Copano Energy Reports Third Quarter 2010 Results
Total Distributable Cash Flow Increases 7% over Second Quarter
HOUSTON, Nov. 4, 2010 /PRNewswire-FirstCall/ -- Copano Energy, L.L.C. (Nasdaq: CPNO) today announced its financial results for the three and nine months ended September 30, 2010.
"Despite lower commodity prices during the third quarter compared to the first half of 2010, we continue to improve our total distributable cash flow and distribution coverage for the year and remain focused on executing our growth initiatives, primarily in the Eagle Ford Shale and Barnett Shale Combo plays," said R. Bruce Northcutt, Copano Energy's President and Chief Executive Officer.
"Going forward, key drivers of near-term cash flow growth from our operating segments include volumes at our Saint Jo plant – which reached an all-time high in October, Eagle Ford Shale volumes – which have almost doubled since the first quarter of this year, and growing contributions from the fractionator at our Houston Central Complex," Northcutt added.
Third Quarter Financial Results
Total distributable cash flow for the third quarter of 2010 increased to $35.7 million from $33.5 million in the second quarter of 2010 and from $33.4 million for the third quarter of 2009, an increase of 7% for each period. Third quarter 2010 total distributable cash flow represents 93% coverage of the third quarter distribution of $0.575 per unit, based on total common units outstanding on the distribution record date.
Revenue for the third quarter of 2010 increased 25% to $237.7 million compared to $189.5 million for the third quarter of 2009. Total segment gross margin increased to $57.9 million for the third quarter of 2010 compared to $56.8 million for the second quarter of 2010 and to $53.4 million for the third quarter of 2009, increases of 2% and 8%, respectively.
Adjusted EBITDA for the third quarter of 2010 increased to $42.3 million compared to $41.2 million for the third quarter of 2009. Non-cash amortization expense relating to the option component of Copano's risk management portfolio, which is not added back in determining adjusted EBITDA, totaled $8.2 million, $8.1 million and $9.2 million, respectively, for the third quarter of 2010, the second quarter of 2010 and the third quarter of 2009.
Net income, which is prior to deducting in-kind preferred unit distributions, increased 97% to $7.3 million for the third quarter of 2010 compared to net income of $3.7 million for the third quarter of 2009, primarily as a result of higher total segment gross margin reflecting average NGL price increases of 32% on the Conway index and 14% on the Mt. Belvieu index and lower interest expense associated with Copano's outstanding debt.
Net loss to common units after deducting $7.5 million of in-kind preferred unit distributions on Copano's Series A convertible preferred units issued in July 2010 totaled $0.2 million, or less than $0.01 per unit on a diluted basis, for the third quarter of 2010 compared to net income to common units of $3.7 million, or $0.06 per unit on a diluted basis, for the third quarter of 2009. Weighted average diluted units outstanding totaled 65.7 million for the third quarter of 2010 as compared to 58.0 million for the same period in 2009.
Total distributable cash flow, total segment gross margin, adjusted EBITDA, and segment gross margin are non-GAAP financial measures that are reconciled to the most directly comparable GAAP measures at the end of this news release.
Third Quarter Operating Results by Segment
Copano manages its business in three geographical operating segments: Oklahoma, which provides midstream natural gas services in central and east Oklahoma; Texas, which provides midstream natural gas services in Texas and also includes a processing plant in southwest Louisiana; 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%.
Oklahoma
Segment gross margin for Oklahoma increased 26% for the third quarter of 2010 to $23.0 million compared to $18.3 million for the third quarter of 2009. The increase resulted primarily from a 22% increase in realized margins on service throughput compared to the third quarter of 2009 ($0.93 per MMBtu in 2010 compared to $0.76 per MMBtu in 2009), reflecting higher NGL and natural gas prices. During the third quarter of 2010, weighted-average NGL prices on the Conway index, based on Copano's product mix for the period, were $36.53 per barrel compared to $27.62 per barrel during the third quarter of 2009, an increase of 32%. During the third quarter of 2010, natural gas prices on the CenterPoint East index averaged $4.14 per MMBtu compared to $2.98 per MMBtu during the third quarter of 2009, an increase of 39%.
The Oklahoma segment gathered an average of 270,184 MMBtu/d of natural gas, processed an average of 156,676 MMBtu/d of natural gas and produced an average of 16,541 Bbls/d of NGLs at its own plants and third-party plants during the third quarter of 2010. Compared to the third quarter of 2009, this represents a 4% increase in service throughput, a 6% decrease in plant inlet volumes and flat 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. Lower plant inlet volumes at the Paden plant resulted from normal production declines on the Stroud gathering system.
Texas
Segment gross margin for Texas increased 16% for the third quarter of 2010 to $31.2 million compared to $26.9 million for the third quarter of 2009. The increase resulted primarily from a 21% increase in realized margins on service throughput compared to the third quarter of 2009 ($0.58 per MMBtu in 2010 compared to $0.48 per MMBtu in 2009), reflecting higher NGL prices, the impact of Copano's fractionation facilities for a full quarter and an increase of pipeline throughput associated with fee-based contracts in the Eagle Ford Shale and the Barnett Shale Combo Plays. During the third quarter of 2010, weighted-average NGL prices on the Mt. Belvieu index, based on Copano's product mix for the period, were $40.16 per barrel compared to $35.09 per barrel during the third quarter of 2009, an increase of 14%. During the third quarter of 2010, natural gas prices on Houston Ship Channel index averaged $4.33 per MMBtu compared to $3.32 per MMBtu during the third quarter of 2009, an increase of 30%.
During the third quarter of 2010, the Texas segment provided gathering, transportation and processing services for an average of 590,116 MMBtu/d of natural gas compared to 613,234 MMBtu/d for the third quarter of 2009, a decrease of 4%. The Texas segment gathered an average of 319,538 MMBtu/d of natural gas, an increase of 8% over last year's third quarter, primarily due to increased volumes related to the Eagle Ford Shale and Barnett Shale Combo Plays. Processed volumes decreased 5% to an average of 516,949 MMBtu/d of natural gas at Copano's plants and third-party plants because no volumes were available to be processed at Copano's Lake Charles plant during the current quarter. NGL production increased 8% to an average of 19,685 Bbls/d at Copano's plants and third-party plants representing increased volumes behind Copano's Saint Jo plant in the Barnett Shale Combo Play.
Rocky Mountains
Segment gross margin for Rocky Mountains totaled $1.1 million in the third quarter of 2010 compared to $0.6 million for the third quarter of 2009. The increase in segment gross margin was the result of higher compressor rental income from Bighorn.
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 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 4% to 913,730 MMBtu/d in the third quarter of 2010 as compared to 952,126 MMBtu/d in the third quarter of 2009, as low natural gas prices have continued to impact drilling activity for natural gas in the Rocky Mountains.
Corporate and Other
Corporate and other gross margin includes Copano's commodity risk management activities. These activities contributed a gain of $2.6 million for the third quarter of 2010 compared to a gain of $7.6 million for the third quarter of 2009. The gain for the third quarter of 2010 included $11.1 million of net cash settlements received for expired commodity derivative instruments offset by $8.2 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio and $0.3 million of unrealized loss on undesignated economic hedges. The third quarter 2009 gain included $16.4 million of net cash settlements received for expired commodity derivative instruments and $0.4 million of unrealized mark-to-market gains on undesignated economic hedges offset by $9.2 million of non-cash amortization expense relating to the option component of Copano's risk management portfolio.
Cash Distributions
On October 13, 2010, Copano announced its third quarter 2010 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 second quarter of 2010 and will be paid on November 11, 2010 to common unitholders of record at the close of business on November 1, 2010.
Conference Call Information
Copano will hold a conference call to discuss its third quarter 2010 financial results and recent developments on November 5, 2010 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time). To participate in the call, dial (480) 629-9819 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 November 12, 2010 by calling (303) 590-3030 and using the pass code 4375411#.
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 Oklahoma, Texas, Wyoming and Louisiana. Its assets include approximately 6,400 miles of active natural gas gathering and transmission pipelines, 250 miles of NGL pipelines and eight natural gas processing plants, with more than one billion cubic feet per day of combined processing capacity and 22,000 Bbls/d 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 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 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 –
COPANO ENERGY, L.L.C. AND SUBSIDIARIES UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS |
|||||
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||
2010 |
2009 |
2010 |
2009 |
||
(In thousands, except per unit information) |
|||||
Revenue: |
|||||
Natural gas sales |
$ 87,524 |
$ 66,747 |
$292,559 |
$226,243 |
|
Natural gas liquids sales |
118,999 |
99,098 |
353,119 |
271,392 |
|
Transportation, compression and processing fees |
17,909 |
13,926 |
47,539 |
42,838 |
|
Condensate and other |
13,272 |
9,760 |
41,204 |
30,319 |
|
Total revenue |
237,704 |
189,531 |
734,421 |
570,792 |
|
Costs and expenses: |
|||||
Cost of natural gas and natural gas liquids (1) |
174,461 |
129,617 |
551,939 |
395,114 |
|
Transportation (1) |
5,340 |
6,484 |
16,619 |
18,211 |
|
Operations and maintenance |
13,004 |
13,202 |
38,337 |
38,764 |
|
Depreciation and amortization |
15,218 |
14,575 |
46,002 |
41,071 |
|
General and administrative |
9,869 |
9,200 |
31,311 |
29,246 |
|
Taxes other than income |
1,315 |
836 |
3,658 |
2,349 |
|
Equity in (earnings) loss from unconsolidated affiliates |
(2,049) |
(2,529) |
19,788 |
(6,112) |
|
Total costs and expenses |
217,158 |
171,385 |
707,654 |
518,643 |
|
Operating income |
20,546 |
18,146 |
26,767 |
52,149 |
|
Other income (expense): |
|||||
Interest and other income |
15 |
1,065 |
59 |
1,119 |
|
Gain on retirement of unsecured debt |
— |
— |
— |
3,939 |
|
Interest and other financing costs |
(12,943) |
(15,440) |
(41,239) |
(41,889) |
|
Income (loss) before income taxes and discontinued operations |
7,618 |
3,771 |
(14,413) |
15,318 |
|
Provision for income taxes |
(320) |
(304) |
(660) |
(1,039) |
|
Income (loss) from continuing operations |
7,298 |
3,467 |
(15,073) |
14,279 |
|
Discontinued operations, net of tax |
— |
262 |
— |
1,393 |
|
Net income (loss) |
7,298 |
3,729 |
(15,073) |
15,672 |
|
Preferred unit distributions |
(7,500) |
— |
(7,500) |
— |
|
Net (loss) income to common units |
$ (202) |
$ 3,729 |
$(22,573) |
$ 15,672 |
|
Basic net (loss) income per common unit: |
|||||
(Loss) income per common unit from continuing operations |
$ 0.00 |
$ 0.06 |
$ (0.36) |
$ 0.26 |
|
Income per common unit from discontinued operations |
0.00 |
0.01 |
0.00 |
0.03 |
|
Net (loss) income per common unit |
$ 0.00 |
$ 0.07 |
$ (0.36) |
$ 0.29 |
|
Weighted average number of common units |
65,658 |
54,565 |
63,193 |
54,313 |
|
Diluted net (loss) income per common unit: |
|||||
(Loss) income per common unit from continuing operations |
$ (0.00) |
$ 0.06 |
$ (0.36) |
$ 0.25 |
|
Income per common unit from discontinued operations |
0.00 |
0.00 |
0.00 |
0.02 |
|
Net (loss) income per common unit |
$ (0.00) |
$ 0.06 |
$ (0.36) |
$ 0.27 |
|
Weighted average number of common units |
65,658 |
58,036 |
63,193 |
57,953 |
|
(1) Exclusive of operations and maintenance and depreciation and amortization shown separately below. |
|||||
COPANO ENERGY, L.L.C. AND SUBSIDIARIES UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS |
|||
Nine Months Ended September 30, |
|||
2010 |
2009 |
||
(In thousands) |
|||
Cash Flows From Operating Activities: |
|||
Net (loss) income |
$ (15,073) |
$ 15,672 |
|
Adjustments to reconcile net (loss) income to net cash provided by operating activities: |
|||
Depreciation and amortization |
46,002 |
41,628 |
|
Amortization of debt issue costs |
2,773 |
3,060 |
|
Equity in loss (earnings) from unconsolidated affiliates |
19,788 |
(6,112) |
|
Distributions from unconsolidated affiliates |
16,999 |
18,333 |
|
Gain on retirement of unsecured debt |
— |
(3,939) |
|
Non-cash gain on risk management activities, net |
(555) |
(1,443) |
|
Equity-based compensation |
7,118 |
6,692 |
|
Deferred tax provision |
(19) |
538 |
|
Other non-cash items |
(458) |
202 |
|
Changes in assets and liabilities: |
|||
Accounts receivable |
10,586 |
14,857 |
|
Prepayments and other current assets |
2,135 |
1,196 |
|
Risk management activities |
10,766 |
23,462 |
|
Accounts payable |
(6,518) |
(12,034) |
|
Other current liabilities |
945 |
(1,363) |
|
Net cash provided by operating activities |
94,489 |
$100,749 |
|
Cash Flows From Investing Activities: |
|||
Additions to property, plant and equipment |
(101,265) |
(51,540) |
|
Additions to intangible assets |
(2,259) |
(1,756) |
|
Acquisitions |
— |
(6,003) |
|
Investments in unconsolidated affiliates |
(11,186) |
(3,240) |
|
Distributions from unconsolidated affiliates |
2,555 |
3,191 |
|
Proceeds from the sale of assets |
279 |
— |
|
Other |
280 |
(1,358) |
|
Net cash used in investing activities |
(111,596) |
(60,706) |
|
Cash Flows From Financing Activities: |
|||
Proceeds from longterm debt |
80,000 |
50,000 |
|
Repayment of longterm debt |
(350,000) |
(10,000) |
|
Retirement of unsecured debt |
— |
(14,286) |
|
Deferred financing costs |
(995) |
— |
|
Distributions to unitholders |
(107,612) |
(94,217) |
|
Proceeds from issuance placement of Series A preferred units, net of underwriting discounts and commissions of $8,935 |
291,065 |
— |
|
Proceeds from public offering of common units, net of underwriting discounts and commissions of $7,223 |
164,786 |
— |
|
Equity offering costs |
(6,236) |
— |
|
Proceeds from option exercises |
3,188 |
154 |
|
Net cash provided by (used in) financing activities |
74,196 |
(68,349) |
|
Net increase (decrease) in cash and cash equivalents |
57,089 |
(28,306) |
|
Cash and cash equivalents, beginning of year |
44,692 |
63,684 |
|
Cash and cash equivalents, end of period |
$101,781 |
$ 35,378 |
|
COPANO ENERGY, L.L.C. AND SUBSIDIARIES UNAUDITED CONSOLIDATED BALANCE SHEETS |
||||
As of |
||||
September 30, 2010 |
December 31, 2009 |
|||
(In thousands, except unit information) |
||||
ASSETS |
||||
Current assets: |
||||
Cash and cash equivalents |
$ 101,781 |
$ 44,692 |
||
Accounts receivable, net |
81,104 |
91,156 |
||
Risk management assets |
19,438 |
36,615 |
||
Prepayments and other current assets |
2,802 |
4,937 |
||
Total current assets |
205,125 |
177,400 |
||
Property, plant and equipment, net |
910,673 |
841,323 |
||
Intangible assets, net |
183,893 |
190,376 |
||
Investment in unconsolidated affiliates |
589,812 |
618,503 |
||
Escrow cash |
1,859 |
1,858 |
||
Risk management assets |
16,585 |
15,381 |
||
Other assets, net |
19,198 |
22,571 |
||
Total assets |
$1,927,145 |
$1,867,412 |
||
LIABILITIES AND MEMBERS' CAPITAL |
||||
Current liabilities: |
||||
Accounts payable |
$ 106,031 |
$ 111,021 |
||
Accrued interest |
8,698 |
11,921 |
||
Accrued tax liability |
696 |
672 |
||
Risk management liabilities |
7,392 |
9,671 |
||
Other current liabilities |
16,749 |
9,358 |
||
Total current liabilities |
139,566 |
142,643 |
||
Longterm debt (includes $567 and $628 bond premium as of September 30, 2010 and December 31, 2009, respectively) |
582,757 |
852,818 |
||
Deferred tax provision |
1,842 |
1,862 |
||
Risk management and other noncurrent liabilities |
6,130 |
10,063 |
||
Members' capital: |
||||
Series A convertible preferred units, no par value, 10,327,022 and 0 units issued and outstanding as of September 30, 2010 and December 31, 2009, respectively |
292,781 |
— |
||
Common units, no par value, 65,744,236 and 54,670,029 units issued and outstanding as of September 30, 2010 and December 31, 2009, respectively |
1,159,400 |
879,504 |
||
Class D units, no par value, 0 and 3,245,817 units issued and outstanding as of September 30, 2010 and December 31, 2009, respectively |
— |
112,454 |
||
Paid-in capital |
49,559 |
42,518 |
||
Accumulated deficit |
(289,001) |
(158,267) |
||
Accumulated other comprehensive loss |
(15,889) |
(16,183) |
||
1,196,850 |
860,026 |
|||
Total liabilities and members' capital |
$1,927,145 |
$1,867,412 |
||
COPANO ENERGY, L.L.C. AND SUBSIDIARIES OPERATING STATISTICS (Unaudited) |
|||||
Three Months Ended September 30, |
Nine Months Ended September 30, |
||||
2010 |
2009 |
2010 |
2009 |
||
($ in thousands) |
|||||
Total segment gross margin(1) (2) |
$ 57,903 |
$53,430 |
$165,863 |
$157,467 |
|
Operations and maintenance expenses(2) |
13,004 |
13,202 |
38,337 |
38,764 |
|
Depreciation and amortization(2) |
15,218 |
14,575 |
46,002 |
41,071 |
|
General and administrative expenses |
9,869 |
9,200 |
31,311 |
29,246 |
|
Taxes other than income |
1,315 |
836 |
3,658 |
2,349 |
|
Equity in (earnings) loss from unconsolidated affiliates(3) (4) (5) (6) |
(2,049) |
(2,529) |
19,788 |
(6,112) |
|
Operating income(2) (3) |
20,546 |
18,146 |
26,767 |
52,149 |
|
Gain on retirement of unsecured debt |
— |
— |
— |
3,939 |
|
Interest and other financing costs, net |
(12,928) |
(14,375) |
(41,180) |
(40,770) |
|
Provision for income taxes |
(320) |
(304) |
(660) |
(1,039) |
|
Discontinued operations, net of tax |
— |
262 |
— |
1,393 |
|
Net income (loss) |
7,298 |
3,729 |
(15,073) |
15,672 |
|
Preferred unit distributions |
(7,500) |
— |
(7,500) |
— |
|
Net (loss) income to common units |
$ (202) |
$ 3,729 |
$ (22,573) |
$ 15,672 |
|
Total segment gross margin: |
|||||
Oklahoma(2) |
$ 23,010 |
$ 18,284 |
$ 69,106 |
$ 50,058 |
|
Texas |
31,218 |
26,875 |
90,134 |
70,775 |
|
Rocky Mountains(7) |
1,091 |
634 |
3,342 |
2,144 |
|
Segment gross margin(2) |
55,319 |
45,793 |
162,582 |
122,977 |
|
Corporate and other(8) |
2,584 |
7,637 |
3,281 |
34,490 |
|
Total segment gross margin(1) (2) |
$ 57,903 |
$53,430 |
$165,863 |
$157,467 |
|
Segment gross margin per unit: |
|||||
Oklahoma: |
|||||
Service throughput ($/MMBtu) (2) |
$ 0.93 |
$ 0.76 |
$ 0.97 |
$ 0.69 |
|
Texas: |
|||||
Service throughput ($/MMBtu) |
$ 0.58 |
$ 0.48 |
$ 0.57 |
$ 0.41 |
|
Volumes: |
|||||
Oklahoma: (9) |
|||||
Service throughput (MMBtu/d) (10) |
270,184 |
260,296 |
259,710 |
266,306 |
|
Plant inlet volumes (MMBtu/d) |
156,676 |
166,884 |
156,771 |
164,741 |
|
NGLs produced (Bbls/d) |
16,541 |
16,474 |
16,180 |
15,928 |
|
Texas: (11) |
|||||
Service throughput (MMBtu/d) (10) |
590,116 |
613,234 |
577,678 |
629,367 |
|
Pipeline throughput (MMBtu/d) |
319,538 |
296,003 |
321,450 |
296,621 |
|
Plant inlet volumes (MMBtu/d) |
516,949 |
543,994 |
481,285 |
553,876 |
|
NGLs produced (Bbls/d) |
19,685 |
18,197 |
17,818 |
17,846 |
|
Capital expenditures: |
|||||
Maintenance capital expenditures |
$ 3,290 |
$ 1,886 |
$ 6,370 |
$ 7,932 |
|
Expansion capital expenditures |
29,290 |
17,283 |
101,232 |
42,119 |
|
Total capital expenditures |
$ 32,580 |
$19,169 |
$107,602 |
$ 50,051 |
|
Operations and maintenance expenses: |
|||||
Oklahoma(2) |
$ 6,163 |
$ 6,111 |
$ 17,266 |
$ 17,335 |
|
Texas |
6,779 |
7,089 |
20,845 |
21,423 |
|
Rocky Mountains |
62 |
2 |
226 |
6 |
|
Total operations and maintenance expenses(2) |
$ 13,004 |
$13,202 |
$ 38,337 |
$ 38,764 |
|
(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 of operating income (loss), please read "Non-GAAP Financial Measures." |
|
(2) |
Excludes results attributable to Copano's crude oil pipeline and related assets for the three and nine months ended September 30, 2009 as these amounts are shown under the caption "Discontinued operations, net of tax." |
|
(3) |
During the three months ended June 30, 2010, Copano recorded a $25 million non-cash impairment charge relating to our investment in Bighorn. This non-cash impairment charge resulted continued weakness in Rocky Mountains natural gas prices, lack of drilling activity in the Wyoming's Powder River Basin and a downward shift in the Colorado Interstate Gas forward price curve. |
|
(4) |
Includes results and volumes associated with Copano's interests in Bighorn and Fort Union. Combined volumes gathered by Bighorn and Fort Union were 913,730 MMBtu/d and 952,126 MMBtu/d for the three months ended September 30, 2010 and 2009, respectively. Combined volumes gathered by Bighorn and Fort Union were 914,967 MMBtu/d and 979,408 MMBtu/d for the nine months ended September 30, 2010 and 2009, respectively. |
|
(5) |
Includes results and volumes associated with Copano's interest in Southern Dome. For the three months ended September 30, 2010, plant inlet volumes for Southern Dome averaged 12,338 MMBtu/d and NGLs produced averaged 444 Bbls/d. For the three months ended September 30, 2009, plant inlet volumes for Southern Dome averaged 13,857 MMBtu/d and NGLs produced averaged 523 Bbls/d. For the nine months ended September 30, 2010, plant inlet volumes for Southern Dome averaged 13,046 MMBtu/d and NGLs produced averaged 466 Bbls/d. For the nine months ended September 30, 2009, plant inlet volumes for Southern Dome averaged 13,304 MMBtu/d and NGLs produced averaged 490 Bbls/d. |
|
(6) |
Includes results and volumes associated with Copano's interest in Webb Duval. Gross volumes transported by Webb Duval, net of intercompany volumes, were 53,668 MMBtu/d and 72,985 MMBtu/d for the three months ended September 30, 2010 and 2009, respectively. Gross volumes transported by Webb Duval, net of intercompany volumes, were 56,145 MMBtu/d and 82,001 MMBtu/d for the nine months ended September 30, 2010 and 2009, respectively. |
|
(7) |
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 and volumes transported using Copano's firm capacity agreements with Wyoming Interstate Gas Company and compressor rental services provided to Bighorn. Excludes results and volumes associated with Copano's interests in Bighorn and Fort Union. |
|
(8) |
Corporate and other includes results attributable to Copano's commodity risk management activities. |
|
(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 September 30, 2010, plant inlet volumes averaged 118,327 MMBtu/d and NGLs produced averaged 13,458 Bbls/d for plants owned by the Oklahoma segment. For the three months ended September 30, 2009, plant inlet volumes averaged 129,832 MMBtu/d and NGLs produced averaged 13,410 Bbls/d for plants owned by the Oklahoma segment. For the nine months ended September 30, 2010, plant inlet volumes averaged 120,007 MMBtu/d and NGLs produced averaged 13,142 Bbls/d for plants owned by the Oklahoma segment. For the nine months ended September 30, 2009, plant inlet volumes averaged 127,067 MMBtu/d and NGLs produced averaged 12,970 Bbls/d for plants owned by the Oklahoma segment. Excludes volumes associated with Copano's interest in Southern Dome. |
|
(10) |
"Service throughput" means the volume of natural gas delivered to Copano's wholly 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. |
|
(11) |
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 498,057 MMBtu/d and NGLs produced averaged 18,401 Bbls/d for the three months ended September 30, 2010 for plants owned by the Texas segment. Plant inlet volumes averaged 537,099 MMBtu/d and NGLs produced averaged 17,653 Bbls/d for the three months ended September 30, 2009 for plants owned by the Texas segment. Plant inlet volumes averaged 470,292 MMBtu/d and NGLs produced averaged 17,052 Bbls/d for the nine months ended September 30, 2010 for plants owned by the Texas segment. Plant inlet volumes averaged 537,382 MMBtu/d and NGLs produced averaged 16,504 Bbls/d for the nine months ended September 30, 2009 for plants owned by the Texas segment. Excludes volumes associated with Copano's interest in Webb Duval. |
|
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 (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 September 30, |
Nine Months Ended September 30, |
||||
2010 |
2009 |
2010 |
2009 |
||
($ in thousands) |
|||||
Reconciliation of total segment gross margin to operating income (loss): |
|||||
Operating income (loss) |
$20,546 |
$18,146 |
$ 26,767 |
$ 52,149 |
|
Add: Operations and maintenance expenses |
13,004 |
13,202 |
38,337 |
38,764 |
|
Depreciation and amortization |
15,218 |
14,575 |
46,002 |
41,071 |
|
General and administrative expenses |
9,869 |
9,200 |
31,311 |
29,246 |
|
Taxes other than income |
1,315 |
836 |
3,658 |
2,349 |
|
Equity in (earnings) loss from unconsolidated affiliates |
(2,049) |
(2,529) |
19,788 |
(6,112) |
|
Total segment gross margin |
$57,903 |
$53,430 |
$165,863 |
$157,467 |
|
Reconciliation of EBITDA and adjusted EBITDA to net income (loss): |
|||||
Net income (loss) |
$ 7,298 |
$ 3,729 |
$ (15,073) |
$ 15,672 |
|
Add: Depreciation and amortization(1) |
15,218 |
14,628 |
46,002 |
41,628 |
|
Interest and other financing costs |
12,943 |
15,440 |
41,239 |
41,889 |
|
Provision for income taxes |
320 |
304 |
660 |
1,039 |
|
EBITDA |
35,779 |
34,101 |
72,828 |
100,228 |
|
Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments and impairment |
4,418 |
4,792 |
38,708 |
14,395 |
|
Copano's share of depreciation and amortization included in equity in earnings from unconsolidated affiliates |
1,670 |
1,707 |
4,810 |
5,040 |
|
Copano's share of interest and other financing costs incurred by equity method investments |
440 |
615 |
1,305 |
1,093 |
|
Adjusted EBITDA |
$ 42,307 |
$41,215 |
$117,651 |
$120,756 |
|
Reconciliation of EBITDA and adjusted EBITDA to cash flows from operating activities: |
|||||
Cash flow provided by operating activities |
$29,075 |
$21,121 |
$ 94,489 |
$100,749 |
|
Add: Cash paid for interest and other financing costs |
11,961 |
14,545 |
38,466 |
38,829 |
|
Equity in earnings (loss) from unconsolidated affiliates |
2,049 |
2,529 |
(19,788) |
6,112 |
|
Distributions from unconsolidated affiliates |
(6,006) |
(6,894) |
(16,999) |
(18,333) |
|
Risk management activities |
(4,764) |
(4,983) |
(10,766) |
(23,462) |
|
Changes in working capital and other |
3,464 |
7,783 |
(12,574) |
(3,667) |
|
EBITDA |
35,779 |
34,101 |
72,828 |
100,228 |
|
Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments and impairment |
4,418 |
4,792 |
38,708 |
14,395 |
|
Copano's share of depreciation and amortization included in equity in earnings from unconsolidated affiliates |
1,670 |
1,707 |
4,810 |
5,040 |
|
Copano's share of interest and other financing costs incurred by equity method investments |
440 |
615 |
1,305 |
1,093 |
|
Adjusted EBITDA |
$42,307 |
$41,215 |
$117,651 |
$120,756 |
|
Reconciliation of net income (loss) to total distributable cash flow: |
|||||
Net income (loss) |
$ 7,298 |
$ 3,729 |
$ (15,073) |
$ 15,672 |
|
Add: Depreciation and amortization(1) |
15,218 |
14,628 |
46,002 |
41,628 |
|
Amortization of commodity derivative options |
8,163 |
9,236 |
24,211 |
27,715 |
|
Amortization of debt issue costs |
983 |
895 |
2,773 |
3,060 |
|
Equity-based compensation |
2,448 |
2,345 |
7,849 |
6,600 |
|
Distributions from unconsolidated affiliates |
6,563 |
7,297 |
19,554 |
21,524 |
|
Unrealized (gain) loss associated with line fill contributions and gas imbalances |
(240) |
(556) |
2,098 |
(29) |
|
Unrealized loss (gain) on derivatives |
494 |
194 |
(555) |
(1,442) |
|
Deferred taxes and other |
124 |
68 |
(245) |
740 |
|
Less: Equity in (earnings) loss from unconsolidated affiliates |
(2,049) |
(2,529) |
19,788 |
(6,112) |
|
Maintenance capital expenditures |
(3,290) |
(1,886) |
(6,370) |
(7,932) |
|
Total distributable cash flow(2) |
$35,712 |
$33,421 |
$100,032 |
$101,424 |
|
Actual quarterly distribution ("AQD") |
$38,349 |
$31,860 |
|||
Total distributable cash flow coverage of AQD |
93% |
105% |
|||
________________________ |
|||||
(1) Includes depreciation and amortization related to the discontinued operations. |
|||||
(2) Prior to any retained cash reserves established by Copano's Board of Directors. |
|||||
Contacts: |
Carl Luna, SVP & CFO |
|
Copano Energy, L.L.C. |
||
713-621-9547 |
||
Jack Lascar / [email protected] |
||
Anne Pearson / [email protected] |
||
DRG&L / 713-529-6600 |
||
SOURCE Copano Energy, L.L.C.
WANT YOUR COMPANY'S NEWS FEATURED ON PRNEWSWIRE.COM?
Newsrooms &
Influencers
Digital Media
Outlets
Journalists
Opted In
Share this article