HOUSTON--(BUSINESS WIRE)--Kinder Morgan, Inc. (NYSE: KMI) today announced that its board of
directors approved a cash dividend of $0.125 per share for the quarter
($0.50 annualized) payable on Nov. 15, 2016, to common shareholders of
record as of the close of business on Nov. 1, 2016. KMI expects to
declare dividends of $0.50 per share for 2016 and use cash in excess of
dividend payments to fund growth investments and strengthen its balance
sheet.
KMI continues to make significant progress toward enhancing its credit
profile. On Sept. 1, 2016, KMI closed the previously announced agreement
to partner with Southern Company through the sale of a 50 percent
interest in the Southern Natural Gas (SNG) pipeline system for cash
consideration of over $1.4 billion plus Southern Company’s share of
SNG’s debt. KMI used the entire amount of cash proceeds to reduce its
net debt. As of the end of the third quarter, $749 million was held in
escrow to redeem debt and was not included in net debt reduction during
the quarter. The debt was redeemed on Oct. 1, 2016, and will result in
further net debt reduction in the fourth quarter of 2016.
“During the quarter, we substantially reduced our debt, further
positioning Kinder Morgan for long-term value creation. We are ahead of
our plan for 2016 year-end leverage and we’re pleased with the progress
toward reaching our targeted leverage level of around 5.0 times net
debt-to-Adjusted EBITDA,” said Richard D. Kinder, executive chairman.
“This will position us to return substantial value to shareholders
through some combination of dividend increases, share repurchases,
additional attractive growth projects or further debt reduction.
“Additionally, we are pleased with our operational performance for the
quarter despite continued weak market conditions in our industry. Our
performance, adjusted for the SNG transaction, remains consistent with
our guidance provided since April. We remain on track to generate full
year 2016 distributable cash flow in excess of our expected dividends
and our expected growth capital expenditures, eliminating our need to
access the capital markets to fund growth projects in 2016. Moreover,
given our continued efforts to high-grade our backlog, we do not expect
to need to access the capital markets to fund our growth projects for
the foreseeable future beyond 2016.”
President and CEO Steve Kean said, “We had a good third quarter and once
again, we demonstrated the resiliency of our cash flows, generated by a
large, diversified portfolio of predominately fee-based assets. We
generated a loss per common share for the quarter of $0.10, primarily as
a result of non-cash charges discussed below. That said, we produced
distributable cash flow of $0.48 per share relative to our $0.125 per
share dividend, resulting in $801 million of excess distributable cash
flow above our dividend.”
Kean added, “We continue to drive future growth by completing
significant infrastructure development projects in our sizable project
backlog. Our current project backlog is $13.0 billion, down from $13.5
billion at the end of the second quarter of 2016. This reduction was
driven by the delivery of the Garden State and Bay State tankers
as well as placing other projects in service. Excluding the CO2
segment projects, we expect the projects in our backlog to generate an
average capital-to-EBITDA multiple of approximately 6.5 times.”
KMI reported a third quarter net loss available to common stockholders
of $227 million, compared to net income available to common stockholders
of $186 million for the third quarter of 2015, and distributable cash
flow of $1,081 million versus $1,129 million for the comparable period
in 2015. The decrease in distributable cash flow for the quarter was
attributable to lower contributions from the CO2 segment
primarily due to lower commodity prices. In total, KMI’s other business
segments generated higher contributions than the third quarter of 2015.
Net income available to common stockholders was also impacted by a $405
million unfavorable change in total certain items compared to the third
quarter of 2015, including a partial write down of our equity investment
in Midcontinent Express Pipeline (MEP) driven by expectations for lower
future transportation contract rates as well as a non-cash book tax
expense associated with the SNG transaction.
For the first nine months of 2016, KMI reported net income available to
common stockholders of $382 million, compared to $948 million for the
first nine months of 2015, and distributable cash flow of $3,364 million
versus $3,466 million for the comparable period in 2015. The decrease in
distributable cash flow was primarily attributable to lower
contributions from the CO2 segment, higher preferred stock
dividends and higher cash taxes, partially offset by increased
contributions from all of KMI’s other segments and lower interest
expense. Net income available to common stockholders was further
impacted by a $480 million unfavorable change in total certain items
compared to the first nine months of 2015, including the write down of
our equity investment in MEP, the non-cash book tax expense associated
with the SNG transaction, and a $170 million write-off of costs
associated with the Northeast Energy Direct Market and Palmetto Pipeline
projects during the first quarter of 2016.
2016 Outlook
For 2016, KMI expects to declare dividends of $0.50 per share. KMI's
budgeted 2016 distributable cash flow was approximately $4.7 billion and
budgeted 2016 Adjusted EBITDA was approximately $7.5 billion. Consistent
with guidance provided the last two quarters, the company continues to
expect Adjusted EBITDA to be about 3 percent below budget and
distributable cash flow to be about 4 percent below budget. To be
consistent with previous quarters, this guidance does not take the SNG
transaction into account. Including the impact of the SNG transaction,
the company expects Adjusted EBITDA and distributable cash flow to each
be about 4 percent below budget. KMI does not provide budgeted net
income attributable to common stockholders (the GAAP financial measure
most directly comparable to distributable cash flow and Adjusted EBITDA)
due to the inherent difficulty and impracticality of quantifying certain
amounts required by GAAP such as ineffectiveness on commodity, interest
rate and foreign currency hedges, unrealized gains and losses on
derivatives marked to market, and potential changes in estimates for
certain contingent liabilities.
KMI expects to generate excess cash sufficient to fund its growth
capital requirements without needing to access capital markets and
expects to end the year with a net debt-to-Adjusted EBITDA ratio of
approximately 5.3 times, consistent with where KMI ended the third
quarter and below the budgeted year-end ratio of 5.5 times. KMI’s growth
capital forecast for 2016 is approximately $2.7 billion.
The overwhelming majority of cash generated by KMI is fee-based and
therefore is not directly exposed to commodity prices. The primary area
where KMI has direct commodity price sensitivity is in its CO2 segment,
and KMI hedges the majority of its next 12 months of oil production to
minimize this sensitivity. Additionally, KMI continues to closely
monitor counterparty exposure and obtain collateral when appropriate.
Moreover, the company has operations across a broad range of businesses
and a diverse customer base, with its average customer representing less
than one-tenth of 1 percent of annual revenues. Additionally,
approximately two-thirds of KMI’s business is conducted with customers
who are end-users of the products KMI transports and stores, such as
utilities, local distribution companies, refineries and large integrated
firms.
Overview of Business Segments
“The Natural Gas Pipelines segment’s performance for the third
quarter of 2016 was impacted by the sale of a 50 percent interest in
SNG. Excluding this sale, the Natural Gas Pipeline segment’s performance
was in-line with the same period during 2015. The segment benefited from
an increased contribution from Tennessee Gas Pipeline (TGP), driven by
expansion projects placed into service during 2015, and increased
contributions from both the Hiland midstream assets and the Texas
Intrastate Natural Gas Pipelines. These contributions were offset by
declines attributable to reduced volumes affecting certain of our
midstream gathering and processing assets, unfavorable contract renewals
on Colorado Interstate Gas pipeline, and a customer contract buyout at
Kinder Morgan Louisiana pipeline during 2015,” Kean said.
Natural gas transport volumes were down 1 percent compared to the third
quarter last year, driven by lower throughput on the Texas Intrastate
Natural Gas Pipelines due to lower Eagle Ford Shale volumes, lower
throughput on Ruby Pipeline due to increased Canadian imports to the
Pacific Northwest, and lower throughput on Fayetteville Express Pipeline
due to lower production from the Fayetteville Shale. These declines were
partially offset by higher throughput on TGP due to projects placed in
service, higher throughput on NGPL due to deliveries to Sabine Pass LNG
facility and to South Texas to meet demand from Mexico, and higher
throughput on Citrus pipeline due to strong weather-driven demand in
Florida. Natural gas gathered volumes were down 17 percent from the
third quarter last year due primarily to lower natural gas volumes on
multiple systems gathering from the Eagle Ford Shale and lower volumes
on the KinderHawk system compared to the third quarter of 2015.
Natural gas continues to be the fuel of choice for America’s evolving
energy needs, and industry experts are projecting natural gas demand
increases of approximately 35 percent to over 105 billion cubic feet per
day (Bcf/d) over the next 10 years. Over the last 2.8 years, KMI has
entered into new and pending firm transport capacity commitments
totaling 8.2 Bcf/d (1.9 Bcf/d of which is existing, previously unsold
capacity). Of the natural gas consumed in the United States, about 38
percent moves on KMI pipelines. KMI expects future natural gas
infrastructure opportunities will be driven by greater demand for
gas-fired power generation across the country, liquefied natural gas
(LNG) exports, exports to Mexico and continued industrial development,
particularly in the petrochemical industry. In fact, natural gas
deliveries on KMI pipelines to gas-fired power plants, to Mexico and to
LNG facilities were up 9 percent, 6 percent, and approximately 346,000
dekatherms per day (Dth/d), respectively, compared to the third quarter
of 2015.
“The CO
2
segment was impacted by lower
commodity prices, as our realized weighted average oil price for the
quarter was $62.12 per barrel compared to $74.18 per barrel for the
third quarter of 2015,” Kean said. “Combined oil production across all
of our fields was down 5 percent compared to 2015 on a net to Kinder
Morgan basis, primarily driven by lower SACROC production. Third quarter
2016 net NGL sales volumes of 10.6 thousand barrels per day (MBbl/d) was
consistent with volumes in the same period in 2015. Net CO2 volumes
increased 3 percent versus the third quarter of 2015. We continued to
offset some of the impact of lower commodity prices by generating cost
savings across our CO2 business.”
Combined gross oil production volumes averaged 53.7 MBbl/d for the third
quarter, down 6 percent from 57.3 MBbl/d for the same period in 2015.
SACROC’s third quarter gross production was 11 percent below third
quarter 2015 results, and Yates gross production was 6 percent below
third quarter 2015 results. Both decreases were partially driven by
project deferrals during 2016. Third quarter gross production from Katz,
Goldsmith and Tall Cotton was 16 percent above the same period in 2015,
but below plan. KMI had record high gross NGL production of 21.7 MBbl/d
for the quarter and is on track for record annual NGL production. The
average West Texas Intermediate unhedged crude oil price for the third
quarter was $44.94 per barrel versus $46.43 for the third quarter of
2015.
“The Terminals segment experienced strong performance at our
liquids terminals, which comprise more than 75 percent of the segment’s
business. Growth in the liquids business during the quarter versus the
third quarter of 2015 was driven by increased contributions from our
Jones Act tankers, our refined products terminals joint venture with BP
and various expansions across our network,” Kean said. The Lone Star
State, Magnolia State, Garden State and Bay State tankers
were delivered in December 2015, May 2016, July 2016 and September 2016,
respectively. These tankers are each contracted with major energy
customers under long-term, firm time charters.
Growth from the liquids terminals was partially offset by a decline in
the bulk terminals as compared to the same period in 2015, largely
driven by the bankruptcies of Arch Coal and Peabody Energy.
“The Products Pipelines segment was favorably impacted by the
startup of the second petroleum condensate processing facility along the
Houston Ship Channel during 2015, and favorable performance in our
Transmix business compared to 2015 due to unfavorable market price
impacts during the third quarter of 2015,” Kean said.
Total refined products volumes were up 3 percent for the third quarter
versus the same period in 2015. NGL volumes were down 1 percent from the
same period last year. Crude and condensate pipeline volumes were up 6
percent from the third quarter of 2015 primarily due to higher volumes
on Double H and KMCC.
Kinder Morgan Canada contributions were up slightly in the third
quarter of 2016 compared to the third quarter of 2015.
Other News
Natural Gas Pipelines
-
On Sept. 1, 2016, KMI and Southern Company closed on the previously
announced joint venture transaction involving Southern Company’s
acquisition of a 50 percent equity interest in SNG. As previously
announced, Kinder Morgan will continue to operate the system, and the
companies are pursuing specific growth opportunities to develop
additional natural gas infrastructure for the strategic venture.
Including SNG’s existing debt and cash consideration for Southern
Company’s 50 percent share of the equity interest, the transaction
implies a total enterprise value for SNG of approximately $4.15
billion.
-
On June 1, 2016, Elba Liquefaction Company and Southern LNG Company
received FERC authorization for the Elba Liquefaction Project. As
expected, requests for rehearing were filed by the Sierra Club and
associated individuals and are currently pending before the FERC.
Construction will begin on Nov. 1, 2016. The approximately $2 billion
project will be constructed and operated at the existing Elba Island
LNG Terminal near Savannah, Georgia. Initial liquefaction units are
expected to be placed in service in mid-2018, with final units coming
on line by early 2019. The project is supported by a 20-year contract
with Shell. In 2012, the Elba Liquefaction Project received
authorization from the Department of Energy to export to Free Trade
Agreement (FTA) countries. An application to export to non-FTA
countries is pending, but is not required for the project to move
ahead. The project is expected to have a total capacity of
approximately 2.5 million tonnes per year of LNG for export,
equivalent to approximately 350 million cubic feet per day of natural
gas.
-
Construction continues for Elba Express Company (EEC) and SNG
facilities that will provide additional gas supplies for industrial
customers and utilities in Georgia and Florida, and serve the Elba
Island liquefaction facility. On June 1, 2016, FERC also issued
certificates for both the EEC Modification Project and the SNG Zone 3
Expansion Project. These projects, which are supported by long-term
customer contracts, total $302 million. The FERC approved the start of
construction in late June, and the EEC and SNG facilities are expected
to be placed in service beginning late in the fourth quarter of 2016.
-
On Sept. 6, 2016, the FERC issued separate certificate orders
approving TGP’s Broad Run Expansion and Susquehanna West Projects:
-
Pending receipt of all required permits, TGP plans to begin
construction of the Broad Run Expansion Project in December 2016 and
place the project facilities in service on or before June 1, 2018. The
project will provide an incremental 200,000 Dth/d of firm
transportation capacity along the same capacity path (West Virginia to
delivery points in Mississippi and Louisiana) as the Broad Run
Flexibility Project, which was placed in service on Nov. 1, 2015 and
provided an incremental 590,000 Dth/d of capacity. In 2014, Antero
Resources Corporation was awarded a total of 790,000 Dth/d of 15-year
firm capacity under the two projects. Estimated capital expenditures
for the combined projects are approximately $800 million.
-
Pending receipt of all required permits, TGP plans to begin
construction of the $156 million Susquehanna West Project in early
2017, and place the project facilities in service on or before Nov. 1,
2017. The project will provide 145,000 Dth/d of additional capacity to
an interconnection with National Fuel Supply in Potter County,
Pennsylvania, and is fully subscribed by StatOil Natural Gas LLC.
-
TGP continues to seek the remaining permits required for the start of
construction of its FERC-approved $93 million Connecticut Expansion
project, which will upgrade portions of TGP’s existing system in New
York, Massachusetts and Connecticut, and provide approximately 72,100
Dth/d of additional firm transportation capacity for three local
distribution company customers. Due to state and federal permit
delays, the project’s original in-service date of Nov. 1, 2016, has
been changed to Nov. 1, 2017.
-
TGP completed construction on the last phase of its $230 million,
500,000 Dth/d South System Flexibility Project on schedule and placed
the final capacity increment in service on Oct. 1, 2016. The project,
which is supported by long-term contracts, provides incremental supply
access from TGP’s Station 87 Pool in Tennessee to delivery points in
South Texas.
-
On Sept. 29, 2016, the FERC issued an Environmental Assessment for
TGP’s proposed $178 million, 900,000 Dth/d Southwest Louisiana Supply
Project, which is designed to serve the Cameron LNG export complex.
The project, which is supported by long-term contracts, is expected to
be placed in service by Feb. 1, 2018.
-
On Aug. 1, 2016, NGPL filed an application with the FERC for
facilities associated with its approximately $212 million Gulf Coast
Southbound Expansion Project. The project, which is fully subscribed
under long-term customer contracts, is designed to transport 460,000
Dth/d of incremental firm transportation service from NGPL’s
interstate pipeline interconnects in Illinois, Arkansas and Texas to
points south on NGPL’s pipeline system to serve growing demand in the
Gulf Coast area. Pending regulatory approvals, the project is expected
to be fully in service by the fourth quarter of 2018.
-
Construction is nearing completion on NGPL’s Chicago Market Expansion
project. This approximately $74 million project will increase NGPL’s
capacity by 238,000 Dth/d and provide transportation service on its
Gulf Coast mainline system from the Rockies Express Pipeline
interconnection in Moultrie County, Illinois, to points north on
NGPL’s system. NGPL has executed binding agreements with four
customers for incremental firm transportation service to markets near
Chicago and the project is expected to be placed in service on Nov. 1,
2016.
-
Phase 1 of the Texas Intrastate Natural Gas system’s Crossover project
was placed in service on Sept. 1, 2016, as planned. Phase 1 provides
transportation capacity to serve customers in Texas and Mexico and is
supported by commitments of over 800,000 Dth/d, including contracts
with Cheniere Energy, Inc. at its Corpus Christi LNG facility (once
the facility is placed in service) and with Comisión Federal de
Electricidad (CFE). Work continues on Phase 2 of the project, which is
supported by a long-term commitment from SK E&S LNG, LLC for service
to the Freeport LNG export facility. Phase 2 is expected to go into
service in late 2018 and will bring the total project capacity to over
1,100,000 Dth/d. The total cost for both phases is approximately $326
million.
CO
2
-
Construction is nearing completion on the northern portion of the
Cortez Pipeline expansion project. The approximately $226 million
project will increase CO2 transportation capacity on the
Cortez Pipeline from 1.35 Bcf/d to 1.5 Bcf/d. The pipeline transports
CO2 from southwestern Colorado to eastern New Mexico and
West Texas for use in enhanced oil recovery projects. The third of
five facilities was placed into service in the third quarter of 2016,
with the final two facilities expected to be in service by the end of
the year.
-
We continue to find high-return enhanced oil recovery projects in the
current price environment across the portfolio and have benefited from
cost savings in our operations and in our expansion capital program.
Terminals
-
Construction is nearly complete on the second of two new deep-water
liquids berths being developed along the Houston Ship Channel, with
in-service expected in the fourth quarter of this year. The first dock
was placed in service at the end of March 2016. The docks, which are
pipeline-connected to Kinder Morgan’s Pasadena and Galena Park
terminals via three cross-channel lines, are capable of loading
ocean-going vessels at rates up to 15,000 barrels per hour. The
approximately $72 million project is a response to customers’ growing
demand for waterborne outlets for refined products along the ship
channel, and is supported by firm vessel commitments from existing
customers at the Galena Park and Pasadena terminals.
-
Construction continues at the Base Line Terminal, a new crude oil
storage facility being developed in Edmonton, Alberta. In March 2015,
Kinder Morgan and Keyera Corp. announced the new 50-50 joint venture
terminal and entered into long-term, firm take-or-pay agreements with
strong, creditworthy customers to build 12 tanks with total crude oil
storage capacity of 4.8 million barrels. KMI’s investment in the joint
venture terminal is approximately CAD$372 million. Commissioning is
expected to begin in the first quarter of 2018.
-
Work continues on the Kinder Morgan Export Terminal (KMET) along the
Houston Ship Channel. The approximately $245 million project includes
12 storage tanks with 1.5 million barrels of storage capacity, one
ship dock, one barge dock and cross-channel pipelines to connect with
Kinder Morgan’s Galena Park terminal. KMET is anticipated to be in
service in the first quarter of 2017.
-
In July and September 2016, Kinder Morgan’s American Petroleum Tankers
(APT) took delivery of the Garden State and Bay State,
respectively, the third and fourth of five 50,000-deadweight-ton
product tankers from General Dynamics’ NASSCO Shipyard in San Diego,
California. Each of the ECO class vessels, with cargo capacities of
330,000-barrels and LNG conversion ready engine capabilities, is fixed
under long-term, firm time charters with major energy companies. The
construction programs at NASSCO and Philly Shipyard, Inc. remain
on-budget and substantially on-time. Five additional vessels are
scheduled to be delivered through the end of 2017, bringing APT’s
best-in-class fleet to 16 vessels.
-
In August 2016, Kinder Morgan placed in service three 100,000 barrel
tanks at its Carteret, New Jersey terminal. The tanks, which are
outfitted with internal floating roofs and pipeline, dock and truck
rack connectivity as well as in-tank butane blending capabilities, are
leased pursuant to a long-term, firm take-or-pay storage agreement.
The $32 million project adds to Kinder Morgan’s strong position in the
strategic New York Harbor petroleum product hub.
Products Pipelines
-
Work continues on the Utopia Pipeline Project, with landowner
discussions and permitting activities underway. The approximately $500
million new pipeline will have an initial design capacity of 50,000
barrels per day (bpd), and will move ethane and ethane-propane
mixtures across Ohio to Windsor, Ontario, Canada. The project is fully
supported by a long-term, fee-based transportation agreement with a
petrochemical customer. The project has a planned in-service date of
January 2018, subject to permitting and land acquisition.
Kinder Morgan Canada
-
On May 19, 2016, the National Energy Board (NEB) issued a report
recommending that the federal government approve the Trans Mountain
Expansion Project, subject to 157 conditions. The deadline for the
Federal Government Order in Council decision is Dec. 20, 2016. As
previously announced, the government conducted further consultation
with First Nations related to the 157 conditions and the project
impact. In addition, the federal government implemented a Ministerial
Panel to hear from the general public with respect to identifying
views not heard by the initial NEB review. The Ministerial Panel held
public and by invitation-only sessions in 19 communities in Alberta
and British Columbia and launched an online questionnaire for
Canadians to submit feedback on the project. The panel is required to
produce a report for the Minister of Natural Resources by Nov. 1,
2016. If approved, the project is expected to be in service by the end
of 2019. The in-service date for the expansion will depend on the
final conditions contained in the Order in Council from the federal
government. The proposed USD$5.4 billion expansion will increase
capacity on Trans Mountain from approximately 300,000 to 890,000 bpd.
Thirteen companies have signed firm long-term contracts supporting the
project for approximately 708,000 bpd. Kinder Morgan Canada is
currently in negotiations with construction contractors and continues
to engage extensively with landowners, Aboriginal groups, communities
and stakeholders along the proposed expansion route and adjacent
marine areas.
Financings
-
On Aug. 16, 2016, CIG issued $375 million of 10-year senior notes at a
fixed rate of 4.15 percent.
-
On Sept. 1, 2016, KMI sold a 50 percent equity interest in SNG. As a
result, KMI will no longer consolidate SNG, including its $1,211
million of public debt outstanding as of Sept. 30, 2016. SNG’s debt
will continue to be guaranteed by KMI until Dec. 2, 2016, when SNG’s
investment grade rating requirement imposed by the cross guarantee is
expected to be met.
-
On Sept. 30, 2016, KMI repaid the $332 million principal amount of
Copano Energy, LLC’s 7.125 percent senior notes due 2021, plus accrued
interest and a fixed price premium.
-
On Oct. 1, 2016, KMI repaid the $749 million principal amount of
Hiland Partners, LP’s 7.25 percent senior notes due 2020. As of Sept.
30, 2016, funds for this extinguishment, plus $54 million for accrued
interest and a fixed price premium, were held in escrow as a
restricted deposit.
Kinder Morgan, Inc. (NYSE: KMI) is the largest energy infrastructure
company in America. It owns an interest in or operates approximately
84,000 miles of pipelines and approximately 180 terminals. KMI’s
pipelines transport natural gas, gasoline, crude oil, CO2 and
other products, and its terminals store petroleum products and
chemicals, and handle bulk materials like coal and petroleum coke. For
more information please visit www.kindermorgan.com.
Please join Kinder Morgan at 4:30 p.m. Eastern Time on Wednesday,
Oct. 19, at
www.kindermorgan.com
for a LIVE webcast conference call on the company’s third quarter
earnings.
Non-GAAP Financial Measures
The non-generally accepted accounting principles (non-GAAP) financial
measures of distributable cash flow (DCF), both in the aggregate and per
share, segment earnings before depreciation, depletion, amortization and
amortization of excess cost of equity investments (DD&A) and certain
items (Segment EBDA before certain items), and net income before
interest expense, taxes, DD&A and certain items (Adjusted EBITDA) are
presented herein.
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, asset impairments), 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 certain legal settlements, hurricane impacts and casualty
losses).
DCF
is a significant performance
measure used by us and by external users of our financial statements to
evaluate our performance and to measure and estimate the ability of our
assets to generate cash earnings after servicing our debt and preferred
stock dividends, paying cash taxes and expending sustaining capital,
that could be used for discretionary purposes such as common stock
dividends, stock repurchases, retirement of debt, or expansion capital
expenditures. Management uses this measure and believes it
provides users of our financial statements a useful measure reflective
of our business’s ability to generate cash earnings to supplement the
comparable GAAP measure. We believe the GAAP measure most
directly comparable to DCF is net income available to common
stockholders. A reconciliation of DCF to net income available to
common stockholders is provided herein. DCF per share is DCF
divided by average outstanding shares, including restricted stock awards
that participate in dividends.
Segment EBDA before certain items
is used by management in its analysis of segment performance and
management of our business. General and administrative expenses
are generally not under the control of our segment operating managers,
and therefore, are not included when we measure business segment
operating performance. We believe Segment EBDA before certain
items is a significant performance metric because it provides us and
external users of our financial statements additional insight into the
ability of our segments to generate segment cash earnings on an ongoing
basis. We believe it is useful to investors because it is a
measure that management uses to allocate resources to our segments and
assess each segment’s performance. We believe the GAAP measure
most directly comparable to Segment EBDA before certain items is segment
earnings before DD&A and amortization of excess cost of equity
investments (Segment EBDA). Segment EBDA before certain items is
calculated by adjusting Segment EBDA for the certain items attributable
to a segment, which are specifically identified in the footnotes to the
accompanying tables.
Adjusted EBITDA
is used by
management and external users, in conjunction with our net debt, to
evaluate certain leverage metrics. Therefore, we believe Adjusted
EBITDA is useful to investors. We believe the GAAP measure most
directly comparable to Adjusted EBITDA is net income. Adjusted
EBITDA is calculated by adjusting net income before interest expense,
taxes, and DD&A (EBITDA) for certain items, noncontrolling interests
before certain items, and KMI’s share of certain equity investees’ DD&A
and book taxes, which are specifically identified in the footnotes to
the accompanying tables.
Our non-GAAP measures described above should not be considered
alternatives to GAAP net income or other GAAP measures and have
important limitations as analytical tools. Our computations of
DCF, Segment EBDA before certain items and Adjusted EBITDA may differ
from similarly titled measures used by others. You should not
consider these non-GAAP measures in isolation or as substitutes for an
analysis of our results as reported under GAAP. DCF should not be
used as an alternative to net cash provided by operating activities
computed under GAAP. 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.
Important Information Relating to
Forward-Looking Statements
This news release includes forward-looking statements within the
meaning of the U.S. Private Securities Litigation Reform Act of 1995 and
Section 21E of the Securities and Exchange Act of 1934. Generally the
words “expects,” “believes,” anticipates,” “plans,” “will,” “shall,”
“estimates,” and similar expressions identify forward-looking
statements, which are generally not historical in nature. Forward-looking
statements are subject to risks and uncertainties and are based on the
beliefs and assumptions of management, based on information currently
available to them. Although Kinder Morgan believes that these
forward-looking statements are based on reasonable assumptions, it can
give no assurance that any such forward-looking statements will
materialize. Important factors that could cause actual results to
differ materially from those expressed in or implied from these
forward-looking statements include the risks and uncertainties described
in Kinder Morgan’s reports filed with the Securities and Exchange
Commission (SEC), including its Annual Report on Form 10-K for the
year-ended December 31, 2015 (under the headings “Risk Factors” and
“Information Regarding Forward-Looking Statements” and elsewhere) and
its subsequent reports, which are available through the SEC’s EDGAR
system at
www.sec.gov
and on our website at ir.kindermorgan.com. Forward-looking
statements speak only as of the date they were made, and except to the
extent required by law, Kinder Morgan undertakes no obligation to update
any forward-looking statement because of new information, future events
or other factors. Because of these risks and uncertainties,
readers should not place undue reliance on these forward-looking
statements.
|
Kinder Morgan, Inc. and Subsidiaries
Preliminary Consolidated Statements of Income
(Unaudited)
(In millions, except per share amounts)
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
$
|
3,330
|
|
|
|
$
|
3,707
|
|
|
|
|
|
|
$
|
9,669
|
|
|
|
$
|
10,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs, expenses and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs of sales
|
|
|
|
|
971
|
|
|
|
1,106
|
|
|
|
|
|
|
2,454
|
|
|
|
3,281
|
|
|
|
|
Operations and maintenance
|
|
|
|
|
576
|
|
|
|
612
|
|
|
|
|
|
|
1,744
|
|
|
|
1,707
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
549
|
|
|
|
617
|
|
|
|
|
|
|
1,652
|
|
|
|
1,725
|
|
|
|
|
General and administrative
|
|
|
|
|
171
|
|
|
|
160
|
|
|
|
|
|
|
550
|
|
|
|
540
|
|
|
|
|
Taxes, other than income taxes
|
|
|
|
|
106
|
|
|
|
108
|
|
|
|
|
|
|
324
|
|
|
|
339
|
|
|
|
|
Loss on impairments and divestitures, net
|
|
|
|
|
76
|
|
|
|
385
|
|
|
|
|
|
|
307
|
|
|
|
489
|
|
|
|
|
Other income, net
|
|
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
—
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
2,448
|
|
|
|
2,986
|
|
|
|
|
|
|
7,031
|
|
|
|
8,076
|
|
|
|
|
Operating income
|
|
|
|
|
882
|
|
|
|
721
|
|
|
|
|
|
|
2,638
|
|
|
|
2,691
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from equity investments
|
|
|
|
|
137
|
|
|
|
114
|
|
|
|
|
|
|
343
|
|
|
|
330
|
|
|
|
|
Loss on impairments and divestitures of equity investments, net
|
|
|
|
|
(350
|
)
|
|
|
—
|
|
|
|
|
|
|
(344
|
)
|
|
|
(26
|
)
|
|
|
|
Amortization of excess cost of equity investments
|
|
|
|
|
(15
|
)
|
|
|
(13
|
)
|
|
|
|
|
|
(45
|
)
|
|
|
(39
|
)
|
|
|
|
Interest, net
|
|
|
|
|
(472
|
)
|
|
|
(540
|
)
|
|
|
|
|
|
(1,384
|
)
|
|
|
(1,524
|
)
|
|
|
|
Other, net
|
|
|
|
|
12
|
|
|
|
9
|
|
|
|
|
|
|
42
|
|
|
|
33
|
|
|
|
|
Income before income taxes
|
|
|
|
|
194
|
|
|
|
291
|
|
|
|
|
|
|
1,250
|
|
|
|
1,465
|
|
|
|
|
Income tax expense
|
|
|
|
|
(377
|
)
|
|
|
(108
|
)
|
|
|
|
|
|
(744
|
)
|
|
|
(521
|
)
|
|
|
|
Net (loss) income
|
|
|
|
|
(183
|
)
|
|
|
183
|
|
|
|
|
|
|
506
|
|
|
|
944
|
|
|
|
|
Net (income) loss attributable to noncontrolling interests
|
|
|
|
|
(5
|
)
|
|
|
3
|
|
|
|
|
|
|
(7
|
)
|
|
|
4
|
|
|
|
|
Net (loss) income attributable to Kinder Morgan, Inc.
|
|
|
|
|
(188
|
)
|
|
|
186
|
|
|
|
|
|
|
499
|
|
|
|
948
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
(39
|
)
|
|
|
—
|
|
|
|
|
|
|
(117
|
)
|
|
|
—
|
|
|
|
|
Net (loss) income available to common stockholders
|
|
|
|
|
$
|
(227
|
)
|
|
|
$
|
186
|
|
|
|
|
|
|
$
|
382
|
|
|
|
$
|
948
|
|
|
|
|
Class P Shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted (loss) earnings per common share
|
|
|
|
|
$
|
(0.10
|
)
|
|
|
$
|
0.08
|
|
|
|
|
|
|
$
|
0.17
|
|
|
|
$
|
0.43
|
|
|
|
|
Basic weighted average common shares outstanding (1)
|
|
|
|
|
2,230
|
|
|
|
2,203
|
|
|
|
|
|
|
2,229
|
|
|
|
2,173
|
|
|
|
|
Diluted weighted average common shares outstanding (1)
|
|
|
|
|
2,230
|
|
|
|
2,203
|
|
|
|
|
|
|
2,229
|
|
|
|
2,181
|
|
|
|
|
Declared dividend per common share
|
|
|
|
|
$
|
0.125
|
|
|
|
$
|
0.510
|
|
|
|
|
|
|
$
|
0.375
|
|
|
|
$
|
1.480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment EBDA
|
|
|
|
|
|
|
|
|
|
|
%
change
|
|
|
|
|
|
|
|
|
%
change
|
Natural Gas Pipelines
|
|
|
|
|
$
|
540
|
|
|
|
$
|
993
|
|
|
|
(46
|
)%
|
|
|
$
|
2,498
|
|
|
|
$
|
2,936
|
|
|
|
(15
|
)%
|
CO2
|
|
|
|
|
217
|
|
|
|
29
|
|
|
|
648
|
%
|
|
|
606
|
|
|
|
605
|
|
|
|
—
|
%
|
Terminals
|
|
|
|
|
286
|
|
|
|
249
|
|
|
|
15
|
%
|
|
|
831
|
|
|
|
798
|
|
|
|
4
|
%
|
Products Pipelines
|
|
|
|
|
293
|
|
|
|
288
|
|
|
|
2
|
%
|
|
|
765
|
|
|
|
811
|
|
|
|
(6
|
)%
|
Kinder Morgan Canada
|
|
|
|
|
43
|
|
|
|
42
|
|
|
|
2
|
%
|
|
|
123
|
|
|
|
120
|
|
|
|
3
|
%
|
Other
|
|
|
|
|
2
|
|
|
|
(9
|
)
|
|
|
122
|
%
|
|
|
(11
|
)
|
|
|
(55
|
)
|
|
|
80
|
%
|
Total Segment EBDA
|
|
|
|
|
$
|
1,381
|
|
|
|
$
|
1,592
|
|
|
|
(13
|
)%
|
|
|
$
|
4,812
|
|
|
|
$
|
5,215
|
|
|
|
(8
|
)%
|
|
Note
|
(1)
|
|
For all periods presented, all potential common share equivalents
were antidilutive, except for the nine months ended September 30,
2015 during which the KMI warrants were dilutive.
|
|
|
Kinder Morgan, Inc. and Subsidiaries
Preliminary Earnings Contribution by Business Segment
(Unaudited)
(In millions, except per share amounts)
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
%
change
|
|
|
2016
|
|
|
2015
|
|
|
%
change
|
Segment EBDA before certain items (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Pipelines
|
|
|
|
|
$
|
957
|
|
|
|
$
|
975
|
|
|
|
(2
|
)%
|
|
|
$
|
3,045
|
|
|
|
$
|
3,027
|
|
|
|
1
|
%
|
CO2
|
|
|
|
|
229
|
|
|
|
282
|
|
|
|
(19
|
)%
|
|
|
679
|
|
|
|
849
|
|
|
|
(20
|
)%
|
Terminals
|
|
|
|
|
285
|
|
|
|
263
|
|
|
|
8
|
%
|
|
|
837
|
|
|
|
798
|
|
|
|
5
|
%
|
Product Pipelines
|
|
|
|
|
294
|
|
|
|
287
|
|
|
|
2
|
%
|
|
|
877
|
|
|
|
807
|
|
|
|
9
|
%
|
Kinder Morgan Canada
|
|
|
|
|
43
|
|
|
|
42
|
|
|
|
2
|
%
|
|
|
123
|
|
|
|
120
|
|
|
|
3
|
%
|
Other
|
|
|
|
|
(2
|
)
|
|
|
(10
|
)
|
|
|
80
|
%
|
|
|
(19
|
)
|
|
|
(23
|
)
|
|
|
17
|
%
|
Subtotal
|
|
|
|
|
1,806
|
|
|
|
1,839
|
|
|
|
(2
|
)%
|
|
|
5,542
|
|
|
|
5,578
|
|
|
|
(1
|
)%
|
DD&A and amortization of excess investments
|
|
|
|
|
(564
|
)
|
|
|
(630
|
)
|
|
|
|
|
|
(1,697
|
)
|
|
|
(1,764
|
)
|
|
|
|
General and administrative (1) (2)
|
|
|
|
|
(159
|
)
|
|
|
(152
|
)
|
|
|
|
|
|
(493
|
)
|
|
|
(485
|
)
|
|
|
|
Interest, net (1) (3)
|
|
|
|
|
(505
|
)
|
|
|
(524
|
)
|
|
|
|
|
|
(1,526
|
)
|
|
|
(1,565
|
)
|
|
|
|
Subtotal
|
|
|
|
|
578
|
|
|
|
533
|
|
|
|
|
|
|
1,826
|
|
|
|
1,764
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate book taxes (4)
|
|
|
|
|
(191
|
)
|
|
|
(185
|
)
|
|
|
|
|
|
(626
|
)
|
|
|
(606
|
)
|
|
|
|
Certain items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition related costs (5)
|
|
|
|
|
(4
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
(12
|
)
|
|
|
(14
|
)
|
|
|
|
Pension plan net benefit
|
|
|
|
|
—
|
|
|
|
5
|
|
|
|
|
|
|
—
|
|
|
|
28
|
|
|
|
|
Fair value amortization
|
|
|
|
|
53
|
|
|
|
24
|
|
|
|
|
|
|
106
|
|
|
|
72
|
|
|
|
|
Contract early termination revenue
|
|
|
|
|
18
|
|
|
|
—
|
|
|
|
|
|
|
57
|
|
|
|
—
|
|
|
|
|
Legal and environmental reserves (6)
|
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
(55
|
)
|
|
|
(78
|
)
|
|
|
|
Mark to market and ineffectiveness (7)
|
|
|
|
|
(30
|
)
|
|
|
118
|
|
|
|
|
|
|
(23
|
)
|
|
|
162
|
|
|
|
|
Losses on impairments and divestitures, net (8)
|
|
|
|
|
(426
|
)
|
|
|
(387
|
)
|
|
|
|
|
|
(505
|
)
|
|
|
(516
|
)
|
|
|
|
Project write-offs
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
(170
|
)
|
|
|
—
|
|
|
|
|
Other
|
|
|
|
|
(10
|
)
|
|
|
(17
|
)
|
|
|
|
|
|
(22
|
)
|
|
|
(4
|
)
|
|
|
|
Subtotal certain items before tax
|
|
|
|
|
(398
|
)
|
|
|
(260
|
)
|
|
|
|
|
|
(624
|
)
|
|
|
(350
|
)
|
|
|
|
Book tax certain items (9)
|
|
|
|
|
(172
|
)
|
|
|
95
|
|
|
|
|
|
|
(70
|
)
|
|
|
136
|
|
|
|
|
Total certain items
|
|
|
|
|
(570
|
)
|
|
|
(165
|
)
|
|
|
|
|
|
(694
|
)
|
|
|
(214
|
)
|
|
|
|
Net (loss) income
|
|
|
|
|
(183
|
)
|
|
|
183
|
|
|
|
|
|
|
506
|
|
|
|
944
|
|
|
|
|
Net (income) loss attributable to noncontrolling interests
|
|
|
|
|
(5
|
)
|
|
|
3
|
|
|
|
|
|
|
(7
|
)
|
|
|
4
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
(39
|
)
|
|
|
—
|
|
|
|
|
|
|
(117
|
)
|
|
|
—
|
|
|
|
|
Net (loss) income available to common stockholders
|
|
|
|
|
$
|
(227
|
)
|
|
|
$
|
186
|
|
|
|
|
|
|
$
|
382
|
|
|
|
$
|
948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income available to common stockholders
|
|
|
|
|
$
|
(227
|
)
|
|
|
$
|
186
|
|
|
|
|
|
|
$
|
382
|
|
|
|
$
|
948
|
|
|
|
|
Total certain items
|
|
|
|
|
570
|
|
|
|
165
|
|
|
|
|
|
|
694
|
|
|
|
214
|
|
|
|
|
Noncontrolling interests certain item (10)
|
|
|
|
|
—
|
|
|
|
(6
|
)
|
|
|
|
|
|
(9
|
)
|
|
|
(20
|
)
|
|
|
|
Net income available to common stockholders before certain items
|
|
|
|
|
343
|
|
|
|
345
|
|
|
|
|
|
|
1,067
|
|
|
|
1,142
|
|
|
|
|
DD&A and amortization of excess investments (11)
|
|
|
|
|
653
|
|
|
|
708
|
|
|
|
|
|
|
1,961
|
|
|
|
2,004
|
|
|
|
|
Total book taxes (12)
|
|
|
|
|
230
|
|
|
|
224
|
|
|
|
|
|
|
745
|
|
|
|
713
|
|
|
|
|
Cash taxes (13)
|
|
|
|
|
(22
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
(61
|
)
|
|
|
(19
|
)
|
|
|
|
Other items (14)
|
|
|
|
|
11
|
|
|
|
7
|
|
|
|
|
|
|
31
|
|
|
|
23
|
|
|
|
|
Sustaining capital expenditures (15)
|
|
|
|
|
(134
|
)
|
|
|
(152
|
)
|
|
|
|
|
|
(379
|
)
|
|
|
(397
|
)
|
|
|
|
DCF
|
|
|
|
|
$
|
1,081
|
|
|
|
$
|
1,129
|
|
|
|
|
|
|
$
|
3,364
|
|
|
|
$
|
3,466
|
|
|
|
|
Weighted average common shares outstanding for dividends (16)
|
|
|
|
|
2,239
|
|
|
|
2,210
|
|
|
|
|
|
|
2,237
|
|
|
|
2,189
|
|
|
|
|
DCF per common share
|
|
|
|
|
$
|
0.48
|
|
|
|
$
|
0.51
|
|
|
|
|
|
|
$
|
1.50
|
|
|
|
$
|
1.58
|
|
|
|
|
Declared dividend per common share
|
|
|
|
|
$
|
0.125
|
|
|
|
$
|
0.510
|
|
|
|
|
|
|
$
|
0.375
|
|
|
|
$
|
1.480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (17)
|
|
|
|
|
$
|
1,770
|
|
|
|
$
|
1,803
|
|
|
|
|
|
|
$
|
5,414
|
|
|
|
$
|
5,425
|
|
|
|
|
|
Notes ($ million)
|
(1)
|
|
Excludes certain items: 3Q 2016 - Natural Gas Pipelines $(417),
CO2 $(12), Terminals $1, Products Pipelines $(1), Other $4, general
and administrative $(4), interest expense $31. 3Q 2015 -
Natural Gas Pipelines $18, CO2 $(253), Terminals $(14), Products
Pipelines $1, Other $1, general and administrative $2, interest
expense $(15). YTD 2016 - Natural Gas Pipelines $(547), CO2
$(73), Terminals $(6), Products Pipelines $(112), Other $8, general
and administrative $(32), interest expense $140. YTD 2015 -
Natural Gas Pipelines $(91), CO2 $(244), Products Pipelines $4,
Other $(32), general and administrative $(27), interest expense $40.
|
(2)
|
|
General and administrative expense is net of management fee revenues
from an equity investee: 3Q 2016 - $(8) 3Q 2015 - $(10) YTD
2016 - $(25) YTD 2015 - $(28)
|
(3)
|
|
Interest expense excludes interest income that is allocable to the
segments: 3Q 2016 - Other $2. 3Q 2015 - Products Pipelines
$1, Other $(2). YTD 2016 - Products Pipelines $1, Other $1. YTD
2015 - Products Pipelines $2, Other $(1).
|
(4)
|
|
Corporate book taxes exclude book tax certain items not allocated to
the segments of $(172) in 3Q 2016, $95 in 3Q 2015, $(72) YTD 2016,
and $136 YTD 2015. Also excludes income tax that is allocated to the
segments: 3Q 2016 - Natural Gas Pipelines $(2), Terminals $(8),
Products Pipelines $1, Kinder Morgan Canada $(5). 3Q 2015 -
Natural Gas Pipelines $(1), CO2 $(1), Terminals $(8), Products
Pipelines $(3), Kinder Morgan Canada $(5). YTD 2016 - Natural
Gas Pipelines $(5), CO2 $(2), Terminals $(25), Products Pipelines
$3, Kinder Morgan Canada $(17). YTD 2015 - Natural Gas
Pipelines $(5), CO2 $(3), Terminals $(21), Products Pipelines $(7),
Kinder Morgan Canada $(15).
|
(5)
|
|
Acquisition related costs for closed or pending acquisitions.
|
(6)
|
|
Legal reserve adjustments related to certain litigation and
environmental matters.
|
(7)
|
|
Gains or losses are reflected when realized.
|
(8)
|
|
Includes the following non-cash impairments: 3Q 2016 and YTD
2016 include a $350 million impairment of our equity investment in
Midcontinent Express Pipeline LLC. 3Q 2015 and YTD 2015 includes
$388 million of CO2 long lived asset impairments primarily related
to our Goldsmith oil and gas field.
|
(9)
|
|
3Q and YTD 2016 include a $276 million book tax expense certain item
due to the non-deductibility, for tax purposes, of approximately
$800 million of goodwill included in the loss calculation related to
the sale of a 50% interest in SNG, resulting in a gain for tax
purposes.
|
(10)
|
|
Represents noncontrolling interest share of certain items.
|
(11)
|
|
Includes KMI's share of certain equity investees' DD&A: 3Q
2016 - $89 3Q 2015 - $78 YTD 2016 - $264 YTD 2015 -
$240
|
(12)
|
|
Excludes book tax certain items and includes income tax allocated to
the segments. Also, includes KMI's share of taxable equity
investees' book tax expense: 3Q 2016 - $25 3Q 2015 - $21 YTD
2016 - $71 YTD 2015 - $56
|
(13)
|
|
YTD 2015 excludes a $195 million income tax refund received.
Includes KMI's share of taxable equity investees' cash taxes: 3Q
2016 - $(25) 3Q 2015 - $(2) YTD 2016 - $(59) YTD 2015
- $(8)
|
(14)
|
|
Consists primarily of non-cash compensation associated with our
restricted stock program.
|
(15)
|
|
Includes KMI's share of certain equity investees' sustaining capital
expenditures (the same equity investees for which DD&A is added
back): 3Q 2016 - $(24) 3Q 2015 - $(16) YTD 2016 -
$(66) YTD 2015 - $(50)
|
(16)
|
|
Includes restricted stock awards that participate in common share
dividends and dilutive effect of warrants, as applicable.
|
(17)
|
|
Adjusted EBITDA is net (loss) income before certain items, less net
income attributable to noncontrolling interests (before certain
items), plus DD&A (including KMI's share of certain equity
investees' DD&A), book taxes (including income tax allocated to the
segments and KMI’s share of certain equity investees’ book tax), and
interest expense (before certain items). Adjusted EBITDA is
reconciled as follows, with any difference due to rounding:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
|
|
Nine Months Ended
September 30,
|
|
|
|
2016
|
|
2015
|
|
|
|
2016
|
|
2015
|
Net (loss) income
|
|
|
$
|
(183
|
)
|
|
$
|
183
|
|
|
|
|
$
|
506
|
|
|
$
|
944
|
|
Total certain items
|
|
|
|
570
|
|
|
|
166
|
|
|
|
|
|
694
|
|
|
|
214
|
|
Net income attributable to noncontrolling interests
|
|
|
|
(5
|
)
|
|
|
(3
|
)
|
|
|
|
|
(16
|
)
|
|
|
(16
|
)
|
DD&A and amortization of excess investments (see (11) above)
|
|
|
|
653
|
|
|
|
708
|
|
|
|
|
|
1,960
|
|
|
|
2,005
|
|
Book taxes (see (12) above)
|
|
|
|
230
|
|
|
|
224
|
|
|
|
|
|
745
|
|
|
|
713
|
|
Interest, net (see (1) and (3) above)
|
|
|
|
505
|
|
|
|
525
|
|
|
|
|
|
1,525
|
|
|
|
1,565
|
|
Adjusted EBITDA
|
|
|
$
|
1,770
|
|
|
$
|
1,803
|
|
|
|
|
$
|
5,414
|
|
|
$
|
5,425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume Highlights
(historical pro forma for acquired assets)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
|
Nine Months Ended
September 30,
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
Natural Gas Pipelines
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transport Volumes (BBtu/d) (1) (2)
|
|
|
|
|
28,144
|
|
|
|
|
28,438
|
|
|
|
|
28,162
|
|
|
|
|
28,076
|
|
Sales Volumes (BBtu/d) (3)
|
|
|
|
|
2,438
|
|
|
|
|
2,445
|
|
|
|
|
2,350
|
|
|
|
|
2,416
|
|
Gas Gathering Volumes (BBtu/d) (2) (4)
|
|
|
|
|
2,935
|
|
|
|
|
3,541
|
|
|
|
|
3,044
|
|
|
|
|
3,554
|
|
Crude/Condensate Gathering Volumes (MBbl/d) (2) (5)
|
|
|
|
|
283
|
|
|
|
|
343
|
|
|
|
|
310
|
|
|
|
|
340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CO
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southwest Colorado Production - Gross (Bcf/d) (6)
|
|
|
|
|
1.20
|
|
|
|
|
1.20
|
|
|
|
|
1.18
|
|
|
|
|
1.22
|
|
Southwest Colorado Production - Net (Bcf/d) (6)
|
|
|
|
|
0.62
|
|
|
|
|
0.60
|
|
|
|
|
0.60
|
|
|
|
|
0.58
|
|
Sacroc Oil Production - Gross (MBbl/d) (7)
|
|
|
|
|
28.92
|
|
|
|
|
32.49
|
|
|
|
|
29.72
|
|
|
|
|
34.44
|
|
Sacroc Oil Production - Net (MBbl/d) (8)
|
|
|
|
|
24.09
|
|
|
|
|
27.07
|
|
|
|
|
24.76
|
|
|
|
|
28.69
|
|
Yates Oil Production - Gross (MBbl/d) (7)
|
|
|
|
|
17.85
|
|
|
|
|
18.89
|
|
|
|
|
18.52
|
|
|
|
|
18.94
|
|
Yates Oil Production - Net (MBbl/d) (8)
|
|
|
|
|
7.94
|
|
|
|
|
7.60
|
|
|
|
|
8.24
|
|
|
|
|
8.20
|
|
Katz, Goldsmith, and Tall Cotton Oil Production - Gross (MBbl/d) (7)
|
|
|
|
|
6.89
|
|
|
|
|
5.95
|
|
|
|
|
6.86
|
|
|
|
|
5.60
|
|
Katz, Goldsmith, and Tall Cotton Oil Production - Net (MBbl/d) (8)
|
|
|
|
|
5.84
|
|
|
|
|
4.99
|
|
|
|
|
5.78
|
|
|
|
|
4.71
|
|
NGL Sales Volumes (MBbl/d) (9)
|
|
|
|
|
10.55
|
|
|
|
|
10.51
|
|
|
|
|
10.26
|
|
|
|
|
10.33
|
|
Realized Weighted Average Oil Price per Bbl (10)
|
|
|
|
$
|
62.12
|
|
|
|
$
|
74.18
|
|
|
|
$
|
61.27
|
|
|
|
$
|
73.19
|
|
Realized Weighted Average NGL Price per Bbl
|
|
|
|
$
|
18.03
|
|
|
|
$
|
16.29
|
|
|
|
$
|
16.42
|
|
|
|
$
|
18.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids Leasable Capacity (MMBbl)
|
|
|
|
|
88.9
|
|
|
|
|
81.5
|
|
|
|
|
88.9
|
|
|
|
|
81.5
|
|
Liquids Utilization %
|
|
|
|
|
95.6
|
%
|
|
|
|
93.1
|
%
|
|
|
|
95.6
|
%
|
|
|
|
93.1
|
%
|
Bulk Transload Tonnage (MMtons) (11)
|
|
|
|
|
17.2
|
|
|
|
|
16.9
|
|
|
|
|
46.3
|
|
|
|
|
48.9
|
|
Ethanol (MMBbl)
|
|
|
|
|
17.3
|
|
|
|
|
15.0
|
|
|
|
|
48.9
|
|
|
|
|
47.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Products Pipelines
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pacific, Calnev, and CFPL (MMBbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline (12)
|
|
|
|
|
76.3
|
|
|
|
|
74.1
|
|
|
|
|
218.4
|
|
|
|
|
216.0
|
|
Diesel
|
|
|
|
|
28.2
|
|
|
|
|
28.5
|
|
|
|
|
80.8
|
|
|
|
|
80.8
|
|
Jet Fuel
|
|
|
|
|
24.7
|
|
|
|
|
23.2
|
|
|
|
|
69.8
|
|
|
|
|
67.0
|
|
Sub-Total Refined Product Volumes - excl. Plantation and Parkway
|
|
|
|
|
129.2
|
|
|
|
|
125.8
|
|
|
|
|
369.0
|
|
|
|
|
363.8
|
|
Plantation (MMBbl) (13)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline
|
|
|
|
|
21.1
|
|
|
|
|
19.1
|
|
|
|
|
62.5
|
|
|
|
|
59.5
|
|
Diesel
|
|
|
|
|
4.7
|
|
|
|
|
5.6
|
|
|
|
|
13.9
|
|
|
|
|
15.9
|
|
Jet Fuel
|
|
|
|
|
3.2
|
|
|
|
|
3.5
|
|
|
|
|
9.2
|
|
|
|
|
10.8
|
|
Sub-Total Refined Product Volumes - Plantation
|
|
|
|
|
29.0
|
|
|
|
|
28.2
|
|
|
|
|
85.6
|
|
|
|
|
86.2
|
|
Total (MMBbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline (12)
|
|
|
|
|
97.4
|
|
|
|
|
93.2
|
|
|
|
|
280.9
|
|
|
|
|
275.5
|
|
Diesel
|
|
|
|
|
32.9
|
|
|
|
|
34.1
|
|
|
|
|
94.7
|
|
|
|
|
96.7
|
|
Jet Fuel
|
|
|
|
|
27.9
|
|
|
|
|
26.7
|
|
|
|
|
79.0
|
|
|
|
|
77.8
|
|
Total Refined Product Volumes
|
|
|
|
|
158.2
|
|
|
|
|
154.0
|
|
|
|
|
454.6
|
|
|
|
|
450.0
|
|
NGLs (MMBbl) (14)
|
|
|
|
|
9.9
|
|
|
|
|
10.0
|
|
|
|
|
28.9
|
|
|
|
|
29.4
|
|
Crude and Condensate (MMBbl) (15)
|
|
|
|
|
28.8
|
|
|
|
|
27.3
|
|
|
|
|
87.6
|
|
|
|
|
70.9
|
|
Total Delivery Volumes (MMBbl)
|
|
|
|
|
196.9
|
|
|
|
|
191.3
|
|
|
|
|
571.1
|
|
|
|
|
550.3
|
|
Ethanol (MMBbl) (16)
|
|
|
|
|
10.1
|
|
|
|
|
10.7
|
|
|
|
|
30.9
|
|
|
|
|
31.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trans Mountain (MMBbls - mainline throughput)
|
|
|
|
|
30.7
|
|
|
|
|
29.5
|
|
|
|
|
88.1
|
|
|
|
|
86.9
|
|
|
|
|
|
(1)
|
|
|
Includes Texas Intrastates, Copano South Texas, KMNTP, Monterrey,
TransColorado, MEP, KMLA, FEP, TGP, EPNG, CIG, WIC, Cheyenne Plains,
SNG, Elba Express, Ruby, Sierrita, NGPL, and Citrus pipeline
volumes. Joint Venture throughput reported at KMI share.
|
(2)
|
|
|
Volumes for acquired pipelines are included for all periods.
|
(3)
|
|
|
Includes Texas Intrastates and KMNTP.
|
(4)
|
|
|
Includes Copano Oklahoma, Copano South Texas, Eagle Ford Gathering,
Copano, North Texas, Altamont, KinderHawk, Camino Real, Endeavor,
Bighorn, Webb/Duval Gatherers, Fort Union, EagleHawk, Red Cedar, and
Hiland Midstream throughput. Joint Venture throughput reported at
KMI share.
|
(5)
|
|
|
Includes Hiland Midstream, EagleHawk, and Camino Real. Joint Venture
throughput reported at KMI share.
|
(6)
|
|
|
Includes McElmo Dome and Doe Canyon sales volumes.
|
(7)
|
|
|
Represents 100% production from the field.
|
(8)
|
|
|
Represents KMI's net share of the production from the field.
|
(9)
|
|
|
Net to KMI.
|
(10)
|
|
|
Includes all KMI crude oil properties.
|
(11)
|
|
|
Includes KMI's share of Joint Venture tonnage.
|
(12)
|
|
|
Gasoline volumes include ethanol pipeline volumes.
|
(13)
|
|
|
Plantation reported at KMI share.
|
(14)
|
|
|
Includes Cochin and Cypress (KMI share).
|
(15)
|
|
|
Includes KMCC, Double Eagle (KMI share), and Double H.
|
(16)
|
|
|
Total ethanol handled including pipeline volumes included in
gasoline volumes above.
|
|
|
|
|
|
|
|
Kinder Morgan, Inc. and Subsidiaries
Preliminary Consolidated Balance Sheets
(Unaudited)
(In millions)
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2016
|
|
|
2015
|
ASSETS
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
$
|
357
|
|
|
|
$
|
229
|
|
Other current assets
|
|
|
|
3,006
|
|
|
|
|
2,595
|
|
Property, plant and equipment, net
|
|
|
|
38,780
|
|
|
|
|
40,547
|
|
Investments
|
|
|
|
7,358
|
|
|
|
|
6,040
|
|
Goodwill
|
|
|
|
22,163
|
|
|
|
|
23,790
|
|
Deferred charges and other assets
|
|
|
|
9,940
|
|
|
|
|
10,903
|
|
TOTAL ASSETS
|
|
|
$
|
81,604
|
|
|
|
$
|
84,104
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
Short-term debt
|
|
|
$
|
2,944
|
|
|
|
$
|
821
|
|
Other current liabilities
|
|
|
|
3,100
|
|
|
|
|
3,244
|
|
Long-term debt
|
|
|
|
36,708
|
|
|
|
|
40,632
|
|
Preferred interest in general partner of KMP
|
|
|
|
100
|
|
|
|
|
100
|
|
Debt fair value adjustments
|
|
|
|
1,710
|
|
|
|
|
1,674
|
|
Other
|
|
|
|
2,074
|
|
|
|
|
2,230
|
|
Total liabilities
|
|
|
|
46,636
|
|
|
|
|
48,701
|
|
|
|
|
|
|
|
|
Shareholders’ Equity
|
|
|
|
|
|
|
Accumulated other comprehensive loss
|
|
|
|
(557
|
)
|
|
|
|
(461
|
)
|
Other shareholders’ equity
|
|
|
|
35,163
|
|
|
|
|
35,580
|
|
Total KMI equity
|
|
|
|
34,606
|
|
|
|
|
35,119
|
|
Noncontrolling interests
|
|
|
|
362
|
|
|
|
|
284
|
|
Total shareholders’ equity
|
|
|
|
34,968
|
|
|
|
|
35,403
|
|
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
$
|
81,604
|
|
|
|
$
|
84,104
|
|
|
|
|
|
|
|
|
Net Debt (1) (3)
|
|
|
$
|
39,248
|
|
|
|
$
|
41,224
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
Twelve Months Ended
|
|
|
|
September 30,
|
|
|
December 31,
|
Reconciliation of Net (Loss) Income to Adjusted EBITDA (2)
|
|
|
2016
|
|
|
2015
|
Net (loss) income
|
|
|
$
|
(228
|
)
|
|
|
$
|
208
|
|
Total certain items
|
|
|
|
1,920
|
|
|
|
|
1,441
|
|
Net income attributable to noncontrolling interests
|
|
|
|
(18
|
)
|
|
|
|
(18
|
)
|
DD&A and amortization of excess investments
|
|
|
|
2,638
|
|
|
|
|
2,683
|
|
Book taxes
|
|
|
|
1,007
|
|
|
|
|
976
|
|
Interest, net
|
|
|
|
2,042
|
|
|
|
|
2,082
|
|
Adjusted EBITDA
|
|
|
$
|
7,361
|
|
|
|
$
|
7,372
|
|
|
|
|
|
|
|
|
Net Debt to Adjusted EBITDA (3)
|
|
|
|
5.3
|
|
|
|
|
5.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2016
|
Reconciliation of Forecasted GAAP Capital Expenditures to Growth
Capital Forecast for 2016
|
|
|
|
|
|
|
Forecasted capital expenditures(4)
|
|
|
|
|
|
$
|
2,728
|
|
Growth capital expenditures of unconsolidated joint ventures and
acquisitions, net of divestitures
|
|
|
|
|
|
|
450
|
|
Less: Sustaining capital expenditures
|
|
|
|
|
|
|
(455
|
)
|
Growth Capital Forecast for 2016
|
|
|
|
|
|
$
|
2,723
|
|
|
Notes
|
(1)
|
|
Amounts exclude: (i) the preferred interest in general partner of
KMP, (ii) debt fair value adjustments and (iii) the foreign exchange
impact on our Euro denominated debt of $47 million and less than $1
million as of September 30, 2016 and December 31, 2015,
respectively, as we have entered into swaps to convert that debt to
US$.
|
(2)
|
|
Adjusted EBITDA is net (loss) income before certain items, less net
income attributable to noncontrolling interests (before certain
items), plus DD&A (including KMI's share of certain equity
investees' DD&A), book taxes (including income tax allocated to the
segments and KMI’s share of certain equity investees’ book tax), and
interest expense (before certain items), with any difference due to
rounding.
|
(3)
|
|
As of September 30, 2016, $749 million of cash was held in escrow to
redeem debt, which occurred on October 1, 2016, and therefore, not
included in cash and cash equivalents or the calculation of Net
Debt. Had this cash been included in cash and cash equivalents as of
September 30, 2016, Net Debt would have been $38,499 million and the
Net Debt to Adjusted EBITDA ratio would have been 5.2 times for the
twelve months ended September 30, 2016.
|
(4)
|
|
Excludes accrued capital expenditures and contractor retainage.
|