Filed by Kinder Morgan, Inc.
Pursuant to Rule 425 under the Securities Act of 1933
and deemed filed pursuant to Rule 14a-12
of the Securities Exchange Act of 1934.
Subject Company: El Paso Corporation
Commission File No.: 001-14365
Commission File No. for Registration Statement
on Form S-4: 333-177895
Representatives of Kinder Morgan, Inc (“KMI”) made presentations, including the following presentations, on January 25, 2012 during KMI’s 2012 Investor Conference.
 Stable Platforms, Exceptional Growth
January 25, 2012 |
 IMPORTANT ADDITIONAL INFORMATION WILL BE FILED WITH THE SEC
Kinder
Morgan,
Inc.
(“KMI”)
has
filed
with
the
SEC
a
Registration
Statement
on
Form
S-4
in
connection
with
the
merger
agreement
providing
for
the
proposed
acquisition
of
El
Paso
Corporation
(“EP”),
including
a
preliminary
Information
Statement/Prospectus
of
KMI
and
a
preliminary
Proxy
Statement
of
EP.
The
Registration
Statement
has
not
yet
become
effective.
Following
the
Registration
Statement
having
been
declared
effective
by
the
SEC,
KMI
and
EP
plan
to
file
with
the
SEC
and
mail
to
their
respective
stockholders
a
definitive
Information
Statement/Proxy
Statement/Prospectus
in
connection
with
the
proposed
transaction.
INVESTORS
AND
SECURITY
HOLDERS
ARE
URGED
TO
READ
THE
REGISTRATION
STATEMENT
AND
THE
PRELIMINARY
INFORMATION
STATEMENT/PROXY
STATEMENT/PROSPECTUS
AND
ANY
OTHER
RELEVANT
DOCUMENTS
FILED
OR
TO
BE
FILED
BY
KMI
OR
EP,
INCLUDING
THE
DEFINITIVE
INFORMATION
STATEMENT/PROXY
STATEMENT/PROSPECTUS,
BECAUSE
THEY
CONTAIN
OR
WILL
CONTAIN
IMPORTANT
INFORMATION.
Investors
and
security
holders
are
able
to
obtain
free
copies
of
the
Registration
Statement
and
the
preliminary
Information
Statement/Proxy
Statement/Prospectus
and
other
documents
filed
with
the
SEC
by
KMI
and
EP
through
the
web
site
maintained
by
the
SEC
at
www.sec.gov
or
by
phone,
e-mail
or
written
request
by
contacting
the
investor
relations
department
of
KMI
or
EP
at
the
following:
Kinder Morgan, Inc.
El Paso Corporation
Address:
500 Dallas Street, Suite 1000
1001 Louisiana Street
Houston, Texas 77002
Houston, Texas 77002
Attention: Investor Relations
Attention: Investor Relations
Phone:
(713) 369-9490
(713) 420-5855
E-mail:
kmp_ir@kindermorgan.com
investorrelations@elpaso.com
This
communication
shall
not
constitute
an
offer
to
sell
or
the
solicitation
of
an
offer
to
buy
any
securities,
nor
shall
there
be
any
sale
of
securities
in
any
jurisdiction
in
which
such
offer,
solicitation
or
sale
would
be
unlawful
prior
to
the
registration
or
qualification
under
the
securities
laws
of
any
such
jurisdiction.
No
offering
of
securities
shall
be
made
except
by
means
of
a
prospectus
meeting
the
requirements
of
Section
10
of
the
Securities
Act
of
1933,
as
amended.
PARTICIPANTS IN THE SOLICITATION
KMI and EP, and their respective directors and executive officers, may be deemed to be
participants in the solicitation of proxies in respect of the proposed transactions contemplated by the
merger agreement. Information regarding KMI’s directors and executive officers is
contained in KMI’s Form 10-K for the year ended December 31, 2010, which has been filed with the SEC.
Information regarding EP’s directors and executive officers is contained in
EP’s Form 10-K for the year ended December 31, 2010 and its proxy statement dated March 29, 2011, which are filed with
the SEC. A more complete description will be available in the Registration Statement
and the Information Statement/Proxy Statement/Prospectus. SAFE HARBOR FOR
FORWARD-LOOKING STATEMENTS Statements
in
this
document
regarding
the
proposed
transaction
between
KMI
and
EP,
the
expected
timetable
for
completing
the
proposed
transaction,
future
financial
and
operating
results,
benefits
and
synergies
of
the
proposed
transaction,
future
opportunities
for
the
combined
company,
the
sale
of
EP’s
exploration
and
production
assets,
the
possible
drop-down
of
assets
and
any
other
statements
about
KMI
or
EP
managements’
future
expectations,
beliefs,
goals,
plans
or
prospects
constitute
forward
looking
statements
within
the
meaning
of
the
Private
Securities
Litigation
Reform
Act
of
1995.
Any
statements
that
are
not
statements
of
historical
fact
(including
statements
containing
the
words
“believes,”
“plans,”
“anticipates,”
“expects,”
“estimates”
and
similar
expressions)
should
also
be
considered
to
be
forward
looking
statements.
There
are
a
number
of
important
factors
that
could
cause
actual
results
or
events
to
differ
materially
from
those
indicated
by
such
forward
looking
statements,
including:
the
ability
to
consummate
the
proposed
transaction;
the
ability
to
obtain
the
requisite
regulatory,
shareholder
approvals
and
the
satisfaction
of
other
conditions
to
consummation
of
the
transaction;
the
possibility
that
financing
might
not
be
available
on
the
terms
committed;
the
ability
to
consummate
contemplated
asset
sales;
the
ability
of
KMI
to
successfully
integrate
EP’s
operations
and
employees;
the
ability
to
realize
anticipated
synergies
and
cost
savings;
the
potential
impact
of
announcement
of
the
transaction
or
consummation
of
the
transaction
on
relationships,
including
with
employees,
suppliers,
customers
and
competitors;
the
ability
to
achieve
revenue
growth;
national,
international,
regional
and
local
economic,
competitive
and
regulatory
conditions
and
developments;
technological
developments;
capital
and
credit
markets
conditions;
inflation
rates;
interest
rates;
the
political
and
economic
stability
of
oil
producing
nations;
energy
markets,
including
changes
in
the
price
of
certain
commodities;
weather
conditions;
environmental
conditions;
business
and
regulatory
or
legal
decisions;
the
pace
of
deregulation
of
retail
natural
gas
and
electricity
and
certain
agricultural
products;
the
timing
and
success
of
business
development
efforts;
terrorism;
and
the
other
factors
described
in
KMI’s
and
EP’s
Annual
Reports
on
Form
10
K
for
the
year
ended
December
31,
2010
and
their
most
recent
quarterly
reports
filed
with
the
SEC.
KMI
and
EP
disclaim
any
intention
or
obligation
to
update
any
forward
looking
statements
as
a
result
of
developments
occurring
after
the
date
of
this
document.
2 |
 Use of Non-GAAP Financial Measures
KMP
The non-generally accepted accounting principles ("non-GAAP")
financial measures of distributable cash flow before certain items (both in the
aggregate
and
per
unit),
segment
earnings
before
depreciation,
depletion,
amortization
and
amortization
of
excess
cost
of
equity
investments
("DD&A") and certain items, segment distributable cash flow before
certain items, and earnings before interest, taxes and DD&A ("EBITDA") before
certain items are included in this presentation. Our non-GAAP financial
measures may be different from those used by others, and should not be
considered as alternatives to GAAP measures such as net income or any other GAAP
measure of liquidity or financial performance. Distributable cash flow before
certain items and EBITDA before certain items are significant metrics used by us and by external users of our financial
statements, such as investors, research analysts, commercial banks and others, to
compare basic cash flows generated by us to the cash distributions we expect
to pay our unitholders on an ongoing basis. Management uses these metrics to evaluate our overall performance.
Distributable cash flow before certain items also allows management to simply
calculate the coverage ratio of estimated ongoing cash flows to expected
cash distributions. Distributable cash flow before certain items and EBITDA before certain items are also important non-GAAP financial
measures
for
our
unitholders
because
they
serve
as
indicators
of
our
success
in
providing
a
cash
return
on
investment.
These
financial
measures
indicate
to
investors
whether
or
not
KMP
typically
is
generating
cash
flow
at
a
level
that
can
sustain
or
support
an
increase
in
the
quarterly
distributions
we
are
paying
pursuant
to
the
KMP
partnership
agreement.
The
partnership
agreement
requires
us
to
distribute
all
available
cash.
Distributable
cash
flow
before
certain
items,
EBITDA
before
certain
items
and
similar
measures
used
by
other
publicly
traded
partnerships
are
also
quantitative
measures
used
in
the
investment
community
because
the
value
of
a
unit
of
such
an
entity
is
generally
determined
by
the
unit's
yield
(which
in
turn
is
based
on
the
amount
of
cash
distributions
the
entity
pays
to
a
unitholder).
The
economic
substance
behind
our
use
of
distributable
cash
flow
before
certain
items
and
EBITDA
before
certain
items
is
to
measure
and
estimate
the
ability
of
our
assets
to
generate
cash
flows
sufficient
to make distributions to our investors.
We
define
distributable
cash
flow
before
certain
items
to
be
limited
partners'
pretax
income
before
certain
items
and
DD&A,
less
cash
taxes
paid
and
sustaining capital expenditures for KMP, plus DD&A less sustaining capital
expenditures for Rockies Express, Midcontinent Express, Fayetteville
Express, KinderHawk (through second quarter 2011), Eagle Hawk, Red Cedar and
Cypress, our equity method investees, less equity earnings plus cash
distributions
received
for
Express
and
Endeavor,
additional
equity
investees.
Distributable
cash
flow
before
certain
items
per
unit
is
distributable
cash flow before certain items divided by average outstanding units. Segment
distributable cash flow before certain items is segment earnings before
certain
items
and
DD&A
less
sustaining
capital
expenditures.
In
certain
instances
to
calculate
segment
distributable
cash
flow,
we
also
add
DD&A
less
sustaining
capital
expenditures
for
Rockies
Express,
Midcontinent
Express,
Fayetteville
Express,
KinderHawk
(through
second
quarter
2011),
Eagle
Hawk,
Red
Cedar
and
Cypress,
our
equity
method
investees.
We
define
EBITDA
before
certain
items
as
pretax
income
before
certain
items,
plus interest expense and DD&A, including the DD&A of REX, MEP, FEP,
KinderHawk (through second quarter 2011), Eagle Hawk, Red Cedar and Cypress,
our equity method investees. 3 |
 Use
of
Non-GAAP
Financial
Measures
–
Cont’d
4
"Certain items" are items that are required by GAAP to be reflected in net income, but
typically either (1) do not have a cash impact, for example, goodwill impairments, allocated
compensation for which we will never be responsible, and results from assets prior to our ownership that are
required to be reflected in our results due to accounting rules regarding entities under common
control, or (2) by their nature are separately identifiable from our normal business operations
and in our view are likely to occur only sporadically, for example legal settlements, hurricane
impacts and casualty losses. Management uses this measure and believes it is important to users
of our financial statements because it believes the measure more effectively reflects our
business' ongoing cash generation capacity than a similar measure with the certain items included. For
similar reasons, management uses segment earnings before DD&A and certain items and segment
distributable cash flow before certain items in its analysis of segment performance and
managing our business. We believe segment earnings before DD&A and certain items and segment
distributable cash flow before certain items are significant performance metrics because they enable
us and external users of our financial statements to better understand the ability of our
segments to generate cash on an ongoing basis. We believe they are useful metrics to investors
because they are measures that management believes are important and that our chief operating decision
makers use for purposes of making decisions about allocating resources to our segments and
assessing the segments' respective performance.
We believe the GAAP measure most directly comparable to distributable cash flow before certain items
and to EBITDA before certain items is net income. Segment earnings before DD&A is the
GAAP measure most directly comparable to segment earnings before DD&A and certain items and
segment distributable cash flow before certain items.
Our non-GAAP measures described above should not be considered as an alternative to GAAP net
income, segment earnings before DD&A or any other GAAP measure. Distributable cash flow
before certain items, segment earnings before DD&A and certain items, segment distributable
cash flow before certain items and EBITDA before certain items are not financial measures in
accordance with GAAP and have important limitations as analytical tools. You should not
consider any of these non-GAAP measures in isolation or as a substitute for an analysis of our
results as reported under GAAP. Because distributable cash flow before certain items and EBITDA
before certain items exclude some but not all items that affect net income and because these
measures are defined differently by different companies in our industry, our distributable cash flow
before certain items and EBITDA before certain items may not be comparable to similarly titled
measures of other companies. Segment earnings before DD&A and certain items and
segment distributable cash flow have similar limitations. Management compensates for the limitations of
these non-GAAP measures by reviewing our comparable GAAP measures, understanding the differences
between the measures and taking this information into account in its analysis and its decision
making processes.
The maps contained in this presentation have been carefully compiled and printed by Kinder Morgan from
available information. Kinder Morgan does not guarantee the accuracy of these maps or
information delineated thereon, nor does Kinder Morgan assume responsibility for any reliance
thereon. Recipient agrees not to copy, distribute or digitize this map without express consent
from Kinder Morgan or its affiliates.
For certain financial information in this presentation, a reconciliation of these measures to the most
comparable GAAP measures is included in the Appendix to this presentation.
|
 Use
of
Non-GAAP
Financial
Measures
–
Cont’d
5
KMI
The non-generally accepted accounting principles, or non-GAAP, financial measure
of cash available to pay dividends is presented in this news release. This non-GAAP
financial measure should not be considered as an alternative to a GAAP measure such as net income or any other
GAAP measure of liquidity or financial performance. Cash available to pay dividends is a significant
metric used by us and by external users of our financial statements, such as investors,
research analysts, commercial banks and others, to compare basic cash flows generated by us to the
cash dividends we expect to pay our shareholders on an ongoing basis. Management uses this metric to
evaluate our overall performance. Cash available to pay dividends is also an important
non-GAAP financial measure for our shareholders because it serves as an indicator of our success
in providing a cash return on investment. This financial measure indicates to investors whether or not
we typically are generating cash flow at a level that can sustain or support an increase in the
quarterly dividends we are paying. Our dividend policy provides that, subject to applicable law,
we will pay quarterly cash dividends generally representing the cash we receive from our subsidiaries
less any cash disbursements and reserves established by our board of directors. Cash available
to pay dividends is also a quantitative measure used in the investment community because the
value of a share of an entity like KMI that pays out all or a substantial proportion of its cash flow, is generally determined by the dividend yield
(which in turn is based on the amount of cash dividends the corporation pays to its shareholders). The
economic substance behind our use of cash available to pay dividends is to measure and estimate
the ability of our assets to generate cash flows sufficient to pay dividends to our investors. We believe the
GAAP measure most directly comparable to cash available to pay dividends is income from continuing operations. A reconciliation
of cash available to pay dividends to income from continuing operations is provided in this release.
Our non-GAAP measure described above should not be considered as an alternative to GAAP net
income and has important limitations as an analytical tool. Our computation of cash available
to pay dividends may differ from similarly titled measures used by others. You should not consider this non-GAAP measure in isolation or
as a substitute for an analysis of our results as reported under GAAP. Management compensates for the
limitations of this non-GAAP measure by reviewing our comparable GAAP measures,
understanding the differences between the measures and taking this information into account in its
analysis and its decision making processes. The maps
contained in this presentation have been carefully compiled and printed by Kinder Morgan from available information. Kinder Morgan
does not guarantee the accuracy of these maps or information delineated thereon, nor does Kinder
Morgan assume responsibility for any reliance thereon. Recipient agrees not to copy,
distribute or digitize this map without express consent from Kinder Morgan or its affiliates.
For certain financial information in this presentation, a reconciliation of these measures to the most
comparable GAAP measures is included in the Appendix to this presentation. |
 Kinder Morgan 2012 Investor Conference
Agenda
8:00
–
8:45
Corporate
Overview:
Vision
–
Rich
Kinder
8:45
–
9:00
Corporate
Overview:
Financial
Excellence
–
Park
Shaper
9:00
–
9:15
Corporate
Overview:
Operational
Excellence
–
Steve
Kean
9:15
–
9:30
Break
9:30
–
10:15
Natural
Gas
Pipelines
–
Tom
Martin
10:15
–
10:45
Products
Pipelines
–
Tom
Bannigan
10:45
–
11:30
Terminals –
Jeff Armstrong
11:30
–
11:45
Kinder Morgan Canada –
Ian Anderson
11:45
–
12:30
Lunch
12:30
–
1:00
CO2
–
Tim Bradley
1:00
–
1:30
Financial Review –
Kimberly Dang
1:30
–
2:00
Q & A
6 |
 Vision
Rich Kinder
Chief Executive Officer |
 Then (first analyst
conference-2001)
and Now:
Stable Platforms, Exceptional Growth
Then
(a)
Enterprise
value
of
$14B
(c)
KMP Total distributions of $333MM
KMP
LP
distribution
of
$1.71/unit
(d)
3,569 employees
Now
(b)
(excluding El Paso)
Enterprise
value
of
$63B
(c)
KMP Total distributions of $3.1B
KMP LP distribution of $4.98/unit
8,328 employees
2
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
As of and for the year ended 12/31/2000, representing Kinder Morgan at the time of
the inaugural Kinder Morgan analyst day held 1/24/2001 (b)
Enterprise value / employees as of and for the year ended 12/31/2011, KMP total
distributions / KMP LP distribution per unit represent the budget for 2012
(c)
Kinder Morgan Energy Partners, L.P., Kinder Morgan Management, LLC and Kinder
Morgan, Inc. combined (d)
Split-adjusted |
 Stayed the Course
Focus on stable fee-based assets that are core to North American energy
infrastructure
—
Market leader in each of our business segments
Control costs
—
It’s the investors’
money, not management’s –
treat it that way
Leverage asset footprint to seek attractive capital investment
opportunities, both expansion and acquisition
—
KMP has completed $11.7 billion in acquisitions and $13.3 billion in
greenfield / expansion projects since inception
(a)
Maintaining a strong balance sheet is paramount
—
Enables continued access to capital markets to grow the business
—
KMP accessed capital markets for nearly $26 billion since inception
(a,b)
3
(a)
From
1997
through
2011
(b)
Gross
capital
issued,
$24
billion
net
of
refinancing |
 4
Kinder Morgan
Asset Footprint
Note: excludes El Paso
(a)
2012 budget
(b)
2011 data not available
(c)
Excludes transload facilities (35) and transmix processing facilities (6)
(d)
Includes leased capacity
Largest independent transporter of
petroleum products in the U.S.
—
Transport ~1.9 MMBbl/d
(a)
2
largest
transporter
of
natural
gas
in the U.S.
—
Own an interest in / operate over
25,000 miles of natural gas pipeline
—
Connected to many important
natural gas shale plays including
Eagle Ford, Haynesville, Fayetteville
and Barnett
—
Largest provider of contracted
natural gas treating services in U.S.
Largest
transporter
of
CO2
in
the
U.S.
—
Transport
~1.3
Bcf/d
of
CO2
(a)
2
largest
oil
producer
in
Texas
(b)
—
Produce ~51 MBbl/d of crude oil
gross (~34 MBbl/d net)
(a)
Largest independent terminal
operator in the U.S.
—
Own an interest in or operate ~180
liquids / dry bulk terminals
(c)
—
~111 MMBbls domestic liquids
capacity
(d)
—
Handle ~108 MMtons of dry bulk
products
(a)
•
Including 44 MMtons of coal
(a)
Only Oilsands pipeline serving the
West Coast
—
TMPL transports ~300 MBbl/d to
Vancouver / Washington State
NGPL GAS STORAGE (KMI)
NATURAL GAS PROCESSING
NGPL (KMI)
NATURAL GAS STORAGE
NATURAL GAS PIPELINES
PRODUCTS PIPELINES
TERMINALS
TRANSMIX FACILITIES
PRODUCTS PIPELINES
GAS TREATERS
CO
PIPELINES
CO
OIL FIELDS
CRUDE OIL PIPELINES
TERMINALS
KM HEADQUARTERS
PETROLEUM PIPELINES
INDICATES NUMBER OF
FACILITIES IN AREA
PETROLEUM PIPELINES
TERMINALS
2
2
nd
nd |
 Kinder Morgan: Three Ways to Invest
5
85MM
(86%)
14MM
(14%)
Distributions
in additional
i-units / shares
KMR
(LLC)
99 million shares
(a)
LP & GP
Distributions
$1.6B
(c)
KMI
Public
Float
KMI
Cash
distributions
KMP
(Partnership)
238 million units
(a)
216MM
(91%)
KMI
(Inc.)
707 million shares
(d)
Public
Float
Management /
Original S/H
Sponsors
22MM
(9%)
114MM
(16%)
320MM
(45%)
273MM
(39%)
Kinder Morgan Energy Partners, L.P.
Market Equity
Debt
Enterprise Value
2012E LP Distribution per Unit
2012E Total Distributions
Kinder Morgan, Inc.
Market Equity
$22.8B
(d)
Debt
3.2B
(e)
Enterprise Value
$26.0B
2012E Dividend per Share
$1.35
(c)
2012E Total Dividends
$956MM
(c)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
As of 12/30/2011; KMP market equity based on ~238 million common units (includes 5.3
million Class B units owned by Kinder Morgan, Inc.; Class B units are unlisted KMP common
units) at a price of $84.95, and ~99 million KMR shares at a price of $78.52
(b)
Debt balance as of 12/31/2011, excludes the fair value of interest rate swaps, net of
cash
(c)
2012 budget
(d) As of 12/30/2011; KMI market equity
based on 707 million shares (assumes full conversion of Class A, B and C shares in to Class P shares) at a price of $32.17
(e)
Debt of KMI and its subsidiaries, excluding KMP and its subsidiaries as of 12/31/2011;
excludes the fair value of interest rate swaps, purchase accounting and Kinder Morgan G.P.,
Inc.’s $100 million of Series A Fixed-to-floating Rate Term Cumulative Preferred Stock due 2057, net of cash
$28.0B
(a)
12.4B
(b)
$40.4B
$4.98
(c)
$3.1B
(c) |
 Delivering Consistent Growth
Total Distributions (GP + LP) ($MM)
KMP Annual LP Distribution per Unit
(b)
Net Debt to EBITDA
(c,d)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
In 2010, total distributions paid were $2,250 million. These distributions
would have been $2,420 million ($170 million greater) if all distributions paid in August 2010 had been cash from operations, rather than a portion
being a distribution of cash from interim capital transactions; the GP receives only
2% of distributions of cash from interim capital transactions (b)
Annual LP declared distributions, rounded to 2 decimals where applicable
(c)
Debt is net of cash and excluding fair value of interest rate swaps
(d)
For
KMI,
net
debt
also
excludes
purchase
accounting
and
Kinder
Morgan
G.P.,
Inc.’s
preferred
stock;
distributions
received
from
equity
investees
net
of
G&A
and
sustaining
capital
expenditures
EBITDA
6 |
 Significant Historical Returns
(a)
7
KMI: 11.4% Initial Annualized Return
(e)
KMP: 26% CAGR Since ‘96
(b)
KMR: 16% CAGR Since ‘01
(c)
(d)
Alerian MLP index
(e)
Annualized total return based on partial year return following IPO on 2/10/2011;
partial-year return for period is 10.0%
(f)
Calculated through 12/30/2011; start dates for 2-year, 3-year, 5-year
and 10-year return calculations are 12/31/2009, 12/29/2008, 12/31/2006
and 12/31/2001, respectively $0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
Dec-96
Dec-99
Dec-02
Dec-05
Dec-08
Dec-11
Dollars
AMZ
(d)
= $1,003
KMP = $3,362
S&P 500 = $222
Total Return
2011
2-yr
3-yr
(f)
5-
yr
10-
yr
KMP
29%
58%
129%
150%
342%
KMR
26%
66%
148%
150%
327%
KMI
11%
n/a
n/a
n/a
n/a
S&P 500 Index
Alerian MLP Index
MSCI REIT Index
Philadelphia UTY Index
(f)
(f)
(f)
(e)
2%
17%
49%
1%
33%
14%
55%
173%
95%
324%
9%
40%
79%
7%
224%
19%
26%
39%
20%
119%
-
-
$0
$75
$150
$225
$300
$375
$450
$525
Dec-
01
Dec-
03
Dec-
05
Dec-
07
Dec-09
Dec-
11
KMR = $474
AMZ
= $464
Dollars
IPO 5/14/2001
S&P 500 = $124
(d)
$0
$20
$40
$60
$80
$100
$120
$140
Dec
10
Feb-
11
Apr-
11
Jun-
11
Aug
11
Oct-
11
Dec -
Dollars
IPO 2/10/2011
UTY = $117
KMI = $110
MSCI = $104
S&P 500 = $97
-
-
11
Source: Bloomberg
(a)
Total returns calculated on daily basis through 12/30/2011, except where noted; assumes
dividends / distributions reinvested in index / stock / unit
(b)
Start date 12/31/1996
(c)
Start date 5/14/2001: KMR initial public offering; KMP CAGR over same period is 16%
|
 Promises Made, Promises Kept
8
Promises Made
Promises Kept
KMP achieved
LP distribution
target in 11
out of 12 years
(a)
On a paid basis; KMI paid a prorated dividend for 1Q 2011 of $0.14 per share on
5/16/2011; based on a full quarter, the dividend amounts to $0.29 per share
KMP Budgeted
LP Distribution:
KMI Budgeted
Dividend:
2000: $1.60
2001: $1.95
2002: $2.40
2003: $2.63
2004: $2.84
2005: $3.13
2006: $3.28
2007: $3.44
2008: $4.02
2009: $4.20
2010: $4.40
2011: $4.60
2011: $1.16
(a)
2000: $1.71
2001: $2.15
2002: $2.435
2003: $2.63
2004: $2.87
2005: $3.13
2006: $3.26
2007: $3.48
2008: $4.02
2009: $4.20
2010: $4.40
2011: $4.61
2011: $1.18
(a)
KMP Actual
LP Distribution:
KMI Actual
Dividend: |
 Kinder Morgan 2012 Goals (Excludes El Paso)
KMP
(a)
Distribution Target
—
$4.98 per unit (8.0% growth)
—
Excess coverage of $71MM
Maintain Solid Balance Sheet
—
Yr-end 2012 debt / EBITDA = 3.4x
—
Expansions / acquisitions
financed 50% equity, 50% debt
KMI
(a,b)
Dividend Target (declared)
—
$1.35 per share (12.5% growth)
—
$985MM in cash available for
dividends
Maintain Solid Balance Sheet
—
Yr-end 2012 debt / distributions
received less G&A = 2.1x
9
Operate all of our assets in a safe, compliant and environmentally sound manner
(a)
Excludes any impact from the proposed acquisition of El Paso by KMI
(b)
KMI
previously
announced
that
if
the
El
Paso
transaction
were
to
close
on
January
1,
2012,
KMI
would
expect
to
pay
dividends
per
share
of
around
$1.45
for
2012;
since the transaction will not be in effect for the full year 2012, KMI’s actual dividend in 2012
will likely be less than $1.45 |
 KMP |
 Well-Diversified Cash Flow
$1,303MM segment EBDA
(d)
—
41% Interstate
—
59% Intrastate
(e)
$735MM segment EBDA
(d)
—
52% Pipelines
—
44% Associated Terminals
—
4% Transmix
$1,381MM segment EBDA
—
26% CO
2
transport and sales
—
74% oil production related
—
Production hedged
(b)
:
2012=77% ($91)
(c)
2013=51% ($92)
2014=31% ($93)
2015=13% ($98)
$757MM segment EBDA
—
54% Liquids
—
46% Bulk
CO
2
Terminals
Products Pipelines
Natural Gas Pipelines
2012E KMP Segment
Earnings before DD&A
= $4.4 billion
(a,d)
$201MM segment EBDA
11
(KMP)
Kinder Morgan Canada
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Budgeted 2012 segment earnings before DD&A excluding certain items
(b)
Percent of estimated net crude oil and heavy natural gas liquids production; see slide
34 for further detail
(c)
2012 budget assumes an $93.75/Bbl price on unhedged barrels
(d)
Includes $171 million of depreciation for Natural Gas Pipelines JVs REX, MEP, FEP, Eagle
Ford (Copano), EagleHawk and Red Cedar, and Products Pipelines JV Cypress
(e)
Includes upstream assets |
 Stable Asset Base
Natural Gas
Pipelines
Products
Pipelines
CO
2
Terminals
Kinder Morgan
Canada
Volume Security
–
Interstate: virtually all
take or pay
–
Intrastate: ~75%
take or pay
(a)
–
Volume based
–
S&T: primarily
minimum volume
guarantee
–
Take or pay,
minimum volume
guarantees, or
requirements
–
Essentially no
volume risk
Avg. Remaining
Contract Life
–
Transportation: 8.0 yrs
–
Not applicable
–
S&T: 4.0 yrs
–
Liquids: 4.0 yrs
–
Bulk: 3.8 yrs
–
2.0 yrs
(b)
Pricing Security
–
Interstate: primarily
fixed based on contract
–
Intrastate: primarily
fixed margin
–
PPI + 2.65%
–
S&T: 70% of
revenue protected
by floors
–
O&G: volumes
77% hedged
(c)
–
Based on contract;
typically fixed or
tied to PPI
–
Fixed based on
toll settlement
Regulatory
Security
–
Interstate: regulatory
return mitigates
downside; may receive
higher recourse rates for
increased costs
–
Intrastate: essentially
market-based
–
Pipeline: regulatory
return mitigates
downside
–
Terminals &
transmix: not
price regulated
(d)
–
Primarily
unregulated
–
Not price regulated
(d)
–
Regulatory
return mitigates
downside
Commodity
Price Exposure
–
Interstate: no direct
–
Intrastate: limited
–
No direct
–
Full-yr impact is
$5.8MM in DCF
per $1/Bbl change
in oil price
–
No direct
–
No direct
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Transportation
for
intrastate
pipelines
includes
term
purchase
and
sale
portfolio
(b)
Assumes 1-year rate 2012 settlement on Trans Mountain
(c)
Percent of 2012 expected production, includes heavier NGL components (C4+)
(d)
Terminals not FERC regulated, except portion of CALNEV
12
(KMP) |
 2-3%
Annual
Distribution
Growth
without
Investment
Current
Environment
Products Pipelines
PPI escalator
+
Renewables handling
+
Volumes
~
Terminals
Annual escalator
+
Volumes & ancillary charges
+
Renewing contracts
+
Current
Environment
CO
2
Higher price on oil hedges
+
Higher overall oil / NGL prices
+
Recontracting CO
2
supply
+
Oil / NGL volumes
~
Natural Gas
Volume growth (shale & power)
+
Gathering, processing & treating
+
Intrastate margins
~
Storage margins
–
Transport renewals
–
Storage renewals
+
13
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(KMP) |
 2012 Growth Expenditures
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Includes equity contributions to joint ventures of $233 million
(b)
Includes
growth
capital
expenditures
for
Kinder
Morgan
Canada
of
$10
million
(c)
Includes acquisitions of $108 million
Natural Gas
Pipelines
(a)
Products
Pipelines
(a,b)
Terminals
(a,b,c)
CO
2
Oil
Production
2012E Total KMP
Growth Expenditures
= $1.7 billion
(a,b,c)
14
(KMP)
CO
2
S&T
15%
19%
40%
9%
17% |
 Natural Gas Pipelines Growth Drivers
2012
Growth
Drivers:
Growth and full year contribution on Kinder
Hawk
Full year contribution from Eagle Hawk and
SouthTex
Eagle Ford shale development (on
standalone basis, and under JVs with
Copano and BHP)
Full year of higher throughput on
Fayetteville Express (FEP) pipeline (volume
ramp through 2011)
West Clear Lake storage contract rollover
Longer-term
Growth
Drivers:
Natural gas is the logical fuel of choice
—
Cheap, abundant, domestic and clean
Demand growth and shifting supply from
multiple basins lead to:
—
Pipeline / storage expansions and
extensions (e.g. Eagle Ford)
—
Greenfield development
—
Optionality of deploying portions of
existing footprint in different product
uses
Expand service offerings to customers
(e.g. treating and G&P)
LNG exports
Acquisitions
Well-positioned in the Rockies, shales and in Texas
15
(KMP)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
TransColorado
2
2
KMTP
KMTejas
KMIGT
Trailblazer
2
KMLP
REX
REX
FEP
MEP
KinderHawk
Eagle Ford
NATURAL GAS PIPELINES
NATURAL GAS STORAGE
NATURAL GAS PROCESSING
KM HEADQUARTERS
(2)
# OF FACILITIES IN AREA
GAS TREATERS (KMP) |
 Products Pipelines Growth Drivers
2012
Growth
Drivers:
PPI tariff escalator
Modest organic volume growth
Initial year of Crude and Condensate
operations, Cochin E/P project, and
terminal projects including new tank
expansions for refined products and
biodiesel blending services
Longer-term
Growth
Drivers:
Development of shale play liquids
infrastructure
—
Condensate transportation,
processing and storage services from
Eagle Ford
•
Condensate processing facility
located in Houston Ship Channel, in-
service Jan-2014
—
Crude / condensate service on Cochin
Parkway Pipeline in-service 2013
Increased fuel export opportunities
RFS
(a)
increases demand for storage and
ancillary services
—
Ethanol and biodiesel growth
including terminals and pipeline
expansions
Tariff index adjustments / organic volume
growth
Tuck-in acquisitions
Well-located with origin in refinery / port hubs and terminus in population
centers (a)
RFS (U.S. Renewable Fuels Standard) requires an increase in use of renewable fuels,
from 15 Bgal/yr in 2012 to 36 Bgal/yr in 2022 16
Pacific
WCT
Northern
2
Pacific
CALNEV
Cypress
Central
Florida
2
Cochin
2
KMCC
Parkway
Pipeline
Proposed
Condensate
Processing
Plantation
2
4
3
2
2
PRODUCTS PIPELINES
PRODUCTS PIPELINES
TERMINALS
TRANSMIX FACILITIES
(2)
INDICATES NUMBER OF
FACILITIES IN AREA
PIPELINES UNDER CONSTRUCTION
CONDENSATE PROCESSING FACILITY
(KMP) |
 Terminals Growth Drivers
2012 Growth Drivers:
Increase in rates on existing contracts
Higher coal throughput
Full year of 2011 acquisitions (Cushing,
Total, Watco) and expansion projects
(Carteret, Cushing, Deer Park, Port of
Houston)
Partial benefit from over $650 million in
2012 expected growth expenditures
Longer-term Growth Drivers:
Newbuild and expansion of export coal
and petcoke terminals (IMT, Houston,
Whiting)
Expansions and higher rates at well-
located, high-connectivity terminals
Petroleum exports
Canadian crude oil merchant tankage
Increase in use of renewable fuels
(a)
leads to ethanol / biofuel expansion
Acquisition of terminals from “mom
and pop”
owners and from majors
Well-located in refinery / port hubs and inland waterways
17
(a)
RFS (U.S. Renewable Fuels Standard) requires an increase in use of renewable fuels,
from 15 Bgal/yr in 2012 to 36 Bgal/yr in 2022 TERMINALS
KM HEADQUARTERS
# OF FACILITIES IN AREA
(KMP) |
 CO
2
Growth Drivers
2012 Growth Drivers:
Higher overall oil / NGL prices
CO2
S&T price increases
Relatively flat oil production
Longer-term Growth Drivers:
Strong demand for CO2
—
Expansion of CO2
source fields
and pipelines
•
Expect to execute several
large, long-term CO2
S&T
contracts
—
Higher rates and better terms
on new/renewed CO2
S&T
contracts
Billions of barrels of domestic oil
still in place to be recovered at
SACROC, Yates and Katz
18
(KMP)
CO2
PIPELINES
CO2
OIL FIELDS
CRUDE OIL PIPELINES
KM HEADQUARTERS
CO2
SOURCE FIELDS
Own and operate best source of CO
2
for EOR |
 Kinder Morgan Canada Growth Drivers
2012:
Extending new toll settlement on Trans
Mountain pipeline (TMPL); results in
relatively flat financial performance
between 2011 and 2012
Longer-term
Growth
Drivers:
Expand Oilsands export capacity to
West Coast and Asia
—
TMPL is lowest-cost option with
ability to do staged expansions,
or one large expansion
—
Open season underway for firm
commitments to major expansion
Expanded dock capabilities
(Vancouver)
Sole oil pipeline from Oilsands to West Coast / export markets
19
(KMP)
KM HEADQUARTERS
PETROLEUM PIPELINES
PETROLEUM PIPELINES TERMINALS
# OF FACILITIES IN AREA |
 KMI |
 Overview –
99% of Cash Comes from KMP
Limited capital expenditures at KMI
Stock ownership:
—
Public –
16%
—
Rich Kinder, other management
and
original
stockholders
–
39%
—
Sponsors –
45%
In 2012:
—
KMI expects to receive $1.6
billion in distributions
—
$985 million budgeted cash
available for dividends after
paying cash taxes, cash interest
and G&A
General Partner interest receives incentive
distributions from KMP
KMI owns ~11% of total limited partner
interests
21
Interests in KMP
(c)
2012E KMI Total
Cash Receipts
= $1.6 billion
(a)
(KMI)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
2012 budget
(b)
20% equity interest; KMI is operator of Natural Gas Pipeline Company of
America (c)
As of 12/31/2011; includes: (i) general partner interest, (ii) 21.7 million KMP
units and (iii) 14.1 million KMR shares GP
Interest
88%
LP
Interest
11%
NGPL
1%
(b) |
 Growth in KMP Distributions Leads to KMI Growth
Growth in KMP Distributions Received by KMI
22
(KMI)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
2012 budget
$1,600
$1,400
$1,200
$1,000
$800
$600
$400
$200
$0
$1,380
$1,585
$1,217
$1,340
$163
$181
$64
$4.61
$4.98
2011 actual
2012 budget
Budgeted 8%
growth in
KMP Distribution
per LP Unit
LP interests
GP interest
GP Distribution on Additional
16MM KMP Units
An 8% increase in the annualized LP distribution per unit from
$4.61 to $4.98 with a 16MM unit increase in KMP units outstanding results
in
an
increase
of
15%,
or
$205MM,
in
total
distributions
to
KMI
(a) |
 El Paso Update |
 Strong Asset Base
(a)
Horizon
NGPL
Pacific
Northern
TransColorado
2
Pacific
CALNEV
KMCO
2
2
KMTP
KMTejas
Wink
SACROC
Yates
9
5
2
3
2
Plantation
Cypress
4
Central
Florida
7
3
2
2
4
3
2
2
4
3
KMIGT
Trailblazer
2
Cochin
Express
Platte
Trans
Mountain
Claytonville
2
4
KMLP
REX
REX
MEP
2
FEP
2
2
2
3
2
2
KinderHawk
2
2
3
Katz
Eagle Ford
ESPL
2
Puget Sound
NGPL (KMI)
NGPL GAS STORAGE (KMI)
PRODUCTS PIPELINES (KMP)
PRODUCTS PIPELINES
TERMINALS (KMP)
TRANSMIX FACILITIES (KMP)
NATURAL GAS PIPELINES (KMP)
NATURAL GAS
STORAGE (KMP)
NATURAL GAS
PROCESSING (KMP)
CO2
PIPELINES (KMP)
CO2
OIL FIELDS (KMP)
CRUDE OIL PIPELINES (KMP)
TERMINALS (KMP)
KM HEADQUARTERS
PETROLEUM PIPELINES (KMP)
PETROLEUM PIPELINES
TERMINALS (KMP)
(2,3,8
) INDICATES NUMBER OF
FACILITIES IN AREA
GAS TREATERS (KMP)
EL PASO PIPELINES
24
(a)
Shows all current Kinder Morgan assets and
El Paso pipeline assets |
 El Paso Transaction Timeline
El Paso E&P sale process under way
—
Targeting closing all or a material portion of E&P asset portfolio
around time of closing of El Paso acquisition
Integration plan being developed –
targeting $350 million of
synergies
Expect Q1 2012 shareholder meetings
HSR review underway
—
Pre-merger notifications filed
—
2
request
received
—
Providing additional information to FTC
Expect Q2 2012 closing
25
nd |
 Dividend and Distribution Growth Targets
KMI
Current targets excluding El Paso
Declare budgeted 2012 dividends of $1.35
per share (12.5% growth)
Targeted 10% long-term dividend growth
rate
Targets including El Paso
Estimate $1.45 per share dividend paid
had El Paso transaction closed at the
beginning of 2012
—
Since the transaction will not be in
effect for the full year 2012, KMI’s
actual dividend in 2012 will likely be
less than $1.45 per share
—
Also have converted to declared basis
from paid basis (for comparison
$1.35/sh declared = $1.30/sh paid)
Targeted 12.5% long-term dividend growth
rate through 2015
KMP
Current targets excluding El Paso
Declare budgeted 2012 LP distributions of
$4.98 per unit (8.0% growth)
Targeted 5% long-term distribution growth
rate
Targets including El Paso
Targeted 7% long-term distribution growth
rate, driven by expected dropdowns
resulting from the EP transaction
26 |
 Unparalleled asset footprint
Established track record
Industry leader in all business segments
Experienced management team
Supportive general partner
Transparency to investors
Attractive returns driven by combination of yield plus growth
27
KMI, KMP & KMR:
Attractive Value Proposition |
 Financial Excellence
Park Shaper
President |
 ($ in
billions) Note: excludes any impact from the proposed acquisition of El Paso
by KMI (a)
Includes equity contributions to joint ventures
(b)
1998 –
2011, does not include 2012 budget
Total
Invested
by
Type
(a,b)
Total Invested by Segment
(a,b)
29
Total Invested by Year
(a)
~$25B of Growth Capital Invested at KMP
(a,b) |
 How We Have Done: KMP Returns on Capital
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
Segment ROI
(a)
:
Products Pipelines
11.9%
11.8%
12.8%
12.9%
12.4%
11.6%
11.8%
13.2%
12.5%
13.4%
13.7%
12.9%
Natural Gas Pipelines
13.3
15.5
12.9
13.5
14.0
15.5
16.7
17.5
16.9
14.0
11.9
11.9
CO2
27.5
24.6
22.0
21.9
23.8
25.7
23.1
21.8
25.9
23.5
25.7
26.2
Terminals
19.1
18.2
17.7
18.4
17.8
16.9
17.1
15.8
15.5
15.1
14.6
14.3
Kinder Morgan Canada
--
--
--
--
--
--
--
11.0
12.1
12.8
13.7
14.1
KMP ROI
12.3%
12.7%
12.6%
13.1%
13.6%
14.3%
14.4%
14.1%
14.9%
13.9%
13.5%
13.5%
KMP Return on Equity
17.2%
19.4%
20.9%
21.7%
23.4%
23.9%
22.6%
22.9%
25.2%
25.2%
24.3%
24.0%
Note: a definition of these measures may be found in the Appendix to this
presentation (a)
G&A is deducted to calculate the KMP ROI, but is not allocated to the segments
and therefore not deducted to calculate the individual Segment ROI 30
|
 KMP Cost of Capital
Operated
Cost of capital varies over time:
—
Current ~7.2%
(a)
—
2011 analyst conf 7.8%
—
2010 analyst conf 8.8%
—
2009 analyst conf 9.8%
—
2008 analyst conf 9.0%
—
2004 analyst conf 8.3%
—
2003 analyst conf 9.1%
—
2002 analyst conf 8.2%
Long-term cost of capital ~9%
—
Well in excess of long-term cost of capital
Delivered attractive returns to LP investors
Supportive GP
—
GP has demonstrated willingness to forego distributions for transitional time
period for appropriate acquisitions or expansions (e.g., KinderHawk)
—
If we get to a point where we cannot deliver attractive returns to LP investors,
we would consider other options
31
(a)
Targeted unlevered returns typically 12-15% for pipelines
(higher for CO
2
)
in
“50/50
splits”
since
1997
As of 12/30/2011; calculation of current cost of capital can be found in the Appendix to this
presentation |
 KMP Access to Capital
Issued
~$25.8
billion
of
capital
at
KMP
in
the
public
markets
since
inception
(a)
—
~$11.9
billion
in
equity
raised
(a)
—
~$13.9 billion in KMP long-term debt (~$12.1B net of refinancing)
Accessed in difficult markets
—
Sep’01
to
Sep’02
~$1.9
billion
in
equity
and
debt
issued
(a)
—
Aug’07
to
Dec’09
~$7.6
billion
in
equity
and
debt
issued
(a)
Limited equity issuance needed in 2012
—
KMR dividend = ~$491 million in 2012
—
KMP $385 million public secondary offering(s) / ATM program
32
Note: all figures as of 12/31/2011; excludes any impact from the proposed acquisition of El Paso by
KMI
(a)
Includes KMR share dividends |
 KMR 101
(a)
Discount Has Narrowed, But Still Wide
KMR Discount to KMP
Management Purchases of KMR / KMP
(c)
(a)
All
figures
through
/
as
of
12/30/2011;
see
footnotes
on
slide
7
for
explanation
of
total
return
calculations
(b)
Calculation of share dividend: KMP quarterly cash distribution per unit divided by
KMR 10-day average price prior to x-date = fractional share paid for every KMR share owned, e.g. $1.16
/ $65.986 = 0.017579 share; example reflects actual KMR share dividend calculated
for 3Q 2011 paid on 11/14/2011; refer to KMP 3Q 2011 10-Q for more information
(c)
Purchase of KMR shares and KMP units by directors and officers of KMR/KMP since the
KMR IPO in 2001, as reported in SEC Form 4 filings; 7:1
ratio
excludes
one
open
market
purchase
of
KMP
units
relating
to
an
arrangement
requiring
cash
distributions
for
payment
of
interest
33
KMR
is
KMP
KMR shares are pari passu with KMP units
KMR dividend equal to KMP cash distribution, but paid in
additional shares; effectively a dividend reinvestment
program
(b)
Like
KMP
units,
KMR
shares
are
tax
efficient
—
but
with
simplified tax reporting (no K-1s, UBTI)
KMR is a significant entity
KMR market cap = $7.7 billion, ~30% of total KMP
capitalization
~$20 million in daily liquidity
KMR has generated a 15.8% compound annual total return
since ‘01 IPO, vs. 16.1% for KMP
Although the KMR trading discount to KMP has narrowed,
at 7.6% it still leaves substantial room for improvement
EP transaction expected to lead to more KMR issuance
Highlighting the security and further improving liquidity
Potential for KMP to become self-funding through KMR
dividend
Possibility of KMR share buybacks if quarterly dividends
exceed equity funding needs
Insiders prefer KMR
Management has purchased KMR at a rate of about 2:1 vs.
KMP,
or
almost
7:1
excluding
one
transaction
(c)
-20%
-15%
-10%
-5%
0%
5%
10%
Dec-01
Dec-03
Dec-05
Dec-07
Dec-09
Dec-11
$0
$2
$4
$6
$8
$10
KMR
KMP
$8.1
$4.5
(millions)
IPO 5/14/2001 |
 KMP CO
2
Oil Production Hedge Profile
Avoid businesses with direct
commodity exposure
Hedge CO
2
BOE equivalent
—
Targeted minimum
hedge amounts:
Current Year: 70%
Year 2:
50%
Year 3: 30%
Year 4: 10%
Net Oil Production
34
77%
51%
31%
13%
0
10
20
30
40
2012
2013
2014
2015
Avg Hedge Px
WTI & WTS
($/Bbl)
(a)
$90.64
$92.23
$93.40
$98.11
Hedged
Unhedged
% Hedged
(a)
Where collars are used, pricing incorporated into average hedge price is the collar floor; for swaps
and puts, strike price net of premium is used
(b)
Net equity production: 2012 = budget; 2013-2016 = based on Netherland, Sewell reserve report plus
Katz project estimated barrels; includes heavier NGL components (C4+) |
 KMP Risks
Regulatory
—
Pacific Products Pipeline FERC / CPUC cases
—
Periodic rate reviews
—
Unexpected policy changes
Crude Oil Production Volumes
Crude Oil Prices
—
2012 budget assumes $93.75/Bbl realized price on unhedged barrels
—
2012
sensitivity
is
~$5.8
million
DCF
per
$1/Bbl
change
in
crude
oil
prices
Economically Sensitive Businesses (e.g., steel terminals)
Environmental
Terrorism
Interest Rates
—
~50% floating rate debt
—
The full-year impact of a 100-bp increase in rates equates to an
approximate $65 million increase in interest expense
35
Note: excludes any impact from the proposed acquisition of El Paso by KMI
|
 KMP Focused on Distribution Growth
History of Delivering
Distribution Growth
(a)
:
—
1-year growth = 4.8%
—
3-year growth = 4.7%
—
5-year growth = 7.2%
Annual LP Distribution Per Unit
(b)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Compound annual growth in KMP LP distributions per unit for the 1-year,
3-year and 5-year periods ending 12/31/2011 (b)
Annual LP distribution, rounded to 2 decimals where applicable
36
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012E
$0.63
$0.94
$1.24
$1.42
$1.71
$2.15
$2.44
$2.63
$2.87
$3.13
$3.26
$3.48
$4.02
$4.20
$4.40
$4.61
$4.98 |
 KMP Drives KMI Growth
Substantial cash flow
Minimal capital expenditures
at KMI level
Strong balance sheet
Growing distributions and
investment at KMP drive KMI
dividend growth
KMP Cash Distributions Received by KMI
37
GP Interest
LP Units Owned
$65
$77
$85
$96
$100
$96
$104
$127
$140
$152
$163
$181
$58
$113
$208
$278
$336
$406
$492
$529
$635
$830
$967
$1,087
$1,218
$1,404
$3
$6
$40
$68
$153
$273
$355
$421
$502
$592
$625
$739
$957
$1,107
$1,239
$1,381
$1,585
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012E
(a)
$40
__________________________
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
In 2010, total distributions paid to KMI (GP + LP) were $1,032 million. These
distributions to KMI would have been $1,202 million ($170 million greater) if all
distributions
paid
in
August
2010
had
been
cash
from
operations,
rather
than
a
portion
being
a
distribution
of
cash
from
interim
capital
transactions;
the
GP
receives
only 2% of distributions of cash from interim capital transactions
|
 Operational Excellence
Steve Kean
Chief Operating Officer |
 Operations Goals –
Safe, Reliable, Efficient Operations
Continuous reduction in risk to the public, employees,
contractors, assets and the environment
Continuous improvement in the efficiency and productivity of
existing
operations
Establish culture of excellence in operations
39
Well-executed
expansions
and
effective
integration
of
acquired
operations |
 Efficiency
Part of weekly asset review
—
Throughput
—
Operating costs (including energy use and L&U)
—
Sustaining capex updates
Detailed, “bottoms up”
budget process for operating expenses and
sustaining capex
—
Separately identify safety and compliance needs; separately track
spending on those items
Shared best practices on common activities
—
Working groups
—
Quarterly KM operations meeting
40 |
 KM Operating Efficiency
G&A per MMDth Natural Gas Received
O&M per MMDth Natural Gas Received
41
Source: third party analysis
$-
$0.01
$0.02
$0.03
$0.04
$0.05
$0.06
$0.07
$0.08
$0.09
$0.10
Company
A
Company
B
Company
C
Company
D
Company
E
Company
F
Company
G
Company
H
KM-
Line
operated
-
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
$0.40
$0.45
$0.50
Company
A
Company
B
Company
C
Company
D
Company
E
Company
F
Company
G
Company
H
KM
operated
Line
$
- |
 Implementation Plan
Immediate Risk Reduction
ROW protection programs
Liquids pipeline O&M re-write
EHS (environmental, health and
safety) “boot camps”
in Terminals
Audits and assessments (annual
program)
Acceleration of certain pipeline
integrity work
PSM / RMP compliance
(a)
Tank and in-facility pipe integrity
program
Terminals SQE (safety, quality and
environmental) ongoing
Separate review of high
consequence assets and
operations
Continuous Improvement
Systems Improvement and
extension
Measuring, meeting, adjusting
Training
Auditing
Working Groups –
share best
practices across Kinder Morgan
Systems-making
Compliance Routine
Addressing
operations
performance
in our existing processes —
Operations Management System
—
Annual budget
—
Compensation
—
QBR’s
—
Operations quarterly meetings
—
Monthly business unit meetings
—
Monthly major projects review
—
Weekly asset meetings
Compliance systems
—
OpsInfo extension (2008 –
11)
—
Datastream
—
Petris
—
Audit tracking system
—
Exceptions reported to business
unit management
Incident and near miss reporting
systems
—
ERL
—
STARS
—
Incident Review Committee
42
(a)
“PSM”
= Process Safety Management
“RMP”
= Risk Management Plan |
 Compliance Summary
Key elements:
1.
Clear statement of requirement, assignment of responsibility and
deadline for completion, and
2.
Exception reporting to management
Performance:
—
OpsInfo expanded to nearly 114,000 compliance actions per
year
•
Timely compliance: 99.5% in 2011
Other items tracked: regulatory changes, audit exceptions
tracked and closed
43 |
 Compliance Summary –
Cont’d
44
(a)
“SPCC”
= Spill Prevention Control and Countermeasures
(b)
“PSM”
= Process Safety Management
“RMP”
= Risk Management Plan
Business
Unit
Env. Permits
Hazardous
Waste / Transport
SPCC
(a)
Safety
PSM / RMP
(b)
DOT and
DOT
Maintenance
Security
Contractors
Damage
Prevention
Natural Gas
Pipelines
OpsInfo
INFOR EAM
OpsInfo
INFOR EAM
OpsInfo
ISNetworld
Petris
Products
Pipelines
OpsInfo
OpsInfo
OpsInfo
OpsInfo
OpsInfo
ISNetworld
Petris
Terminals
OpsInfo
OpsInfo
OpsInfo
OpsInfo
OpsInfo
ISNetworld
Petris
Kinder Morgan
Canada
OpsInfo & IVARA
OpsInfo for
Trans Mountain &
IVARA for
Platte & Express
Regulations
are Not
Applicable
OpsInfo &
IVARA
IVARA
ISNetworld
Petris
CO2
OpsInfo
OpsInfo
OpsInfo
INFOR EAM
OpsInfo
ISNetworld
Petris |
 Incidents & Releases: Liquids Pipeline ROW
Liquids
Pipeline
Incidents
per
1,000
Miles
(a)
Liquids
Pipeline
Release
Rate
(a)
45
Note: KM totals exclude non-DOT jurisdictional CO2 Gathering and Crude Gathering for compatibility
with industry comparisons (a)
Failures involving onshore pipelines that occurred on the ROW, including valve sites, in which there
is a release of the liquid or carbon dioxide transported resulting in any of the
following: (1)
Explosion or fire not intentionally set by the operator
(2)
Release 5 barrels or greater. (NOTE: PHMSA does not record system location for releases less
than 5 barrels) (3)
Death of any person
(4)
Personal injury necessitating hospitalization
(5)
Estimated property damage, including cost of clean-up and recovery, value of lost product, and
damage to the property of the operator or others, or both, exceeding $50,000; not included:
natural gas transportation assets (b)
2009 most recently reported
KM Incidents
Industry 3-yr Avg
Industry 2009 Avg
(b)
-
5
10
15
20
25
30
35
2006
2007
2008
2009
Industry 3-yr Avg
0.45
0.29
0.21
-
0.08
0.39
-
0.2
0.4
0.6
0.8
1.0
2006
2007
2008
2009
2010
2011
2010
2011
KM Incidents
Industry 2009 Avg
(b)
6.0
15.5
2.5
-
0.01
13.1 |
 Product Pipelines 10-year Release Trend
46
Releases > 5 Gallons ROW and Facilities
0
10
20
30
40
50
60
0
2,000
4,000
6,000
8,000
10,000
12,000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
Total Barrels Released
Cochin Release
Total Number of Incidents
Number of Pacific Only Releases |
 Incidents & Releases: Natural Gas Pipeline ROW
Natural Gas Pipeline Incidents Rate
(a)
47
0.27
0.30
0.13
0.04
-
0.2
0.4
0.6
0.8
1.0
2006
2007
2008
2009
2010
2011
KM Incidents
Current Industry Avg
2005 Industry Avg
0.32
0.27
__________________________
Note: KM totals exclude non-DOT jurisdictional CO2
Gathering and Crude Gathering for compatibility with industry comparisons
(a)
An Incident means any of the following events:
(1)
An event that involves a release of gas from a pipeline or of a liquefied natural gas or gas from an
LNG Facility and (i) A death, or personal injury necessitating in-patient
hospitalization; or (ii) Estimated
property
damage,
including
cost
of
gas
lost,
of
the
operator
or
others,
or
both,
of
$50,000
or
more;
or
(iii) Unintentional estimated gas loss of 3,000 Mcf or more
(2)
An event that results in an emergency shutdown of an LNG facility
(3)
An event that is significant, in the judgment of the operator, even though it did not meet the
criteria of paragraphs (1) or (2) |
 KM Lost-time Incident Rate (DART)
48 |
 Contractor Lost-time Incident Rate (DART)
49
0.44
0.71
1.23
1.00
1.10
1.00
1.84
1.00
-
1
2
3
4
5
Natural Gas
Pipelines
CO2
Products
Pipelines
Terminals
KM Canada
KM Contractor Rate (12-mo)
Industry Avg
- |
 OSHA Recordable Incident Rate
50
1.40
1.02
1.52
2.78
1.05
1.30
1.06
0.74
2.27
0.52
2.30
1.67
1.90
5.90
1.90
2.50
2.60
2.50
6.35
2.50
-
1
2
3
4
5
6
7
Natural Gas
Pipelines
CO2
Products
Pipelines
Terminals
KM Canada
KM Rate (3-yr Avg)
KM Rate (12-mo)
Industry Current Avg
Industry 2005 Avg |
 Vehicle Incident Rate
51
(a)
Industry average not available for Terminals
(a)
0.50
0.69
0.42
1.86
0.59
0.26
0.70
0.68
0.79
0.57
1.40
1.40
2.41
2.41
-
1
2
3
4
5
Natural Gas
Pipelines
CO2
Products
Pipelines
Terminals
KM Canada
KM Rate (3-yr Avg)
-
KM Rate (12-mo)
-
Industry Avg |
 2012 Objectives
Incident rates: better than industry average and better than the
Kinder Morgan 3-year average; zero significant incidents
Terminals SQE program
Continued special emphasis on high consequence assets and
operations
52 |
 53 |
 |
 Natural Gas Pipelines
Tom Martin
President Natural Gas Pipeline Group
** Does not include El Paso acquisition |
 Overview
Market
Environment
Shale activity providing excellent growth opportunities
Transport spreads remain flat
Storage spreads are weak
Processing margins continue to be very strong and roughly equivalent to 2011
performance Value
Proposition
Strong asset base with secure cash flows supported by long-term contracts
Broad pipeline network connected to diverse supply sources and end users lessening
the impact of flat basis spreads
Limited exposure to commodity prices and processing margins
Recently expanded footprint and superior access to capital provides additional
expansion / extension and acquisition opportunities
Summary
System
Financial targets
Asset-by-asset review
Intrastate assets
Growth opportunities
2 |
 Natural Gas Pipelines and Facilities
3 |
 Financial Overview
Budget
'11 -
'12
2006
2007
2008
2009
2010
2011
2012
Change
EBDDA
(a)
$501,103
$548,383
$738,860
$825,388
$981,391
$1,134,424
$1,305,468
$171,044
Sustaining Capex
(27,431)
(29,927)
(29,853)
(22,676)
(19,486)
(30,094)
(43,812)
(13,718)
DCF
$473,672
$518,456
$709,007
$802,712
$961,905
$1,104,329
$1,261,655
$157,326
14.2%
2012 Highlights:
Second half of KinderHawk acquired in July 2011; full-year contribution in
2012 Eagle Ford joint venture in-service; full-year contribution in
2012 Full-year contract quantities on FEP in 2012
SouthTex
acquisition
included
in
KMP
portfolio
in
December
2011;
full-year
contribution
in
2012
EagleHawk joint venture investment included in KMP portfolio in 2011; full-year
contribution in 2012 West Clear Lake storage contract renewal contribution in
2012 Full-year KMIGT rate case settlement in 2012
4
($ in millions)
(a)
EBDDA includes Upstream gathering assets (2010 forward) and includes imputed share
of DD&A of material joint venture investments, and incremental net cash
from Eagle Ford (2011) and Endeavor (2011 and 2012) |
 Contracted Capacity and Term
Interstate
pipelines:
contracted
on
a
“fee
for
service”
basis
Annual
re-contracting
exposure
is
~
2%
-
5%
of
segment
EBDDA
through
2015
Limited exposure to gas commodity pricing; $1/Dth gas price change = ~
$1.1MM in 2012, <1% of segment annual EBDDA Non-Interstate pipelines:
business portfolio Limited exposure to gas commodity pricing, processing
margins, pricing spreads —
Processing
exposure
(a)
:
$1
change
in
WTI
=
~$2MM;
1%
change
in
NGL
crude
ratio
=
~$3MM;
Total processing is ~ 6% of segment annual EBDDA
—
$1 /Dth gas price change = ~$3MM/yr, < 1% of segment annual EBDDA
—
Intrastate pricing spreads: $0.05 Waha to HSC = $1MM
5
Transport Contracts
Avg. = 8 yr, 9 mo
Transport Contracts
Avg. = 6 yr, 2 mo
Contracted
Capacity
Avg. Term
Remaining
Interstate
KM Interstate Gas
Storage
10.7
Bcf
3 yr,
1 mo
Transport
1.0
Bcf/d
3 yr,
6 mo
TransColorado
Transport
1.0
Bcf/d
4 yr,
3 mo
Trailblazer
Transport
0.9
Bcf/d
3 yr,
10 mo
Rockies Express
Transport
2.0
Bcf/d
7 yr,
8 mo
Midcontinent Express
Transport
2.6
Bcf/d
6 yr,
5 mo
KM Louisiana
Transport
2.1
Bcf/d
17 yr,
8 mo
Fayetteville Express
Transport
1.8
Bcf/d
10 yr,
2 mo
Intrastate
Texas Intrastates
Purchases
2.7
Bcf/d
2 yr,
1 mo
Sales
2.3
Bcf/d
2 yr,
1 mo
Storage
144
Bcf
1 yr,
1 mo
Transport
3.9
Bcf/d
5 yr.
7 mo
Eagle Ford JV
Transport
0.6
Bcf/d
9 yr,
11 mo
KinderHawk
Transport
N/A
~4 yr
(life of lease)
(a)
Includes Eagle Ford Gathering and Upstream |
 Asset Summaries |
 Rockies Express Pipeline
REX
1,685 miles of 36”
and 42”
mainline
Originates in Meeker, CO and
terminates in Clarington, OH
Transports Rocky Mountain
production to Midwest and
Northeast markets
JV between KMP (50%),
Sempra (25%) and
ConocoPhillips (25%); KMP
operates
Capacity
—
Zone 1 ~ 2.0 Bcf/d
—
Zone 2/3 ~1.8 Bcf/d
Long haul capacity contracted
at ~97% long term
FERC-regulated
Long
haul
flows
0.9
–
1.8
Bcf/d
7 |
 REX
Opportunities
Firm backhauls (Marcellus and Utica Shale, Biogas)
—
East-end receipts, conversion of existing deliveries to bi-directional
interconnects, and booster compression
—
Forward pricing favors Chicago over Clarington (backhaul within Zone 3)
Park & loan service
Interruptible and short haul service (ITS, PAWS)
Extensions and expansions
—
and LDC’s)
—
New supply basins (Utica and Marcellus shale)
Challenges
Meeker to Clarington price spreads have narrowed
MFN clause restricts full system backhauls (Zone 3 to Zone 1) to
shorter term (364 days max.) contracts
—
Backhauls within Zone 3 exempt
8
Additional
markets
in
Ohio
and
Indiana
(coal
to
gas
conversions, power
plants |
 KMIGT
5,054 miles of various
diameter reticulated
pipeline
Markets:
—
LDCs and industrials
—
Irrigation/grain drying in
NE and KS
—
Mid-Continent
interconnected pipelines
—
Ethanol plants
Growth
—
Power plants
Capacity
—
Transport .98 Bcf/d
—
Storage 14.8 Bcf
—
Marketable on-system
capacity sold out
—
PXP contracted at
96% short term
FERC-regulated
Rate case settlement
approved in 2011;
minimal rate case
exposure through 2015
Kinder Morgan Interstate Gas Transmission
9 |
 KMIGT
Opportunities
Pony Express Pipeline (PXP) conversion from gas to oil service
Power plants
—
New natural gas power plants and conversion of existing coal
power plants to natural gas
Future
production
development
–
Niobrara
Shale
Additional LDC and industrial load
Challenges
Re-contracting PXP capacity long term (if not converted to oil
service)
10 |
 KMIGT Gas to Oil Conversion Project
Fundamentals
Excess western gas export
capacity (~4 Bcf/d) has narrowed
the gas basis differential
Robust Bakken production growth
is projected and DJ/Niobrara
development is anticipated
Oil pipeline export capacity from
the west is fully utilized and
expensive rail/trucking options
being used
Uncertainty lies around the timing
of the Keystone XL project
approval
Conversion relies on upstream
expansion of Bridger-Butte pipeline
FERC abandonment approval
needed
Facilities
Conversion of 432 miles existing pipeline currently in gas
service (previously in oil service)
—
Guernsey to existing KMIGT NGPL gas interconnect
New Build
—
Gas facilities to provide alternative gas transportation
•
Required for FERC abandonment approval
—
~60 mile DJ/Niobrara Lateral
—
~230 miles from existing pipeline to Cushing
—
$700 -
$800M of capex
—
In service target late 2014
—
Open season ended Nov. 2011, working with potential shippers
to secure contracts
11 |
 TransColorado Gas Transmission
TransColorado
301 miles of 22”
& 24”
mainline
Originates at Greasewood, CO
and terminates at Blanco, NM
Primarily serves area producers
Bi-directional Flow
—
Capacity north ~ 0.44 Bcf/d
—
Capacity south
•
Phase 1 ~ 0.165 Bcf/d
•
Phase 2 ~ 0.372 Bcf/d
Less than 10% capacity sold
short term
FERC-regulated
Minimal rate case risk
Completed 18,000 Dth/d
southbound expansion at Conn
Creek CS
Aggregation of gathering and
processing has shifted gas
supply to north end of pipe
12 |
 Trailblazer Pipeline
Trailblazer
436 miles of pipe
3 compressor locations
with 58,000 HP
Max throughput = 0.878
Bcf/d
Lowest total cost pipeline
out of region
FERC-regulated
No rate case filing until
2014
Recontracting of expiring
capacity at lower rates
included in 2012 Budget
2% of segment EBDDA
13
13 |
 Midcontinent Express Pipeline
MEP
507
miles
of
42”,
36”
and
30”
pipe
Originates at Enogex,
Bennington and terminates
at Transco Station 85
Capacity:
—
Zone 1: 1.8 Bcf/d
—
Zone 2: 1.2 Bcf/d
JV between KMP (50%)
and Regency (50%); KMP
operates
Pipeline fully-subscribed
with long-term firm
contracts
FERC-regulated
14
14 |
 MEP
Opportunities
Serves as shale (Barnett, Woodford, Haynesville, and Bossier shales) outlet
with access to multiple markets in the Midwest, Northeast and Southeast
Zone 2 expandability (up to 300 MDth/d)
Shale development, Perryville pile-up could support Zone 2 expansion
Excess long haul capacity of 20 MDth/d has been identified as a result of
operating experience
—
Mainly sold under short-term firm deals in 2011-12
Storage connection access near Perryville area
—
Creates opportunities for hub and wheeling services
—
Sawgrass
Storage
LLC
has
filed
for
FERC
approval
for
development
of
storage
field that would utilize MEP as its transport hub for its customers
Higher recourse rates to reflect higher project costs (long-term
opportunity) 15 |
 Kinder Morgan Louisiana Pipeline
KMLP
133
miles
of
42”
pipe
Originates at Cheniere
Sabine pass LNG and
interconnects with 12
interstate pipelines
Two storage fields
connected to pipeline
Capacity: 3.2 Bcf/d
Pipeline fully-subscribed
with 20-year contacts
(~18 years remaining)
FERC-regulated
16
16 |
 KMLP
Opportunities
Opportunity to transport supply for LNG export
—
Cheniere Sabine Pass has received necessary DOE permits for their
liquefaction project. Awaiting FERC approval.
—
Cheniere signing up Shippers, has announced approximately 1.5 Bcf/d
—
Discussions with Cheniere and Shippers could lead to opportunities in 2015 and
beyond
Multiple
interconnections
–
with
additional
facilities,
may
capture
opportunities
between major interstate pipelines and storage
Potential interconnections with other LNG terminals
17 |
 Fayetteville Express Pipeline
FEP
185
miles
of
42”
pipe
One compressor station
with 72,000 HP
Capacity: 2.0 Bcf/d
15 receipt points
(producer specific)
4 delivery meters
JV between KMP (50%)
and Energy Transfer
(50%); Energy Transfer
operates
1.85 Bcf/d capacity under
long-term contracts
FERC-regulated
18
18 |
 FEP
Opportunities
All major construction completed; final clean-up is continuing as weather
allows —
2.0 Bcf/d of initial pipeline capacity
—
Project costs projected at $0.97 billion, substantially less than original
estimate of $1.26 billion 1.85 Bcf/d capacity sold under long-term firm
contracts; have 0.15 Bcf/d available for sale —
Southwestern: 1.2 Bcf/d, 10 yrs
—
Chesapeake: .375 Bcf/d for 10 yrs
—
BP: .125 Bcf/d for 10 yrs
—
XTO: .150 Bcf/d 12 yrs
Rig
count
in
Fayetteville:
28
rigs
in
December
2011,
maintaining
year-ago
level
—
Exxon purchased XTO assets in June 2010 and PetroHawk assets October 2010
—
BHP purchased Chesapeake assets April 2011 and will take operational control in
2012 —
Area producers still indicate a strong commitment to Fayetteville Shale based on
drilling forecast
Expansion opportunity for capacity up to 2.4 Bcf/d
—
Two additional compressor stations
Avg. daily delivered volumes have increased in the last year from .78 Bcf/d to 1.15
Bcf/d 19 |
 KMI (20% Ownership)
Natural Gas Pipeline Company of America
NGPL
Pipeline miles: 9,200
KM-operated
Market area deliverability: 5.0 Bcf/d
Storage working gas capacity: 278
Bcf (8 fields)
Direct or one-pipe-away access to
most major U.S. and Canadian supply
basins west of the Mississippi,
including major shale plays
Approx. 600 interconnections,
including:
—
34 interstate pipelines
—
38 local distribution companies
—
32 end users, including power
plants
Top customers consist of investment
grade LDCs (excl. NIPSCO),
producers and marketers
Top-10 customers make up 62% of
transportation and storage revenues
Firm transport and storage revenue by
customer segment:
—
LDCs
43%
—
Producers
17%
—
Marketers
34%
—
End users
5%
Rate case settlement reached in 2010
Average firm transport tenure is 2.4
years
Major LDC customer anticipated to
renew
for
3
-
4
years
20 |
 Texas Intrastate Pipelines
Texas Intrastates
6,000 miles of pipeline
Over 5 Bcf/d capacity
(5.5 Bcf/d peak day)
144 Bcf of storage
Access to 685 MMcf/d
processing capacity
180 MMcf/d CO
2
treating
capacity
Combination of fee-for-
service, and purchase /
sale activity
Texas Railroad
Commission regulated –
market-based regulation
in competitive
environment
21 |
 Texas Intrastate Pipelines
Opportunities
Large asset footprint provides real and continued opportunities for expansion capital
investment
New service to end user plants being restarted, expanded or built grass roots along
the Texas Gulf Coast in response to favorable feedstock and fuel outlook
—
Petrochemical, refinery, fractionation and power generation expansions being
planned around expected increase in local/domestic natural gas, NGL and
condensate supplies Economic expansions of deliverability into Mexico to serve
increasing demand for natural gas
Optimization and expansion of West Clear Lake storage facility post termination of
lease to Shell April 1
Other investments in or acquisitions of gathering assets similar
to KinderHawk & Eagle
Hawk
Challenges
Continuing to replace declining natural gas supply from traditional production
areas 22 |
 Eagle Ford Joint Ventures
Eagle Ford Gathering LLC
50/50 JV with Copano in STX
Capacity of 705,000 MMBtu/d based
on contracted processing space
111 miles of 30”/24”
supply lateral
placed into service 3Q 2011…
currently flowing 240,000 MMBtu/d
Approximately 90% of the JV’s long-
term capacity is subscribed
Pipeline capacity is expandable with
compression
62 miles of 24”
crossover pipeline
placed into service 3Q 2011 and
currently flowing approximately
120,000 MMBtu/d into WFS at
Markham
10 miles of 20”
inlet pipeline to
Formosa completed 4Q 2011; initial
deliveries expected in February
Eagle Hawk Field Services LLC
75/25 BHP Petrohawk/KM JV in S. TX
416 miles of pipeline in-service
2012 forecasted capacity:
~ 110K Bbl/d
~ 670 MMcf/d
KM expects to have invested in excess
of $400 million of capital in, and in
support of, these Eagle Ford joint
ventures by year-end 2012
23 |
 Eagle Ford Joint Ventures
Opportunities
Additional EFG gathering and processing expansions as
producers shift rigs into what is one of the most economic basins
in North America
Higher volumes on EagleHawk as BHP continues to increase rig
count in 2012
Challenges
Handle
liquids
fallout
from
higher
than
expected
liquids
content
in
the gas to maintain run times
24 |
 KinderHawk Field Services
KHFS
100% KM in northwest Louisiana
Gathering and treating services
for Haynesville / Bossier Shale
Long-term gathering / treating
contracts
452 miles of pipe installed to-
date
Over 2 Bcf/d of capacity
Well-positioned to access over
20 Tcf of gas
2,600 GPM of treating capacity
in-service (20 plants / 12
locations)
102 wells connected to the
system in 2011
103 wells budgeted to be
connected in 2012
18 interconnections with major
downstream pipelines
1 additional interconnection with
major downstream pipeline to be
constructed 1st Q 2012
2011 annual average: 1.0 Bcf/d
2012 volume forecast:
—
current
1.0 Bcf/d —
annual avg ~1.1-1.3 Bcf/d
25
25 |
 KHFS
Opportunities
Expansions due to infill drilling, additional CDPs and planned
extensions of the system
Higher volumes as BHP is expected to increase rig count in 2012
Bossier Shale development
Some 3
rd
party opportunities remain as lease capture continues
Challenges
Maintaining high amine plant runtime to avoid curtailments
Have regional facilities in place to handle surges of new
production as shift to pad drilling programs begin
Potential impact on developmental drilling from low gas prices
26 |
 Kinder Morgan Upstream (KMULLC)
KMULLC
Own and operate processing plants in
Casper and Douglas, Wyoming and a
carbon dioxide and sulfur treating
facility at West Frenchie Draw,
Wyoming
—
Combined processing capacity of
185 MMcf/d
—
West Frenchie Draw Plant is fully
subscribed for 50 MMcf/d of
natural gas
Red Cedar Gathering (RCG) is a joint
venture between KMP (49%) and the
Southern Ute Indian Tribe (51%)
located within the boundaries of the
Southern Ute Indian Reservation in the
Durango, Colorado area
—
743 miles of gathering pipe
connected to 1,200 producing
wells; 89,400 horsepower of
compression and three (Arkansas
Loop/Simpson and Coyote Gulch)
carbon dioxide treating plants
—
Capacity of approximately 750
MMcf/d
—
Delivers gas into TransColorado,
El Paso and TransWestern
pipelines and the Enterprise Val
Verde Treating Plant at the
Blanco hub
—
Largest customers include BP,
Samson and Red Willow
27 |
 KMULLC
Opportunities
Increased processing volumes at the Douglas Plant
—
Increase in liquids volumes from Chesapeake and DCP over the
next two years
Increased volumes at Red Cedar from development of acreage on
east end of Southern Ute Indian Reservation
—
Approximately 100 MMcf/d is expected to eventually come from the
development of reserves in the eastern end
—
The infrastructure (pipe & compression) to support this development
was completed and put in service in 2011
Challenges
Douglas plant capacity is adequate for increases in volume,
however, expect limitations in fractionation space downstream at
Conoco’s WRB facility
Gas prices have caused large scale development on the east end of
Red Cedar to slow down
28 |
 29
Treating Services
Largest fleet of contract operated
amine plants in the U.S. that
remove CO
2
and H
2
S from natural
gas
—
140 leased amine plants in
service
—
Refurbishment and inventory
yards located in Odessa and
Victoria, TX
Manufacture and lease skid
mounted mechanical refrigeration
units “MRU’s”
that remove liquid
hydrocarbons from natural gas
—
145 leased MRU’s in service
—
Manufacturing facility in Tyler, TX
Acquired SouthTex Treaters in
November 2011 for $155 million
—
84 acre manufacturing facility
located in Odessa, TX
—
Manufacture and sell amine
treating plants, stabilizers, high
pressure vessels and other oil
field related equipment
Treating Services |
 Treating Services
Opportunities
Find new applications on KM’s expanding asset footprint for KM
amine, dew point and MRU equipment
Increase utilization of SouthTex manufacturing capabilities for
both 3
rd
parties and Kinder Morgan internal needs
Challenges
Keep amine lease fleet deployed (especially smaller units) in an
environment where wellhead applications continue to be
displaced by centralized facilities in the shale plays
30 |
 2012
Full-year effect of new projects and acquisitions
—
FEP, KinderHawk, Eagle Hawk, SouthTex
New
growth
continues
with
expansions
and
increases
in
fee
based
services
—
Eagle Ford
—
West Clear Lake Storage
2013 and beyond -
long term / future growth
Shale gas
—
TX
Intrastates
–
Eagle
Ford
expansion,
extension
and
treating/processing
activities
—
KinderHawk
–
extensions
and
expansions
(infill
drilling),
Bossier
production
growth,
additional
service
offerings
—
FEP –
remaining 150,000/d of capacity plus expansion opportunities
—
KMIGT –
Niobrara gathering and processing opportunities
—
REX –
additional downstream market Marcellus (backhaul opportunities)
—
MEP –
additional expansion opportunities (up to 300 MDth/d Zone 2)
—
East
of
Perryville
/
T85
–
Southeast
markets
Storage
—
TX Intrastates
•
West Clear Lake –
significant expansion opportunities
•
Dayton –
further expansions
—
Continue to evaluate new interconnects or investment in storage opportunities
across KM pipeline footprint Acquisitions & other opportunities
—
Conversion of natural gas lines into liquids or oil service (e.g. Pony
Express) —
KMLP –
transportation backhaul opportunities for the export of LNG cargos from Cheniere
LNG facility —
NGPL –
several proposed LNG export facilities in the Gulf region add significant new
market opportunity —
KinderHawk/Eagle Hawk -
replicate in upstream sector
—
Intrastates
–
uniquely
capable
of
pursuing
high
pressure
markets
—
Continue to seek new industrial / end user loads along the pipeline
corridors —
Other pipeline assets that complement KM footprint
Growth Opportunities in 2012, 2013 and Beyond
31 |
 |
 Financial Review
Kimberly Dang
Chief Financial Officer |
 Agenda
KMP:
2012 budget
—
Distributable cash flow
—
Segment earnings before DD&A and LP net income
—
Quarterly profile
—
Budget assumptions
—
Sustaining capital
—
Growth capital
—
Financing plans
Liquidity
Balance sheet ratios
KMI:
2012 budget
—
Cash available to pay dividends
—
Quarterly profile
Liquidity
Summary
2 |
 KMP |
 2012 DCF Budget
(a)
4
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Excluding certain items
(b)
Includes $171 million of joint venture DD&A in both 2011 and 2012, for our
share of REX, MEP, FEP, KinderHawk (until May-2011), EagleHawk, Eagle Ford (2012-
only), Red Cedar and Cypress
(c)
Eagle Ford in 2011 only
(d)
Includes joint venture sustaining capex for our share of REX, MEP, FEP, KinderHawk
(until May-2011), EagleHawk, Eagle Ford (2012 only), Red Cedar and Cypress
2011
2012
Change
Actual
Budget
$
%
Distributable cash flow
Net income
$1,742
$2,148
$406
23%
DD&A
(b)
1,133
1,206
73
6
Book / cash tax difference
27
26
(1)
(4)
Eagle
Ford
/
Express
/
Endeavor
(c)
15
7
(8)
(53)
Sustaining capex
(d)
(212)
(249)
(37)
17
Total distributable cash flow
2,705
3,138
433
16
General partner's interest
(1,180)
(1,362)
(182)
15
Distributable cash flow
$1,525
$1,776
$251
16%
Average Units Outstanding
326
342
16
5%
Total DCF per unit
$4.68
$5.19
$0.51
11%
LP distribution per unit
$4.61
$4.98
$0.37
8%
Excess coverage
$21
$71
$50
(millions, except per unit)
(KMP) |
 2012 Income Budget
(a)
5
(millions, except per unit)
2011
2012
Change
Actual
Budget
$
%
Segment earnings before DD&A (EBDA)
Products Pipelines
$694
$734
$40
6%
Natural Gas Pipelines
951
1,133
182
19
CO2
1,094
1,381
287
26
Terminals
701
757
56
8
Kinder Morgan Canada
199
201
2
1
Total segment EBDA
3,639
4,206
567
16
DD&A
(961)
(1,036)
(75)
8
G&A
(388)
(411)
(23)
6
Interest
(531)
(588)
(57)
11
Non-controlling interest
(17)
(23)
(6)
35
Net income
1,742
2,148
406
23
GP share
(1,180)
(1,362)
(182)
15
Limited
partners’
net
income
$562
$786
$224
40%
Units outstanding (avg)
326
342
16
5%
LP income per unit
$1.72
$2.30
$0.58
34%
Natural
Gas
EBDA
plus
JV
DD&A
(b)
$1,122
$1,303
$181
16%
Total
segment
EBDA
plus
JV
DD&A
(c)
$3,810
$4,377
$567
15%
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Excluding certain items
(b)
Natural gas pipelines EBDA adding back our share of REX, MEP, FEP, KinderHawk
(until May-2011), EagleHawk, Eagle Ford (2012-only) and Red Cedar JV DD&A of $171
million and $170 million in 2011 and 2012, respectively
(c)
Total segment EBDA adding back our share of REX, MEP, FEP, KinderHawk (until
May-2011), EagleHawk, Eagle Ford (2012-only), Red Cedar and Cypress JV DD&A
of $171 million in both 2011 and 2012
(KMP) |
 2012 Budgeted Quarterly Profile
(a)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Excluding certain items; please see KMP’s periodic reports on Form 10-K
and Form 10-Q for a more detailed presentation (b)
Includes joint venture DD&A for our share of REX, MEP, FEP, KinderHawk (until
May-2011), EagleHawk, Eagle Ford (2012-only), Red Cedar and Cypress
(c)
Includes our share of joint venture DD&A and is reduced by our share of joint
venture sustaining capital expenditures for the following investments: REX, MEP, FEP,
KinderHawk (until May-2011), EagleHawk, Eagle Ford (2012-only), Red Cedar
and Cypress 1Q
2Q
3Q
4Q
Year
Total
Segment
EBDA
w/JV
DD&A
(b)
2012B
25%
24%
24%
27%
$4,377
2011
24%
23%
26%
27%
$3,810
DCF/unit
(c)
2012B
27%
22%
23%
28%
$5.19/unit
2011
26%
22%
25%
27%
$4.68/unit
Earnings/unit
2012B
27%
20%
22%
31%
$2.30/unit
2011
25%
17%
26%
32%
$1.72/unit
($ in millions, except per unit)
(KMP)
6 |
 Budget Assumptions
Segments:
—
Natural Gas
•
Growth
and
full-year
contributions
from
KinderHawk,
EagleHawk,
and
SouthTex,
and
partial-year
contributions
from
Eagle
Ford
JV
with Copano
•
Full year of higher throughput on FEP (volumes contractually ramped up through
2011) •
West Clear Lake storage contract rollover
—
CO2
•
Oil price on unhedged oil volumes in CO2
~$93.75/Bbl
•
CO2
S&T contract price increases
•
Relatively flat oil production: SACROC volumes = 27.9 MBbl/d, Yates = 21.0, Katz =
2.3 —
Products
•
Modest refined product volume growth = -0.4% excluding Plantation, +0.5%
including Plantation •
PPI tariff escalator
•
Partial-year
of
crude
and
condensate
operations,
Cochin
E/P
project,
and
terminal
projects
including
new
tank
expansions
for
refined products and biodiesel blending services
—
Terminals
•
Increase in rates on existing contracts
•
Higher coal throughput
•
Full year of 2011 acquisitions (Cushing, Total, Watco) and expansion projects
(Carteret, Cushing, Deer Park, Port of Houston) •
Partial-year benefit from over $650 million in 2012 expected growth
expenditures —
Kinder Morgan Canada
•
Extended 1-year toll settlement on TMPL
Equity and Debt:
—
Total 2012 equity budgeted = $876 million
•
Issue $385 million in secondary equity
•
KMR dividend $491 million
—
KH giveback $25.5 million
—
Total 2012 long-term debt = $2 billion ($1 billion net of refinancing)
Interest Expense:
—
Average 3-month LIBOR rate of 0.80% for the year, based on forward curve at
time of budget; current average 3-mo LIBOR curve = ~0.60%
7
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(KMP) |
 2012 Sustaining Capital Budget
(a)
8
2011
2012
Actual
Budget
Change
Sustaining capital
Products Pipelines
$50
$51
$1
Natural Gas Pipelines
35
51
16
CO
2
12
16
4
Terminals
91
105
14
Kinder Morgan Canada
18
20
2
Corporate
6
6
-
Total sustaining capital
$212
$249
$37
($ in millions)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Excluding certain items
(KMP) |
 2011 vs. 2012 Growth Capital
9
($ in millions)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
2011
2012
Actual
Budget
Expansion capital
Products Pipelines
$207
$239
Natural Gas Pipelines
121
145
CO
2
416
437
Terminals
224
492
Kinder Morgan Canada
11
10
Total expansion capital
979
1,323
Contributions to JVs
382
233
Subtotal
1,361
1,556
Acquisitions
1,243
108
Total growth capital
$2,604
$1,664
(KMP) |
 2012 Growth Capital Budget
10
($ in millions)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
Total
Expansion
Equity
Growth
Capital
Contributions
Acquisitions
Capital
Expansion capital
Products Pipelines
$239
$72
-
$311
Natural Gas Pipelines
145
101
1
247
CO
2
437
-
-
437
Terminals
492
60
107
659
Kinder Morgan Canada
10
-
-
10
Total growth capital
$1,323
$233
$108
$1,664
(KMP) |
 2012 Financing Plans
11
($ in millions)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Excludes any changes in working capital
2012
Budget
Equity
Secondary offerings / ATM
$385
KMR dividends
491
Total equity
$876
Debt
Long-term debt issuance
$2,000
Decrease
in
revolver
(a)
(254)
Debt maturities in March / September
(958)
Incremental debt
$788
$1,664
(KMP) |
 Liquidity Summary
(a)
Revolver Liquidity
Long-term Debt Maturities
12
($ in millions)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
As of 12/31/2011
(b)
Primary 2012 maturities: $450 million 7.125% senior notes due 3/15/2012, $500
million 5.85% senior notes due 9/15/2012 Total bank credit
$2,200
Less:
Commercial paper
(645)
LCs outstanding
(230)
Liquidity
$1,325
2012
$958
(b)
2013
$508
2014
$503
2015
$300
2016
$500
(KMP) |
 Balance Sheet Ratios
13
2012
2004
2005
2006
2007
2008
2009
2010
2011
Budget
Debt / EBITDA
3.5x
3.2x
3.3x
3.4x
3.4x
3.8x
3.7x
3.6x
3.4x
EBITDA / interest exp.
6.9x
6.3x
5.2x
5.2x
6.2x
6.4x
6.1x
6.5x
6.8x
(KMP)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
|
 KMI |
 2012 Budget for Cash Available to Pay Dividends
15
($ in millions)
Declared Basis
2011
2012
Change
Actual
Budget
$
%
Distributions
KMP distributions
To general partner
$1,217
$1,404
$187
15%
On KMP units owned by KMI
100
108
8
8
On KMR shares owned by KMI
63
73
10
16
Total KMP distributions to KMI
1,380
1,585
205
15
NGPL’s cash available for distribution to KMI
30
14
(16)
(53)
Total cash generated
1,410
1,599
189
13
G&A
and
sustaining
capital
expenditures
(a)
(10)
(10)
-
-
Interest expense
(166)
(167)
(1)
1
Cash available to pay dividends b/f cash taxes
1,234
1,422
188
15
Cash taxes
(368)
(437)
(69)
19
Cash available to pay dividends
$866
$985
$119
14
Dividend
$849
$956
$107
13%
Average fully-diluted shares outstanding
708
709
1
Dividend per share
$1.20
$1.35
$0.15
13%
Excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Excludes certain items
(b)
KMI paid a prorated dividend for 1Q 2011, for the portion of the
quarter that it was public, of $0.14 per share;
based on a full quarter, the dividend amounts to $0.29 per share
(b)
(KMI) |
 2012 Budgeted Quarterly Profile
16
KMI
–
yield-oriented
investment
valued
on
a
cash
flow
basis
1Q
2Q
3Q
4Q
Year
Cash available to pay dividends
2012B
31%
18%
21%
30%
$985
2011
(a)
30%
19%
22%
29%
$866
Earnings per share
2012B
24%
24%
25%
27%
$1.03/sh
2011
n/m
n/m
n/m
n/m
$0.74/sh
($ in millions, except per share)
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Excludes certain items
(KMI) |
 Credit / Liquidity Summary
(a)
17
2012
$839
(c)
2013
---
2014
---
2015
$250
2016
$850
Total Bank Credit
$1,000
Less:
Revolver Drawn
(421)
Letters of Credit
(48)
Excess Capacity
$531
Credit Summary
Revolver Capacity
2010
2011
Budget
2012
2.5x
2.3x
2.1x
Note: excludes any impact from the proposed acquisition of El Paso by KMI, except
debt balance which includes some transaction fees already paid (a)
Unless otherwise noted, as of 12/31/2011; debt of KMI’s subsidiary, Kinder
Morgan Kansas, Inc. excluding the fair value of interest rate swaps, purchase accounting
and Kinder Morgan G.P., Inc.’s $100 million of Series A
Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057
(b)
Debt as described in footnote above and net of cash; 2010 distributions received
less G&A adjusted to exclude the ICT (c)
$839 million 6.5% senior notes due 9/1/2012
($ in millions)
Long-term Debt Maturities
(KMI)
Net Debt / Distributions Received Less G&A
(b)
|
 Summary
KMP Budget
Grow budgeted declared distribution to $4.98/unit (8.0% growth)
—
$71 million in excess coverage
Finance expansion budget approximately 50 / 50 debt / equity to maintain strong
credit metrics
—
Year-end 2012 Debt / EBITDA of 3.4x
Distribute $3.1 billion in 2012
KMI Budget
Declare $1.35 / share in dividends (12.5% growth)
Year-end 2012 Debt / Distributions Received Less G&A of 2.1x
18
Note: excludes any impact from the proposed acquisition of El Paso by KMI, except
debt balance which includes some transaction fees already paid |
 Appendix |
 KMP Current Cost of Capital Calculation
2
Annualized
Indicated LP
Distribution
Current KMP
Unit Price
Equity
Current KMP Yield
$4.64
$84.95
5.5%
GP Gross-up
55%
Cost of Equity
=
9.9%
Equity % of Capital Structure
x
50%
Equity Component of Cost of Capital
=
4.9%
Interest
Rate
% of Overall
Debt
Debt
Short-term Floating Rate
(a)
3.0%
X
50%
1.5%
Long-term Fixed Rate
6.0%
X
50%
+
3.0%
Cost of Debt
=
4.5%
Debt % of Capital Structure
x
50%
Debt Component of Cost of Capital
=
2.3%
Equity
Component
Debt
Component
Current
Cost of Capital
4.9%
+
2.3%
=
7.2%
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Includes fixed-floating interest rate swaps |
 Explanation of Return Calculations
3
Formula
Notes
Segment
Return on Investment =
Segment
Distributable Cash Flow
before Certain Items
(a)
Average Total Investment
(c)
KMP
Return on Investment =
KMP
Distributable Cash Flow
before Certain Items
(b)
Average Total Investment
(c)
Return on Equity =
Distributable Cash Flow
before Certain Items
(d)
Average Equity
(e)
(a)
Segment Distributable Cash Flow before Certain Items is defined as the applicable segment earnings
before DD&A and certain items less sustaining capex. In addition, several adjustments
are made to segment earnings before DD&A to more closely tie to cash: (1) KMP’s share of REX, MEP, FEP, KinderHawk (until May-
2011), EagleHawk, Red Cedar and Cypress DD&A is added back and sustaining capex is deducted, (2)
Express, Endeavor and Eagle Ford pre-tax earnings are subtracted and cash received is added
back
(b)
KMP Distributable Cash Flow before Certain Items is defined as the sum of the five individual Segment
Distributable Cash Flow before Certain Items less G&A
(c)
See next page for calculation, annual number is calculated based on average of the quarterly Total
Investment
(d)
Distributable Cash Flow before Certain Items is defined as outlined on the Non-GAAP Financial
Measures slide plus the general partner’s incentive and the general partner
non-controlling interest
(e)
Equity is based on cumulative equity raised inception to date as of the end of each quarter and then
averaged for the year |
 Explanation
of
Return
Calculations
–
Cont’d
4
Formula
Notes
Calculation of
Total Investment:
Gross PP&E
Investments
Goodwill
Gross intangibles (excluding amortization)
(a)
Plus:
Asset write-offs / retirements
Cumulative environmental reserves
Legal reserves / expenditures
(b)
Cumulative cash spent on asset retirement
(d)
Minus:
Cumulative sustaining capex
Assumed liabilities
Trans Mountain / Express adjustment
(c)
Cumulative asset retirement costs
(d)
Book value of sold assets / investments
Equals:
Total investment
(e)
(a)
(b)
Litigation
and
environmental
reserves
deducted
as
certain
items
are
added
to
investment,
except
for
SFPP
and
Calnev
litigation
reserves.
For
SFPP
and
Calnev,
actual legal payments are added to the investment when they are made
(c)
For assets acquired from Kinder Morgan, Inc. (Express, Trans Mountain) which
represent a transfer of assets between entities under common control and are
recorded at KMI’s carrying value on KMP’s financials, an adjustment has
been made to reflect these assets at KMP’s purchase price (d)
The present value of accumulated asset retirement costs are included in gross
PP&E; for purposes of this calculation, we decrease our Total Investment / subtract out
the accumulated asset retirement costs, and increase our Total Investment / add
back the cash actually spent on asset retirement (e)
Van Wharves, Cochin, Trans Mountain, and Express Total Investment is based on
acquisition price plus cumulative expansion capital including overhead. The
purpose of calculating Total Investment in this manner is to exclude the foreign
exchange impact reflected in our GAAP financials. GAAP financials revalue the entire
asset balance based on the end of period exchange rate
Investments are calculated based on GAAP book value equal to cumulative contributions plus cumulative
earnings less cumulative distributions, except REX, MEP, FEP, KinderHawk (until May-2011
when consolidated), EagleHawk, Eagle Ford, Cypress, Parkway, Plantation and Red Cedar, which are based on cumulative equity
contributed. These investments are not adjusted for earnings or distributions |
 KMP CO
2
Asset Summary
5
CO2
Reserves
KMP
Interest
Location
Remaining
Deliverability
Operator
McElmo Dome
45%
SW Colorado
18+ years
KMP
Doe Canyon
87%
SW Colorado
18+ years
KMP
Bravo Dome
11%
NE New Mexico
9+ years
Oxy
Pipelines
KMP
Interest
Location
Capacity
(MMcf/d)
Operator
Cortez
50%
McElmo Dome to
Denver City
1,350
KMP
Bravo
13%
Bravo Dome to
Denver City
375
Oxy
Central Basin (CB)
100%
Denver City to
McCamey
700
KMP
Canyon Reef
98%
McCamey to
Snyder
290
KMP
Centerline
100%
Denver City to
Snyder
300
KMP
Pecos
~70%
McCamey to Iraan
125
KMP
Eastern Shelf
100%
Snyder to Katz
65
KMP
Wink (crude)
100%
McCamey & Snyder
to El Paso
125 MBbl/d
KMP
Crude Reserves
KMP Interest /
(Net of royalty)
Location
Remaining
Life
Operator
SACROC
97% (83%)
W Texas
8+ years
KMP
Yates
50% (44%)
W Texas
25+ years
KMP
Katz
99% (83%)
W Texas
20+ years
(a)
KMP
(a)
Based on current development plan |
 KMP GAAP Reconciliation
6
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
DCF = Distributable cash flow
(b)
Includes REX, MEP, FEP, KinderHawk (until May-2011), EagleHawk, Eagle Ford
(2012-only), Red Cedar and Cypress JV DD&A (c)
Includes joint venture sustaining capex for our share of REX, MEP, FEP, KinderHawk
(until May-2011), EagleHawk, Eagle Ford (2012-only), Red Cedar and Cypress
(d)
KMR distributes additional shares in lieu of cash
(e)
Gain on sale of assets and asset disposition expenses, Cochin imputed interest
expense, FX gain on Cochin note payable, Terminals overhead credit on certain items capex, acquisition
costs,
legal
expenses,
insurance
deductible,
casualty
losses
and
reimbursements
(f)
Gain on sale of assets
2011
2012B
2011
2012B
KMP
Consolidated
DCF
Excluding
Certain
Items
(a)
Total Distributions
Net income per GAAP income statement
$ 1,258
$ 2,156
LP distributions per GAAP cash flow statement
$ 1,054
Certain items (net of minority interest)
484
(8)
Difference
due
to
KMR
and
timing
on
cash
payment
(d)
450
Net income before certain items
1,742
2,148
Calendar-year LP declared distribution
$ 1,504
DD&A
961
1,036
JV
DD&A
-
KM
share
(b)
171
171
GP distributions per GAAP cash flow statement
$ 1,189
Eagle Ford / Express / Endeavor contribution
15
7
Difference due to timing and minority interest
8
Book / (cash) tax difference
27
26
Calendar-year GP declared distribution
$ 1,197
Sustaining
capex
(c)
(212)
(249)
KMP DCF
$ 2,705
$ 3,138
Total declared distributions (GP + LP)
$ 2,701
Segment
DCF
Excluding
Certain
Items
(a)
Debt Ratios
Segment earnings before DD&A (EBDA)
$ 3,242
$ 4,214
Long-term debt excluding market value of swaps
$ 10,660
Certain items impacting segments
397
(8)
Notes payable & current maturities
2,138
Segment EBDA excluding certain items
3,639
4,206
Less: cash & equivalents
(409)
JV
DD&A
-
KM
share
(b)
171
171
Debt, net of cash
$ 12,389
$ 13,499
Segment EBDA exc certain items, inc JV DD&A
3,810
4,377
Segment
sustaining
capex
without
overhead
(c)
(189)
(223)
EBITDA to interest
6.5x
6.8x
Segment DCF
$ 3,621
$ 4,154
Debt to EBITDA
3.6x
3.4x
EBITDA Excluding Certain Items
Certain
Items
(Net
of
Minority
Interest)
Net income per GAAP income statement
$ 1,258
$ 2,156
Allocated non-cash long-term compensation
$ (81)
Certain items (net of minority interest)
484
(8)
Environmental reserves
(10)
Net income before certain items
1,742
2,148
Legal reserves and settlements
(231)
Income taxes
55
70
Mark-to-market & ineffectiveness of certain hedges
5
DD&A
961
1,036
Loss on remeasurement of asset to fair value
(165)
JV
DD&A
-
KM
share
(b)
171
171
Prior period asset write-off
(10)
Interest, net of interest income
531
588
Other
8
(e)
8
(f)
EBITDA excluding certain items
$ 3,460
$ 4,013
Total
$ (484)
$ 8
|
 KMI GAAP Reconciliation
7
Note: excludes any impact from the proposed acquisition of El Paso by KMI
(a)
Distributions from equity investments and distributions from equity investments in
excess of cumulative earnings (b)
Difference between cash and book interest expense for Kinder Morgan Kansas,
Inc. (c)
Consists of timing differences between earnings and cash, and cash flow in excess
of our distributions 2011
2012B
2011
2012B
Cash Available to Pay Dividends
Distributions Received Less G&A
Income from continuing operations
$ 652
$ 1,366
Cash available to pay dividends (above)
$ 866
$ 985
DD&A
1,092
1,166
Cash taxes
368
437
Amortization of excess cost of investments
7
7
Interest expense
166
167
Income from equity investments
(313)
(341)
Distributions received less G&A
Distributions
from
equity
investments
(a)
523
529
KMP certain items (pre-tax)
493
(8)
Debt Ratios
Kinder Morgan Kansas, Inc. purchase accounting
(9)
10
Long-term debt -
Kinder Morgan Kansas, Inc.
$ 1,941
Difference between cash & book taxes
(32)
59
Current
portion
of
L-T
debt
-
Kinder
Morgan
Kansas,
Inc.
1,260
Difference
between
cash
&
book
interest
expense
(b)
(1)
11
Less:
cash
&
equivalents
-
Kinder
Morgan
Kansas,
Inc.
(2)
Sustaining capital expenditures
(213)
(250)
Add back: purchase accounting
37
KMP declared distribution on LP units owned by public
(1,357)
(1,533)
Debt, net of cash
$ 3,236
$ 3,363
Other
(c)
24
(31)
Cash available to pay dividends
$ 866
$ 985
Net debt / distributions received less G&A
2.3x
2.1x
$ 1,400
$ 1,589 |
 Investor Relations Contacts
8
Institutional Investors / Sell-side Analysts
David Kinder
VP, Corporate Development & Treasurer
(713) 369-9469
david_kinder@kindermorgan.com
Peter Staples
Director, Investor Relations
(713) 369-9221
peter_staples@kindermorgan.com
Retail Investors / Brokers
Mindy Thornock
Director, Treasury
(713) 369-9449
mindy_thornock@kindermorgan.com |