Copano Energy Reports Second Quarter 2012 Results – Issues 2013 Guidance
HOUSTON, Aug. 8, 2012 /PRNewswire/ — Copano Energy, L.L.C. (NASDAQ: CPNO) today announced its financial results for the three months ended June 30, 2012.
Second Quarter 2012 Highlights:
- Total distributable cash flow of $39.5 million, a 5% increase from second quarter 2011
- Total segment gross margin of $72.9 million, a 12% increase from the prior year period
- Adjusted EBITDA of $58.3 million, a 7% increase from the prior year period
- Volumes gathered from the Eagle Ford Shale play averaged 490,000 MMBtu/d, a 277% increase from the prior year period
- Texas segment NGL production of over 50,000 Bbls/d, an 86% increase from second quarter 2011
2013 Guidance:
- Adjusted EBITDA forecasted to range from $300 million to $330 million
- Total Distributable Cash Flow forecasted to range from $220 million to $240 million
- Common unit distribution growth rate target of 7% to 9%
“Continued strong volume growth from the Eagle Ford Shale and increased volumes at our Saint Jo plant, combined with improving asset performance, led to increased financial results during the second quarter,” said R. Bruce Northcutt, Copano’s President and Chief Executive Officer. “Our results also benefited from our strategy of transitioning to a more fee-based business, which has reduced the impact of the lower commodity price environment.”
“We are pleased with our progress on capital projects and look forward to achieving the full benefits of our Eagle Ford strategy, which will drive cash flow and distribution growth in 2013. At the same time, we have begun to focus on new long-term growth opportunities to create additional value for Copano unitholders,” Northcutt added.
Second Quarter Financial Results
Total distributable cash flow increased 5% from a year ago, to $39.5 million for the second quarter of 2012, and 19% from the first quarter of 2012. The increase from the prior-year period was primarily due to:
- increased throughput from the Eagle Ford Shale, north Barnett Shale Combo and Woodford Shale plays,
- volumes processed at the Lake Charles plant in Louisiana, and
- lower maintenance capital expenditures.
These benefits were partially offset by lower natural gas liquids (NGL) prices and higher interest and operating expenses.
Second-quarter 2012 total distributable cash flow represents 93% coverage of the second-quarter distribution of $0.575 per unit, based on common units outstanding on the distribution record date.
Revenue for the second quarter of 2012 decreased 8% from the second quarter of 2011 to $317.3 million, and 6% from the first quarter of 2012. Total segment gross margin increased 12% from both the second quarter of 2011 and first quarter of 2012 to $72.9 million. Adjusted EBITDA increased 7% from the second quarter of 2011, to $58.3 million and 16% from first quarter of 2012. Net income to common was $12.2 million for the second quarter of 2012, compared to net loss of $17.4 million for the second quarter of 2011.
Corporate and other activities, which include Copano’s commodity risk management efforts, contributed a gain of $3.4 million for the second quarter of 2012 compared to a loss of $10.3 million for the second quarter of 2011 and a loss of $5.1 million for the first quarter of 2012.
Total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin are non-GAAP financial measures, which are reconciled to their most directly comparable GAAP measures at the end of this news release. Please read “Use of Non-GAAP Financial Measures” beginning on page 6 of this news release.
Second Quarter Operating Results by Segment
Texas
Segment gross margin for Texas increased 6% from the second quarter of 2011 to $49.1 million, and increased 8% from the first quarter of 2012. The increase from the prior year was primarily a result of volume growth from the Eagle Ford Shale and north Barnett Shale Combo plays, partially offset by lower NGL prices and a decline in lean gas volumes, which were displaced by rich gas volumes at the Houston Central complex. Also, the Lake Charles plant, which contributed $2.5 million to Texas gross margin for the second quarter of 2012, did not operate during the prior-year period.
During the second quarter of 2012, the Texas segment provided gathering and processing services for an average of 924,465 MMBtu/d of natural gas, an increase of 39% from the second quarter of 2011. The Texas segment gathered an average of 566,388 MMBtu/d of natural gas, an increase of 28% over the second quarter of 2011, primarily due to increased volumes from the Eagle Ford Shale and north Barnett Shale Combo plays. Volumes processed at Copano’s plants and third-party plants in Texas averaged 834,846 MMBtu/d during the second quarter of 2012, an increase of 42% over the second quarter of 2011 primarily due to increased volumes from the north Barnett Shale Combo play and at the Lake Charles plant. Second-quarter NGL production averaged 50,146 Bbls/d at Copano-owned plants and third-party plants, an increase of 86% from the second quarter of 2011 and 42% from the first quarter of 2012, reflecting a substantial increase in the NGL content of volumes at the Houston Central complex, and increased volumes at the Saint Jo plant in the north Barnett Shale Combo play and the Lake Charles plant in Louisiana.
Eagle Ford Gathering, Copano’s unconsolidated joint venture with Kinder Morgan, has been in full service since December 2011 and provided gathering services for an average of 252,912 MMBtu/d during the second quarter of 2012. Texas segment gross margin results do not include the financial results and volumes associated with Copano’s interest in Eagle Ford Gathering, which is accounted for under the equity method of accounting and shown in Copano’s financial statements under “Equity in (earnings) loss from unconsolidated affiliates.” For the second quarter of 2012, equity earnings and distributions from Eagle Ford Gathering totaled $9.8 million and $4.8 million, respectively.
Oklahoma
Segment gross margin for Oklahoma was $20.2 million for the second quarter of 2012, a decrease of 30% compared to the second quarter of last year and 17% from the first quarter of 2012. The year-over-year decrease resulted primarily from a decrease of 39% in realized margins on service throughput compared to the second quarter of 2011 ($0.68 per MMBtu in 2012 compared to $1.11 per MMBtu in 2011) due to lower NGL and natural gas prices. This decrease was partially offset by an increase in service throughput attributable to lean gas volume growth from the Woodford Shale play.
The Oklahoma segment gathered an average of 324,915 MMBtu/d of natural gas, an increase of 14% compared to the second quarter of 2011, due primarily to lean gas from the Woodford Shale area, which increased 46% compared to the second quarter of 2011. Volumes processed at wholly-owned and third-party plants in Oklahoma were flat compared to the second quarter of 2011, averaging 158,016 MMBtu/d. Second quarter NGL production at Copano-owned plants and third-party plants averaged 17,028 Bbls/d, a decrease of 2% from the second quarter of 2011.
Rocky Mountains
Segment gross margin for the Rocky Mountains segment totaled $0.2 million in the second quarter of 2012 compared to $0.8 million for the second quarter of 2011 and $0.4 million for the first quarter of 2012. Rocky Mountains segment gross margin results do not include the financial results and volumes associated with Copano’s interest in Bighorn Gas Gathering and Fort Union Gas Gathering, which are accounted for under the equity method of accounting and shown in Copano’s financial statements under “Equity in (earnings) loss from unconsolidated affiliates.”
Average pipeline throughput for Bighorn and Fort Union on a combined basis increased 40% to 747,009 MMBtu/d in the second quarter of 2012 as compared to 533,329 MMBtu/d in the second quarter of 2011. The volume increase is due primarily to producers increasing volumes on Fort Union to access downstream markets; however, because Fort Union has firm volume commitments, the increase did not have a material impact on Copano’s equity earnings or distributions. For the second quarter of 2012, combined equity earnings for Bighorn and Fort Union totaled $2.6 million, compared to $0.6 million for the same period in 2011. Combined distributions from Bighorn and Fort Union totaled $7.3 million in the second quarter of 2012, compared to $6.3 million in the second quarter of last year.
Cash Distributions
On July 11, 2012, Copano announced its second quarter 2012 cash distribution of $0.575 per unit, or $2.30 per unit on an annualized basis, for all of its outstanding common units. This distribution is unchanged from the first quarter of 2012 and will be paid on August 9, 2012 to common unitholders of record at the close of business on July 31, 2012.
2013 Guidance
Copano announced today its forecast for certain financial items for 2013, as outlined in the table below:
($ in millions) Calendar 2013
-------------
Adjusted EBITDA $300 to $330
Total distributable cash flow $220 to $240
Common unit distribution growth rate
target(1) 7% to 9%
Quarterly common unit distribution
coverage target 100% to 115%
Fee-based margin(2) 55% to 60%
Capital expenditures:
Expansion $250 to $300
Maintenance $13 to $18
___________________________
(1) Based on annualized fourth quarter 2013 declared distribution
(2) Represents fee-based component of our total segment gross
margin and our share of gross margin from our unconsolidated
affiliates
The above forecasted amounts are based on various assumptions, which include an average natural gas price of $3.80 per MMBtu, weighted-average Mont Belvieu and Conway NGL prices of $33.16 per barrel and $29.34 per barrel, respectively, and an average NYMEX crude price of $90.34 per barrel. Additionally, for the third and fourth quarters of 2013, Copano assumes no conversion of its preferred units then outstanding and payment of cash rather than in-kind preferred unit distributions.
Additional assumptions include, among others, timely and on-budget completion of Copano’s announced expansion capital projects, forecasted operational volumes from existing operations and expansion capital projects, Copano’s existing contract portfolio and outstanding commodity hedge portfolio, receipt of volume deficiency payments under certain contracts, consistent operations at third-party facilities and timely completion of expansions at third-party facilities that impact Copano’s operations, estimated interest rates, and budgeted operations and maintenance and general and administrative costs. Management will issue updated 2013 guidance in subsequent earnings announcements only if revised expectations fall outside the ranges set forth above.
Management does not develop detailed forecasts for certain items, including GAAP revenues, depreciation, amortization and non-cash changes in derivatives, and therefore is unable to provide forecasted net income, a comparable GAAP measure, for the period presented.
With respect to the third and fourth quarters of 2012, management expects to continue to provide quarterly gross margin trends and any material updates to full-year 2012 capital expenditures and expense guidance.
Conference Call Information
Copano will hold a conference call on August 9, 2012 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) to discuss its second quarter 2012 financial results. To participate in the call, dial (480) 629-9645 and ask for the Copano call at least 10 minutes prior to the start time, or access it live over the internet at www.copano.com on the “Investor Overview” page of the “Investor Relations” section of Copano’s website.
A replay of the audio webcast will be available shortly after the call on Copano’s website. A telephonic replay will be available through August 16, 2012 by calling (303) 590-3030 and using the pass code 4551423#.
Use of Non-GAAP Financial Measures
This news release and the accompanying schedules include non-generally accepted accounting principles, or non-GAAP, financial measures of total distributable cash flow, total segment gross margin, adjusted EBITDA and segment gross margin. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP. Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Copano’s non-GAAP financial measures may not be comparable to similarly titled measures of other companies, who may not calculate their measures in the same manner.
Copano’s management team uses non-GAAP financial measures to evaluate its core profitability and to assess the financial performance of its assets. Subject to the limitations expressed above, Copano believes that investors and other market participants benefit from access to the various financial measures that its management uses in evaluating its performance because it allows them to independently evaluate Copano’s performance with the same information used by management.
Copano Energy, L.L.C. is a midstream natural gas company with operations in Texas, Oklahoma, Wyoming and Louisiana. More information is available at http://www.copano.com.
This press release includes “forward-looking statements,” as defined by the Securities and Exchange Commission. Statements that address activities or events that Copano believes will or may occur in the future are forward-looking statements. These statements include, but are not limited to, statements about future producer activity and Copano’s total distributable cash flow and distribution coverage. These statements are based on management’s experience and perception of historical trends, current conditions, expected future developments and other factors management believes are reasonable. Important factors that could cause actual results to differ materially from those in forward-looking statements include the following risks and uncertainties, many of which are beyond Copano’s control: the volatility of prices and market demand for natural gas and natural gas liquids; Copano’s ability to continue to obtain new sources of natural gas supply and retain its key customers; the impact on volumes and resulting cash flow of technological, economic and other uncertainties inherent in estimating future production; producers’ ability to drill and successfully complete and attach new natural gas supplies; the NGL content of new gas supplies; Copano’s ability to access or construct new processing, fractionation and transportation capacity; the availability of downstream transportation and other facilities for natural gas and NGLs; mechanical failures and other operational risks affecting the performance of Copano’s processing plants and other facilities, higher construction costs or project delays due to inflation, limited availability of required resources, or the effects of environmental, legal or other uncertainties; general economic conditions; the effects of government regulations and policies; and other financial, operational and legal risks and uncertainties detailed from time to time in Copano’s quarterly and annual reports filed with the Securities and Exchange Commission.
Contacts: Carl A. Luna, SVP and CFO
Copano Energy, L.L.C.
713-621-9547
Jack Lascar / jlascar@drg-l.com
Anne Pearson / apearson@drg-l.com
DRG&L / 713-529-6600
-financial statements follow -
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended Six Months Ended
June 30, June 30,
2012 2011 2012 2011
---- ---- ---- ----
(In thousands, except per unit information)
Revenue:
Natural gas
sales $69,993 $123,928 $156,205 $227,723
Natural gas
liquids sales 188,780 180,758 383,967 329,759
Transportation,
compression and
processing fees 43,241 27,898 83,080 52,369
Condensate and
other 15,289 13,472 31,279 26,130
Total revenue 317,303 346,056 654,531 635,981
------- ------- ------- -------
Costs and expenses:
Cost of natural
gas and natural
gas liquids (1) 238,482 274,398 504,433 498,128
Transportation
(1) 5,971 6,362 12,420 12,211
Operations and
maintenance 18,287 15,763 36,929 30,862
Depreciation and
amortization 19,062 17,363 38,150 34,232
Impairment - - 28,744 -
General and
administrative 10,298 11,901 25,242 24,499
Taxes other than
income 2,110 1,397 3,476 2,527
Equity in
(earnings) loss
from
unconsolidated
affiliates (12,437) (1,306) 102,291 (3,008)
Total costs and expenses 281,773 325,878 751,685 599,451
------- ------- ------- -------
Operating income (loss) 35,530 20,178 (97,154) 36,530
Other income (expense):
Interest and
other income 521 8 559 15
Loss on
refinancing of
unsecured debt - (18,233) - (18,233)
Interest and
other financing
costs (14,602) (11,454) (29,026) (23,370)
Income (loss) before income taxes 21,449 (9,501) (125,621) (5,058)
Provision for income taxes (331) 140 (932) (771)
---- --- ---- ----
Net income (loss) 21,118 (9,361) (126,553) (5,829)
Preferred unit distributions (8,915) (8,076) (17,613) (15,956)
Net income (loss) to common units $12,203 $(17,437) $(144,166) $(21,785)
======= ======== ========= ========
Basic net income (loss) per common unit:
Net income
(loss) per
common unit $0.17 $(0.26) $(2.01) $(0.33)
Weighted average
number of
common units 72,300 66,143 71,630 66,065
Diluted net income (loss) per common unit:
Net income
(loss) per
common unit $0.14 $(0.26) $(2.01) $(0.33)
Weighted average
number of
common units 85,176 66,143 71,630 66,065
Distributions declared per common unit $0.575 $0.575 $1.150 $1.150
=== ====== ====== ====== ======
____________
(1) Exclusive of operations and maintenance, depreciation and amortization and impairment shown separately below
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended June 30,
2012
2011
----
Cash Flows From Operating Activities: (In thousands)
Net loss $(126,553) $(5,829)
Adjustments to
reconcile net loss
to net cash
provided by
operating
activities:
Depreciation and
amortization 38,150 34,232
Impairment 28,744 -
Amortization of
debt issue
costs 1,978 1,949
Equity in loss
(income) from
unconsolidated
affiliates 102,291 (3,008)
Distributions
from
unconsolidated
affiliates 20,618 12,323
Loss on
refinancing of
unsecured debt - 18,233
Non-cash gain
on risk
management
activities, net (6,021) (1,536)
Equity-based
compensation 2,314 5,340
Deferred tax
provision 185 168
Other non-cash
items 346 (10)
Changes in
assets and
liabilities,
net of
acquisitions:
Accounts
receivable 24,756 (15,637)
Prepayments
and other
current
assets 2,733 2,110
Risk
management
activities 6,105 5,455
Accounts
payable (45,705) 21,498
Other current
liabilities 3,621 718
----- ---
Net cash provided by
operating activities 53,562 76,006
------ ------
Cash Flows From Investing Activities:
Additions to
property, plant
and equipment (142,465) (98,289)
Additions to
intangible assets (2,740) (4,140)
Acquisitions - (16,084)
Investments in
unconsolidated
affiliates (34,165) (65,027)
Distributions from
unconsolidated
affiliates 1,896 1,249
Escrow cash - 6
Proceeds from sale
of assets 178 141
Other 3,366 (185)
Net cash used in
investing activities (173,930) (182,329)
-------- --------
Cash Flows From Financing Activities:
Proceeds from long-
term debt 330,375 605,000
Repayment of long-
term debt (317,000) (392,665)
Payments of
premiums and
expenses on
redemption of
unsecured debt - (14,572)
Deferred financing
costs (3,434) (15,670)
Distributions to
unitholders (84,150) (76,571)
Proceeds from
public offering of
common units, net
of underwriting
discounts
and commissions
of $7,590 188,083 -
Equity offering
costs (360) (4)
Proceeds from
option exercises 888 2,431
Net cash provided by
financing activities 114,402 107,949
------- -------
Net (decrease) increase in cash and cash equivalents (5,966) 1,626
Cash and cash equivalents, beginning of year 56,962 59,930
------ ------
Cash and cash equivalents, end of period $50,996 $61,556
======= =======
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2012 2011
---- ----
(In thousands, except unit
information)
ASSETS
Current assets:
Cash and cash
equivalents $50,996 $56,962
Accounts
receivable,
net 95,105 119,193
Risk management
assets 21,995 4,322
Prepayments and
other current
assets 2,381 5,114
Total current assets 170,477 185,591
------- -------
Property, plant and equipment, net 1,238,893 1,103,699
Intangible assets, net 160,391 192,425
Investments in unconsolidated affiliates 453,380 544,687
Escrow cash 1,848 1,848
Risk management assets 10,445 6,452
Other assets, net 27,851 29,895
------ ------
Total assets $2,063,285 $2,064,597
========== ==========
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Accounts
payable $120,632 $155,921
Accrued capital
expenditures 19,712 7,033
Accrued
interest 10,951 8,686
Accrued tax
liability 729 1,182
Risk management
liabilities 1,833 3,565
Other current
liabilities 15,953 15,007
Total current liabilities 169,810 191,394
------- -------
Long term debt (includes $3,263 and $0 bond premium as
of June 30, 2012
and December
31, 2011,
respectively) 1,007,788 994,525
Deferred tax liability 2,385 2,199
Other noncurrent liabilities 5,105 4,581
Commitments and contingencies
Members' capital:
Series A
convertible
preferred
units, no par
value,
12,275,579
units and
11,684,074 units issued and
outstanding as of June 30,
2012 and
December 31, 2011, respectively 285,168 285,168
Common units,
no par value,
72,365,674
units and
66,341,458
units issued
and
outstanding as of June 30, 2012
and December 31, 2011,
respectively 1,353,504 1,164,853
Paid in capital 67,034 62,277
Accumulated deficit (834,712) (624,121)
Accumulated other comprehensive income (loss) 7,203 (16,279)
----- -------
878,197 871,898
------- -------
Total liabilities and members'
capital $2,063,285 $2,064,597
========== ==========
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED RESULTS OF OPERATIONS
Three Months Ended Six Months Ended
June 30, June 30,
-------- --------
2012 2011 2012 2011
---- ---- ---- ----
($ In thousands)
Total segment gross margin(1) $72,850 $65,296 $137,678 $125,642
Operations and maintenance expenses 18,287 15,763 36,929 30,862
Depreciation and amortization 19,062 17,363 38,150 34,232
Impairment - - 28,744 -
General and administrative expenses 10,298 11,901 25,242 24,499
Taxes other than income 2,110 1,397 3,476 2,527
Equity in (earnings) loss from unconsolidated
affiliates(2)(3) (12,437) (1,306) 102,291 (3,008)
------- ------ ------- ------
Operating income
(loss) 35,530 20,178 (97,154) 36,530
Loss on refinancing of unsecured debt - (18,233) - (18,233)
Interest and other financing costs, net (14,081) (11,446) (28,467) (23,355)
Provision for income taxes (331) 140 (932) (771)
---- --- ---- ----
Net income (loss) 21,118 (9,361) (126,553) (5,829)
Preferred unit distributions (8,915) (8,076) (17,613) (15,956)
------ ------ ------- -------
Net income (loss) to common units $12,203 $(17,437) $(144,166) $(21,785)
======= ======== ========= ========
Basic net income (loss) per common unit $0.17 $(0.26) $(2.01) $(0.33)
=== ===== ====== ====== ======
Weighted average number of common units - basic 72,300 66,143 71,630 66,065
====== ====== ====== ======
Diluted net income (loss) per common unit $0.14 $(0.26) $(2.01) $(0.33)
===== ====== ====== ======
Weighted average number of common units - diluted 85,176 66,143 71,630 66,065
====== ====== ====== ======
Total segment gross margin:
Texas $49,101 $46,134 $94,442 $91,145
Oklahoma 20,171 28,665 44,370 51,747
Rocky
Mountains(4) 187 771 545 1,813
Segment gross margin 69,459 75,570 139,357 144,705
Corporate and
other(5) 3,391 (10,274) (1,679) (19,063)
Total segment gross margin(1) $72,850 $65,296 $137,678 $125,642
======= ======= ======== ========
Segment gross margin per unit:
Texas:
Service throughput ($/MMBtu) $0.58 $0.76 $0.56 $0.76
Oklahoma:
Service throughput ($/MMBtu) $0.68 $1.11 $0.76 $1.03
Volumes:
Texas:(6)
Service throughput (MMBtu/d)(7) 924,465 665,040 934,257 660,741
Pipeline throughput (MMBtu/d) 566,388 444,186 565,949 422,429
Plant inlet volumes (MMBtu/d) 834,846 588,533 834,004 574,794
NGLs produced (Bbls/d) 50,146 26,913 42,745 25,080
Oklahoma:(8)
Service throughput (MMBtu/d)(7) 324,915 283,870 321,600 280,293
Plant inlet volumes (MMBtu/d) 158,106 157,424 157,579 156,856
NGLs produced (Bbls/d) 17,028 17,331 16,994 17,067
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED RESULTS OF OPERATIONS
Capital Expenditures:
Maintenance
capital
expenditures $3,798 $5,555 $6,241 $7,601
Expansion
capital
expenditures 115,562 69,382 163,925 120,901
Total capital expenditures $119,360 $74,937 $170,166 $128,502
======== ======= ======== ========
Operations and maintenance expenses:
Texas $11,275 $8,908 $21,893 $17,733
Oklahoma 6,962 6,794 14,943 13,013
Rocky Mountains 50 61 93 116
Total operations and maintenance
expenses $18,287 $15,763 $36,929 $30,862
======= ======= ======= =======
(1) Total segment
gross margin
is a non-GAAP
financial
measure.
Please read
"Unaudited
Non-GAAP
Financial
Measures" for
a
reconciliation
of total
segment gross
margin to its
most directly
comparable
GAAP measure
of operating
income.
(2) During the
three months
ended March
31, 2012,
Copano
recorded a
$120 million
non-cash
impairment
charge
relating to
its
investments in
Bighorn and
Fort Union.
(3) The following
table
summarizes the
results and
volumes
associated
with our
unconsolidated
affiliates ($
in thousands):
Three Months Ended June 30,
2012 2011
---- ----
Volume Equity (Earnings)/Loss Volume Equity (Earnings)/Loss
------ ---------------------- ------ ----------------------
Eagle Ford Gathering $(9,846) $8
Pipeline throughput (MMBtu/d) 252,912 -
NGLs produced(a) (Bbls/d) 10,169 -
Liberty Pipeline Group (Bbls/d) 22,379 139 - 1
Webb Duval(b) (MMBtu/d) 63,199 (47) 48,045 (18)
Southern Dome (13) (669)
Plant inlet (MMBtu/d) 7,352 11,730
NGLs produced (Bbls/d) 249 432
Bighorn and Fort Union(c) (MMBtu/d) 747,009 (2,574) 533,329 (615)
Six Months Ended June 30,
2012 2011
---- ----
Volume Equity (Earnings)/Loss Volume Equity (Earnings)/Loss
------ ---------------------- ------ ----------------------
Eagle Ford Gathering $(11,908) $38
Pipeline throughput (MMBtu/d) 229,991 -
NGLs produced(a) (Bbls/d) 10,040 -
Liberty Pipeline Group (Bbls/d) 17,690 274 - 1
Webb Duval(b) (MMBtu/d) 62,567 (190) 48,744 184
Southern Dome (401) (1,371)
Plant inlet (MMBtu/d) 8,684 11,457
NGLs produced (Bbls/d) 306 413
Bighorn and Fort Union(c) (MMBtu/d) 767,188 114,711 557,059 (1,834)
____________________________________
(a) Net of NGLs produced at our Houston Central complex
(b) Net of intercompany volumes
(c) Changes in pipeline throughput at Fort Union did not have a material impact on gross margin because Fort Union received payments for additional volumes under long-term contractual commitments in each of the periods indicated
(4) Rocky Mountains segment gross
margin includes results from
producer services, including
volumes purchased for resale,
volumes gathered under firm
capacity gathering agreements
with Fort Union, volumes
transported using Copano's firm
capacity agreements with
Wyoming Interstate Gas Company
and compressor rental services
provided to Bighorn.
(5) Corporate and other includes
results attributable to
Copano's commodity risk
management activities.
(6) Plant inlet volumes and NGLs
produced represent total
volumes processed and produced
by the Texas segment at all
plants, including plants owned
by the Texas segment and plants
owned by third parties.
(7) "Service throughput" means the
volume of natural gas delivered
to Copano's 100%-owned
processing plants by third-
party pipelines plus Copano's
"pipeline throughput," which is
the volume of natural gas
transported or gathered through
Copano's pipelines.
(8) Plant inlet volumes and NGLs
produced represent total
volumes processed and produced
by the Oklahoma segment at all
plants, including plants owned
by the Oklahoma segment and
plants owned by third parties.
COPANO ENERGY, L.L.C. AND SUBSIDIARIES
UNAUDITED NON-GAAP FINANCIAL MEASURES
Three Months Ended June 30, Six Months Ended June 30,
2012 2011 2012 2011
---- ---- ---- ----
Reconciliation of total segment gross margin to operating
income (loss): (In thousands)
Operating income
(loss) $35,530 $20,178 $(97,154) $36,530
Add: Operations and
maintenance
expenses 18,287 15,763 36,929 30,862
Depreciation
and
amortization 19,062 17,363 38,150 34,232
Impairment - - 28,744 -
General and
administrative
expenses 10,298 11,901 25,242 24,499
Taxes other
than income 2,110 1,397 3,476 2,527
Equity in
(earnings)
loss from
unconsolidated
affiliates (12,437) (1,306) 102,291 (3,008)
------- ------ ------- ------
Total segment gross
margin $72,850 $65,296 $137,678 $125,642
Reconciliation of EBITDA, adjusted EBITDA and total
distributable
cash flow to net
income (loss):
Net income (loss) $21,118 $(9,361) $(126,553) $(5,829)
Add: Depreciation
and amortization 19,062 17,363 38,150 34,232
Interest and
other
financing
costs 14,602 11,454 29,026 23,370
Provision for
income taxes 331 (140) 932 771
--- ---- --- ---
EBITDA 55,113 19,316 (58,445) 52,544
Add: Amortization
of commodity
derivative options 5,039 7,357 10,078 14,627
Distributions
from
unconsolidated
affiliates 12,185 7,099 22,514 13,572
Loss on
refinancing
of unsecured
debt - 18,233 - 18,233
Equity-based
compensation 1,121 4,109 4,352 7,091
Equity in
(earnings)
loss from
unconsolidated
affiliates (12,437) (1,306) 102,291 (3,008)
Unrealized
(gain) loss
from
commodity
risk
management
activities (4,980) 180 (4,401) (363)
Impairment - - 28,744 -
Other non-
cash
operating
items 2,252 (572) 3,485 (848)
----- ---- ----- ----
Adjusted EBITDA 58,293 54,416 108,618 101,848
Less: Interest
expense (14,548) (10,988) (28,781) (22,594)
Current income
tax expense
and other (418) (293) (747) (624)
Maintenance
capital
expenditures (3,798) (5,555) (6,241) (7,601)
------ ------ ------ ------
Total distributable
cash flow(1) $39,529 $37,580 $72,849 $71,029
Actual quarterly
distribution $42,336 $38,687
Total distributable
cash flow coverage 93% 97%
(1) Prior to any retained cash reserves established by Copano's Board of Directors
SOURCE Copano Energy, L.L.C.
