | | | | 2,588 | |
| % of equity method investment interest and other financing costs | | | (30 | ) | | | (944 | ) | | | 478 | | | | 1,226 | |
| Adjusted EBITDA | | $ | 38,976 | | | $ | 57,388 | | | $ | 79,541 | | | $ | 103,174 | |
| | | | | | | | | | | | | | | | | |
| Reconciliation of net income to total distributable cash flow: | | | | | | | | | | | | | | | | |
| Net income | | $ | 6,038 | | | $ | 23,202 | | | $ | 11,943 | | | $ | 37,704 | |
| Add: Depreciation and amortization | | | 13,835 | | | | 12,767 | | | | 27,000 | | | | 24,337 | |
| Amortization of commodity derivative options | | | 9,291 | | | | 8,495 | | | | 18,479 | | | | 16,057 | |
| Amortization of debt issue costs | | | 895 | | | | 851 | | | | 2,165 | | | | 1,619 | |
| Equity-based compensation | | | 2,296 | | | | 1,023 | | | | 4,255 | | | | 1,992 | |
| Distributions from unconsolidated affiliates | | | 7,296 | | | | 7,543 | | | | 14,227 | | | | 12,595 | |
| Unrealized losses associated with line fill contributions and gas imbalances(4) | | | 361 | | | | (2,681 | ) | | | 527 | | | | (2,607 | ) |
| Unrealized (gains)/losses on derivatives | | | (1,396 | ) | | | 5,528 | | | | (1,636 | ) | | | 10,001 | |
| Deferred taxes and other | | | 325 | | | | 106 | | | | 672 | | | | 167 | |
| Less: Equity in earnings from unconsolidated affiliates | | | (2,099 | ) | | | (4,788 | ) | | | (3,583 | ) | | | (5,184 | ) |
| Maintenance capital expenditures | | | (3,895 | ) | | | (3,094 | ) | | | (6,046 | ) | | | (6,153 | ) |
Total distributable cash flow(3)(4) | | $ | 32,947 | | | $ | 48,952 | | | $ | 68,003 | | | $ | 90,528 | |
| | | | | | | | | | | | | | | | | |
| Actual quarterly distribution (“AQD”) | | $ | 31,869 | | | $ | 26,952 | | | | | | | | | |
| Total distributable cash flow coverage of AQD | | | 103 | % | | | 182 | % | | | | | | | | |
_______________________
| (1) | Reflects net non-cash mark-to-market gains associated with (a) contractual obligations to maintain certain levels of line fill contributions with third parties of $380,000 and (b) gas imbalance losses of $741,000. |
| (2) | Reflects non-cash mark-to-market charges associated with gas imbalances not previously reflected in total distributable cash flow. |
| (3) | Prior to any retained cash reserves established by Copano’s Board of Directors. |
| (4) | Beginning with the third quarter of 2008, unrealized non-cash losses (gains) associated with line fill contributions and gas imbalances have been added back in the determination of total distributable cash flow. Prior periods have been adjusted to reflect this change. |
