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8-K - COPANO ENERGY, L.L.C. FORM 8-K - Copano Energy, L.L.C. | form8-k.htm |
EX-99.1 - COPANO ENERGY, L.L.C. PRESS RELEASE - Copano Energy, L.L.C. | ex99-2.htm |
NAPTP
Annual MLP Investor
Conference
May 12, 2010
Conference
May 12, 2010
NASDAQ: CPNO
Disclaimer
Statements made by
representatives of Copano Energy, L.L.C. (“Copano”) during this presentation
will
include “forward-looking statements,” as defined in the federal securities laws. All statements that
address activities, events or developments that Copano believes will or may occur in the future are
forward-looking statements. Underlying these statements are assumptions made by Copano’s
management based on their experience and perceptions of historical trends, current conditions,
expected future developments and other factors management believes are appropriate under the
circumstances.
include “forward-looking statements,” as defined in the federal securities laws. All statements that
address activities, events or developments that Copano believes will or may occur in the future are
forward-looking statements. Underlying these statements are assumptions made by Copano’s
management based on their experience and perceptions of historical trends, current conditions,
expected future developments and other factors management believes are appropriate under the
circumstances.
Whether future
results and developments will conform to Copano’s expectations is subject to a
number
of risks and uncertainties, many of which are beyond Copano’s control. If one or more of these risks or
uncertainties materializes, or if underlying assumptions prove incorrect, then Copano’s actual results
may differ materially from those implied or expressed by forward-looking statements made during this
presentation. These risks and uncertainties include the volatility of prices and market demand for
natural gas and natural gas liquids; Copano’s ability to complete any pending acquisitions and integrate
any acquired assets or operations; Copano’s ability to continue to obtain new sources of natural gas
supply; the ability of key producers to continue to drill and successfully complete and attach new
natural gas supplies; Copano’s ability to retain key customers; the availability of local, intrastate and
interstate transportation systems and other facilities to transport natural gas and natural gas liquids;
Copano’s ability to access sources of liquidity when needed and to obtain additional financing, if
necessary, on acceptable terms; the effectiveness of Copano’s hedging program; unanticipated
environmental or other liability; 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
the Risk Factors sections of Copano’s annual and quarterly reports filed with the Securities and
Exchange Commission.
of risks and uncertainties, many of which are beyond Copano’s control. If one or more of these risks or
uncertainties materializes, or if underlying assumptions prove incorrect, then Copano’s actual results
may differ materially from those implied or expressed by forward-looking statements made during this
presentation. These risks and uncertainties include the volatility of prices and market demand for
natural gas and natural gas liquids; Copano’s ability to complete any pending acquisitions and integrate
any acquired assets or operations; Copano’s ability to continue to obtain new sources of natural gas
supply; the ability of key producers to continue to drill and successfully complete and attach new
natural gas supplies; Copano’s ability to retain key customers; the availability of local, intrastate and
interstate transportation systems and other facilities to transport natural gas and natural gas liquids;
Copano’s ability to access sources of liquidity when needed and to obtain additional financing, if
necessary, on acceptable terms; the effectiveness of Copano’s hedging program; unanticipated
environmental or other liability; 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
the Risk Factors sections of Copano’s annual and quarterly reports filed with the Securities and
Exchange Commission.
Copano undertakes
no obligation to update any forward-looking statements, whether as a result of
new
information or future events.
information or future events.
2
Introduction
to Copano
Independent
midstream company founded in 1992
■ Best in class
service to customers
■ Entrepreneurial
approach
■ Focus on long-term
accretive growth
Provides midstream
services in multiple producing areas through
three operating segments
three operating segments
■ Texas
● South Texas
conventional and Eagle Ford Shale
● North Texas
Barnett Shale Combo play
■ Central and
Eastern Oklahoma
● Conventional,
Hunton De-Watering play and Woodford Shale
■ Rocky
Mountains
● Powder River
Basin
3
Key
Metrics
Service throughput
volumes approximate 1.8 Bcf/d of natural gas(1)
Over 6,700 miles
of active pipelines
8 natural gas
processing plants with over 1.1 Bcf/d of combined
processing capacity
processing capacity
One NGL
fractionation facility with total capacity of 22,000 Bbls/d
Equity market cap:
$1.6 billion(2)
Enterprise value:
$2.2 billion(2)
4
Based
on 1Q 2010 results. Includes
unconsolidated affiliates.
As
of May 7, 2010.
Copano’s
LLC Structure
5
Growth
Strategy
Goal: to become a
diversified midstream company with scale and
stability of cash flows, above-average returns on invested capital
and “investment-grade quality distributions”
stability of cash flows, above-average returns on invested capital
and “investment-grade quality distributions”
Key tenets of
growth strategy:
■ Execute on organic
growth opportunities around existing assets
■ Explore
opportunities beyond traditional gathering and processing
● Be more proactive
in seeking assets and opportunities
■ Reduce sensitivity
of cash flows to commodity price fluctuations
● Hedging
program
● Contracts -
increase fee-for-service component
6
Agenda
7
2010
Regional
Outlook |
Commodity
Prices and
Margin Sensitivities |
Financing
and
Commodity Risk Management |
Conclusions
|
2010
Outlook
Texas
■ North Texas:
Significant drilling and development activity in the Barnett Shale
Combo play
Combo play
■ South Texas: Ramp
up of Eagle Ford Shale directed drilling
Oklahoma
■ Moderate drilling
activity behind both the Hunton De-Watering and Woodford
Shale plays
Shale plays
Rocky
Mountains
■ Minimal new
drilling; flat volumes
8
Texas
Outlook
North
Texas
■ 9 rigs running in
the area with
as many as 4 more anticipated
later this year
as many as 4 more anticipated
later this year
● Leasing activity
also
continues
continues
■ Crude oil play
with associated
gas requiring a full slate of
midstream services
gas requiring a full slate of
midstream services
■ Based on producer
drilling
schedule, expect steady
increase in plant inlet volumes
in 2010
schedule, expect steady
increase in plant inlet volumes
in 2010
● Current spot
volumes of
approximately 38 MMcf/d vs.
1Q 2010 average volumes of
21 MMcf/d
approximately 38 MMcf/d vs.
1Q 2010 average volumes of
21 MMcf/d
9
Texas
Outlook
South
Texas
■ Fractionation
start-up at Houston Central complete
■ To date we have
connected 6 Eagle Ford Shale wells with a combined IP rate
of 40 MMcf/d with significant associated condensate
of 40 MMcf/d with significant associated condensate
■ Finalizing joint
venture agreements with Kinder Morgan for the western
portion of the Eagle Ford Shale
portion of the Eagle Ford Shale
■ Expect further
Eagle Ford Shale volume increases in 2Q 2010
10
Texas
Recent Developments
North
Texas
■ Recently executed
key producer
contract
contract
● Long-term
gathering, treating and
processing agreement
processing agreement
● Fee-for-service
contract
● Highly rated
producer
■ Additional 50
MMcf/d of compression
expected in service early 4Q 2010,
bringing total plant capacity to 100
MMcf/d
expected in service early 4Q 2010,
bringing total plant capacity to 100
MMcf/d
■ Approximately $30
million in expansion
capex for 2010 (compression and
pipelines)
capex for 2010 (compression and
pipelines)
■ $30 - $35 million
in fee-based cash flow
expected by year-end 2010 on an
annualized basis
expected by year-end 2010 on an
annualized basis
11
DeWitt-Karnes
Pipeline
Recently announced
DeWitt-
Karnes pipeline
Karnes pipeline
■ Targets rich Eagle
Ford Shale gas
■ 38 miles of 24”
pipe - expected to
be in service by August 1, 2010
be in service by August 1, 2010
■ Anticipated 2010
capex -
approximately $45 million
approximately $45 million
Conducting
preliminary
engineering work to relocate
200 MMcf/d Lake Charles
plant to Houston Central
engineering work to relocate
200 MMcf/d Lake Charles
plant to Houston Central
12
Texas
Fractionation Facility
Responding to NGL
transportation and fractionation constraints
along the Texas Gulf Coast, Copano started its fractionator at
Houston Central
along the Texas Gulf Coast, Copano started its fractionator at
Houston Central
Utilizing Houston
Central’s fractionation unit and extensive
tailgate NGL pipelines, Copano began to deliver purity products
to market in April 2010
tailgate NGL pipelines, Copano began to deliver purity products
to market in April 2010
■ Total capacity of
22,000 Bbls/d
■ Approximate cost
of $17 million
■ Estimated
fee-based cash flow between $8 and $10 million on an
annualized basis at current throughput volumes
annualized basis at current throughput volumes
13
Oklahoma
Outlook
Rich
gas
(primarily Hunton De-Watering play)
■ Drilling activity
remains steady
■ 2 rigs currently
running in the Hunton and 7 rigs in other rich gas areas
■ Attractive
processing upgrade and low geologic risk
■ 2Q 2010 volumes
expected to be flat to slightly up vs. 1Q 2010
■ Burbank processing
plant in service 2Q 2010 (10 MMcf/d capacity)
Lean
gas
(primarily Woodford Shale and coalbed methane)
■ Drilling activity
in the Woodford Shale has recently increased
■ 5 rigs currently
running
■ 2Q 2010 volumes
expected to be slightly up from 1Q 2010
14
Oklahoma
Rich Gas vs. Lean Gas
15
Prices
as of 5/7/10
Full
value prior to deduction of Copano’s margin. Excludes
value of condensate and crude oil recovered by the producer at the
wellhead.
Implied
NGL prices are based on a six-year historical regression analysis.
Assumes
9 GPM gas with a Btu factor of 1.375 processed at Copano’s cryogenic plant, and
field fuel of 6.25%.
Assumes
unprocessed gas with a Btu factor of 1.0 and field fuel of
6%.
Rocky
Mountains Outlook
Drilling and
dewatering will be driven by commodity prices and
producer economics
producer economics
2Q 2010 volumes
expected to be slightly lower to flat vs. 1Q 2010
For Bighorn, 130
previously drilled wells can be connected with
minimal capital expenditures
minimal capital expenditures
■ An additional 70
drilled wells can be connected with moderate capital
expenditures
expenditures
2010 Adjusted
EBTIDA expected to be flat vs. 2009
■ Forward pricing
curve indicates drilling and dewatering activity should resume
this year and if this occurs, 2014 Adjusted EBITDA could double from current
levels
this year and if this occurs, 2014 Adjusted EBITDA could double from current
levels
16
Commodity
Prices and Margin Sensitivities
17
2010
Regional
Outlook |
Commodity
Prices and
Margin Sensitivities |
Financing
and
Commodity Risk Management |
Conclusions
|
Historical
Commodity Prices
18
May-09
NGL prices are month-to-date through May 6, 2010.
NGL
prices for Jan-09 through Mar-10 are calculated based on the weighted-average
product mix for the period indicated. NGL
prices for Apr-10 through
May-10 are calculated based on the first quarter 2010 product mix.
May-10 are calculated based on the first quarter 2010 product mix.
Forward
Commodity Prices
19
Note:
Forward prices as of May 6, 2010
Combined
Commodity-Sensitive Segment
Margins and Hedging Settlements
Margins and Hedging Settlements
20
Financing
and Commodity Risk Management
21
2010
Regional
Outlook |
Commodity
Prices and
Margin Sensitivities |
Financing
and
Commodity Risk Management |
Conclusions
|
2010
Expansion Capex
Copano has
approximately $130 million(1) in approved
expansion
capital projects for 2010. Major areas of focus include:
capital projects for 2010. Major areas of focus include:
■ Eagle Ford Shale
and Houston Central processing plant in south Texas
● DeWitt-Karnes
pipeline
■ Saint Jo
processing plant and pipelines in north Texas
■ Additional
pipeline and processing capacity in Oklahoma
■ Expect capital to
be invested at a multiple of approximately 5x
Financing to be
consistent with Copano’s historical policy - balance
of debt and equity
of debt and equity
22
Includes
Copano’s net share for unconsolidated affiliates.
Recent
Equity Offering
In March 2010
Copano sold approximately 7.45 million common
units in a public offering
units in a public offering
■ Approximately $164
million in net proceeds (including greenshoe)
■ Proceeds used to
reduce revolver borrowings, which ultimately will fund
expansion capex
expansion capex
■ Demonstrated
commitment to raising capital and maintaining liquidity
Enhances liquidity
available to fund expansion capex and balance
sheet
sheet
■ At March 31, 2010,
total liquidity of approximately $301 million
23
Hedging
Strategy
Option-based,
product-specific
2010 price exposed
volumes are well hedged
■ Between 70% and
80% of propane, butane, natural gasoline and condensate
price exposure is hedged
price exposure is hedged
■ Approximately 40%
of ethane price exposure is hedged
■ Expect $32 - $34
million of non-cash amortization expense in 2010 related to
option component of hedge portfolio
option component of hedge portfolio
So far in
2010:
■ Added ethane puts
for 2011 (net cost of approximately $0.7 million)
■ Added ethane,
propane, isobutane, normal butane and WTI puts for 2012 (net
cost of approximately $10.1 million)
cost of approximately $10.1 million)
2010 focus -
adding to 2012 hedging positions
24
Conclusions
25
2010
Regional
Outlook |
Commodity
Prices and
Margin Sensitivities |
Financing
and
Commodity Risk Management |
Conclusions
|
Conclusions
Growth projects
recently completed are expected to contribute to
increased total distributable cash flow in 2010
increased total distributable cash flow in 2010
■ Volumes at Saint
Jo plant increasing
■ Start-up of
fractionator at Houston Central plant
■ Burbank plant
in-service
■ Portions of
DeWitt-Karnes header in-service
Significant funnel
of growth opportunities
■ Expansion of Saint
Jo plant to 100 MMcf/d anticipated by early 4Q 2010
■ Completion of
DeWitt Karnes Header expected by mid-3Q 2010
■ Finalizing Kinder
Morgan joint venture in western Eagle Ford Shale
■ Other processing
plant expansions, fractionation expansion and additional
pipelines
pipelines
Ample liquidity
and access to capital to support growth initiatives
26
Appendix
27
Oklahoma
Assets
28
OKLAHOMA
South
Texas Assets
29
TEXAS
North
Texas Assets
30
TEXAS
Rocky
Mountains Assets
31
WYOMING
Processing
Modes
32
Full
Recovery
|
|
|
Texas and
Oklahoma - If the value of
recovered NGLs exceeds the fuel and gas shrinkage costs of recovering NGLs |
Ethane
Rejection
|
|
|
Texas and
Oklahoma - If the value of ethane
is less than the fuel and shrinkage costs to recover ethane (in Oklahoma, ethane rejection at Paden plant is limited by nitrogen rejection facilities) |
Conditioning
Mode
|
|
|
Texas - If
the value of recovered NGLs is less
than the fuel and gas shrinkage cost of recovering NGLs (available at Houston Central plant and at Saint Jo plant in North Texas) |
Commodity-Related
Margin Sensitivities
Matrix reflects 1Q
2010 wellhead and plant inlet volumes, adjusted
using Copano’s 2010 planning model
using Copano’s 2010 planning model
33
Note: Please
see Appendix for definitions of processing modes and additional
details.
Consists
of Texas and Oklahoma Segment gross margins.
Combined
Commodity-Sensitive Segment
Margins and Hedging Settlements
Margins and Hedging Settlements
34
Note:
Weighted
average NGL prices are based on Copano product mix for period
indicated.
Does
not include non-cash expenses included in Corporate and Other for purposes of
calculating Total Segment Gross Margin. See
Appendix for
reconciliation of Total Segment Gross Margin.
reconciliation of Total Segment Gross Margin.
Reflects
the average of April and May (as of May 6, 2010)
prices.
Oklahoma
Contract Mix
35
Source:
Copano Energy internal financial planning models for consolidated
subsidiaries.
Excludes
14,130 MMBtu/d service throughput for Southern Dome, a majority-owned
affiliate.
Oklahoma
Net Commodity Exposure
36
Note: See
explanation of processing modes in this Appendix. Values
reflect rounding.
Source: Copano
Energy internal financial planning models for consolidated
subsidiaries.
Ethane
rejection at Paden plant is limited by nitrogen rejection
facilities.
Reflects
impact of producer delivery point allocations, offset by field condensate
collection and stabilization.
Oklahoma
Commodity Price Sensitivities
Oklahoma segment
gross margins excluding hedge settlements
■ Matrix reflects 1Q
2010 volumes, adjusted using Copano’s 2010 planning
model
model
37
Texas
Contract Mix
38
Source: Copano
Energy internal financial planning models for consolidated
subsidiaries.
Excludes
66,764 MMBtu/d service throughput for Webb Duval, a majority-owned
affiliate.
Texas
Net Commodity Exposure
39
Note: See
explanation of processing modes in this Appendix.
Source: Copano
Energy internal financial planning models for consolidated subsidiaries. Based on
1Q 201 daily wellhead/plant inlet volumes.
Fractionation
at Houston Central processing plant permits significant reductions in ethane
recoveries in ethane rejection mode and full ethane rejection in
conditioning mode. To optimize profitability, plant operations can also be adjusted to partial recovery mode.
conditioning mode. To optimize profitability, plant operations can also be adjusted to partial recovery mode.
At
the Houston Central processing plant, pentanes+ may be sold as
condensate.
Texas
Commodity Price Sensitivities
Texas segment
gross margins excluding hedge settlements
■ Matrix reflects 1Q
2010 volumes and operating conditions, adjusted using
Copano’s 2010 planning model
Copano’s 2010 planning model
40
Rocky
Mountains Sensitivities
1Q 2010 Adjusted
EBITDA volume sensitivity (positive or negative
impact)
impact)
■ Bighorn: 10,000
MMBtu/d = $244,000(1)
■ Fort Union: 10,000
MMBtu/d = $70,000(1)
41
Note: See
this Appendix for reconciliation of Adjusted EBITDA. Values
reflect rounding.
Impact
on Adjusted EBITDA based on Copano’s interest in the unconsolidated
affiliate.
Hedging
Impact of Commodity Price
Sensitivities
Sensitivities
42
Liquidity
and Debt Facilities
At March 31,
2010:
■ Cash:
Approximately $54 million
■ $550 million
revolving credit facility
● Approximately $247
million available (limited by debt covenants)
● Remaining term:
approximately 2.6 years
● LIBOR + 200
bps
■ $582 million
senior notes
● $332,665,000 8 ⅛%
due 2016
● $249,525,000 7 ¾%
due 2018
● Weighted average
rate: 7.96%
● Weighted average
maturity: 6.9 years
43
Key
Debt Terms and Covenants
Senior Secured
Revolving Credit Facility
■ $550 million
facility with $100 million accordion
■ Maintenance
tests:
● 5x total debt to
defined EBITDA(1)
limitation
Ø 3.7x at March
31, 2010
● Minimum required
interest coverage 2.5x defined EBITDA
Ø 3.5x at March
31, 2010
● Defined EBITDA
adds back hedge amortization and other non-cash
expenses
expenses
■ Following an
acquisition, Copano may increase total debt to defined EBITDA
limitation to 5.5x for three quarters
limitation to 5.5x for three quarters
Senior
Notes
■ Incurrence
tests:
● Minimum defined
EBITDA to interest test of 2.00x for debt incurrence
● Minimum defined
EBITDA to interest test of 1.75x for restricted payments
● Defined EBITDA is
similar to that for credit facility
44
See
this Appendix for reconciliation of defined EBITDA, which is referred to in our
credit facility as “Consolidated EBITDA.”
Distribution
Outlook
45
Reconciliation
of Non-GAAP Financial
Measures
Measures
Segment
Gross Margin and Total Segment Gross Margin
We define segment
gross margin, with respect to a Copano operating segment, as segment revenue
less cost of sales. Cost of
sales includes the
following: cost of natural gas and NGLs purchased from third parties, cost of natural gas and NGLs purchased from affiliates, cost of crude oil purchased
from third parties, costs paid to third parties to transport volumes and costs paid to affiliates to transport 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. We view
total segment gross margin as an important performance measure of the core profitability of our 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.
following: cost of natural gas and NGLs purchased from third parties, cost of natural gas and NGLs purchased from affiliates, cost of crude oil purchased
from third parties, costs paid to third parties to transport volumes and costs paid to affiliates to transport 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. We view
total segment gross margin as an important performance measure of the core profitability of our 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.
46
Reconciliation
of Non-GAAP Financial
Measures
Measures
Adjusted
EBITDA
We define EBITDA as
net income (loss) plus interest expense, provision for income taxes and
depreciation and amortization expense. Because a portion
of our net income (loss) is attributable to equity in earnings (loss) from our equity investees (which include Bighorn, Fort Union, Webb Duval and
Southern Dome), our management also calculates Adjusted EBITDA to reflect the depreciation and amortization expense embedded in equity in
earnings (loss) from unconsolidated affiliates. Specifically, our management determines Adjusted EBITDA by adding to EBITDA (i) the amortization
expense attributable to the difference between our 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 our ownership interest in that
unconsolidated affiliate and (iii) the portion of each unconsolidated affiliate’s interest and other financing costs, which is proportional to our ownership
interest in that unconsolidated affiliate.
of our net income (loss) is attributable to equity in earnings (loss) from our equity investees (which include Bighorn, Fort Union, Webb Duval and
Southern Dome), our management also calculates Adjusted EBITDA to reflect the depreciation and amortization expense embedded in equity in
earnings (loss) from unconsolidated affiliates. Specifically, our management determines Adjusted EBITDA by adding to EBITDA (i) the amortization
expense attributable to the difference between our 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 our ownership interest in that
unconsolidated affiliate and (iii) the portion of each unconsolidated affiliate’s interest and other financing costs, which is proportional to our ownership
interest in that unconsolidated affiliate.
External users of
our financial statements such as investors, commercial banks and research
analysts use EBITDA or Adjusted EBITDA, and our
management uses Adjusted EBITDA, as a supplemental financial measure to assess:
management uses Adjusted EBITDA, as a supplemental financial measure to assess:
■ The financial
performance of our assets without regard to financing methods, capital structure
or historical cost basis;
■ The ability of our
assets to generate cash sufficient to pay interest costs and support our
indebtedness;
■ Our 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
structure; and
■ The viability of
acquisitions and capital expenditure projects and the overall rates of return on
alternative investment opportunities.
47
Reconciliation
of Non-GAAP Financial
Measures
Measures
Consolidated
EBITDA
EBITDA is also a
financial measure that, with negotiated pro forma adjustments relating to
acquisitions completed during
the period, is reported to our lenders as Consolidated EBITDA and is used to compute our financial covenants under our
senior secured revolving credit facility.
the period, is reported to our lenders as Consolidated EBITDA and is used to compute our financial covenants under our
senior secured revolving credit facility.
The following
table presents a reconciliation of the non-GAAP financial measure of
Consolidated EBITDA to the GAAP
financial measure of net income (loss):
financial measure of net income (loss):
48
Definitions
of Non-GAAP Financial Measures
Total
Distributable Cash Flow
We define total
distributable cash flow as net income plus: (i) depreciation, amortization and
impairment expense
(including amortization expense relating to the option component of our 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 our 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 our assets and to extend their useful lives, or other capital expenditures that
are incurred in maintaining existing system volumes and related cash flows.
(including amortization expense relating to the option component of our 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 our 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 our 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 us (prior to the establishment of any retained cash reserves by our Board of Directors) to the cash
distributions we expect to pay our unitholders, and it also correlates with the metrics of our 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 our
unitholders because it serves as an indicator of our success in providing a cash return on investment — specifically,
whether or not we are generating cash flow at a level that can sustain or support an increase in our 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 entities’ equity securities is significantly influenced by the
amount of cash they can distribute to unitholders.
generated by us (prior to the establishment of any retained cash reserves by our Board of Directors) to the cash
distributions we expect to pay our unitholders, and it also correlates with the metrics of our 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 our
unitholders because it serves as an indicator of our success in providing a cash return on investment — specifically,
whether or not we are generating cash flow at a level that can sustain or support an increase in our 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 entities’ equity securities is significantly influenced by the
amount of cash they can distribute to unitholders.
49