UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2009
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to .
Commission File Number 1-33825
El Paso Pipeline Partners, L.P.
(Exact Name of Registrant as Specified in Its Charter)
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Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
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26-0789784
(I.R.S. Employer
Identification No.) |
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El Paso Building |
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1001 Louisiana Street |
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Houston, Texas
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77002 |
(Address of Principal Executive Offices)
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(Zip Code) |
Telephone Number: (713) 420-2600
Internet Website: www.eppipelinepartners.com
Securities registered pursuant to Section 12(b) of the Act:
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Name of Each Exchange |
Title of Each Class
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on which Registered |
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Common Units Representing Limited Partnership Interests
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes þ No o.
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes o No þ.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o.
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ.
The aggregate market value of the common units representing limited partner interests held by
non-affiliates of the registrant was approximately $712,410,891 on June 30, 2009, the last business
day of the registrants most recently completed second fiscal quarter, based on the price of $17.53
per unit, the closing price of the common units as reported on the New York Stock Exchange on such
date.
There were 107,484,747 Common Units, 27,727,411 Subordinated Units and 2,759,432 General
Partner Units outstanding as of February 23, 2010:
Documents Incorporated by Reference: None.
EL PASO PIPELINE PARTNERS, L.P.
TABLE OF CONTENTS
Below is a list of terms that are common to our industry and used throughout this document:
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/d
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= per day
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LNG
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= liquefied natural gas |
BBtu
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= billion British thermal units
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MDth
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= thousand dekatherm |
Bcf
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= billion cubic feet
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MMcf
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= million cubic feet |
Dth
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= dekatherm
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MMcf/d
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= million cubic feet per day |
Tonne
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= metric ton |
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When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds
per square inch.
When we refer to us, we, our, or ours, we are describing El Paso Pipeline Partners,
L.P. and/or our subsidiaries.
Overview and Strategy
We are a Delaware master limited partnership (MLP) formed in November 2007 by El Paso
Corporation (El Paso) to own and operate natural gas transportation pipelines and storage assets.
We conduct our business activities through various natural gas pipeline systems and storage
facilities including the Wyoming Interstate Company, Ltd. (WIC) system, a 58 percent general
partner interest in Colorado Interstate Gas Company (CIG) and a 25 percent general partner interest
in Southern Natural Gas Company (SNG). In November 2007, we completed an initial public offering of
our common units, issuing 28.8 million common units to the public. In conjunction with our
formation, El Paso contributed to us 100 percent of WIC, as well as 10 percent general partner
interests in each of CIG and SNG. In September 2008, we acquired from El Paso an additional 30
percent general partner interest in CIG and an additional 15 percent general partner interest in
SNG. On July 24, 2009, we acquired an additional 18 percent general partner interest in CIG from El
Paso.
WIC is an interstate pipeline transportation business located in Wyoming, Utah and Colorado.
CIG is an interstate pipeline transportation and storage business that extends from production
areas in the U.S. Rocky Mountain region to interconnection points on pipelines transporting gas to
the midwest, southwest and northwest U.S. and to market areas in the Front Range of Colorado and
Wyoming. SNG is an interstate pipeline transportation and storage business that extends from
production fields in the southern U.S. and the Gulf of Mexico to market areas across the Southeast.
Our pipeline systems and storage facilities operate under tariffs approved by the Federal
Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms
and conditions of services to our customers. The fees or rates established under our tariff are a
function of our costs of providing services to our customers, including a reasonable return on our
invested capital.
Our primary business objectives are to generate stable cash flows sufficient to make
distributions to our unitholders and to grow our business through the construction, development and
acquisition of additional energy infrastructure assets. We intend to increase our cash
distributions over time by enhancing the value of our transportation and storage assets by:
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providing outstanding customer service; |
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executing successfully on time and on budget for our committed expansion projects; |
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focusing on increasing utilization, efficiency and cost control in our operations; |
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pursuing economically attractive organic and greenfield expansion opportunities; |
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successfully recontracting expiring contracts for transportation capacity; |
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pursuing strategic asset acquisitions from third parties and El Paso to grow our
business; and |
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maintaining the integrity and ensuring the safety of our pipeline systems and other
assets. |
1
Our Assets
The table below and discussion that follows provide detail on our pipeline systems as of
December 31, 2009:
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As of December 31, 2009 |
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Transmission |
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Ownership |
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Miles of |
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Design |
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Storage |
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Average Throughput(1) |
System |
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Interest |
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Pipeline |
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Capacity |
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Capacity |
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2009 |
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2008 |
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2007 |
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(Percent) |
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(MMcf/d) |
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(Bcf) |
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(BBtu/d) |
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WIC |
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100 |
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800 |
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3,340 |
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2,652 |
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2,543 |
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2,071 |
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CIG (2)(3) |
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58 |
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4,200 |
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3,750 |
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35 |
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2,299 |
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2,225 |
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2,339 |
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SNG (2)(4) |
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25 |
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7,600 |
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3,700 |
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60 |
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2,322 |
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2,339 |
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2,345 |
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(1) |
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The WIC throughput includes 131 BBtu/d, 181 BBtu/d and 239 BBtu/d transported by
WIC on behalf of CIG for the years ended
December 31, 2009, 2008, and 2007. |
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Volumes reflected are 100 percent of the volumes transported on the CIG system and
the SNG system, respectively. |
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CIGs storage capacity includes 6 Bcf of storage capacity from Totem Gas Storage,
which is owned by WYCO Development LLC (WYCO), CIGs 50 percent equity investee. |
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SNGs storage capacity includes the storage capacity associated with their 50
percent ownership interest in Bear Creek Storage Company, LLC (Bear Creek), a joint venture
with Tennessee Gas Pipeline Company (TGP), our affiliate. |
WIC. WIC is comprised of a mainline system that extends from western Wyoming to northeast
Colorado (the Cheyenne Hub) and several lateral pipeline systems that extend from various
interconnections along the WIC mainline into western Colorado and northeast Wyoming and into
eastern Utah. WIC is one of the primary interstate natural gas transportation systems providing
takeaway capacity from the mature Overthrust, Piceance, Uinta, Powder River and Green River Basins.
CIG is the operator of the WIC system pursuant to a service agreement with WIC.
CIG. CIG is comprised of pipelines that deliver natural gas from production areas in the U.S.
Rocky Mountains and the Anadarko Basin directly to customers in Colorado, Wyoming and indirectly to
the midwest, southwest, California and Pacific northwest. CIG also owns interests in five storage
facilities located in Colorado and Kansas with approximately 35 Bcf of underground working natural
gas storage capacity and one natural gas processing plant located in Wyoming.
CIG owns a 50 percent ownership interest in WYCO, a joint venture with an affiliate of Public
Service Company of Colorado (PSCo). WYCO owns Totem Gas Storage and the High Plains pipeline, which
were placed in service in June 2009 and November 2008, respectively, and are operated by CIG. The
High Plains pipeline consists of a 164-mile interstate gas pipeline extending from the Cheyenne Hub
in northeast Colorado to PSCos Fort St. Vrain electric generation plant and other points of
interconnections with PSCos system. The system added approximately 900 MMcf/d of overall
transportation capacity to our system. The increased capacity is fully contracted with PSCo and
Coral Energy Resources pursuant to firm contracts through 2029 and
2019. The Totem Gas Storage facility consists
of a natural gas storage field that services and interconnects with the High Plains Pipeline. The
Totem Gas Storage field has 6 Bcf of working natural gas storage capacity with a maximum withdrawal
rate of 200 MMcf/d and a maximum injection rate of 100 MMcf/d. All of the storage capacity of this
new storage field is fully contracted with PSCo pursuant to a firm contract through 2040. WYCO also
owns a state regulated intrastate gas pipeline that extends from the Cheyenne Hub in northeast
Colorado to PSCos Fort St. Vrains electric generation plant, which CIG does not operate, and a
compressor station in Wyoming operated by WIC.
SNG. SNG is comprised of pipelines extending from natural gas supply basins in Texas,
Louisiana, Mississippi, Alabama and the Gulf of Mexico to market areas in Louisiana, Mississippi,
Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of
Atlanta and Birmingham. SNG is the principal natural gas transporter to southeastern markets in
Alabama, Georgia and South Carolina. SNG owns interests in two storage facilities along the system
with approximately 60 Bcf of underground working natural gas storage capacity. The SNG system is
also connected to El Pasos Elba Island LNG terminal near Savannah, Georgia.
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Markets and Competition
Our customers consist of natural gas distribution and industrial companies, electric
generation companies, natural gas producers, other natural gas pipelines and natural gas marketing
and trading companies. We provide transportation and storage services in both our natural gas
supply and market areas. Our pipeline systems connect with multiple pipelines that provide our
customers with access to diverse sources of supply, including supply from unconventional sources,
and various natural gas markets. The natural gas industry is undergoing a major shift in supply
sources. Production from conventional sources is declining while production from unconventional
sources such as shale, tight sands, and coal bed methane is rapidly increasing. This shift will
change the supply patterns and flows of pipelines. The impacts will vary among pipelines according
to the proximity of the new supply sources.
Electric power generation
has been a growing demand sector of the natural gas market. The market slowdown had a minimal
impact on SNG as electric market demand increased due to attractive natural gas pricing relative to
coal. The growth of natural gas fired electric power benefits the natural gas industry by creating
more demand for natural gas. This potential benefit is offset, in varying degrees, by increased
generation efficiency, the more effective use of surplus electric capacity and the use and
availability of other fuel sources for power generation. In addition, in several regions of the
country, new additions in electric generating capacity have exceeded load growth and electric
transmission capabilities out of those regions. These developments may inhibit owners of new power
generation facilities from signing firm transportation contracts with
natural gas pipelines.
Growth of the natural gas market has been adversely affected by the current economic slowdown
in the U.S. and world economies. The decline in economic activity reduced industrial demand for
natural gas and electricity, which affected natural gas demand both directly in end-use markets and
indirectly through lower power generation demand for natural gas. We expect the demand and growth
for natural gas to return as the economy recovers. Natural gas has a favorable competitive position
as an electric generation fuel because it is a clean and abundant fuel with lower capital
requirements compared with other alternatives. The lower demand and the credit restrictions on
investments in the recent past may slow development of supply projects. While WICs, CIGs and
SNGs pipelines could experience some level of reduced throughput and revenues, or slower
development of future expansion projects as a result of these factors, each of these pipelines
generates a significant (approximately 90 percent) portion of its revenues through fixed monthly
reservation or demand charges on long-term contracts at rates stipulated under its tariffs or in
its contracts. Additionally, on CIG and WIC, we do not expect production in the U.S. Rocky Mountain
region to significantly decrease from current levels due to the need to replace diminishing exports
from Canada and declining production from traditional domestic sources.
WIC. Our WIC system competes with other interstate and intrastate pipelines for deliveries to
multiple-connection customers and its four largest customers are generally able to obtain a
significant portion of their natural gas transportation requirements from other pipelines,
including the Rockies Express Pipeline LLC (Rockies Express Pipeline) and CIG. In addition, WIC
competes with CIG, third party pipelines and gathering systems for connection to the rapidly
growing supply sources in the U.S. Rocky Mountain region. Natural gas delivered from the WIC system
competes with alternative energy sources used to generate electricity, such as hydroelectric power,
solar, wind, coal and fuel oil.
WIC and CIG are competitors for lateral expansions to various U.S. Rocky Mountain supply
basins. Both WIC and CIG have supply laterals in the Piceance Basin, Powder River Basin and the
Uinta Basin. Since the WIC mainline system and the Wyoming portion of the CIG system parallel each
other, a supply lateral can effectively interconnect with either system. Additionally, for many
years CIG has contracted for firm capacity on the WIC system to support CIGs Wyoming area contract
obligations and CIG uses its capacity on the WIC system as an operational loop of the CIG system.
WIC and CIG may compete for the same business opportunities. Economic, market and other factors
related to each individual opportunity will have a significant impact on the determination of
whether WIC, CIG or another affiliate pursue such business opportunities and ultimately carry out
expansion projects or acquisitions, but the decision will be at the sole discretion of El Paso.
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CIG. Our CIG system serves two major markets, an on-system market, consisting of utilities and
other customers located along the Front Range of the U.S. Rocky Mountains in Colorado and Wyoming,
and an off-system market, consisting of the transportation of U.S. Rocky Mountain natural gas
production from multiple supply basins to users accessed through interconnecting pipelines in the
midwest, southwest, California and the Pacific northwest. Recent growth in the on-system market
from both the space heating segment and electric generation segment has provided CIG with
incremental demand for transportation services. Competition for our on-system market consists of an
intrastate pipeline, an interstate pipeline, local production from the Denver-Julesburg basin, and
long-haul shippers who elect to sell into this market rather than the off-system market.
Competition for our off-system market consists of other interstate pipelines, including WIC, that
are directly connected to our supply sources. CIG also faces competition from other existing
pipelines and alternative energy sources that are used to generate electricity such as
hydroelectric power, wind, solar, coal and fuel oil.
CIG also competes with other interstate and intrastate pipelines for deliveries to
multiple-connection customers who can take deliveries at alternative points. Some of CIGs largest
customers are able to obtain a significant portion of their natural gas requirements through
transportation from other pipelines. CIGs most direct competitor in the U.S. Rocky Mountain region
is the Rockies Express Pipeline. The Rockies Express Pipeline could result in additional
discounting on the CIG system.
SNG.
The southeastern market served by the SNG system is one of the fastest growing natural gas
demand regions in the U.S. Demand for deliveries from the SNG system is characterized by two peak
delivery periods, the winter heating season and the summer cooling season.
SNG competes with other interstate and intrastate pipelines for deliveries to
multiple-connection customers who can take deliveries at alternative delivery points. Natural gas
delivered from the SNG system competes with alternative energy sources used to generate
electricity, such as hydroelectric power, coal and fuel oil. Some of SNGs largest customers are
able to obtain a significant portion of their natural gas requirements through transportation from
other pipelines. In addition, SNG competes with third party pipelines and gathering systems for
connection to new supply sources.
SNGs most direct competitor is Transco, which owns an approximately 10,500-mile pipeline
extending from Texas to New York. It has firm transportation contracts with some of SNGs largest
customers, including Atlanta Gas Light Company, Alabama Gas Corporation, SCANA, and Southern
Company Services.
The following table details our customers and contracts for each of our pipeline systems as of December 31, 2009. Our firm customers reserve capacity on our pipeline system or storage
facilities and are obligated to pay a monthly reservation or demand charge, regardless of the
amount of natural gas they transport or store, for the term of their contracts. Our interruptible
customers are customers without reserved capacity that pay usage charges based on the volume of gas
actually transported, stored, injected or withdrawn.
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WIC |
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Customer Information |
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Contract Information |
Approximately 50 firm and interruptible customers. |
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Approximately 60 firm transportation contracts. Weighted average remaining contract term of approximately eight years. |
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Major Customers: |
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Williams Gas Marketing, Inc. |
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(1,320 BBtu/d) |
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Expires in 2010-2021. |
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Anadarko Petroleum Corporation |
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(1,260 BBtu/d) |
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Expires in 2010-2023. |
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CIG |
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Customer Information |
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Contract Information |
Approximately 100 firm and interruptible customers. |
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Approximately 170 firm transportation contracts. Weighted average remaining contract term of approximately eight years. |
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Major Customers: |
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PSCo |
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(1,787 BBtu/d) |
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Expires in 2010-2029. |
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Williams Gas Marketing, Inc. |
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(498 BBtu/d) |
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Expires in 2010-2014. |
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Anadarko Petroleum Corporation |
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(280 BBtu/d) |
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Expires in 2011-2015. |
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SNG |
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Customer Information |
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Contract Information |
Approximately 270 firm and interruptible customers. |
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Approximately 200 firm transportation contracts. Weighted average remaining contract term of approximately six years. |
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Major Customers: |
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Atlanta Gas Light Company(1) |
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(1,063 BBtu/d) |
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Expires in 2013-2024. |
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Southern Company Services |
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(433 BBtu/d) |
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Expires in 2011-2018. |
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Alabama Gas Corporation |
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(372 BBtu/d) |
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Expires in 2010-2013. |
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SCANA Corporation |
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(315 BBtu/d) |
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Expires in 2013-2019. |
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(1) |
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Atlanta Gas Light Company is currently releasing a significant portion of its
firm capacity to a subsidiary of SCANA Corporation under terms allowed by SNGs tariff. |
Regulatory Environment
Our interstate natural gas transmission systems transport and store natural gas for local
distribution companies (LDCs), other natural gas distribution and industrial companies, electric
generation companies, natural gas producers, other natural gas pipelines and natural gas marketing
and trading companies. Our systems do not take title to the natural gas transported or stored for
our customers, which mitigates our direct commodity price risk. The rates our systems charge are
regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005.
The FERC approves tariffs that establish rates, cost recovery mechanisms, and other terms and
conditions of services to our customers. The fees or rates established under our tariffs are a
function of providing services to our customers, including a reasonable return on our invested
capital. The FERCs authority also extends to:
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rates and charges for natural gas transportation and storage and related services; |
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certification and construction of new facilities; |
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extension or abandonment of services and facilities; |
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maintenance of accounts and records; |
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relationships between pipelines and certain affiliates; |
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terms and conditions of service; |
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depreciation and amortization policies; |
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acquisition and disposition of facilities; and |
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initiation and discontinuation of services. |
Our interstate pipeline systems are also subject to federal, state and local safety and
environmental statutes and regulations of the U.S. Department of Transportation (DOT) and the U.S.
Department of the Interior. We have ongoing inspection programs designed to keep our facilities in
compliance with pipeline safety and environmental requirements and we believe that our systems are
in material compliance with the applicable regulations. For a further discussion of the potential
impact of regulatory matters on us, see Item 1A, Risk Factors and Part II, Item 7, Managements
Discussion and Analysis of Financial Condition and Results of Operations.
Our Relationship with El Paso Corporation
El Paso is an energy company founded in 1928 in El Paso, Texas that primarily operates in the
regulated natural gas transportation sector and the exploration and production sector of the energy
industry. El Paso owns our two percent general partner interest, all of our incentive distribution
rights, a 60 percent limited partner interest in us including both common and subordinated units
and the remaining 42 percent general partner interest in CIG and 75 percent general partner interest in SNG not owned by us. We have an omnibus agreement with
El Paso and our general partner that governs our relationship with them regarding the provision of
specified services to us, as well as certain reimbursement and indemnification matters.
As a substantial owner in us, El Paso is motivated to promote and support the successful
execution of our business strategies, including utilizing our partnership as a growth vehicle for
its natural gas transportation, storage and other energy infrastructure businesses. Although we
expect to have the opportunity to make additional acquisitions directly from El Paso in the future,
El Paso is under no obligation to make acquisition opportunities available to us.
Environmental
A description of our environmental activities is included in Part II, Item 8 Financial
Statements and Supplementary Data, Note 8.
Employees
We do not have employees. We are managed and operated by the directors and officers of our
general partner, El Paso Pipeline GP Company, L.L.C., a subsidiary of El Paso. Additionally, WIC is operated by
CIG, and SNG is operated by El Paso and its affiliates. We have an omnibus agreement with El Paso
and its affiliates under which we reimburse El Paso for the provision of various general and
administrative services for our benefit, for direct expenses incurred by El Paso on our behalf and
for expenses allocated to us as a result of us being a public entity. A further discussion of our
affiliate transactions is included in Part II, Item 8, Financial Statements and Supplementary Data,
Note 12.
Available Information
Our website is http://www.eppipelinepartners.com. We make available, free of charge on or
through our website, our annual, quarterly and current reports, and any amendments to those
reports, as soon as is reasonably possible after these reports are filed with the Securities and
Exchange Commission (SEC). Information about each of our Board members, as well as each of our
Boards standing committee charters, our Corporate Governance Guidelines and our Code of Business
Conduct are also available, free of charge, through our website. Information contained on our
website is not part of this report.
6
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS
This report contains forward-looking statements that are based on assumptions or beliefs that
we believe to be reasonable; however assumed facts almost always vary from the actual results, and
differences between assumed facts and actual results can be material, depending upon the
circumstances. Where, based on assumptions, we or our management express an expectation or belief
as to future results, that expectation or belief is expressed in good faith and is believed to have
a reasonable basis. We cannot assure you, however, that the stated expectation or belief will
occur, be achieved or accomplished. The words believe, expect, estimate, anticipate and
similar expressions will generally identify forward-looking statements. All of our forward-looking
statements, whether written or oral, are expressly qualified by these cautionary statements and any
other cautionary statements that may accompany such forward-looking statements. In addition, we
disclaim any obligation to update any forward-looking statements to reflect events or circumstances
after the date of this report.
With this in mind, you should consider the risks discussed elsewhere in this report and other
documents we file with the SEC from time to time and the following important factors that could
cause actual results to differ materially from those expressed in any forward-looking statement
made by us or on our behalf.
Limited partner interests are inherently different from the capital stock of a corporation,
although many of the business risks to which we are subject are similar to those that would be
faced by a corporation engaged in a similar business. If any of the following risks were actually
to occur, our business, results of operations and financial condition could be materially adversely
affected. In that case, we might not be able to pay distributions on our common units, the trading
price of our common units could decline, and you could lose all or part of your investment.
The risks referred to herein refer to risks inherent to both our wholly-owned operations
through WIC and our general partner interests in CIG and SNG.
Risks Inherent in Our Business
Our success depends on factors beyond our control.
The results of operations of our transportation and storage operations are impacted by the
volumes of natural gas we transport or store and the prices we are able to charge for doing so. The
volumes of natural gas we are able to transport and store depend on the actions of third parties
and are beyond our control. Such actions include factors that impact our customers demand and
producers supply, including factors that negatively impact our customers need for natural gas
from us, as well as the continued availability of natural gas production and reserves connected to
our pipeline systems. Further, the following factors, most of which are also beyond our control,
may unfavorably impact our ability to maintain or increase current throughput or to remarket
unsubscribed capacity:
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service area competition; |
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expiration or turn back of significant contracts; |
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changes in regulation and actions of regulatory bodies; |
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weather conditions that impact natural gas throughput and storage levels; |
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weather fluctuations or warming and cooling trends that may impact demand in the
markets in which we do business, including trends potentially attributable to climate
change; |
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drilling activity and decreased availability of conventional gas supply sources and the
availability and timing of other natural gas sources such as LNG and gas shale supplies; |
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continued development of additional sources of gas supply that can be accessed; |
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decreased natural gas demand due to various factors, including economic recession (as
further discussed below), availability of alternative energy sources and increases in
prices; |
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legislative, regulatory or judicial actions, such as
mandatory renewable portfolio
standards and greenhouse gas (GHG) regulations and/or legislation that could result in (i)
changes in the demand for natural gas and oil, (ii) changes in the availability of or
demand for alternative energy sources such as hydroelectric and nuclear power, wind and
solar energy or (iii) changes in the demand for lower carbon intensive energy sources; |
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availability and cost to fund ongoing maintenance and growth projects, especially in
periods of prolonged economic decline; |
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opposition to energy infrastructure development, especially in environmentally
sensitive areas; |
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adverse general economic conditions including prolonged recessionary periods that might
negatively impact natural gas demand and the capital markets; |
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our ability to achieve targeted annual operating and administrative expenses achieved
primarily by reducing internal costs and improving efficiencies from leveraging a
consolidated supply chain organization; and |
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unfavorable movements in natural gas prices in supply and demand areas. |
We may not have sufficient cash from operations following the establishment of cash reserves and
payment of fees and expenses, including cost reimbursements to our general partner, to enable us to
make cash distributions to holders of our common units and subordinated units at our current
quarterly distribution.
We may not have sufficient available cash each quarter to continue to pay quarterly
distributions at our current quarterly distribution rate. Under this circumstance, we may be
required to borrow under our revolving credit facility to pay the annualized quarterly
distribution. Under our cash distribution policy, the amount of cash we can distribute on our units
principally depends upon the amount of cash generated from our operations and not on reported net
earnings for financial accounting purposes. Our cash flows will fluctuate based on, among other
things:
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the rates we charge and the volumes under contract for our transportation and storage
services; |
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the quantities of natural gas available for transport and the demand for natural gas; |
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the price of natural gas; |
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legislative or regulatory action affecting demand for and supply of natural gas, and
the rates we are allowed to charge in relation to our operating costs; |
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the level of our operating and maintenance and general and administrative costs; and |
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the creditworthiness of our shippers. |
In addition, the actual amount of cash we will have available for distribution will depend on
other factors, some of which are beyond our control, including:
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the level of capital expenditures we make; |
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our debt service requirements, retirement of debt and other liabilities; |
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fluctuations in working capital needs; |
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our ability to borrow funds and access capital markets; |
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the amount of cash distributed to us by the entities in which we own a minority
interest; |
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restrictions on distributions contained in debt agreements; and |
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the amount of cash reserves established by our general partner, which may include
reserves for tariff rates that are subject to refund. |
8
We own minority interests in one of our three primary assets, with the remaining interest in this
asset owned by El Paso or its other subsidiaries. As a result, we will be unable to control the
amount of cash we will receive from its operations and we could be required to contribute
significant cash to fund our share of its operations, including capital expenditures. If we fail to
make these contributions, we will be subject to specified penalties.
Our inability to control the operations of SNG and its respective subsidiaries and
unconsolidated affiliates may mean that we do not receive the amount of cash we expect to be
distributed to us. We expect our interest in SNG to generate in excess of 20 percent of the cash we
distribute in 2010 and, accordingly, our performance is substantially dependent on SNGs
distributions to us. Since we only have a 25 percent interest in SNG, we are unable to control its
ongoing operational and investment decisions, which may adversely affect the amount of cash
otherwise available for distribution to us, including:
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decisions with respect to incurrence of expenses and distributions to us; |
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establishing reserves for working capital, maintenance capital expenditures,
environmental matters and legal and rate proceedings; |
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incurring additional indebtedness and principal and interest payments; and |
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requiring us to make additional capital contributions to SNG to fund working capital,
maintenance capital and expansion capital expenditures which could be material. In the
event we elect not to make a required capital contribution or are unable to do so, our
partnership interest could be diluted or it could affect the receipt of distributions until
we have forgone distributions equal to our portion of the capital call plus a specified
premium. |
Our natural gas transportation and storage systems are subject to regulation by agencies, including
the FERC, which could have an adverse impact on our ability to establish transportation and storage
rates that would allow recovery of the full cost of operating these pipeline systems and storage
facilities, including a reasonable return, and our ability to make distributions.
Our interstate natural gas transportation and storage operations are subject to federal, state
and local regulatory authorities. Specifically, our natural gas pipeline systems and our storage
facilities and related assets are subject to regulation by the FERC, the DOT, the United States
Department of the Interior, and various state and local regulatory agencies. Regulatory actions
taken by these agencies have the potential to adversely affect our profitability. Federal
regulation extends to such matters as:
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rates, operating terms and conditions of service, with CIG required to file a new rate
case to be effective no later than October 2011; |
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the types of services we may offer to our customers; |
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the contracts for service entered into with our customers; |
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construction and abandonment of new facilities; |
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the integrity and safety of our pipeline systems and related operations; |
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acquisition, extension or abandonment of services or facilities; |
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accounts and records; and |
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relationships with affiliated companies involved in certain aspects of the natural gas
business. |
9
We are subject to various governmental investigations from time to time, including
investigations by the FERC and the U.S. Department of Transportation Office of Pipeline Safety. The
results of any investigation could have a material adverse effect on our business, financial
condition or results of operation. In addition, pursuant to laws and regulations, our existing
rates may be challenged by complaint. The FERC commenced several complaint proceedings in 2009
against unaffiliated pipeline systems to reduce the rates they were charging their customers. There
is a risk that the FERC or our customers could file similar complaints on one or more of our
pipeline systems and that a successful complaint against our pipelines rates could have an adverse
impact on our business, financial condition, results of operations and thus our ability to make
distributions.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations
and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of
2005, the FERC has civil penalty authority under the Natural Gas Act of 1938 to impose penalties
for current violations of up to $1,000,000 per day for each violation, to revoke existing
certificate authority and to order disgorgement of profits associated with any violation.
Finally, we do not know how future regulations will impact the operation of our natural gas
transportation and storage businesses or the effect such regulations could have on our business,
financial condition, results of operations and thus our ability to make distributions.
The application of certain FERC policy statements could affect the rate of return on our equity we
are allowed to recover through rates and the amount of any allowance (if any) our systems can
include for income taxes in establishing their rates for service, which would in turn impact our
revenues and/or equity earnings.
In setting authorized rates of return, the FERC uses a discounted cash flow model that
incorporates the use of proxy groups to develop a range of reasonable returns earned on equity
interests in companies with corresponding risks. The FERC then assigns a rate of return on equity
within that range to reflect specific risks of that pipeline when compared to the proxy group
companies. The FERC allows MLPs to be included in the proxy group to determine return on equity.
However, as to such MLPs, the FERC will generally adjust the long-term growth rate used to
calculate the equity cost of capital. The FERC stated that the long-term growth projection for
natural gas pipeline MLPs will be equal to fifty percent of gross domestic product (GDP), as
compared to the unadjusted GDP used for corporations. Therefore, to the extent that master limited
partnerships are included in a proxy group, the FERCs policy lowers the return on equity that
might otherwise be allowed if there were no adjustment to the master limited partnership growth
projection used for the discounted cash flow model. This could lower the return on equity that we
would otherwise be able to obtain.
The FERC currently allows partnerships to include in their cost-of-service an income tax
allowance. Any changes to the FERCs treatment of income tax allowances in cost-of-service and to
potential adjustment in a future rate case of our pipelines respective equity rates of return that
underlie their recourse rates may cause their recourse rates to be set at a level that is
different, and in some instances lower than the level otherwise in effect.
Certain
of our systems provide a portion of their transportation services pursuant to long-term,
fixed-price negotiated rate contracts that are not subject to adjustment, even if our cost to
perform such services exceeds the revenues received from such contracts, and, as a result, our
costs could exceed our revenues received under such contracts.
It is possible that costs to perform services under negotiated rate contracts will exceed
the negotiated rates. If this occurs, it could decrease the cash flow realized by WIC, CIG and SNG
and, therefore, the cash we have available for distribution to our unitholders. Under FERC policy,
a regulated service provider and a customer may mutually agree to sign a contract for service at a
negotiated rate which may be above or below the FERC regulated recourse rate for that service,
and that contract must be filed and accepted by FERC. These negotiated rate contracts are not
generally subject to adjustment for increased costs which could be produced by inflation, increases
in cost of capital and taxes or other factors relating to the specific facilities being used to
perform the services. Any shortfall of revenue, representing the difference between recourse
rates (if higher) and negotiated rates, under current FERC policy is generally not recoverable
from other shippers.
10
Increased competition from alternative natural gas transportation and storage options and
alternative fuel sources could have a significant financial impact on us.
Our ability to renew or replace existing contracts at rates sufficient to maintain current
revenues and cash flows could be adversely affected by activities of other interstate and
intrastate pipelines and storage facilities that may expand or construct competing transportation
and storage systems. In addition, future pipeline transportation and storage capacity could be
constructed in excess of actual demand and with lower fuel requirements, operating and maintenance
costs than our facilities, which could reduce the demand for and the rates that we receive for our
services in particular areas. Further, natural gas also competes with alternative energy sources
available to our customers that are used to generate electricity, such as hydroelectric power,
solar, wind, nuclear, coal and fuel oil.
We also compete as it relates to rates, terms of service, access to natural gas supplies,
flexibility and reliability. The FERCs policies promoting competition may cause us to experience
some turnback of firm capacity as existing agreements with customers expire. If WIC, CIG or SNG
are unable to remarket this capacity or can remarket it only at substantially discounted rates
compared to previous contracts, they may have to bear the costs associated with the turned back
capacity. Increased competition could also reduce the volumes of natural gas transported or stored
or, in cases where we do not have long-term fixed rate contracts, could force us to lower our
rates. All of these competitive pressures could have a material adverse effect on our business,
financial condition, results of operations, and ability to make distributions.
Competition in more actively priced markets from pipelines that may be able to provide our shippers
with capacity at a lower price could cause us to reduce our rates or otherwise reduce our revenues.
We face competition from other pipelines, including the Rockies Express Pipeline, that may be
able to provide our shippers with capacity on a more competitive basis or access to consuming
markets that would pay a higher price for the shippers gas. An increase in competition in our key
markets could arise from new ventures or expanded operations from existing competitors. As a
result, significant competition from the Rockies Express Pipeline and other third-party competitors
could have a material adverse effect on our financial condition, results of operations and ability
to make distributions.
Any significant decrease in supplies of natural gas in our areas of operation could adversely
affect our business and operating results and reduce our cash available for distribution to
unitholders.
All of our businesses are dependent on the continued availability of natural gas production
and reserves. Low prices for natural gas or regulatory limitations could adversely affect
development of additional reserves and production that are accessible by our pipeline and storage
assets. Production from existing wells and natural gas supply basins with access to our pipelines
will naturally decline over time without development of additional reserves. Additionally, the
amount of natural gas reserves underlying these wells may also be less than anticipated, and the
rate at which production from these reserves declines may be greater than anticipated. Accordingly,
to maintain or increase the volume of natural gas transported, or throughput, on our pipelines and
cash flows associated with the transportation of gas, our customers must continually obtain new
supplies of natural gas. For example, if expected increases of natural gas supplies in the U.S.
Rocky Mountain region do not materialize or there is a decline in supply from such producing region
to our interstate pipelines that is not replaced with new supplies, our operating results and our
cash available for distribution could be adversely affected as our firm contracts expire.
A substantial portion of the revenues of our pipeline businesses are generated from transportation
contracts that must be renegotiated periodically.
Substantially
all of our pipeline revenues are generated under contracts which expire
periodically and must be renegotiated and extended or replaced. If we or El Paso are unable to
extend or replace these contracts when they expire or renegotiate contract terms as favorable as
the existing contracts, we could suffer a material reduction in our revenues, earnings and cash
flows. For additional information on the expiration of our contract portfolio, see Part II, Item 7,
Managements Discussion and Analysis of Financial Condition and Results of Operations. In
particular, our ability to extend and replace contracts on terms comparable to prior contracts or
on any terms at all, could be adversely affected by factors we cannot control, as discussed in more
detail above.
11
Our systems rely on a limited number of customers for a significant portion of our revenues.
For the year ended December 31, 2009, the four largest natural gas transportation customers for
each of WIC, CIG and SNG accounted for approximately 71 percent, 60 percent and 44 percent of their
respective operating revenues. The loss of all or even a portion of the contracted volumes of these
customers, as a result of competition, creditworthiness, inability to negotiate extensions, or
replacements of contracts or otherwise, could have a material adverse effect on our financial
condition, results of operations and our ability to make distributions.
Fluctuations in energy commodity prices could adversely affect our business.
Revenues generated by our transportation and storage contracts depend on volumes and rates,
both of which can be affected by the price of natural gas. Increased natural gas prices could
result in a reduction of the volumes transported by our customers, including power companies that
may not dispatch natural gas-fired power plants if natural gas prices increase. Increased prices
could also result in industrial plant shutdowns or load losses to competitive fuels as well as
local distribution companies loss of customer base. On the other hand, decreased natural gas
prices could result in reduced development of additional gas supplies and in reduced volume of
natural gas available for transportation and storage through our system.
Pricing volatility may, in some cases for CIG or WIC, impact our fuel imbalance revaluations
and related gas balance items. We obtain in-kind fuel reimbursements from shippers in accordance
with each individual tariff or applicable contract terms. We revalue our natural gas imbalances and
other gas owed to or from shippers to an index price and periodically settle these obligations in
cash pursuant to each individual tariff, regulatory approval or each balancing contract. Currently, both
the CIG and WIC tariffs provide that the difference between the quantity of fuel retained and fuel
used in operations will be flowed-through or charged to shippers. The CIG tariff provides that all
liquid revenue proceeds, including those proceeds associated with CIGs processing plants, are used
to reimburse shrinkage or other system fuel and lost-or-unaccounted-for costs and variations in
liquid revenues and variations in shrinkage volumes are included in the reconciliation of retained
fuel and burned fuel. CIG must purchase gas volumes from time to time due, in part, to such
shrinkage associated with liquid production and such expenses vary with both price and quantity.
If natural gas prices in the supply basins connected to our pipeline system are higher than
prices in other natural gas producing regions, our ability to compete with other transporters may
be negatively impacted on a short-term basis, as well as with respect to our long-term
recontracting activities. Furthermore, fluctuations in pricing between supply sources and market
areas could negatively impact our transportation revenues. Consequently, a significant prolonged
downturn in natural gas prices could have a material adverse effect on our financial condition,
results of operations and ability to make distributions.
Fluctuations in energy prices are caused by a number of factors, including:
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regional, domestic and international supply and demand, including changes in
supply and demand due to general economic conditions and weather; |
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availability and adequacy of gathering, processing and transportation facilities; |
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energy legislation and regulation, including potential changes associated with
greenhouse gas (GHG) emissions and renewable portfolio standards; |
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federal and state taxes, if any, on the transportation and storage of natural
gas; |
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the price and availability of supplies of alternative energy sources; and |
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the level of imports, including the potential impact of political unrest among
countries producing oil and LNG, as well as the ability of certain foreign countries to
maintain natural gas and oil price, production and export controls. |
12
Adverse general domestic economic conditions could negatively affect our operating results,
financial condition, liquidity or our ability to make cash distributions.
We are subject to the risks arising from adverse changes in general domestic economic
conditions including recession or economic slowdown. The global economy is experiencing a recession
and the financial markets have experienced extreme volatility and instability. If we experience
prolonged periods of recession or slowed economic growth in the United States, demand growth from
consumers for natural gas transported by us may continue to decrease, which could impact the
development of our future expansion projects. Additionally, our access to capital could be impeded
and the cost of capital we obtain could be higher. We are also subject to the risks arising from
changes in legislation and government regulation associated with any such recession or economic
slowdown, including creating preferences for renewables, as part of a legislative package to
stimulate the economy. Any of these events, which are beyond our control, could negatively impact
our business, results of operations, financial condition, and ability to make cash distributions.
We are exposed to the credit risk of our customers and our credit risk management may not be
adequate to protect against such risk.
We are subject to the risk of delays in payment as well as losses resulting from nonpayment
and/or nonperformance by our customers, including default risk associated with adverse economic
conditions. Our credit procedures and policies may not be adequate to fully eliminate customer
credit risk. In addition, in certain situations, we may assume certain additional credit risks for
competitive reasons or otherwise. If our existing or future customers fail to pay and/or perform
and we are unable to re-market the capacity, our business, results of operations, financial
condition and ability to make cash distributions could be adversely affected. We may not be able to
effectively re-market capacity during and after insolvency proceedings involving a shipper.
We are exposed to the credit and performance risk of our key contractors and suppliers.
As an owner of large energy infrastructure, including significant capital expansion programs,
we rely on contractors for certain construction and drilling operations and we rely on suppliers
for key materials and supplies, including steel mills and pipe manufacturers. There is a risk that
such contractors and suppliers may experience credit and performance issues that could adversely
impact their ability to perform their contractual obligations with us. This could result in delays
or defaults in performing such contractual obligations, which could adversely impact our financial
condition and results of operations.
SNG is not prohibited from incurring indebtedness, which may affect our ability to make
distributions.
SNG is not prohibited by the terms of its general partnership agreement from incurring
indebtedness. If SNG were to incur significant amounts of additional indebtedness, it may inhibit
its ability to make distributions to us which would materially and adversely affect our ability to
make our minimum quarterly distributions because we expect SNGs distributions to us will be a
significant portion of the cash we distribute.
Restrictions in our credit facility and note purchase agreement could limit our ability to make
distributions to our unitholders. The conditions of the U.S. and international capital markets may
adversely affect our ability to draw on our current credit facility.
Our credit facility and the note purchase agreement related to our issuance of senior
unsecured notes contain covenants limiting our ability to make distributions to our unitholders and
equity repurchases. Our ability to comply with any restrictions and covenants may be affected by
events beyond our control, including prevailing economic, financial and industry conditions. If we
are unable to comply with these restrictions and covenants, a significant portion of indebtedness
under our credit facility or the note purchase agreement may become immediately due and payable,
and our lenders commitment to make further loans to us under our credit facility may terminate. We
might not have, or be able to obtain, sufficient funds to make these accelerated payments. For a
further discussion of our covenants related to our debt obligations, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 6.
13
In September 2008, Lehman Brothers Holdings Inc., whose subsidiaries have a $48 million credit
commitment under the credit facility, filed for bankruptcy. We have determined the potential
exposure to a loss of available capacity under the credit facility to be approximately $15 million.
If other financial institutions that have extended credit commitments to us and our subsidiaries
are adversely affected by the conditions of the U.S. and international capital markets, they may
become unable to fund borrowings under their credit commitments, which could have a material and
adverse impact on our financial condition and our ability to borrow additional funds, if needed.
Our payment of principal and interest on any future indebtedness will reduce our cash
available for distribution on our units. Further, our credit facility limits our ability to pay
distributions to our unitholders during an event of default or if an event of default would result
from the distribution.
In addition, any future levels of indebtedness may:
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adversely affect our ability to obtain additional financing for future operations or
capital needs; |
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limit our ability to pursue acquisitions and other business opportunities; or |
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make our results of operations more susceptible to adverse economic or operating
conditions. |
Various limitations in any future financing agreements may reduce our ability to incur
additional indebtedness, to engage in some transactions or to capitalize on business opportunities.
Increases in interest rates and general volatility in the financial markets and economy could
adversely impact our unit price, our ability to make distributions and our ability to issue
additional equity to make acquisitions, incur debt or for other purposes.
We cannot predict how interest rates will react to changing market conditions and potential
deficits of federal and state governments. Interest rates on our credit facilities, variable rate
senior unsecured notes and future debt offerings could be higher than current levels, causing our
financing costs to increase accordingly. As with other yield-oriented securities, our unit price is
impacted by the level of our cash distributions and implied distribution yield. The distribution
yield is often used by investors to compare and rank related yield-oriented securities for
investment decision-making purposes. Therefore, changes in interest rates may affect the yield
requirements of investors who invest in our units, and a rising interest rate environment could
have an adverse impact on our unit price and our ability to issue additional equity to make
acquisitions, to incur debt or for other purposes. In addition, the general volatility in the
financial markets and economy may also alter the yield requirements of investors and could
adversely impact our unit price.
The credit and risk profile of our general partner and its owner, El Paso, could adversely affect
our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability
to raise capital.
Any adverse change in the financial condition of El Paso, including the degree of its
financial leverage and its dependence on cash flow from the partnership to service its
indebtedness, may adversely affect our credit ratings and risk profile.
If we were to seek credit ratings in the future, our credit ratings may be adversely affected
by the leverage of our general partner or El Paso, as credit rating agencies such as Standard &
Poors Ratings Services and Moodys Investors Service may consider the leverage and credit profile of El Paso and its
affiliates because of their ownership interest in and control of us and the strong operational
links between El Paso and us. The ratings assigned to El Pasos senior unsecured indebtedness are
below investment grade. The ratings assigned to both CIGs and SNGs senior unsecured indebtedness
by Moodys Investor Services and Fitch Ratings are currently investment grade, with a Baa3 and a
BBB- rating. Standard & Poors has assigned a below investment grade rating of BB to CIGs and
SNGs senior unsecured indebtedness. El Paso and all of its subsidiaries, including CIG and SNG,
are (i) on a stable outlook with Moodys Investor Service and Fitch Ratings and (ii) on a negative
outlook with Standard & Poors. There is a risk that these credit ratings may be adversely affected in the
future as the credit rating agencies continue to review El Pasos, CIGs and SNGs leverage,
liquidity and credit profile. Any reduction in El Pasos, CIGs or SNGs credit ratings could impact our ability to access the capital
markets, as well as our cost of capital.
14
If our systems do not successfully complete expansion projects or make and integrate acquisitions
that are accretive, our future growth may be limited.
A principal focus of our strategy is to continue to grow the cash distributions on our units
by expanding our business. Our ability to grow depends on our ability to complete expansion
projects and make acquisitions that result in an increase in cash per unit generated from
operations. We may be unable to successfully complete accretive expansion projects or acquisitions,
which could adversely affect our financial position, results of operations and ability to make
distributions, for any of the following reasons:
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unable to identify attractive expansion projects or acquisition candidates or we are
outbid by competitors; |
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El Paso elects not to sell or contribute additional interests in its pipeline systems
that it owns to us or to offer attractive expansion projects or acquisition candidates to
us; |
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unable to identify attractive acquisitions that are accretive to our limited partner
unitholders due to the incentive distributions to our general partner; |
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unable to obtain necessary approvals by the FERC and other regulatory agencies on a
timely basis and on terms that are acceptable to us, including the potential impact of
delays and increased costs or such approvals caused by certain environmental and landowner
groups with interests along the route of our pipelines; |
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impediments on our ability to obtain necessary rights of way or land rights or to
commence and complete construction on a timely basis or on terms that are acceptable to us; |
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unable to realize anticipated costs savings and successful integration of the
businesses we build or acquire; |
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unable to raise financing for expansion projects or acquisitions on economically
acceptable terms, especially in periods of prolonged economic decline; |
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mistaken assumptions about volumes, revenues and costs, including synergies and
potential growth; |
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unable to secure adequate transportation, storage or throughput commitments to support
the expansion or acquisition of new facilities; |
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the assumption of unknown liabilities when making acquisitions for which we are not
indemnified or for which our indemnity is inadequate; |
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the diversion of managements and employees attention to other business concerns; |
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unforeseen difficulties operating in new product areas or new geographic areas
including opposition to energy infrastructure development, especially in environmentally
sensitive areas; |
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there is a lack of available of skilled labor, equipment, and materials to complete
expansion projects; |
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potential changes in federal, state and local statutes and regulations, such as
environmental requirements, including climate change requirements, that delay or prevent a
project from proceeding or increase the anticipated cost of the project; |
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our ability to construct expansion projects within anticipated costs, including the
risk that we may incur cost overruns resulting from inflation or increased costs of
equipment, materials, labor, a lack of contractor productivity, delays in construction or
other factors beyond our control, that may be material; and |
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the lack of future growth in natural gas supply or demand. |
Any of these risks could prevent a project from proceeding, delay its completion or increase
its anticipated costs. There is also the risk that the downturn in the economy and its negative
impact upon natural gas demand may result in either slower development in our expansion projects or
adjustments in the contractual commitments supporting such projects. As a result, new facilities
may be delayed or may not achieve our expected investment return, which could adversely affect our
results of operations, cash flows, financial position and our ability to make distributions.
15
The amount of cash we have available for distribution depends primarily on our cash flow and not
solely on profitability, which may prevent us from making cash distributions during periods when we
record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow,
including cash flow from financial reserves and working capital or other borrowings, and not solely
on profitability, which will be affected by non-cash items. As a result, we may make cash
distributions during periods when we record net losses for financial accounting purposes and may
not make cash distributions during periods when we record net earnings for financial accounting
purposes.
We do not own all of the land on which our pipelines and facilities are located, which could
disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and
we are therefore subject to the possibility of more onerous terms and/or increased costs to retain
necessary land use if we do not have valid rights-of-way, if such rights-of-way lapse or terminate
or if our facilities are not properly located within the boundaries of such rights-of-way. Although
many of these rights are perpetual in nature, we occasionally obtain the rights to construct and
operate our pipelines on land owned by third parties and governmental agencies for a specific
period of time. Our loss of these rights, through our inability to renew right-of-way contracts or
otherwise, could have a material adverse effect on our business, results of operations and
financial condition and our ability to make cash distributions.
Our operations are subject to operational hazards and uninsured risks.
Our operations are subject to the inherent risks normally associated with those operations,
including pipeline failures, pollution, release of toxic substances, fires, adverse weather
conditions (such as hurricanes and flooding), terrorist activity or acts of aggression, and other
hazards. Each of these risks could result in damage to or destruction of our facilities or damages
or injuries to persons and property causing us to suffer substantial losses. In addition, although
the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are
uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse
gas could have a negative impact upon our operations in the future.
While we maintain insurance against many of these risks to the extent and in amounts that we
believe are reasonable, our insurance coverages have material deductibles and self-insurance
levels, limits on our maximum recovery, and do not cover all risks. There is also the risk that our
coverages will change over time in light of increased premiums or changes in the terms of the
insurance coverages that could result in our decision to either terminate certain coverages,
increase our deductibles and self-insurance levels or decrease our maximum recoveries. In addition,
there is a risk that our insurers may default on their coverage obligations. As a result, our
financial condition and ability to make cash distributions could be adversely affected if a
significant event occurs that is not fully covered by insurance.
Environmental compliance and remediation costs and the costs of environmental liabilities could
exceed our estimates.
Our natural gas transportation, storage and processing activities are subject to stringent and
complex federal, state and local environmental laws and regulations. We may incur substantial costs
in order to conduct our operations in compliance with these laws and regulations. For instance, we
may be required to obtain and maintain permits and approvals issued by various federal, state and
local governmental authorities; limit or prevent releases of materials from our operations in
accordance with these permits and approvals; and install pollution control equipment. Also, under
certain environmental laws and regulations, we may be exposed to potentially substantial
liabilities for any pollution or contamination that may result from our operations. Moreover, new,
stricter environmental laws, regulations or enforcement policies could be implemented that
significantly increase our compliance costs or the cost of any remediation of environmental
contamination that may become necessary, and these costs could be material.
16
In estimating our environmental liabilities, we face uncertainties that include:
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estimating pollution control and clean up costs, including sites where preliminary site
investigation or assessments have been completed; |
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discovering new sites or additional information at existing sites; |
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forecasting cash flow timing to implement proposed pollution control and cleanup costs; |
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receiving regulatory approval for remediation programs; |
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quantifying liability under environmental laws that may impose joint and several
liability on potentially responsible parties and managing allocation responsibilities; |
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evaluating and understanding environmental laws and regulations, including their
interpretation and enforcement; |
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interpreting whether
various maintenance activities performed in the past and currently being performed require
pre-construction permits pursuant to the Clean Air Act; and |
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changing environmental laws and regulations that may increase our costs. |
In addition to potentially increasing the cost of our environmental liability, changing
environmental laws and regulations may increase our future compliance costs, such as the costs of
complying with ozone standards, emission standards with regard to our reciprocating internal
combustion engines on our pipeline systems, GHG reporting and potential mandatory GHG emissions
reductions. Future environmental compliance costs relating to GHGs associated with our operations
are not yet clear. For a further discussion on GHGs see Part II, Item 7, Managements Discussion
and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies.
Although it is uncertain what impact legislative, regulatory, and judicial actions might have
on us until further definition is provided in those forums, there is a risk that such future
measures could result in changes to our operations and to the consumption and demand for natural
gas. Changes to our operations could include increased costs to (i) operate and maintain our
facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities,
(iv) acquire allowances or pay taxes related to our GHG and other emissions and (v) administer and
manage an emissions program for GHG and other emissions. Changes in regulations, including adopting
new standards for emission controls for certain of our facilities, could also result in delays in
obtaining required permits to construct or operate our facilities. While we may be able to include
some or all of the costs associated with our environmental liabilities and environmental compliance
in the rates charged by our pipelines, our ability to recover such costs is uncertain and may
depend on events beyond our control including the outcome of future rate proceedings before the
FERC and the provisions of any final regulations and legislation.
Risks Inherent in Our Structure and Relationship with El Paso
El Paso controls our general partner, which has sole responsibility for conducting our business and
managing our operations. Our general partner and its affiliates, including El Paso, have conflicts
of interest with us and limited fiduciary duties, and they may favor their own interests to the
detriment of our unitholders.
El Paso owns and controls our general partner, and appoints all of the directors of our
general partner. Some of our general partners directors, and some of its executive officers, are
directors or officers of El Paso or its affiliates. Although our general partner has a fiduciary
duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of
our general partner have a fiduciary duty to manage our general partner in a manner beneficial to
El Paso. Therefore, conflicts of interest may arise between El Paso and its affiliates, including
our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving
these conflicts of interest, our general partner may favor its own interests and the interests of
its affiliates over the interests of our unitholders.
17
Affiliates of our general partner, including El Paso and its other subsidiaries, are not limited in
their ability to compete with us and are not obligated to offer us the opportunity to pursue
additional assets or businesses, which could limit our commercial activities or our ability to
acquire additional assets or businesses.
Neither our partnership agreement nor the omnibus agreement among us, El Paso and others will
prohibit affiliates of our general partner, including El Paso, El Paso Natural Gas Company (EPNG),
Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains) and TGP, from owning assets or
engaging in businesses that compete directly or indirectly with us. In addition, El Paso and its
affiliates may acquire, construct or dispose of additional transportation or other assets in the
future, without any obligation to offer us the opportunity to purchase or construct any of those
assets. Each of these entities is a large, established participant in the interstate pipeline
and/or storage business, and each may have greater resources than we have, which factors may make
it more difficult for us to compete with these entities with respect to commercial activities as
well as for acquisition candidates. As a result, competition from these entities could adversely
impact our results of operations and cash available for distribution.
Holders of our common units have limited voting rights and are not entitled to elect our general
partner or its directors, which could reduce the price at which the common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting
rights on matters affecting our business and, therefore, limited ability to influence managements
decisions regarding our business. Unitholders will not elect our general partner or its board of
directors, and will have no right to elect our general partner or its board of directors on an
annual or other continuing basis. The board of directors of our general partner, including the
independent directors, will be chosen entirely by its owners and not by the unitholders. Unlike
publicly traded corporations, we will not conduct annual meetings of our unitholders to elect
directors or conduct other matters routinely conducted at such annual meetings of stockholders.
Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they
will have little ability to remove our general partner. As a result of these limitations, the price
at which the common units will trade could be diminished because of the absence or reduction of a
takeover premium in the trading price.
Cost reimbursements to our general partner and its affiliates for services provided, which will be
determined by our general partner, will be substantial and will reduce our cash available for
distribution.
Pursuant to an omnibus agreement we entered into with El Paso, our general partner and certain
of their affiliates, El Paso and its affiliates will receive reimbursement for the payment of
operating and capital expenses related to our operations and for the provision of various general
and administrative services for our benefit, including costs for rendering administrative staff and
support services to us, and overhead allocated to us, which amounts will be determined by the
general partner in good faith. Payments for these services will be substantial and will reduce the
amount of cash available for distribution to unitholders. In addition, WIC reimburses CIG for the
costs incurred to operate and maintain the WIC system pursuant to an operating agreement. CIG also
reimburses certain of its affiliates for costs incurred and services it receives (primarily from
EPNG and TGP) and receives reimbursements for costs incurred and services it provides to other
affiliates (primarily Cheyenne Plains and Young Gas Storage Company Ltd.). Similarly, the El Paso subsidiary that is the operator and
general partner of CIG or SNG will be entitled to be reimbursed for the costs incurred to operate
and maintain such system. In addition, under Delaware partnership law, our general partner has
unlimited liability for our obligations, such as our debts and environmental liabilities, except
for our contractual obligations that are expressly made without recourse to our general partner. To
the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or
indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our
general partner may take actions to cause us to make payments of these obligations and liabilities.
Any such payments could reduce the amount of cash otherwise available for distribution to our
unitholders.
18
Our partnership agreement limits our general partners fiduciary duties to holders of our common
units and subordinated units and restricts the remedies available to holders of our common units
and subordinated units for actions taken by our general partner that might otherwise constitute
breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the fiduciary standards to which our
general partner would otherwise be held by state fiduciary duty laws. The limitation and definition
of these duties is permitted by the Delaware law governing limited partnerships. In addition, the
general partnership agreements of CIG and SNG contain similar provisions that define the fiduciary
standards of each partner (a subsidiary of El Paso owns a 42 percent and 75 percent general partner interest in CIG and SNG, and we own a 58 percent and
25 percent general partner interest in CIG and SNG) to the other. In addition, the general
partnership agreements include provisions that define the fiduciary standards that the members of
the management committee of each such partnership appointed by a partner (El Paso has appointed one
member to CIGs committee and three members to SNGs committee, and we have appointed three members
to CIGs committee and one member to SNGs committee) owe to the partners that did not designate
such person. In both instances, the defined fiduciary standards are more limited than those that
would apply under Delaware law in the absence of such definition.
Limited unitholders cannot remove our general partner without its consent.
The vote of the holders of at least 662/3 percent of all outstanding common and subordinated
units voting together as a single class is required to remove our general partner. Our general
partner and its affiliates own 61 percent of our aggregate outstanding common and subordinated units. Accordingly, our
unitholders are currently unable to remove our general partner without its consent because
affiliates of our general partner own sufficient units to be able to prevent the general partners
removal. Also, if our general partner is removed without cause during the subordination period and
units held by our general partner and its affiliates are not voted in favor of that removal, all
remaining subordinated units will automatically be converted into common units and any existing
arrearages on the common units will be extinguished. In addition, under certain circumstances the
successor general partner may be required to purchase the combined general partner interest and
incentive distribution rights of the removed general partner, or alternatively, such interests will
be converted into common units. A removal of our general partner under these circumstances would
adversely affect the common units by prematurely eliminating their distribution and liquidation
preference over the subordinated units, which would otherwise have continued until we had met
certain distribution and performance tests.
Our general partner may elect to cause us to issue Class B common units to it in connection with a
resetting of the target distribution levels related to our general partners incentive distribution
rights without the approval of the conflicts committee of our general partner or holders of our
common units and subordinated units. This may result in lower distributions to holders of our
common units in certain situations.
Our general partner has the right, at a time when there are no subordinated units outstanding
and it has received incentive distributions at the highest level to which it is entitled (48
percent) for each of the prior four consecutive fiscal quarters, to reset the initial cash target
distribution levels at higher levels based on the distribution at the time of the exercise of the
reset election. Following a reset election by our general partner, the minimum quarterly
distribution amount will be reset to an amount equal to the average cash distribution amount per
common unit for the two fiscal quarters immediately preceding the reset election (such amount is
referred to as the reset minimum quarterly distribution) and the target distribution levels will
be reset to correspondingly higher levels based on percentage increases above the reset minimum
quarterly distribution amount.
19
In connection with resetting these target distribution levels, our general partner will be
entitled to receive a number of Class B common units. The Class B common units will be entitled to
the same cash distributions per unit as our common units and will be convertible into an equal
number of common units. The number of Class B common units to be issued will be equal to that
number of common units whose aggregate quarterly cash distributions equaled the average of the
distributions to our general partner on the incentive distribution rights in the prior two
quarters. We anticipate that our general partner would exercise this reset right in order to
facilitate acquisitions or internal growth projects that would not be sufficiently accretive to
cash distributions per common unit without such conversion; however, it is possible that our
general partner could exercise this reset election at a time when it is experiencing, or may be
expected to experience, declines in the cash distributions it receives related to its incentive
distribution rights and may therefore desire to be issued our Class B common units, which are
entitled to receive cash distributions from us on the same priority as our common units, rather
than retain the right to receive incentive distributions based on the initial target distribution
levels. As a result, a reset election may cause our common unitholders to experience dilution in
the amount of cash distributions that they would have otherwise received had we not issued new
Class B common units to our general partner in connection with resetting the target distribution
levels related to our general partner incentive distribution rights.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or
in a sale of all or substantially all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the ability of the members of our general
partner from transferring their member interest in our general partner to a third party. The new
owners of our general partner would then be in a position to replace the board of directors and
officers of the general partner with their own choices and to control the decisions taken by the
board of directors and officers of the general partner. This effectively permits a change of
control of the partnership without unitholders vote or consent. In addition, pursuant to the
omnibus agreement with El Paso, any new owner of the general partner would be required to change
our name so that there would be no further reference to El Paso.
If we are deemed an investment company under the Investment Company Act of 1940, it would
adversely affect the price of our common units and could have a material adverse effect on our
business.
Our assets consist of a 100 percent ownership interest in WIC, a 58 percent general partner
interest in CIG and a 25 percent general partner interest in SNG. If a sufficient amount of our
assets, such as our ownership interests in CIG or SNG or other assets acquired in the future, are
deemed to be investment securities within the meaning of the Investment Company Act of 1940, we
would either have to register as an investment company under the Investment Company Act, obtain
exemptive relief from the SEC or modify our organizational structure or our contract rights to fall
outside the definition of an investment company. Although general partner interests are typically
not considered securities or investment securities, there is a risk that our ownership interests
in CIG and SNG could be deemed investment securities. In that event, it is possible that our
ownership of these interests, combined with our assets acquired in the future, could result in our
being required to register under the Investment Company Act if we were not successful in obtaining
exemptive relief or otherwise modifying our organizational structure or applicable contract rights.
Registering as an investment company could, among other things, materially limit our ability to
engage in transactions with affiliates, including the purchase and sale of certain securities or
other property to or from our affiliates, restrict our ability to borrow funds or engage in other
transactions involving leverage and require us to add additional directors who are independent of
us or our affiliates. The occurrence of some or all of these events would adversely affect the
price of our common units and could have a material adverse effect on our business.
Moreover, treatment of us as an investment company would prevent our qualification as a
partnership for federal income tax purposes in which case we would be treated as a corporation for
federal income tax purposes. As a result, we would pay federal income tax on our taxable income at
the corporate tax rate, distributions would generally be taxed again as corporate distributions and
none of our income, gains, losses or deductions would flow through. Because a tax would be imposed
upon us as a corporation, our cash available for distribution would be substantially reduced.
Therefore, treatment of us as an investment company would result in a material reduction in the
anticipated cash flow and after-tax return to the unitholders, likely causing a substantial
reduction in the value of our common units.
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We may issue additional units without approval which would dilute existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests
that we may issue at any time without the approval of our unitholders. The issuance by us of
additional common units or other equity securities of equal or senior rank will have the following
effects:
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each unitholders proportionate ownership interest in us will decrease; |
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the amount of cash available for distribution on each unit may decrease; |
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because a lower percentage of total outstanding units will be subordinated units, the
risk that a shortfall in the payment of the minimum quarterly distribution will be borne by
our common unitholders will increase; |
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the ratio of taxable income to distributions may increase; |
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new classes of securities could be issued that provide preferences to the new class in
relation to existing unitholders, including preferences on distributions of available cash,
distributions upon our liquidation and voting rights; |
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the relative voting strength of each previously outstanding unit may be diminished; and |
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the market price of the common units may decline. |
Our general partner has a limited call right that may require unitholders to sell common units at
an undesirable time or price.
If at any time our general partner and its affiliates own more than 75 percent of the common
units excluding, until September 30, 2010, common units received by El Pasos affiliates in
connection with El Pasos contribution to us of additional general partner interest in each of CIG
and SNG in September 2008, our general partner will have the right, but not the obligation, which
it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the
common units held by unaffiliated persons at a price not less than their then-current market price.
As a result, unitholders would be required to sell common units at an undesirable time or price and
may not receive any return on investment. Unitholders might also incur a tax liability upon a sale
of such units. Our general partner is not obligated to obtain a fairness opinion regarding the
value of the common units to be repurchased by it upon exercise of the limited call right. There is
no restriction in our partnership agreement that prevents our general partner from issuing
additional common units and exercising its call right. If our general partner exercised its limited
call right, the effect would be to take us private and, if the units were subsequently
deregistered, we would no longer be subject to the reporting requirements of the Securities
Exchange Act of 1934. Our general partner and its affiliates own approximately 51 percent of our
outstanding common units. At the end of the subordination period, assuming no additional issuances
of common units (other than for the conversion of the subordinated units into common units), our
general partner and its affiliates will own approximately 61 percent of our aggregate outstanding
common units.
Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of
our common units.
Our partnership agreement restricts unitholders voting rights by providing that any units
held by a person that owns 20 percent or more of any class of units then outstanding, other than
our general partner and its affiliates, their transferees and persons who acquired such units with
the prior approval of the board of directors of our general partner, cannot vote on any matter. The
partnership agreement also contains provisions limiting the ability of unitholders to call meetings
or to acquire information about our operations, as well as other provisions limiting the
unitholders ability to influence the manner or direction of management.
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Unitholder liability may not be limited if a court finds that unitholder action constitutes control
of our business.
A general partner of a partnership generally has unlimited liability for the obligations of
the partnership, except for those contractual obligations of the partnership that are expressly
made without recourse to the general partner. Our partnership is organized under Delaware law and
we conduct business in a number of other states. The limitations on the liability of holders of
limited partner interests for the obligations of a limited partnership have not been clearly
established in some of the other states in which we do business. Unitholders could be liable for
any and all of our obligations as if they were a general partner if a court or government agency
determined that:
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we were conducting business in a state but had not complied with that particular
states partnership statute; or |
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unitholders right to act with other unitholders to remove or replace the general
partner, to approve some amendments to our partnership agreement or to take other actions
under our partnership agreement constitute control of our business. |
The market price of our common units could be adversely affected by sales of substantial amounts of
our common units in the public or private markets, including sales by affiliates of our general
partner.
As of December 31, 2009, we had 97,622,247 common units and 27,727,411 subordinated units
outstanding, which includes 55,326,397 common units held by affiliates of our general partner. All
of the subordinated units will convert into common units at the end of the subordination period,
which could occur as early as the first business day after December 31, 2010, assuming certain
tests are met, and all of the subordinated units may convert into common units before December 31,
2010 if additional tests are satisfied. Sales by any of our existing unitholders, including
affiliates of our general partner, of a substantial number of our common units in the public
markets, or the perception that such sales might occur, could have a material adverse effect on the
price of our common units or could impair our ability to obtain capital through an offering of
equity securities. Under our partnership agreement, our general partner and its affiliates have
registration rights relating to the offer and sale of any units that they hold, subject to certain
limitations.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well
as our not being subject to a material amount of additional entity-level taxation by states. If the
Internal Revenue Service were to treat us as a corporation or if we become subject to a material
amount of additional entity-level taxation for state tax purposes, then it would substantially
reduce the amount of cash available for distribution to our unitholders.
The anticipated after-tax economic benefit of an investment in the common units depends
largely on our being treated as a partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer
to as the IRS, on this or any other tax matter affecting us.
If we were treated as a corporation for federal income tax purposes, we would pay federal
income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35
percent, and would likely pay state income tax at varying rates. Distributions would generally be
taxed again as corporate distributions, and no income, gains, losses, deductions or credits would
flow through. Because a tax would be imposed upon us as a corporation, our cash available to pay
distributions would be substantially reduced. Thus, treatment of us as a corporation would result
in a material reduction in the anticipated cash flow and after-tax return to the unitholders,
likely causing a substantial reduction in the value of our common units.
Current law may change, causing us to be treated as a corporation for federal income tax
purposes or otherwise subjecting us to entity-level taxation. For example, because of widespread
state budget deficits, several states are evaluating ways to subject partnerships to entity-level
taxation through the imposition of state income, franchise or other forms of taxation. If any state
was to impose a tax upon us as an entity, the cash available to pay distributions would be reduced.
We are, for example, subject to an entity-level tax on the portion of our income that is generated
in Texas. The imposition of such a tax on us by Texas, or any other state, will reduce the cash
available for distribution.
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Our partnership agreement provides that if a law is enacted or existing law is modified or
interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to
entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly
distribution amount and the target distribution amounts will be adjusted to reflect the impact of
that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be
subject to potential legislative, judicial or administrative changes and differing interpretations,
possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us,
or an investment in our common units may be modified by administrative, legislative or judicial
interpretation at any time. For example, in response to certain events that occurred in previous
years, members of Congress have considered substantive changes to the definition of qualifying
income under Section 7704(d) of the Internal Revenue Code. Recently, the House of Representatives
passed the Tax Extenders Act of 2009, H.R. 4213, a bill which includes a provision that would treat
items of income and gain generated by a publicly traded partnership that is engaged in the
performance of investment management services as non-qualifying income. Although we do not
believe that this provision would apply to us as currently drafted, we are unable to predict
whether any changes will be made to the provision or whether the legislation will ultimately be
enacted. Moreover, even if this current proposal is not enacted, it is possible that these efforts
could resume and result in changes to the existing U.S. tax laws that affect publicly traded
partnerships, including us. Any modification to the U.S. federal income tax laws and
interpretations thereof may or may not be applied retroactively. We are unable to predict whether
any of these changes, or other proposals, will ultimately be enacted. Any such changes could
negatively impact the value of an investment in our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our
units each month based upon the ownership of our units on the first day of each month, instead of
on the basis of the date a particular unit is transferred. The IRS may challenge this treatment,
which could change the allocation of items of income, gain, loss and deduction among our
unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees
of our units each month based upon the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is transferred. The use of this proration
method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this
method or new Treasury Regulations were issued, we may be required to change the allocation of
items of income, gain, loss and deduction among our unitholders.
An Internal Revenue Service contest of the federal income tax positions we take may adversely
affect the market for our common units, and the cost of any Internal Revenue Service contest will
reduce our cash available for distribution to our unitholders.
We have not requested any ruling from the IRS with respect to our treatment as a partnership
for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that
differ from the positions we take. It may be necessary to resort to administrative or court
proceedings to sustain some or all of the positions we take. A court may not agree with some or all
the positions we take. Any contest with the IRS may materially and adversely impact the market for
our common units and the price at which they trade. In addition, the costs of any contest with the
IRS will result in a reduction in cash available to pay distributions to our unitholders and our
general partner and thus will be borne indirectly by our unitholders and our general partner.
Unitholders will be required to pay taxes on their share of our income even if they do not receive
any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income
which could be different in amount than cash we distribute, they will be required to pay federal
income taxes and, in some cases, state and local income taxes on their share of our taxable income,
whether or not cash is distributed from us. Cash distributions may not equal a unitholders share
of our taxable income or even equal the actual tax liability that results from the unitholders
share of our taxable income.
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The tax gain or loss on the disposition of our common units could be different than expected.
If our unitholders sell units, they will recognize a gain or loss equal to the difference
between the amount realized and their tax basis in those common units. Prior distributions to them
in excess of the total net taxable income they were allocated for a common unit, which decreased
their tax basis in that common unit, will, in effect, become taxable income to them if the common
unit is sold at a price greater than their tax basis in that common unit, even if the price they
receive is less than their original cost. A substantial portion of the amount realized, regardless
of whether such amount represents gain, may be taxed as ordinary income to our unitholders due to
potential recapture items, including depreciation recapture. In addition, if they sell their units,
they may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may
result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts
(known as IRAs) and non-United States persons raises issues unique to them. For example, virtually
all of our income allocated to organizations that are exempt from federal income tax, including
IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to
them. Distributions to non-United States persons will be reduced by withholding taxes at the
highest applicable effective tax rate, and non-United States persons will be required to file
United States federal income tax returns and pay tax on their share of our taxable income.
Tax-exempt entities or foreign persons should consult their tax advisor regarding their investment
in our common units.
We will treat each purchaser of units as having the same tax benefits without regard to the actual
common units purchased. The IRS may challenge this treatment, which could adversely affect the
value of the common units.
Because we cannot match transferors and transferees of common units, we will adopt
depreciation and amortization positions that may not conform with all aspects of existing Treasury
Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax
benefits available to our unitholders. It also could affect the timing of these tax benefits or the
amount of gain from their sale of our common units and could have a negative impact on the value of
our common units or result in audit adjustments to their tax returns.
We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and
deduction between the general partner and the unitholders. The IRS may challenge this treatment,
which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the
fair market value of our assets and allocate any unrealized gain or loss attributable to our assets
to the capital accounts of our unitholders and our general partner. Our methodology may be viewed
as understating the value of our assets. In that case, there may be a shift of income, gain, loss
and deduction between certain unitholders and the general partner, which may be unfavorable to such
unitholders. Moreover, under our methodologies subsequent purchasers of common units may have a
greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible
assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods,
or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible
assets, and allocations of income, gain, loss and deduction between the general partner and certain
of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount
of taxable income or loss being allocated to our unitholders. It also could affect the amount of
gain from our unitholders sale of common units and could have a negative impact on the value of
the common units or result in audit adjustments to our unitholders tax returns without the benefit
of additional deductions.
The sale or exchange of 50 percent or more of our capital and profits interests during any 12-month
period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if
there is a sale or exchange of 50 percent or more of the total interests in our capital and profits
within a twelve-month period. Our termination would, among other things, result in the closing of
our taxable year for all unitholders and could result in a deferral of depreciation deductions
allowable in computing our taxable income.
24
Unitholders will likely be subject to state and local taxes and return filing requirements in
states where they do not live as a result of their investment in our common units.
In addition to federal income taxes, unitholders will likely be subject to other taxes,
including foreign, state and local taxes, unincorporated business taxes and estate, inheritance, or
intangible taxes that are imposed by the various jurisdictions in which we do business or own
property, even if they do not live in any of those jurisdictions. Unitholders will likely be
required to file state and local income tax returns and pay state and local income taxes in some or
all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to
comply with those requirements. As we make acquisitions or expand our business, we may own assets
or conduct business in additional states that impose an income tax. It is the unitholders
responsibility to file all federal, state and local tax returns.
|
|
|
ITEM 1B. |
|
UNRESOLVED STAFF COMMENTS |
None.
A description of our properties is included in Part I, Item 1, Business, and is incorporated
herein by reference.
We believe that we have satisfactory title to the properties owned and used in our businesses,
subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit
arrangements and easements and restrictions that do not materially detract from the value of these
properties, our interests in these properties, or the use of these properties in our businesses. We
believe that our properties are adequate and suitable for the conduct of our business in the
future.
|
|
|
ITEM 3. |
|
LEGAL PROCEEDINGS |
A description of our legal proceedings is included in Part II, Item 8, Financial Statements
and Supplementary Data, Note 8, and is incorporated herein by reference.
Natural
Buttes. In May 2004, the Environmental Protection Agency
(EPA) issued a Compliance Order to CIG related to alleged
violations of a Title V air permit in effect at CIGs Natural Buttes Compressor Station. In
September 2005, the matter was referred to the U.S. Department of Justice (DOJ). CIG entered into a
tolling agreement with the United States and conducted settlement discussions with the DOJ and the
EPA. While conducting some testing at the facility, CIG discovered that three generators installed
in 1992 may have been emitting oxides of nitrogen at levels which suggested the facility should
have obtained a Prevention of Significant Deterioration (PSD) permit when the generators were first
installed, and CIG promptly reported those test data to the EPA. CIG executed a Consent Decree with
the DOJ and has paid a total of $1.02 million to settle all of these Title V and PSD issues at the
Natural Buttes Compressor Station. In addition, as required by the Consent Decree, ambient air
monitoring at the Uintah Basin commenced on January 1, 2010 for a period of two years.
In November 2009, CIG sold its Natural Buttes compressor station and
gas processing plant to a third party for $9.0 million.
In addition to the above matters, we and our affiliates are named defendants in numerous
lawsuits and governmental proceedings that arise in the ordinary course of our business.
|
|
|
ITEM 4. |
|
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
None.
25
PART II
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our
common units are traded on the New York Stock Exchange under the
symbol EPB. As of February 23, 2010, we had 24 unitholders of record, which does not include beneficial owners
whose shares are held by a clearing agency, such as a broker or bank.
The following table reflects the quarterly high and low sales prices for our common units
based on the daily composite listing of stock transactions for the New York Stock Exchange and the
cash distributions per unit we declared in each quarter:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
Low |
|
Distributions |
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
26.52 |
|
|
$ |
19.98 |
|
|
$ |
0.35000 |
|
Third Quarter |
|
$ |
21.30 |
|
|
$ |
17.14 |
|
|
$ |
0.33000 |
|
Second Quarter |
|
$ |
19.80 |
|
|
$ |
16.53 |
|
|
$ |
0.32500 |
|
First Quarter |
|
$ |
20.00 |
|
|
$ |
14.91 |
|
|
$ |
0.32000 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter |
|
$ |
21.80 |
|
|
$ |
11.95 |
|
|
$ |
0.30000 |
|
Third Quarter |
|
$ |
21.95 |
|
|
$ |
11.72 |
|
|
$ |
0.29500 |
|
Second Quarter |
|
$ |
24.35 |
|
|
$ |
20.57 |
|
|
$ |
0.28750 |
|
First Quarter |
|
$ |
25.00 |
|
|
$ |
18.53 |
|
|
$ |
0.12813 |
|
Cash Distribution Policy. We will distribute to the holders of common and subordinated units
on a quarterly basis at least the minimum quarterly distribution of $0.28750 per common unit ($1.15
per common unit on an annualized basis) to the extent we have sufficient cash from operations after
establishment of cash reserves and payment of fees and expenses, including payments to our general
partner and its affiliates. Our ability to pay cash distributions at this minimum quarterly
distribution rate is subject to various restrictions and other factors. On February 12, 2010, we
paid a distribution of $0.36000 per unit to all unitholders of record at the close of business on
February 1, 2010. Our partnership agreement requires us to distribute all of our cash on hand at
the end of each quarter, less reserves established by our general partner. We refer to this cash as
available cash. Our partnership agreement also requires that we distribute all of our available
cash from operating surplus each quarter in the following manner: first, 98 percent to the holders
of common units and 2 percent to our general partner, until each common unit has received a minimum
quarterly distribution of $0.28750 plus any arrearages from prior quarters; second, 98 percent to
the holders of subordinated units and 2 percent to our general partner, until each subordinated
unit has received a minimum quarterly distribution of $0.28750; and third, 98 percent to all
unitholders, pro rata, and 2 percent to our general partner, until each unit has received a
distribution of $0.33063. If cash distributions to our unitholders exceed $0.33063 per unit in any
quarter, our general partner will receive, in addition to distributions on its 2 percent general
partner interest, increasing percentages, up to 48 percent, of the cash we distribute in excess of
that amount. We refer to these distributions as incentive distributions. Our general partner
received incentive distributions of $0.4 million in 2009. In February 2010, our general partner
received incentive distributions of $0.6 million.
26
Incentive Distribution Rights. Our general partner, as the holder of our incentive
distribution rights, has the right under our partnership agreement to elect to relinquish the right
to receive incentive distribution payments based on the initial cash target distribution levels and
to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution
levels upon which the incentive distribution payments to our general partner would be set. In
connection with this election, our general partner will be entitled to receive a number of newly
issued Class B common units and general partner units based on a predetermined formula. Our general
partners right to reset the minimum quarterly distribution amount and the target distribution
levels upon which the incentive distributions payable to our general partner is based, may be
exercised, without approval of our unitholders or the conflicts committee of our general partner,
at any time when there are no subordinated units outstanding and we have made cash distributions to
the holders of the incentive distribution rights at the highest level of incentive distribution for
each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount
and target distribution levels will be higher than the minimum quarterly distribution amount and
the target distribution levels prior to the reset such that our general partner will not receive
any incentive distributions under the reset target distribution levels until cash distributions per
unit following this event increase.
The following table illustrates the percentage allocations of available cash from operating
surplus between the unitholders and our general partner based on the specified target distribution
levels. The amounts set forth under Marginal Percentage Interest in Distribution are the
percentage interests of our general partner and the unitholders in any available cash from
operating surplus we distribute up to and including the corresponding amount in the column Total
Quarterly Distribution Per Unit Target Amount, until available cash from operating surplus we
distribute reaches the next target distribution level, if any. The percentage interests shown for
the unitholders and the general partner for the minimum quarterly distribution are also applicable
to quarterly distribution amounts that are less than the minimum quarterly distribution. The
percentage interests set forth below for our general partner include its 2 percent general partner
interest and assume our general partner has contributed any additional capital necessary to
maintain its two percent general partner interest and has not transferred its incentive
distribution rights.
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage |
|
|
Total Quarterly |
|
Interest in Distribution |
|
|
Distribution per Unit |
|
|
|
General |
|
|
Target Amount |
|
Unitholders |
|
Partner |
Minimum Quarterly Distribution |
|
$0.28750 |
|
98% |
|
2% |
First Target Distribution |
|
above $0.28750 up to $0.33063 |
|
98% |
|
2% |
Second Target Distribution |
|
above $0.33063 up to $0.35938 |
|
85% |
|
15% |
Third Target Distribution |
|
above $0.35938 up to $0.43125 |
|
75% |
|
25% |
Thereafter |
|
above $0.43125 |
|
50% |
|
50% |
Subordination Period. Our partnership agreement provides that, during the subordination
period, the common units will have the right to receive distributions of available cash from
operating surplus each quarter in an amount equal to $0.28750 per common unit, which is defined in
our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment
of the minimum quarterly distribution on the common units from prior quarters, before any
distributions of available cash from operating surplus may be made on the subordinated units.
Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the
subordinated units is to increase the likelihood that during the subordination period there will be
available cash to be distributed on the common units.
The subordination period will end on the first business day after we have earned and paid at
least $0.43125
(150 percent of the minimum quarterly distribution) on each outstanding limited partner unit
and general partner unit for each quarter in any four quarter period ending or after December 31,
2008, or on the first business day after we have earned and paid at least $0.28750 on each
outstanding limited partner unit and general partner unit for any three consecutive,
non-overlapping four quarter periods ending on or after December 31, 2010. The subordination period
also will end upon the removal of our general partner other than for cause if the units held by our
general partner and its affiliates are not voted in favor of such removal.
27
ITEM 6. SELECTED FINANCIAL DATA
The historical operating results data for each of the four years ended December 31, 2009 and
the financial position data as of December 31, 2009, 2008 and 2007 were derived from our audited
financial statements. We derived the operating results data for the year ended December 31, 2005
and the financial position data as of December 31, 2006 and 2005 from our accounting records. Our
historical results are not necessarily indicative of results to be expected in the future. In
conjunction with our formation on November 21, 2007, El Paso contributed to us 10 percent general
partner interests in CIG and SNG. On September 30, 2008, we acquired an additional 30 percent
general partner interest in CIG and an additional 15 percent general partner interest in SNG from
El Paso. On July 24, 2009, we acquired an additional 18 percent general partner interest in CIG
and, as a result, own a 58 percent general partner interest in CIG. We have the ability to control
CIGs operating and financial decisions and policies and accordingly have consolidated CIG and have
retrospectively adjusted our historical financial statements in all periods to reflect the change
in reporting entity. Prior to November 2007, our historical financial statements only reflect the
operating results and financial position of WIC and CIG. We have recorded our share of SNGs
operating results as earnings from unconsolidated affiliates from the dates we received interests
in SNG. The selected financial data should be read together with Item 7, Managements Discussion
and Analysis of Financial Condition and Results of Operations and Item 8, Financial Statements and
Supplementary Data included in this Report on Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of or for the Year Ended December 31, |
|
|
2009 |
|
2008 |
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
(In millions, except per unit amounts) |
|
|
|
|
Operating Results Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
537.6 |
|
|
$ |
457.2 |
|
|
$ |
418.1 |
|
|
$ |
393.6 |
|
|
$ |
373.9 |
|
Operating income |
|
|
292.5 |
|
|
|
229.8 |
|
|
|
207.8 |
|
|
|
210.6 |
|
|
|
146.9 |
|
Earnings from unconsolidated affiliates(1) |
|
|
53.4 |
|
|
|
32.9 |
|
|
|
4.1 |
|
|
|
0.4 |
|
|
|
|
|
Income from continuing operations |
|
|
279.5 |
|
|
|
234.0 |
|
|
|
169.4 |
|
|
|
152.7 |
|
|
|
106.0 |
|
Net income |
|
|
279.5 |
|
|
|
234.0 |
|
|
|
175.2 |
|
|
|
158.4 |
|
|
|
110.1 |
|
Net income attributable to El Paso Pipeline Partners, L.P. |
|
|
213.5 |
|
|
|
171.6 |
|
|
|
127.9 |
|
|
|
119.0 |
|
|
|
79.6 |
|
Net income attributable to El Paso Pipeline Partners, L.P. per limited
partner unit-basic and diluted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units(2) |
|
$ |
1.64 |
|
|
$ |
1.26 |
|
|
$ |
0.11 |
|
|
$ |
|
|
|
$ |
|
|
Subordinated units(2) |
|
|
1.56 |
|
|
|
1.12 |
|
|
|
0.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions declared per common unit(3) |
|
$ |
1.33 |
|
|
$ |
1.01 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Position Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
$ |
2,018.5 |
|
|
$ |
1,908.1 |
|
|
$ |
1,633.2 |
|
|
$ |
1,347.0 |
|
|
$ |
1,245.2 |
|
Investment in unconsolidated affiliates(1) |
|
|
417.5 |
|
|
|
410.8 |
|
|
|
171.8 |
|
|
|
15.9 |
|
|
|
|
|
Total assets |
|
|
2,668.2 |
|
|
|
2,675.8 |
|
|
|
2,585.8 |
|
|
|
2,310.9 |
|
|
|
2,135.3 |
|
Long-term debt and other financing obligations, less current maturities |
|
|
1,357.6 |
|
|
|
1,357.3 |
|
|
|
1,037.7 |
|
|
|
608.2 |
|
|
|
708.6 |
|
Total partners capital |
|
|
1,161.6 |
|
|
|
1,117.4 |
|
|
|
1,351.7 |
|
|
|
1,236.7 |
|
|
|
1,083.6 |
|
|
|
|
(1) |
|
El Paso contributed to us 10 percent general partner interests in SNG on
November 21, 2007. On September 30, 2008, we acquired an additional 15 percent general partner
interest in SNG from El Paso, as further described in Item 8, Financial Statements and
Supplementary Data, Note 2. |
|
(2) |
|
Earnings per unit in 2007 are based on income allocable to us subsequent to
completion of our initial public offering. |
|
(3) |
|
In 2007, there were no distributions declared or paid per common unit. |
28
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
Our Managements Discussion and Analysis (MD&A) should be read in conjunction with our
consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking
statements that are subject to risks and uncertainties that may result in actual results differing
from the statements we make. These risks and uncertainties are discussed further in Part 1, Item
1A, Risk Factors.
In November 2007, we completed an initial public offering of 28.8 million common units. In
conjunction with our formation, El Paso contributed to us 100 percent of WIC, an interstate natural
gas system, as well as 10 percent general partner interests in each of El Pasos SNG and CIG
interstate natural gas pipeline systems. On July 24, 2009 and September 30, 2008, we acquired 18
percent and 30 percent general partner interests in CIG, respectively, from El Paso. Subsequent to
the July 2009 acquisition, we own a 58 percent general partner interest in CIG and have the ability
to control its operating and financial decisions and policies. Accordingly, we have consolidated
CIG and retrospectively adjusted our historical financial statements in all periods to reflect the
change in reporting entity. We have reflected El Pasos 42 percent general partner interest in CIG
as a non-controlling interest in our financial statements for all periods presented. The
transaction was accounted for as a reorganization of entities under common control. We began
recording earnings from unconsolidated affiliates from our 10 percent ownership interest in SNG
from the date of its contribution in November 2007. Effective September 30, 2008, we acquired from
El Paso an additional 15 percent general partner interest in SNG. We accounted for the acquisition
of our additional equity interest in SNG prospectively beginning on September 30, 2008. For a
further discussion of each of these acquisitions, see Item 8, Financial Statements and
Supplementary Data, Note 2. Since our interest in SNG is not reflected for periods prior to
November 2007, the historical results of operations and the period to period comparison of results
may not be indicative of future results.
We have included a discussion in this MD&A of items that may affect the partnership and our
general partner interests in each of CIG and SNG as they operate in the future. The matters
discussed in our MD&A are as follows:
|
|
|
General description of our business assets and operations and growth projects; |
|
|
|
|
Comparative discussion of our historical results of operations; and |
|
|
|
|
Liquidity and capital resource related matters, including our available liquidity,
sources and uses of cash, our historical cash flow activities, contractual obligations and
commitments, and critical accounting policies, among other items. |
Our Business. We are a Delaware limited partnership formed by El Paso (our general partner) to
own and operate natural gas transportation and storage assets. We hold a 100 percent ownership
interest in the approximately 800-mile WIC interstate natural gas pipeline system with a design
capacity of approximately 3.3 Bcf/d and an average daily throughput in 2009 of 2,652 BBtu/d.
We also own a 58 percent general partner interest in CIG and a 25 percent general partner
interest in SNG whose operations are summarized below:
|
|
|
CIG. CIG is an interstate natural gas pipeline system with approximately 4,200 miles of
pipeline with a design capacity of approximately 3.8 Bcf/d and an average daily throughput
in 2009 of 2,299 BBtu/d. It has associated storage facilities with 35 Bcf of underground
working natural gas storage capacity, which includes 6 Bcf of storage capacity from Totem
Gas Storage associated with CIGs 50 percent ownership interest in WYCO. |
|
|
|
|
SNG. SNG is an interstate natural gas pipeline system with approximately 7,600 miles of
pipeline with a design capacity of approximately 3.7 Bcf/d and an average daily throughput
in 2009 of 2,322 BBtu/d. It has associated storage facilities with a total of approximately
60 Bcf of underground working natural gas storage capacity, which includes the storage
capacity associated with a 50 percent ownership interest in Bear Creek, a joint venture
with TGP, our affiliate.
|
29
Each of these businesses faces varying degrees of competition from other existing and proposed
pipelines and LNG facilities, as well as from alternative energy sources used to generate
electricity, such as hydroelectric power, coal and fuel oil. Our revenues from transportation and
storage services consist of the following types:
|
|
|
|
|
|
|
|
|
Type |
|
Description |
|
Percent
of Total Revenues in 2009(1) |
|
|
|
|
WIC |
|
CIG |
|
SNG |
Reservation |
|
Reservation revenues are from customers (referred to as firm customers) that reserve
capacity on our pipeline systems and storage facilities. These firm customers are obligated to pay a monthly reservation or
demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. |
|
98 |
|
91 |
|
88 |
|
|
|
|
|
|
|
|
|
Usage and Other |
|
Usage revenues are from both firm customers and interruptible customers
(those without reserved capacity) that pay usage charges based on the volume of gas actually
transported, stored, injected or withdrawn. We also earn revenues from other miscellaneous sources. |
|
2 |
|
9 |
|
12 |
|
|
|
(1) |
|
Excludes liquids transportation revenue, amounts associated with retained fuel, and, in the case of
CIG, liquids revenue associated with CIGs processing plants. The revenues described in this table constituted
approximately 100%, 94% and 99% of WICs, CIGs and SNGs total revenues, respectively, earned during the year ended December 31,
2009. |
The FERC regulates the rates we can charge our customers. These rates are generally a function
of the cost of providing services to our customers, including a reasonable return on our invested
capital. Because of our regulated nature and the high percentage of our revenues attributable to
reservation charges, our revenues have historically been relatively stable. However, our financial
results can be subject to volatility due to factors such as changes in natural gas prices, changes
in supply and demand, regulatory actions, competition, declines in the creditworthiness of our
customers and weather. In January 2010, the FERC approved SNGs settlement in which SNG (i)
increased its base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations,
(iii) agreed to file its next general rate case to be effective
after August 31, 2012
and no later than September 1, 2013, and (iv) extended the vast majority of SNGs firm
transportation contracts until August 31, 2013. CIG is required to file a new rate case to be
effective no later than October 2011.
Growth Projects. We intend to grow our business through organic expansion opportunities and
through strategic asset acquisitions from third parties, El Paso or both. As of December 31, 2009,
each of WIC, CIG and SNG have significant expansion projects in progress as described below:
WIC. WIC expects to spend approximately $60 million on contracted organic growth projects from
2010 through 2014. Of this amount, we expect to spend approximately $47 million in 2010. These
expenditures are related to the WIC Expansion project.
|
|
|
WIC Expansion. We estimate the total cost of this project will be approximately $71
million. Due to increased shipper commitments, WIC expanded the scope of this project to
add a second compressor unit on the Kanda Lateral, which increased its capital cost from
$55 million to $71 million. This portion of the project will add a 12,400 horsepower
compressor station on the Kanda Lateral which will increase the Kanda Lateral capacity to
595 MDth/d. WIC filed an application with the FERC for certificate authorization to
construct this portion of the project in July 2009, and the anticipated in-service date is
November 2010. WIC also plans to install three miles of pipeline and reconfigure one
compressor at its Wamsutter station which will provide 155 MDth/d natural gas deliveries
from the WIC Mainline into a third-party pipeline and onto the Opal Hub and El Pasos
proposed Ruby Pipeline. WIC filed an application with the FERC for certificate
authorization to construct this portion of the project in November 2009, and it is
anticipated to be placed in service in the first quarter of 2011. |
30
CIG. CIG expects to spend approximately $110 million on contracted organic growth projects
from 2010 through 2014. Of this amount, CIG expects to spend $86 million in 2010 primarily on its
Raton 2010 expansion described below:
|
|
|
Raton 2010. The Raton 2010 expansion project will consist of approximately 118 miles of
pipeline from the Raton Basin Wet Canyon Lateral to the south end of the Valley Line. This
project will provide additional capacity of approximately 130 MMcf/d from the Raton Basin
in southern Colorado to the Cheyenne Hub in northern Colorado. The estimated total cost of
the project is $146 million. The estimated in-service date is December 2010. In September
2009, CIG filed an application for certificate authorization with the FERC for this
project. |
SNG. SNG expects to spend approximately $403 million on contracted organic growth projects
from 2010 through 2014. Of this amount, SNG expects to spend $249 million in 2010. Our share of
SNGs future expected capital expenditures is approximately $101 million. These expenditures are
primarily related to the South System III and the Southeast Supply Header projects.
|
|
|
South System III. The South System III expansion project will expand SNGs pipeline
system in Mississippi, Alabama and Georgia by adding approximately 81 miles of pipeline
looping and replacement on SNGs south system and 17,310 horsepower of compression to serve
an existing power generation facility owned by the Southern Company in the Atlanta, Georgia
area that is being converted from coal fired to cleaner burning natural gas. This expansion
project will be completed in three phases at a total estimated cost of $352 million, with
each phase expected to add an additional 122 MMcf/d of capacity. In August 2009, we
received certification of authorization from the FERC to construct this project. The
project has estimated in-service dates of January 2011 for Phase I, June 2011 for Phase II
and June 2012 for Phase III. SNG has entered into a precedent agreement with Southern
Company Services as agent for its affiliated operating companies, Georgia Power Company,
Alabama Power Company, Mississippi Power Company, Southern Power Company and Gulf Power
Company to provide an incremental firm transportation service to such operating companies,
commencing in phases beginning January 1, 2011, and ending May 31, 2032, which is 20 years
after the estimated in-service date for Phase III. |
|
|
|
|
Southeast Supply Header. SNG owns an undivided interest in the northern portion of the
Southeast Supply Header project jointly owned by Spectra Energy Corp (Spectra) and
CenterPoint Energy, which added a 115-mile supply line to the western portion of the SNG
system. This project is expected to provide access through pipeline interconnects to
several supply basins, including the Barnett Shale, Bossier Sands, Arkoma and Fayetteville
Shale basins. The estimated cost to SNG for Phase II of this project is $69 million and is
expected to provide SNG with an additional 350 MMcf/d of supply capacity. In August 2009,
we received certification of authorization from the FERC to construct Phase II, which is
anticipated to be placed in service in June 2011. |
|
|
|
|
Cypress Phase III. During 2009, BG LNG Services (BG) informed SNG of its intent not to
exercise their option to have SNG construct the Cypress Phase III expansion. However, BG
has made alternative commitments to subscribe to certain other firm capacity on another of
El Pasos pipeline systems and to provide certain rate considerations on its existing
transportation contract for Cypress Phases I and II. |
31
In addition to our backlog of contracted organic growth projects, we have other projects that
are in various phases of commercial development. Many of the potential projects involve expansion
capacity to serve increased natural gas-fired generation loads. Most of these potential expansion
projects would have in-service dates for 2014 and beyond. If we are eventually successful in
contracting for these new loads, the capital requirements could be substantial and would be
incremental to our backlog of contracted organic growth projects. Although we pursue the
development of these potential projects from time to time, there can be no assurance that we will
be successful in negotiating the definitive binding contracts necessary for such projects to be
included in our backlog of contracted organic growth projects.
CIG. Along the Front Range of CIGs system, utilities have various projects under development
that involve constructing new natural gas-fired generation in part to provide backup capacity
required when renewable generation is not available during certain daily or seasonal periods.
SNG. Similar to SNGs South System III expansion project, SNG is pursuing various expansion
projects to service increased natural-gas fired generation loads, either to meet increased electric
loads or to convert existing coal or oil-fired power plants to natural gas usage.
For a further discussion of the capital requirements of us and our unconsolidated affiliates,
see Liquidity and Capital Resources.
32
Results
of Operations
Our management uses earnings before interest expense and income taxes from continuing
operations (EBIT from continuing operations) as a measure to assess the operating results and
effectiveness of our businesses, which consists of consolidated operations as well as investments
in unconsolidated affiliates. We believe EBIT from continuing operations is useful to our investors
to provide them with the same measure used by El Paso to measure our performance. We define EBIT
from continuing operations as net income adjusted for items such as (i) interest and debt expense,
net, (ii) affiliated interest expense, net, (iii) income taxes, (iv) the impact of discontinued
operations, and (v) net income attributable to noncontrolling interest so that investors may
evaluate our operating results without regard to our financing methods or capital structure. EBIT
from continuing operations may not be comparable to measurements used by other companies.
Additionally, EBIT from continuing operations should be considered in conjunction with net income,
income before income taxes and other performance measures such as operating income or operating
cash flows. Below is a reconciliation of our EBIT from continuing operations to net income, our
throughput volumes and an analysis and discussion of our results for each of the three years ended
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(in millions, except volumes) |
|
Operating revenues |
|
$ |
537.6 |
|
|
$ |
457.2 |
|
|
$ |
418.1 |
|
Operating expenses |
|
|
(245.1 |
) |
|
|
(227.4 |
) |
|
|
(210.3 |
) |
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
292.5 |
|
|
|
229.8 |
|
|
|
207.8 |
|
Earnings from unconsolidated affiliates |
|
|
53.4 |
|
|
|
32.9 |
|
|
|
4.1 |
|
Other income, net |
|
|
5.6 |
|
|
|
9.7 |
|
|
|
11.0 |
|
|
|
|
|
|
|
|
|
|
|
EBIT from continuing operations before noncontrolling interests |
|
|
351.5 |
|
|
|
272.4 |
|
|
|
222.9 |
|
Net income attributable to noncontrolling interests |
|
|
(66.0 |
) |
|
|
(62.4 |
) |
|
|
(47.3 |
) |
|
|
|
|
|
|
|
|
|
|
EBIT from continuing operations |
|
|
285.5 |
|
|
|
210.0 |
|
|
|
175.6 |
|
Interest and debt expense, net |
|
|
(73.7 |
) |
|
|
(61.6 |
) |
|
|
(51.1 |
) |
Affiliated interest income, net |
|
|
1.7 |
|
|
|
23.2 |
|
|
|
41.7 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
(44.1 |
) |
Discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
5.8 |
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to El Paso Pipeline Partners, L.P. |
|
|
213.5 |
|
|
|
171.6 |
|
|
|
127.9 |
|
Net income attributable to noncontrolling interests |
|
|
66.0 |
|
|
|
62.4 |
|
|
|
47.3 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
279.5 |
|
|
$ |
234.0 |
|
|
$ |
175.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput volumes (BBtu/d) (1) |
|
|
4,820 |
|
|
|
4,587 |
|
|
|
4,171 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Throughput volumes are presented for WIC and CIG only. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 to 2008 |
|
2008 to 2007 |
|
|
|
Revenue |
|
|
Expense |
|
|
Other |
|
|
Total |
|
|
Revenue |
|
|
Expense |
|
|
Other |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Favorable/(Unfavorable) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation revenues |
|
$ |
(6.4 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(6.4 |
) |
|
$ |
7.2 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
7.2 |
|
Expansions |
|
|
90.1 |
|
|
|
(19.7 |
) |
|
|
(3.7 |
) |
|
|
66.7 |
|
|
|
32.3 |
|
|
|
(12.4 |
) |
|
|
2.1 |
|
|
|
22.0 |
|
Operational gas, revaluations and processing revenues |
|
|
(2.0 |
) |
|
|
(5.0 |
) |
|
|
|
|
|
|
(7.0 |
) |
|
|
(0.7 |
) |
|
|
13.1 |
|
|
|
|
|
|
|
12.4 |
|
Operating and general and administrative expenses |
|
|
|
|
|
|
0.9 |
|
|
|
|
|
|
|
0.9 |
|
|
|
|
|
|
|
(12.9 |
) |
|
|
|
|
|
|
(12.9 |
) |
Transportation expenses |
|
|
|
|
|
|
(3.9 |
) |
|
|
|
|
|
|
(3.9 |
) |
|
|
|
|
|
|
(2.5 |
) |
|
|
|
|
|
|
(2.5 |
) |
Gain on sale of long-lived asset |
|
|
|
|
|
|
7.8 |
|
|
|
|
|
|
|
7.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings from SNG |
|
|
|
|
|
|
|
|
|
|
22.7 |
|
|
|
22.7 |
|
|
|
|
|
|
|
|
|
|
|
27.2 |
|
|
|
27.2 |
|
Net income attributable to noncontrolling interests |
|
|
|
|
|
|
|
|
|
|
(3.6 |
) |
|
|
(3.6 |
) |
|
|
|
|
|
|
|
|
|
|
(15.1 |
) |
|
|
(15.1 |
) |
Other(1) |
|
|
(1.3 |
) |
|
|
2.2 |
|
|
|
(2.6 |
) |
|
|
(1.7 |
) |
|
|
0.3 |
|
|
|
(2.4 |
) |
|
|
(1.8 |
) |
|
|
(3.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact on EBIT from continuing operations |
|
$ |
80.4 |
|
|
$ |
(17.7 |
) |
|
$ |
12.8 |
|
|
$ |
75.5 |
|
|
$ |
39.1 |
|
|
$ |
(17.1 |
) |
|
$ |
12.4 |
|
|
$ |
34.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Consists of individually insignificant items. |
33
Transportation Revenues. For the year ended December 31, 2009, our EBIT from continuing
operations decreased primarily as a result of decreased usage revenues on both CIG and WIC. For the
year ended December 31, 2008, we experienced higher revenues as a result of increased demand for
firm capacity on WICs mainline system and for CIGs off-system capacity.
Expansions. Our EBIT from continuing operations increased during the years ended December 31,
2009 and 2008 due to expansion projects placed into service, as follows:
|
|
|
|
|
|
|
|
|
|
|
2009 to 2008 |
|
|
2008 to 2007 |
|
|
|
(In millions) |
|
CIG |
|
|
|
|
|
|
|
|
High Plains pipeline |
|
$ |
28.0 |
|
|
$ |
7.7 |
|
Totem Gas Storage |
|
|
14.4 |
|
|
|
1.1 |
|
Other |
|
|
4.0 |
|
|
|
|
|
WIC |
|
|
|
|
|
|
|
|
Piceance lateral |
|
|
9.9 |
|
|
|
4.4 |
|
Medicine Bow lateral |
|
|
9.3 |
|
|
|
1.7 |
|
Kanda Lateral |
|
|
1.1 |
|
|
|
7.1 |
|
|
|
|
|
|
|
|
Total impact on EBIT from continuing operations |
|
$ |
66.7 |
|
|
$ |
22.0 |
|
|
|
|
|
|
|
|
Operational Gas, Revaluations and Processing Revenues. Our EBIT from continuing operations
from operational gas, revaluations, and processing revenues was lower during the year ended
December 31, 2009 compared with the same period in 2008. CIG processing revenues were lower during
the year ended December 31, 2009 compared with the same period in 2008, primarily due to an
unfavorable price change for natural gas liquids. This impact, however, was largely offset by
favorable prices for gas consumed in processing these liquids and regulatory-related cost tracking
compared with the same period in 2008. In addition, WIC recorded a cost and revenue tracker
adjustment in 2009, resulting in lower EBIT from continuing operations for the period.
During 2008, CIG and WIC implemented FERC-approved fuel and related gas cost recovery
mechanisms, subject to the outcome of technical conferences. In 2008, we recorded a net favorable
fuel cost and revenue tracker estimated adjustment to reflect the effect of CIGs order on its
current fuel recovery filing period. During the first quarter of 2008, prior to the implementation
of WICs fuel and related gas cost recovery mechanism, we also benefited from increasing natural
gas prices on fuel and related gas balance items owed to WIC from shippers and other
interconnecting pipelines. The implementation of these mechanisms was protested by a limited number
of shippers. On July 31, 2009 and October 1, 2009, the FERC issued orders to CIG and WIC,
respectively, directing us to remove the cost and revenue components from our fuel recovery
mechanisms. Due to these orders,
our future earnings may be impacted by both positive and negative fluctuations in gas prices
related to fuel imbalance revaluations, their settlement, and other gas balance related items. We
continue to explore options to minimize the price volatility associated with these operational
activities.
Our tariffs continue to provide that the difference between the
quantity of fuel retained and fuel used in operations and lost and
unaccounted for will be flowed-through or charged to shippers. These
fuel trackers remove the impact of over or under collecting fuel and
lost and unaccounted for from our operational gas costs.
For a further discussion of CIG and WIC fuel recovery mechanisms, see Item 8, Financial
Statements and Supplementary Data, Note 8.
Operating and General and Administrative Expenses. For the year ended December 31, 2009, our
operating and general and administrative expense decreased primarily as a result of lower field
repair and maintenance expenses, partially offset by higher benefit costs. For the year ended
December 31, 2008, our operating and general and administrative expense increased primarily due to
higher general and administrative costs for the transaction fees associated with the acquisition of
additional interests in SNG and CIG and as a result of being a publicly traded limited partnership.
Operating and general and administrative expenses also increased due to higher allocated costs from
El Paso Natural Gas Company and Tennessee Gas Pipeline Company, our affiliates, associated with
shared pipeline services.
34
Transportation Expenses. For the years ended December 31, 2009 and 2008 we experienced higher
expenses as a result of increased third party capacity commitments.
Gain on Sale of Long-Lived Asset. In the fourth quarter of 2009, we recorded a gain of $7.8
million related to the sale of CIGs Natural Buttes compressor station and gas processing plant.
For a further discussion of the sale of Natural Buttes, see Item 8, Financial Statements and
Supplementary Data, Note 2.
Earnings from SNG. We recorded equity earnings from SNG of $52.5 million and $29.8 million for
the years ended December 31, 2009 and 2008. We began recording equity earnings from our 10 percent
general partner interests in SNG on November 21, 2007, the date these interests were contributed to
us from El Paso in connection with our initial public offering. We began recording equity earnings
on our additional 15 percent general partner interest in SNG on September 30, 2008, the date we
acquired these additional interests from El Paso.
In January 2010, the FERC approved SNGs settlement in which SNG (i) increased its base tariff
rates effective September 1, 2009 (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file its next
general rate case to be effective after August 31, 2012 and no later than September 1,
2013, and (iv) extended the vast majority of SNGs firm transportation contracts until August 31,
2013.
Net Income Attributable to Noncontrolling Interests. We have reflected El Pasos 42 percent
interest in CIG as noncontrolling interest in our financial statements in all periods presented.
For the year ended December 31, 2009, our net income attributable to noncontrolling interest
increased due to an increase in CIGs net income primarily related to additional revenue generated
by CIG from its High Plains pipeline and Totem Gas Storage expansion projects, offset in part by
increased interest and debt expense due to CIGs financing obligations to WYCO and lower affiliated
interest income received from El Paso. During the year ended December 31, 2008, our net income
attributable to noncontrolling interests increased as compared to the same period in 2007 due to an
increase in CIGs net income primarily related to the fact that CIG was no longer subject to income
taxes following its conversion into a partnership on November 1, 2007, as well as the completion of
its High Plains pipeline expansion.
Interest and Debt Expense
For the year ended December 31, 2009, interest and debt expense was $12.1 million higher than
in 2008 primarily due to an increase in average balances outstanding under our credit facility, the
financing obligations to WYCO (see Item 8, Financial Statements and Supplementary Data, Note 6),
and the issuance of $175.0 million of senior unsecured notes and a $10.0 million note payable to El
Paso issued in September 2008 in conjunction with the acquisition of additional interests in CIG
and SNG. The $175.0 million of senior unsecured notes had an average interest rate of 7.2% in 2009.
These increases were partially offset by lower average interest rates on our credit facility
borrowings and by CIGs repurchase of $100 million of its senior notes in June 2008.
During 2008, our interest and debt expense increased $10.5 million primarily due to amounts
borrowed under our credit facility entered into in November 2007. Also contributing to the increase
were the $175.0 million of senior unsecured notes and a $10.0 million note payable issued in
September 2008 as discussed above. The $175.0 million of senior unsecured notes had an average
interest rate of 7.8% in 2008. These increases were partially offset by lower average debt balances
at CIG, primarily due to CIGs repurchase of $100 million of its senior notes in June 2008. For a
further discussion of our long-term financing obligations, see Item 8, Financial Statements and
Supplementary Data, Note 6. The following table shows the average balance outstanding and the
average interest rates under our credit facility for the years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(In millions, except for rates) |
Average credit facility balance outstanding |
|
$ |
565 |
|
|
$ |
517 |
|
Average interest rate on credit facility borrowings |
|
|
0.8 |
% |
|
|
3.3 |
% |
35
Affiliated Interest Income, Net
Prior to our acquisition of additional interests in CIG in July 2009, CIG participated in El
Pasos cash management program. In conjunction with our acquisition, CIG terminated its
participation in El Pasos cash management program and converted its note receivable with El Paso
under its cash management program into a demand note receivable. Prior to our initial public
offering, WIC also participated in El Pasos cash management program. In 2007, WIC repaid the
outstanding balance and is no longer a participant in El Pasos cash management program. Affiliated
interest income decreased $21.5 million for the year ended December 31, 2009 as compared to 2008
and decreased $18.5 million for the year ended December 31, 2008 as compared to 2007 primarily due
to lower average advances due from El Paso and lower short-term interest rates. The following table
shows the average advances due from El Paso and the average short-term interest rates for the years
ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(In millions, except for rates) |
Average advance due from El Paso |
|
$ |
138 |
|
|
$ |
540 |
|
|
$ |
684 |
|
Average short-term interest rate |
|
|
1.7 |
% |
|
|
4.4 |
% |
|
|
6.2 |
% |
Income Taxes
Effective November 1, 2007, CIG no longer pays income taxes as a result of its conversion into
a partnership. Our effective tax rate of 21 percent for the years ended December 31, 2007 was lower
than the statutory rate of 35 percent due to income associated with nontaxable entities, partially
offset by the effect of state income taxes. For a reconciliation of the statutory rate to the
effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 13.
36
Distributable Cash Flow
We use the non-GAAP financial measure Distributable Cash Flow as it provides important
information relating our financial operating performance to our cash distribution capability.
Additionally, we use Distributable Cash Flow in setting forward expectations and in communications
with the board of directors of our general partner. We define Distributable Cash Flow as Adjusted
EBITDA less cash interest expense, maintenance capital expenditures, and other income and expenses,
net, which primarily includes a non-cash allowance for equity funds used during construction
(AFUDC equity) and other non-cash items. Adjusted EBITDA, which is also a non-GAAP financial
measure, is defined as net income adjusted for (i) interest and debt expense, net of interest
income, (ii) affiliated interest income, net of affiliated interest expense, (iii) depreciation and
amortization expense, (iv) the partnerships share of distributions declared by unconsolidated
affiliates for the applicable period, (v) earnings from unconsolidated affiliates, and (vi) CIGs
declared distributions to El Paso.
We believe that the non-GAAP financial measures described above are useful to investors
because these measures are used by many companies in the industry as measures of operating and
financial performance and are commonly employed by financial analysts and others to evaluate the
operating and financial performance of the partnership and to compare it with the performance of
other publicly traded partnerships within the industry.
Neither Distributable Cash Flow nor Adjusted EBITDA should be considered an alternative to net
income, earnings per unit, operating income, cash flow from operating activities or any other
measure of financial performance presented in accordance with U.S. generally accepted accounting
principles (GAAP). These non-GAAP measures both exclude some, but not all, items that affect net
income and operating income and these measures may vary among other companies. Therefore,
Distributable Cash Flow and Adjusted EBITDA may not be comparable to similarly titled measures of
other companies. Furthermore, these non-GAAP measures should not be viewed as indicative of the
actual amount of cash that we have available for distributions or that we plan to distribute for a
given period, nor do they equate to Available Cash as defined in our partnership agreement.
Our distributable cash flow was $241.2 million and $147.7 million for the years ended December
31, 2009 and 2008. The increase in distributable cash flow in 2009 was due primarily to higher
expansion revenues and our increased ownership interest in CIG and SNG. The tables below provide
our reconciliations of Distributable Cash Flow and Adjusted EBITDA for the years ended December 31,
2009 and 2008:
Reconciliation of Distributable Cash Flow to Net Income.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Net income |
|
$ |
279.5 |
|
|
$ |
234.0 |
|
Net income attributable to noncontrolling interests |
|
|
(66.0 |
) |
|
|
(62.4 |
) |
|
|
|
|
|
|
|
Net income attributable to El Paso Pipeline Partners, L.P. |
|
|
213.5 |
|
|
|
171.6 |
|
Add: Interest and debt expense, net |
|
|
73.7 |
|
|
|
61.6 |
|
Less: Affiliated interest income, net |
|
|
(1.7 |
) |
|
|
(23.2 |
) |
|
|
|
|
|
|
|
EBIT from continuing operations (1) |
|
|
285.5 |
|
|
|
210.0 |
|
Add: |
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
67.0 |
|
|
|
58.6 |
|
Distributions declared by unconsolidated affiliates |
|
|
58.4 |
|
|
|
32.9 |
|
Net income attributable to noncontrolling interests |
|
|
66.0 |
|
|
|
62.4 |
|
Less: |
|
|
|
|
|
|
|
|
Earnings from unconsolidated affiliates |
|
|
(53.4 |
) |
|
|
(32.9 |
) |
CIG declared distributions to El Paso (2) |
|
|
(68.1 |
) |
|
|
(101.6 |
) |
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
|
355.4 |
|
|
|
229.4 |
|
|
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
|
Cash interest expense, net |
|
|
(71.3 |
) |
|
|
(41.2 |
) |
Maintenance capital expenditures |
|
|
(25.8 |
) |
|
|
(27.4 |
) |
Other, net (3) |
|
|
(17.1 |
) |
|
|
(13.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow |
|
$ |
241.2 |
|
|
$ |
147.7 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
For a further discussion of our use of EBIT from continuing operations, see Results
of Operations. |
|
(2) |
|
CIG declared distributions to El Paso include distributions of pre-acquisition
earnings at El Pasos historical ownership interest levels of $7.2 million and $44.2 million
for the years ended December 31, 2009 and 2008. |
|
(3) |
|
Includes certain non-cash items such as AFUDC equity and other items. |
37
Reconciliation of Distributable Cash Flow to Net Cash Provided by Operating Activities.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Net cash provided by operating activities |
|
$ |
347.0 |
|
|
$ |
247.9 |
|
Interest and debt expense, net |
|
|
73.7 |
|
|
|
61.6 |
|
Affiliated interest income, net |
|
|
(1.7 |
) |
|
|
(23.2 |
) |
CIG declared distributions to El Paso (1) |
|
|
(68.1 |
) |
|
|
(101.6 |
) |
Changes in working capital and other |
|
|
4.5 |
|
|
|
44.7 |
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
|
|
355.4 |
|
|
|
229.4 |
|
|
|
|
|
|
|
|
|
|
Less: |
|
|
|
|
|
|
|
|
Cash interest expense, net |
|
|
(71.3 |
) |
|
|
(41.2 |
) |
Maintenance capital expenditures |
|
|
(25.8 |
) |
|
|
(27.4 |
) |
Other, net (2) |
|
|
(17.1 |
) |
|
|
(13.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Cash Flow |
|
$ |
241.2 |
|
|
$ |
147.7 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
CIG declared distributions to El Paso include distributions of pre-acquisition
earnings at El Pasos historical ownership interest levels of $7.2 million and $44.2 million
for the years ended December 31, 2009 and 2008. |
|
(2) |
|
Includes certain non-cash items such as AFUDC equity and other items. |
Liquidity and Capital Resources
Our ability to finance our operations, including our ability to make cash distributions, fund
capital expenditures, make acquisitions and satisfy any indebtedness obligations, will depend on
our ability to generate cash in the future and our ability to access the capital markets. Our
ability to generate cash and our ability to access the capital markets is subject to a number of
factors, some of which are beyond our control as discussed below.
Our sources of liquidity include cash generated from our operations, quarterly cash
distributions received from SNG, notes receivable from El Paso and available borrowing capacity
under our $750 million revolving credit facility. This facility is expandable to $1.25 billion for
certain expansion projects and acquisitions. We may also generate additional sources of cash
through future issuances of additional partnership units and/or future debt offerings. As of
December 31, 2009, our remaining availability under the credit facility was approximately $215
million. As part of our determination of available capacity under our credit agreements, we
completed an assessment of the available lenders under the credit facility. This assessment is
based upon the fact that one of our lenders has failed to fund previous requests under this
facility and has filed for bankruptcy. Based on this assessment as of December 31, 2009, our
available capacity noted above was reduced to reflect the potential exposure to a loss of available
capacity of approximately $15 million assuming this lender continues to fail to fund the facility.
At December 31, 2009, we had notes receivable from El Paso of approximately $93.2 million
which was classified as current based on the net amount we anticipate using in the next twelve
months considering available cash sources and needs.
Although recent financial market conditions have shown signs of improvement, continued
volatility in 2010 and beyond in the financial markets could impact our longer-term access to
capital for future growth projects as well as the cost of such capital. Prolonged restricted access
to the financial markets could impact our ability to grow our distributable cash flow through
acquisitions. However, we believe that cash flows from operating activities, including the cash
distributions received from SNG, availability under our credit facility and our note receivables
from El Paso will be adequate to meet our operating needs, our anticipated cash distributions to
our partners and our planned expansion opportunities for the foreseeable future. Additionally, we
believe our exposure to changes in natural gas consumption and demand is largely mitigated by a
revenue base at WIC, CIG, and SNG that is significantly comprised of long term contracts that are
based on firm demand charges and are less affected by a potential reduction in the actual usage or
consumption of natural gas. For further detail on our operations including risk factors including
adverse general economic conditions and our ability to access financial markets which could impact
our operations and liquidity, see Part 1, Item 1A, Risk Factors.
38
SNG, our investee, participates in El Pasos cash management program and is required to make
quarterly distributions of its available cash to its partners, including us. As of December 31,
2009, SNGs sources of cash primarily include cash provided by operations, amounts available from
notes receivable under El Pasos cash management program, and/or contributions from its partners
(including us), if necessary. SNGs uses of cash primarily include capital expenditures, debt
service, and required quarterly distributions to partners.
Overview of Cash Flow Activities. Our cash flows for the year ended December 31, 2009 are
summarized as follows:
|
|
|
|
|
|
|
2009 |
|
|
|
(In millions) |
|
Cash Flow from Operations |
|
|
|
|
Net income |
|
$ |
279.5 |
|
Non-cash income adjustments |
|
|
42.3 |
|
Change in other assets and liabilities |
|
|
25.2 |
|
|
|
|
|
Total cash flow from operations |
|
$ |
347.0 |
|
|
|
|
|
|
|
|
|
|
Other Cash Inflows |
|
|
|
|
Investing activities |
|
|
|
|
Net change in notes receivable from affiliates |
|
$ |
105.8 |
|
Proceeds from sale of assets |
|
|
10.1 |
|
Returns of capital on investment in unconsolidated affiliates |
|
|
2.4 |
|
|
|
|
|
|
Financing activities |
|
|
|
|
Net proceeds from issuance of common and general partner units |
|
|
216.4 |
|
|
|
|
|
Total other cash inflows |
|
$ |
334.7 |
|
|
|
|
|
|
|
|
|
|
Cash Outflows |
|
|
|
|
Investing activities |
|
|
|
|
Capital expenditures |
|
$ |
(154.0 |
) |
Cash paid to acquire additional interests in CIG |
|
|
(143.2 |
) |
Other |
|
|
(0.5 |
) |
|
|
|
|
|
Financing activities |
|
|
|
|
Payments on borrowings under credit facility |
|
|
(64.9 |
) |
Payments to retire long-term debt, including capital lease obligations |
|
|
(4.1 |
) |
Cash distributions to unitholders and general partner |
|
|
(161.5 |
) |
Cash distributions to El Paso |
|
|
(75.7 |
) |
Excess of cash paid for CIG interests over contributed book value |
|
|
(71.3 |
) |
|
|
|
|
Total cash outflows |
|
$ |
(675.2 |
) |
|
|
|
|
Net change in cash and cash equivalents |
|
$ |
6.5 |
|
|
|
|
|
For the year ended December 31, 2009, we generated cash flow from operations of $347.0 million
compared with $247.9 million in the same period in 2008. Our operating cash flow in 2009 increased
primarily due to higher expansion revenue related to our High Plains pipeline, Totem Gas Storage,
Piceance lateral and Medicine Bow expansion projects, increased distributions from the acquisition
of additional ownership interest in SNG in September 2008 and changes in working capital. We also
generated $216.4 million in net proceeds from the issuance of additional common and general partner
units, $214.5 million of which was used to acquire an additional 18 percent general partner
interest in CIG from El Paso. For a further discussion of this acquisition, see Item 8, Financial
Statements and Supplementary Data, Note 2.
During 2009, we utilized our cash inflows to pay distributions, including CIGs distribution
to El Paso of its share of available cash (see Item 8, Financial Statements and Supplementary Data,
Note 12), to fund maintenance and growth projects as further noted below, to make payments to
retire certain long term debt and to acquire additional interests in CIG.
39
As of December 31, 2009, our cash capital expenditures for the year ended December 31, 2009
and those planned for 2010 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected |
|
|
|
2009 |
|
|
2010 |
|
|
|
(In millions) |
|
Maintenance |
|
$ |
25.8 |
|
|
$ |
37 |
|
Expansion |
|
|
128.2 |
|
|
|
146 |
|
|
|
|
|
|
|
|
Total |
|
$ |
154.0 |
|
|
$ |
183 |
|
|
|
|
|
|
|
|
Our expected 2010 expansion capital expenditures include amounts primarily related to our WIC
Expansion and Raton 2010 growth projects. While we expect to fund maintenance capital expenditures
through internally generated funds, we intend to fund our expansion capital expenditures through
borrowings under our credit facility and the repayment of our note receivable from El Paso.
Unconsolidated Affiliates
Capital Requirements. SNGs source of cash primarily includes cash provided by operations,
amounts available from notes receivable under El Pasos cash management program, and/or
contributions from its partners (including us), if necessary. SNGs uses of cash primarily includes
capital expenditures, debt service, and distributions to partners. The balance of the notes
receivable under El Pasos cash management programs was approximately $154 million for SNG as of
December 31, 2009. For 2010, we anticipate SNG will utilize amounts recovered from its notes
receivable with El Paso, together with capital contributions from its partners, including us, to
fund its capital investment needs. We estimate that we will be required to make capital
contributions to SNG of approximately $40 million during 2010. As of December 31, 2009, SNGs
capital expenditures, including committed projects, and other projects, for the year ended December
31, 2009 and those planned for 2010 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Anticipated |
|
|
|
|
2009 |
|
|
2010 |
|
|
|
(In millions) |
|
SNG |
|
|
|
Maintenance |
|
$ |
60.2 |
|
|
$ |
95 |
|
Expansion/Other |
|
|
83.7 |
|
|
|
249 |
|
Hurricanes |
|
|
(6.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
137.4 |
|
|
$ |
344 |
|
|
|
|
|
|
|
|
40
Commitments and Contingencies
Climate Change and Energy Legislation and Regulation. There are various legislative
and regulatory measures relating to climate change and energy policies that have been proposed and,
if enacted, will likely impact our business.
Climate Change Legislation and Regulation. Measures to address climate change and GHG
emissions are in various phases of discussions or implementation at international, federal,
regional and state levels. Over 50 countries, including the US, have submitted formal pledges to
cut or limit their emissions in response to the United Nation-sponsored Copenhagen Accord. It
is reasonably likely that federal legislation requiring GHG controls will be enacted within the
next few years in the United States. Although it is uncertain what legislation will ultimately
be enacted, it is our belief that cap-and-trade or other market-based legislation that sets a
price on carbon emissions will increase demand for natural gas, particularly in the power
sector. We believe this increased demand will occur due to substantially less carbon emissions
associated with the use of natural gas compared with alternative fuel sources for power
generation, including coal and oil-fired power generation. However, the actual impact on demand
will depend on the legislative provisions that are ultimately adopted, including the level of
emission caps, allowances granted, offset programs established, cost of emission credits and
incentives provided to other fossil fuels and lower carbon technologies like nuclear, carbon
capture sequestration and renewable energy sources.
It is also reasonably likely that any federal legislation that is enacted would increase
our cost of environmental compliance by requiring us to install additional equipment to reduce
carbon emissions from our larger facilities as well as to potentially purchase emission
allowances. Based on 2008 operational data we reported to the California Climate Action
Registry (CCAR) that our operations in the United States, which include our 58 percent interest
in CIG and 25 percent interest in SNG, emitted approximately 1.4 million tonnes of carbon
dioxide equivalent emissions during 2008. We believe that approximately 1.3 million tonnes of
the GHG emissions that we reported to CCAR would be subject to regulations under the climate
change legislation that passed in the U.S. House of Representatives in June 2009. Of these
amounts that would be subject to regulation, we believe that approximately 44 percent would be
subject to the cap-and-trade rules contained in the proposed legislation and the remainder would
be subject to performance standards. As proposed by the House, the portion of our GHG emissions
that would be subject to cap-and-trade rules could require us to purchase allowances or offset
credits and the portion of our GHG emissions that would be subject to performance standards
could require us to install additional equipment or initiate new work practice standards to
reduce emission levels at many of our facilities. The costs of purchasing emission allowances or offset
credits and installing additional equipment or changing work practices would likely be material.
Increases in costs of our suppliers to comply with such cap-and-trade rules and performance
standards could also materially increase our costs of operations. Although we believe that many
of these costs should be recoverable in the rates we charge our customers, recovery is still
uncertain at this time. A climate change bill was also voted upon favorably by the Senate
Committee on Energy and Public Works (the Committee) in November 2009 and has been ordered to be
reported out of the Committee. Any final bill passed out of the U.S. Senate will likely see
further substantial changes and we cannot yet predict the form it may take, the timing of when
any legislation will be enacted or implemented, or how it may impact our operations if
ultimately enacted.
The EPA finalized regulations to monitor and report GHG emissions on an annual basis. The
EPA also proposed new regulations to regulate GHGs under the Clean Air Act, which the EPA has
indicated could be finalized as early as March 2010. The effective date and substantive
requirements of any EPA final rule is subject to interpretation and possible legal challenges.
In addition, it is uncertain whether federal legislation might be enacted that either delays the
implementation of any climate change regulations of the EPA or adopts a different statutory
structure for regulating GHGs than is provided for pursuant to the Clean Air Act. Therefore, the
potential impact on our operations and construction projects remains uncertain.
41
In addition, in March 2009, the EPA proposed a rule impacting emissions from reciprocating
internal combustion engines, which would require us to install emission controls on our pipeline
systems. It is expected that the rule will be finalized in August 2010. As proposed, engines
subject to the regulations would have to be in compliance by August 2013. Based upon that
timeframe, we would expect that we would commence incurring expenditures in late 2010, with the
majority of the work and expenditures incurred in 2011 and 2012. If the regulations are
adopted as proposed, we would expect to incur approximately $16 million in capital expenditures
over the period from 2010 to 2013.
Legislative and regulatory efforts are underway in various states and regions. These rules
once finalized may impose additional costs on our operations and permitting our facilities,
which could include costs to purchase offset credits or emission allowances, to retrofit or
install equipment or to change existing work practice standards. In addition, various lawsuits
have been filed seeking to force further regulation of GHG emissions, as well as to require
specific companies to reduce GHG emissions from their operations. Enactment of additional
regulations by the federal or state governments, as well as lawsuits, could result in delays and
have negative impacts on our ability to obtain permits and other regulatory approvals with
regard to existing and new facilities, could impact our costs of operations, as well as require
us to install new equipment to control emissions from our facilities, the costs of which would
likely be material.
Energy Legislation. In conjunction with these climate change proposals, there have been
various federal and state legislative and regulatory proposals that would create additional
incentives to move to a less carbon intensive footprint. These proposals would establish
renewable energy and efficiency standards at both the federal and state level, some of which
would require a material increase in renewable sources, such as wind and solar power generation,
over the next several decades. There have also been proposals to increase the development of
nuclear power and commercialize carbon capture and sequestration especially at coal fired
facilities. Other proposals would establish incentives for energy efficiency and conservation.
Although it is reasonably likely that many of these proposals will be enacted over the next few
years, we cannot predict the form of any laws and regulations that might be enacted, the timing
of their implementation, or the precise impact on our operations or demand for natural gas.
However, such proposals if enacted could negatively impact natural gas demand over the longer
term.
Off-Balance Sheet Arrangements
For a further discussion of our off-balance sheet arrangements, see Item 8, Financial
Statements and Supplementary Data, Note 12.
42
Contractual Obligations
We are party to various contractual obligations, a portion of which are reflected in our
financial statements, such as long-term debt and our capital lease. Other obligations, such as
capital commitments and demand charges under transportation commitments, are not reflected on our
balance sheet. The following table and discussion that follows summarizes our contractual cash
obligations as of December 31, 2009 for each of the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Due in |
|
|
Due in |
|
|
Due in |
|
|
|
|
|
|
|
|
|
Less Than |
|
|
1-3 |
|
|
3-5 |
|
|
|
|
|
|
|
Contractual Obligations |
|
1 Year |
|
|
Years |
|
|
Years |
|
|
Thereafter |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
|
|
|
|
|
Long-term financing obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal |
|
$ |
5.0 |
|
|
$ |
627.0 |
|
|
$ |
98.0 |
|
|
$ |
632.6 |
|
|
$ |
1,362.6 |
|
Interest |
|
|
76.6 |
|
|
|
147.4 |
|
|
|
121.1 |
|
|
|
560.7 |
|
|
|
905.8 |
|
Other contractual liabilities |
|
|
1.8 |
|
|
|
4.0 |
|
|
|
0.9 |
|
|
|
3.6 |
|
|
|
10.3 |
|
Operating leases |
|
|
2.2 |
|
|
|
4.6 |
|
|
|
4.8 |
|
|
|
0.6 |
|
|
|
12.2 |
|
Other contractual commitments and
purchase obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation and storage |
|
|
21.1 |
|
|
|
51.0 |
|
|
|
51.8 |
|
|
|
52.7 |
|
|
|
176.6 |
|
Other |
|
|
35.4 |
|
|
|
3.5 |
|
|
|
|
|
|
|
|
|
|
|
38.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
142.1 |
|
|
$ |
837.5 |
|
|
$ |
276.6 |
|
|
$ |
1,250.2 |
|
|
$ |
2,506.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term Financing Obligations (Principal and Interest). Long-term financing obligations
represent stated maturities. Interest payments are shown through the stated maturity date of the
related debt based on (i) the contractual interest rates for fixed rate debt, (ii) current market
interest rates and the contractual credit spread for our variable rate debt. Included in these
amounts are payments related to the financing obligations of CIG for the construction of WYCOs
High Plains Pipeline and Totem Gas Storage facility. CIG makes monthly interest payments on these
obligations that are based on 50 percent of the operating results of the High Plains Pipeline and
Totem Gas Storage facility. Also included in these amounts is a compressor station under a capital
lease from an affiliate of CIG, WYCO. The compressor station lease expires November 2029. For a
further discussion of our long-term financing and capital lease obligations see Financial
Statements and Supplementary Data, Note 6.
Other contractual liabilities. Included in this amount are environmental liabilities related
to sites that we own or have a contractual or legal obligation with a regulatory agency or property
owner upon which we perform remediation activities. These liabilities are included in other current
and non-current liabilities in our balance sheet.
Operating Leases. For a further discussion of these obligations, see Financial Statements and
Supplementary Data, Note 8.
Other Contractual Commitments and Purchase Obligations. Other contractual commitments and
purchase obligations are defined as legally enforceable agreements to purchase goods or services
that have fixed or minimum quantities and fixed or minimum variable price provisions, and that
detail approximate timing of the underlying obligations. Included are the following:
|
|
|
Transportation and Storage Commitments. Included in these commitments are agreements for
capacity on third party pipeline systems and storage capacity from an affiliate. |
|
|
|
Other Commitments. Included in these amounts are commitments for construction contracts
and purchase obligations. We exclude asset retirement obligations and reserves for
litigation and environmental remediation, other than those disclosed
above, when these liabilities are not contractually fixed as
to timing and amount. We have other planned capital projects that are discretionary in
nature, with no substantial contractual capital commitments made in advance of the actual
expenditures. |
43
Critical Accounting Policies and Estimates
The accounting policies discussed below are considered by management to be critical to an
understanding of our financial statements as, of our current accounting policies, its application
places the most significant demands on managements judgment. Due to the inherent uncertainties
involved with this type of judgment, actual results could differ significantly from estimates and
may have a material impact on our results of operations, partners capital or cash flows. For
additional information concerning our other accounting policies, please read the notes to the
financial statements included in Item 8, Financial Statements and Supplementary Data, Note 1
Cost-Based Regulation. We account for our regulated operations in accordance with current
Financial Accounting Standards Board (FASB) accounting standards
for rate-regulated operations. The
economic effects of regulation can result in a regulated company recording assets for costs that
have been or are expected to be approved for recovery from customers or recording liabilities for
amounts that are expected to be returned to customers in the rate-setting process in a period
different from the period in which the amounts would be recorded by an unregulated enterprise.
Accordingly, we record assets and liabilities that result from the regulated ratemaking process
that would not be recorded under GAAP for non-regulated entities. Management regularly assesses
whether regulatory assets are probable of future recovery or if regulatory liabilities are probable
of being refunded to our customers by considering factors such as applicable regulatory changes and
recent rate orders applicable to other regulated entities. Based on this continual assessment,
management believes the existing regulatory assets are probable of recovery. We periodically
evaluate the applicability of this standard, and consider factors such as regulatory changes and
the impact of competition. If cost-based regulation ends or competition increases, we may have to
reduce certain of our asset balances to reflect a market basis lower than cost and write-off the
associated regulatory assets.
Accounting for Environmental Reserves. We accrue environmental reserves when our assessments
indicate that it is probable that a liability has been incurred and an amount can be reasonably
estimated. Estimates of our liabilities are based on an evaluation of potential outcomes, currently
available facts, existing technology and presently enacted laws and regulations taking into
consideration the likely effects of societal and economic factors, estimates of associated onsite,
offsite and groundwater technical studies and legal costs. Actual results may differ from our
estimates, and our estimates can be, and often are, revised in the future, either negatively or
positively, depending upon actual outcomes or changes in expectations based on the facts
surrounding each matter.
As of December 31, 2009, we had accrued approximately $11 million for environmental matters
related to CIG and its subsidiaries. Our environmental estimates range from approximately $11
million to approximately $35 million and the amounts we have accrued represent a combination of two
estimation methodologies. First, where the most likely outcome can be reasonably estimated, that
cost has been accrued ($3 million). Second, where the most likely outcome cannot be estimated, a
range of costs is established ($8 million to $32 million) and the lower end of the expected range
has been accrued.
Accounting for Other Postretirement Benefits. We reflect an asset or liability for CIGs
postretirement benefit plan based on its over funded or under funded status. As of December 31,
2009, CIGs postretirement benefit plan was over funded by $8.6 million. CIGs postretirement
benefit obligation and net benefit costs are primarily based on actuarial calculations. Various
assumptions are used in performing these calculations, including those related to the return that
CIGs plan assets are expected to return, the estimated cost of health care when benefits are
provided under CIGs plan and other factors. A significant assumption utilized is the discount rate
used in calculating CIGs benefit obligation. The discount rate is selected by matching the timing
and amount of CIGs expected future benefit payments for CIGs postretirement benefit obligation to
the average yields of various high-quality bonds with corresponding maturities.
Actual results may differ from the assumptions included in these calculations, and as a
result, estimates associated with CIGs postretirement benefits can be, and often are, revised in
the future. The income statement impact of the changes in the assumptions on CIGs related benefit
obligation, along with changes to CIGs plan and other items, are deferred and recorded as either a
regulatory asset or liability. A one percent change in the primary assumptions would not have a
material impact on CIGs funded status or net postretirement benefit cost.
44
New Accounting Pronouncements Issued But Not Yet Adopted
See Item 8, Financial Statements and Supplementary Data, Note 1, under New Accounting
Pronouncements Issued But Not Yet Adopted, which is incorporated herein by reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our primary market risk is exposure to changing interest rates. The table below shows the
maturity of the carrying amounts and related weighted-average interest rates on our long-term
interest-bearing securities by expected maturity date as well as the total fair value of those
securities. The fair value on our fixed and variable rate obligations have been estimated based on
quoted market prices for the same or similar issues.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
December 31, 2008 |
|
|
Expected Fiscal Year of Maturity of Carrying Amounts |
|
|
|
|
|
Fair |
|
Carrying |
|
Fair |
|
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
2014 |
|
Thereafter |
|
Total |
|
Value |
|
Amounts |
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and other financing obligations, including current portion fixed rate |
|
$ |
5.0 |
|
|
$ |
42.0 |
|
|
$ |
20.0 |
|
|
$ |
93.0 |
|
|
$ |
5.0 |
|
|
$ |
632.6 |
|
|
$ |
797.6 |
|
|
$ |
845.6 |
|
|
$ |
731.0 |
|
|
$ |
638.1 |
|
Average interest rate |
|
|
14.5 |
% |
|
|
8.6 |
% |
|
|
9.6 |
% |
|
|
8.3 |
% |
|
|
14.5 |
% |
|
|
8.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and other financing obligations, including current portion variable rate |
|
$ |
|
|
|
$ |
|
|
|
$ |
565.0 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
565.0 |
|
|
$ |
529.1 |
|
|
$ |
629.9 |
|
|
$ |
488.2 |
|
Average interest rate |
|
|
|
|
|
|
|
|
|
|
1.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index
Below is an index to the items contained in Part II, Item 8, Financial Statements and
Supplementary Data.
|
|
|
|
|
|
|
Page |
|
|
|
|
47 |
|
|
|
|
48 |
|
|
|
|
50 |
|
|
|
|
51 |
|
|
|
|
52 |
|
|
|
|
53 |
|
|
|
|
54 |
|
|
|
|
54 |
|
|
|
|
59 |
|
|
|
|
61 |
|
|
|
|
62 |
|
|
|
|
64 |
|
|
|
|
66 |
|
|
|
|
68 |
|
|
|
|
68 |
|
|
|
|
71 |
|
|
|
|
73 |
|
|
|
|
73 |
|
|
|
|
73 |
|
|
|
|
77 |
|
|
|
|
78 |
|
46
MANAGEMENTS ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as defined by SEC rules adopted under the Securities Exchange Act of 1934, as
amended. Our internal control over financial reporting is designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles. It consists of
policies and procedures that:
|
|
|
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of our assets; |
|
|
|
|
Provide reasonable assurance that transactions are recorded as necessary to permit
preparation of the financial statements in accordance with generally accepted accounting
principles, and that our receipts and expenditures are being made only in accordance with
authorizations of our management and directors; and |
|
|
|
|
Provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of our assets that could have a material effect on the
financial statements. |
Under the supervision and with the participation of management, including the Chief Executive
Officer (CEO) and Chief Financial Officer (CFO), we made an assessment of the effectiveness of our
internal control over financial reporting as of December 31, 2009. In making this assessment, we
used the criteria established in Internal Control Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded
that our internal control over financial reporting was effective as of December 31, 2009. The
effectiveness of our internal control over financial reporting as of December 31, 2009 has been
audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their
report included herein.
47
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of El Paso Pipeline GP Company, L.L.C.
as General Partner of El Paso Pipeline Partners, L.P.,
and the Partners of El Paso Pipeline Partners, L.P.:
We have audited the accompanying consolidated balance sheets of El Paso Pipeline Partners, L.P.
(the Partnership) as of December 31, 2009 and 2008, and the related consolidated statements of
income, partners capital, and cash flows for each of the three years in the period ended December
31, 2009. Our audits also included the financial statement schedule listed in the Index at Item
15(a) for each of the three years in the period ended December 31, 2009. These financial statements
and schedule are the responsibility of the Partnerships management. Our responsibility is to
express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the consolidated financial position of El Paso Pipeline Partners, L.P. at December 31,
2009 and 2008, and the consolidated results of its operations and its cash flows for each of the
three years in the period ended December 31, 2009, in conformity with U.S. generally accepted
accounting principles. Also, in our opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken as a whole presents fairly in all
material respects the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2008, the
Partnership adopted the provisions of an accounting standard update related to measurement date and changed the measurement date of its postretirement benefit plan.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), El Paso Pipeline Partners, L.P.s internal control over financial reporting
as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
February 26, 2010 expressed an unqualified opinion thereon.
/s/ Ernst
& Young LLP
Houston,
Texas
February 26, 2010
48
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of El Paso Pipeline GP Company, L.L.C.
as General Partner of El Paso Pipeline Partners, L.P.,
and the Partners of El Paso Pipeline Partners, L.P.:
We have audited El Paso Pipeline Partners, L.P.s (the Partnership) internal control over
financial reporting as of December 31, 2009, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (the COSO criteria). El Paso Pipeline Partners, L.P.s management is responsible for
maintaining effective internal control over financial reporting, and for its assessment of the
effectiveness of internal control over financial reporting included in the accompanying
Managements Annual Report on Internal Control over Financial Reporting. Our responsibility is to
express an opinion on the Partnerships internal control over financial reporting based on our
audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, El Paso Pipeline Partners, L.P. maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of El Paso Pipeline Partners, L.P. as of
December 31, 2009 and 2008, and the related consolidated statements of income, partners capital,
and cash flows for each of the three years in the period ended December 31, 2009 of El Paso
Pipeline Partners, L.P. and our report dated February 26, 2010 expressed an unqualified opinion
thereon.
/s/ Ernst
& Young LLP
Houston,
Texas
February 26, 2010
49
El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per unit amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Operating revenues |
|
$ |
537.6 |
|
|
$ |
457.2 |
|
|
$ |
418.1 |
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance |
|
|
154.4 |
|
|
|
147.2 |
|
|
|
144.2 |
|
Depreciation and amortization |
|
|
67.0 |
|
|
|
58.6 |
|
|
|
46.7 |
|
Taxes, other than income taxes |
|
|
23.7 |
|
|
|
21.6 |
|
|
|
19.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
245.1 |
|
|
|
227.4 |
|
|
|
210.3 |
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
292.5 |
|
|
|
229.8 |
|
|
|
207.8 |
|
Earnings from unconsolidated affiliates |
|
|
53.4 |
|
|
|
32.9 |
|
|
|
4.1 |
|
Other income, net |
|
|
5.6 |
|
|
|
9.7 |
|
|
|
11.0 |
|
Interest and debt expense, net |
|
|
(73.7 |
) |
|
|
(61.6 |
) |
|
|
(51.1 |
) |
Affiliated interest income, net |
|
|
1.7 |
|
|
|
23.2 |
|
|
|
41.7 |
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
279.5 |
|
|
|
234.0 |
|
|
|
213.5 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
44.1 |
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
279.5 |
|
|
|
234.0 |
|
|
|
169.4 |
|
Discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
5.8 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
279.5 |
|
|
|
234.0 |
|
|
|
175.2 |
|
Net income attributable to noncontrolling interest |
|
|
(66.0 |
) |
|
|
(62.4 |
) |
|
|
(47.3 |
) |
|
|
|
|
|
|
|
|
|
|
Net income attributable to El Paso Pipeline Partners, L.P. |
|
$ |
213.5 |
|
|
$ |
171.6 |
|
|
$ |
127.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to El Paso Pipeline Partners,
L.P. per limited partner unit |
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
Common units |
|
$ |
1.64 |
|
|
$ |
1.26 |
|
|
$ |
0.11 |
|
Subordinated units |
|
$ |
1.56 |
|
|
$ |
1.12 |
|
|
$ |
0.11 |
|
See accompanying notes.
50
El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In millions, except units)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
17.4 |
|
|
$ |
10.9 |
|
Accounts receivable |
|
|
|
|
|
|
|
|
Customer, net of allowance of $0.5 in 2008 |
|
|
14.2 |
|
|
|
22.0 |
|
Affiliates |
|
|
114.5 |
|
|
|
138.2 |
|
Other |
|
|
0.7 |
|
|
|
3.1 |
|
Materials and supplies |
|
|
11.2 |
|
|
|
8.2 |
|
Regulatory assets |
|
|
4.2 |
|
|
|
28.4 |
|
Other |
|
|
3.8 |
|
|
|
3.7 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
166.0 |
|
|
|
214.5 |
|
|
|
|
|
|
|
|
Property, plant and equipment, at cost |
|
|
2,672.2 |
|
|
|
2,542.5 |
|
Less accumulated depreciation and amortization |
|
|
653.7 |
|
|
|
634.4 |
|
|
|
|
|
|
|
|
Total property, plant and equipment, net |
|
|
2,018.5 |
|
|
|
1,908.1 |
|
|
|
|
|
|
|
|
Other assets |
|
|
|
|
|
|
|
|
Investment in unconsolidated affiliates |
|
|
417.5 |
|
|
|
410.8 |
|
Note receivable from affiliates |
|
|
|
|
|
|
75.9 |
|
Other |
|
|
66.2 |
|
|
|
66.5 |
|
|
|
|
|
|
|
|
|
|
|
483.7 |
|
|
|
553.2 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,668.2 |
|
|
$ |
2,675.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL |
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
|
|
|
|
|
|
Trade |
|
$ |
7.3 |
|
|
$ |
17.5 |
|
Affiliates |
|
|
26.9 |
|
|
|
10.2 |
|
Other |
|
|
15.6 |
|
|
|
34.4 |
|
Taxes payable |
|
|
16.1 |
|
|
|
11.9 |
|
Accrued interest |
|
|
6.7 |
|
|
|
10.6 |
|
Regulatory liabilities |
|
|
14.7 |
|
|
|
29.2 |
|
Contractual deposits |
|
|
8.7 |
|
|
|
9.7 |
|
Deferred credits |
|
|
6.3 |
|
|
|
0.8 |
|
Other |
|
|
7.3 |
|
|
|
8.8 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
109.6 |
|
|
|
133.1 |
|
|
|
|
|
|
|
|
Other liabilities |
|
|
|
|
|
|
|
|
Long-term debt and other financing obligations, less current maturities |
|
|
1,357.6 |
|
|
|
1,357.3 |
|
Other liabilities |
|
|
39.4 |
|
|
|
68.0 |
|
|
|
|
|
|
|
|
|
|
|
1,397.0 |
|
|
|
1,425.3 |
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 8) |
|
|
|
|
|
|
|
|
Partners capital |
|
|
|
|
|
|
|
|
El Paso Pipeline Partners L.P. partners capital |
|
|
|
|
|
|
|
|
Common units
(97,622,247 and 84,970,498 units issued and outstanding
at December 31, 2009 and 2008) |
|
|
1,304.6 |
|
|
|
1,064.8 |
|
Subordinated units (27,727,411 units issued and outstanding at December 31, 2009 and 2008) |
|
|
297.4 |
|
|
|
289.4 |
|
General partner units (2,558,028 and 2,299,526 units issued and outstanding
at December 31, 2009 and 2008) |
|
|
(783.8 |
) |
|
|
(574.9 |
) |
|
|
|
|
|
|
|
Total El Paso Pipeline Partners L.P. partners capital |
|
|
818.2 |
|
|
|
779.3 |
|
Noncontrolling interests |
|
|
343.4 |
|
|
|
338.1 |
|
|
|
|
|
|
|
|
Total partners capital |
|
|
1,161.6 |
|
|
|
1,117.4 |
|
|
|
|
|
|
|
|
Total liabilities and partners capital |
|
$ |
2,668.2 |
|
|
$ |
2,675.8 |
|
|
|
|
|
|
|
|
See accompanying notes.
51
El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Cash flows from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
279.5 |
|
|
$ |
234.0 |
|
|
$ |
175.2 |
|
Less: income from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
5.8 |
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
279.5 |
|
|
|
234.0 |
|
|
|
169.4 |
|
Adjustments to reconcile net income to net cash from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
67.0 |
|
|
|
58.6 |
|
|
|
46.7 |
|
Earnings from unconsolidated affiliates, adjusted for cash distributions |
|
|
(9.6 |
) |
|
|
(9.8 |
) |
|
|
(4.1 |
) |
Deferred income taxes |
|
|
|
|
|
|
|
|
|
|
7.7 |
|
Other non-cash income items |
|
|
(15.1 |
) |
|
|
(9.3 |
) |
|
|
(7.0 |
) |
Asset and liability changes |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
3.9 |
|
|
|
(7.7 |
) |
|
|
3.5 |
|
Accounts payable |
|
|
4.4 |
|
|
|
1.6 |
|
|
|
6.4 |
|
Taxes payable |
|
|
|
|
|
|
|
|
|
|
(56.4 |
) |
Regulatory assets |
|
|
25.0 |
|
|
|
(26.7 |
) |
|
|
1.4 |
|
Regulatory liabilities |
|
|
(11.0 |
) |
|
|
12.3 |
|
|
|
23.3 |
|
Non-current liabilities |
|
|
(0.9 |
) |
|
|
3.3 |
|
|
|
(199.8 |
) |
Other, net |
|
|
3.8 |
|
|
|
(8.4 |
) |
|
|
(0.1 |
) |
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) continuing activities |
|
|
347.0 |
|
|
|
247.9 |
|
|
|
(9.0 |
) |
Cash provided by discontinued activities |
|
|
|
|
|
|
|
|
|
|
3.3 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
|
347.0 |
|
|
|
247.9 |
|
|
|
(5.7 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(154.0 |
) |
|
|
(218.4 |
) |
|
|
(268.6 |
) |
Cash paid to acquire additional interests in CIG and SNG |
|
|
(143.2 |
) |
|
|
(254.3 |
) |
|
|
|
|
Proceeds from sale of assets |
|
|
10.1 |
|
|
|
|
|
|
|
|
|
Returns of capital on investment in unconsolidated affiliates |
|
|
2.4 |
|
|
|
6.9 |
|
|
|
|
|
Net change in notes receivable from affiliates |
|
|
105.8 |
|
|
|
193.2 |
|
|
|
160.2 |
|
Other |
|
|
(0.5 |
) |
|
|
1.4 |
|
|
|
0.2 |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(179.4 |
) |
|
|
(271.2 |
) |
|
|
(108.2 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds from issuance of common and general partner units |
|
|
216.4 |
|
|
|
15.0 |
|
|
|
537.2 |
|
Net proceeds from (payments on) borrowings under credit facility |
|
|
(64.9 |
) |
|
|
129.9 |
|
|
|
453.9 |
|
Net proceeds from issuance of long-term debt |
|
|
|
|
|
|
174.0 |
|
|
|
|
|
Payments to retire long-term debt, including capital lease obligations |
|
|
(4.1 |
) |
|
|
(104.0 |
) |
|
|
(128.5 |
) |
Cash distributions to unitholders and general partner |
|
|
(161.5 |
) |
|
|
(96.1 |
) |
|
|
|
|
Cash distributions to El Paso |
|
|
(75.7 |
) |
|
|
(89.3 |
) |
|
|
(747.8 |
) |
Excess of cash paid for CIG interests over contributed book value |
|
|
(71.3 |
) |
|
|
|
|
|
|
|
|
Contribution from parent |
|
|
|
|
|
|
|
|
|
|
7.1 |
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) financing activities |
|
|
(161.1 |
) |
|
|
29.5 |
|
|
|
121.9 |
|
Cash used in discontinued activities |
|
|
|
|
|
|
|
|
|
|
(3.3 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(161.1 |
) |
|
|
29.5 |
|
|
|
118.6 |
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents |
|
|
6.5 |
|
|
|
6.2 |
|
|
|
4.7 |
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
10.9 |
|
|
|
4.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
$ |
17.4 |
|
|
$ |
10.9 |
|
|
$ |
4.7 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
52
El PASO PIPELINE PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL
(In millions, except units)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor |
|
|
El Paso Pipeline Partners, L.P. Partners Capital |
|
|
|
|
|
|
Total |
|
|
|
Partners |
|
|
Limited Partners |
|
|
General |
|
|
|
|
|
|
Noncontrolling |
|
|
Partners |
|
|
|
Capital |
|
|
Common |
|
|
Subordinated |
|
|
Partner |
|
|
Total |
|
|
Interests |
|
|
Capital |
|
Balance at December 31, 2006 |
|
$ |
854.6 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
382.1 |
|
|
$ |
1,236.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
108.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38.6 |
|
|
|
146.6 |
|
Reclassification to regulatory liabilities (Note 9) |
|
|
(2.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2.1 |
) |
|
|
(5.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at November 20, 2007 |
|
|
959.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
418.6 |
|
|
|
1,378.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution of interests in CIG and SNG |
|
|
253.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
253.7 |
|
Elimination of CIG additional acquired interest from historical capital |
|
|
(102.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(102.2 |
) |
Distribution to noncontrolling interests |
|
|
(18.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18.6 |
|
|
|
|
|
Distribution of discontinued operations |
|
|
(3.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2.4 |
) |
|
|
(5.8 |
) |
Contributions |
|
|
5.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.2 |
|
|
|
10.0 |
|
Cash distributions to El Paso |
|
|
(11.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11.4 |
) |
Conversion to El Paso Pipeline Partners, L.P. |
|
|
(1,083.6 |
) |
|
|
288.1 |
|
|
|
280.9 |
|
|
|
514.6 |
|
|
|
1,083.6 |
|
|
|
|
|
|
|
|
|
Issuance of common units, net of issuance costs |
|
|
|
|
|
|
537.2 |
|
|
|
|
|
|
|
|
|
|
|
537.2 |
|
|
|
|
|
|
|
537.2 |
|
Net income |
|
|
|
|
|
|
6.5 |
|
|
|
3.2 |
|
|
|
10.2 |
|
|
|
19.9 |
|
|
|
8.7 |
|
|
|
28.6 |
|
Cash distributions to El Paso |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(736.4 |
) |
|
|
(736.4 |
) |
|
|
|
|
|
|
(736.4 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.3 |
|
|
|
0.3 |
|
|
|
(0.6 |
) |
|
|
(0.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007 |
|
|
|
|
|
|
831.8 |
|
|
|
284.1 |
|
|
|
(211.3 |
) |
|
|
904.6 |
|
|
|
447.1 |
|
|
|
1,351.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
78.9 |
|
|
|
33.3 |
|
|
|
59.4 |
|
|
|
171.6 |
|
|
|
62.4 |
|
|
|
234.0 |
|
Issuance of common units, net of issuance costs |
|
|
|
|
|
|
15.0 |
|
|
|
|
|
|
|
|
|
|
|
15.0 |
|
|
|
|
|
|
|
15.0 |
|
Cash distributions to unitholders and general partner |
|
|
|
|
|
|
(66.1 |
) |
|
|
(28.0 |
) |
|
|
(2.0 |
) |
|
|
(96.1 |
) |
|
|
|
|
|
|
(96.1 |
) |
Cash distributions to El Paso |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(43.7 |
) |
|
|
(43.7 |
) |
|
|
(45.6 |
) |
|
|
(89.3 |
) |
Non-cash distribution to El Paso |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(144.1 |
) |
|
|
(144.1 |
) |
|
|
(125.9 |
) |
|
|
(270.0 |
) |
Excess of contributed book value of CIG and SNG over cash paid |
|
|
|
|
|
|
205.2 |
|
|
|
|
|
|
|
4.5 |
|
|
|
209.7 |
|
|
|
|
|
|
|
209.7 |
|
Elimination of CIG additional acquired interest from historical capital |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(237.9 |
) |
|
|
(237.9 |
) |
|
|
|
|
|
|
(237.9 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.2 |
|
|
|
0.2 |
|
|
|
0.1 |
|
|
|
0.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008 |
|
|
|
|
|
|
1,064.8 |
|
|
|
289.4 |
|
|
|
(574.9 |
) |
|
|
779.3 |
|
|
|
338.1 |
|
|
|
1,117.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
149.1 |
|
|
|
44.8 |
|
|
|
19.6 |
|
|
|
213.5 |
|
|
|
66.0 |
|
|
|
279.5 |
|
Issuance of common and general partner units, net of issuance costs |
|
|
|
|
|
|
211.9 |
|
|
|
|
|
|
|
4.5 |
|
|
|
216.4 |
|
|
|
|
|
|
|
216.4 |
|
Cash distributions to unitholders and general partner |
|
|
|
|
|
|
(121.2 |
) |
|
|
(36.7 |
) |
|
|
(3.6 |
) |
|
|
(161.5 |
) |
|
|
|
|
|
|
(161.5 |
) |
Cash distributions to El Paso |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15.0 |
) |
|
|
(15.0 |
) |
|
|
(60.7 |
) |
|
|
(75.7 |
) |
Cash paid to general partner to acquire additional interest in CIG |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(214.5 |
) |
|
|
(214.5 |
) |
|
|
|
|
|
|
(214.5 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
(0.1 |
) |
|
|
0.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009 |
|
$ |
|
|
|
$ |
1,304.6 |
|
|
$ |
297.4 |
|
|
$ |
(783.8 |
) |
|
$ |
818.2 |
|
|
$ |
343.4 |
|
|
$ |
1,161.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
53
El PASO PIPELINE PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation and Significant Accounting Policies
Organization
We are
a publicly-traded partnership. El Paso Corporation (El Paso) owned a 65 percent limited
partner interest and a two percent general partner interest in us as of December 31, 2009. We own a
100 percent ownership interest in Wyoming Interstate Company, Ltd. (WIC), an interstate natural gas
system. In November 2007, El Paso contributed to us, at their historical cost, 10 percent general
partner interests in each of Colorado Interstate Gas Company (CIG) and Southern Natural Gas Company
(SNG) which consist of interstate natural gas pipeline systems and related storage facilities. In
connection with our initial public offering, we issued 28.8 million common units to the public for
approximately $537 million, net of issuance costs and expenses. We used the net proceeds from the
common unit offering, together with proceeds of approximately $425 million borrowed under our
revolving credit facility (Note 6), to primarily repay notes payable to El Paso of $225 million and
distribute $737 million to El Paso, in part to reimburse El Paso for capital expenditures incurred
prior to our initial public offering related to the assets contributed to us.
On September 30, 2008, we acquired from El Paso an additional 30 percent interest in CIG and
an additional 15 percent interest in SNG. The acquisition increased our interest in CIG to 40 percent and
our interest in SNG to 25 percent. El Paso operates these systems and owns the remaining general partner interests in
CIG and SNG. For a further discussion of this acquisition, see Note 2.
On July 24, 2009, we acquired an additional 18 percent general partner interest in CIG from El
Paso for $214.5 million. Subsequent to the acquisition, we own a 58 percent general partner
interest in CIG and have the ability to control its operating and financial decisions and policies.
Accordingly, we have consolidated CIG and have retrospectively adjusted our historical financial
statements in all periods to reflect the change in reporting entity. El Paso owns the remaining 42
percent interest in CIG which is reflected as a noncontrolling interest. For a further discussion
of this acquisition, see Note 2.
Basis of Presentation and Principles of Consolidation
Our
consolidated financial statements are prepared in accordance with
United States (U.S.) generally accepted
accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the
elimination of all significant intercompany accounts and transactions.
We consolidate WIC and CIG based on our ability to control their operating and
financial decisions and policies. Both the contribution of CIG and SNG interests in conjunction
with the initial public offering and our acquisitions of additional interests were recorded at
their historical cost since the transactions were between entities under common control. For a
further discussion of our acquisitions, see Note 2.
We account for our investment in SNG using the equity method of accounting based on our
ability to exert significant influence over, but not control, SNG. We reflect our proportionate
share of the operating results of SNG as earnings from unconsolidated affiliates in our financial
statements. Earnings from unconsolidated affiliates includes our 10 percent ownership in SNG from
the date of its contribution to us on November 21, 2007 through September 30, 2008, and our 25
percent ownership in SNG beginning on the date of our acquisition of additional interests on
September 30, 2008.
54
We consolidate entities when we either (i) have the ability to control the operating and
financial decisions and policies of that entity or (ii) are allocated a majority of the entitys
losses and/or returns through our interests in that entity. The determination of our ability to
control or exert significant influence over an entity and whether we are allocated a majority of
the entitys losses and/or returns involves the use of judgment. We apply the equity method of
accounting where we can exert significant influence over, but do not control, the policies and
decisions of an entity and where we are not allocated a majority of the entitys losses and/or
returns. Where we are unable to exert significant influence over the entity, we use the cost method
of accounting.
Use of Estimates
The preparation of our financial statements requires the use of estimates and assumptions that
affect the amounts reported as assets, liabilities, revenues and expenses and the disclosures in
these financial statements. Actual results can, and often do, differ from those estimates.
Regulated Operations
Our interstate natural gas pipelines and storage operations are subject to the jurisdiction of
the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas
Policy Act of 1978 and the Energy Policy Act of 2005. We follow the Financial Accounting Standards
Boards (FASB) accounting standards for regulated operations. Under these standards, we record
regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities.
Regulatory assets and liabilities represent probable future revenues or expenses associated with
certain charges or credits that are expected to be recovered from or refunded to customers through
the rate making process. Items to which we apply regulatory accounting requirements include certain
postretirement benefit plan costs, loss on reacquired debt, an equity return component on regulated
capital projects and certain costs related to gas not used in operations and other costs included
in, or expected to be included in, future rates.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be
cash equivalents.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable and for natural gas imbalances due
from shippers and operators if we determine that we will not collect all or part of the outstanding
balance. We regularly review collectability and establish or adjust our allowance as necessary
using the specific identification method.
Materials and Supplies
We value our materials and supplies at the lower of cost or market value with cost determined
using the average cost method.
Natural Gas Imbalances
Natural gas imbalances occur when the amount of natural gas delivered from or received by a
pipeline system differs from the scheduled amount of gas delivered or received. We value these
imbalances due to or from shippers and operators at current index prices. Imbalances are settled in
cash or made up in-kind, subject to the terms of the tariff.
Imbalances due from others are reported in the balance sheet as either accounts receivable
from customers or accounts receivable from affiliates. Imbalances owed to others are reported in
the balance sheet as either trade accounts payable or accounts payable to affiliates. We classify
all imbalances as current as we expect them to be settled within a year.
55
Property, Plant and Equipment
Our property, plant and equipment is recorded at its original cost of construction or, upon
acquisition, at either the fair value of the assets acquired or the cost to the entity that first
placed the asset in service. For constructed assets, direct costs, such as labor and materials, and
indirect costs, such as overhead, interest and an equity return component are capitalized, as
allowed by the FERC. Major units of property replacements or improvements are capitalized and minor
items are expensed.
We use the composite (group) method to depreciate property, plant and equipment. Under this
method, assets with similar lives and characteristics are grouped and depreciated as one asset. The
FERC-accepted depreciation rate is applied to the total cost of the group until the net book value
equals the salvage value. For certain general plant, the asset is depreciated to zero. Currently,
depreciation rates vary from approximately two percent to 25 percent per year. Using these rates,
the remaining depreciable lives of these assets range from four to 50 years. We re-evaluate
depreciation rates each time we redevelop our transportation and storage rates to file with the
FERC for an increase or decrease in rates. When property, plant and equipment is retired,
accumulated depreciation and amortization is charged for the original cost of the assets in
addition to the cost to remove, sell or dispose of the assets, less salvage value. We do not
recognize a gain or loss unless we sell or retire an entire operating unit, as defined by the FERC.
We include gains or losses on dispositions of operating units in operations and maintenance expense
in our income statements.
At December 31, 2009 and 2008, we had approximately $83.8 million and $127.5 million of
construction work in progress included in our property, plant and equipment.
We capitalize a carrying cost (an allowance for funds used during construction) on debt and
equity funds related to the construction of long-lived assets. This carrying cost consists of a
return on the investment financed by debt and a return on the investment financed by equity. The
debt portion is calculated based on the average cost of debt. Interest costs on debt amounts
capitalized during the years ended December 31, 2009, 2008 and 2007 were $1.9 million, $2.8 million and $2.6 million. These debt amounts are included as a reduction to
interest and debt expense in the income statement. The equity portion of capitalized costs is
calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized during each of the years
ended December 31, 2009, 2008 and 2007 were $5.5 million, $8.7 million and $7.0 million. These
equity amounts are included as other income in our income statement.
Asset and Investment Divestitures/Impairments
We evaluate our assets and investments for impairment when events or circumstances indicate
that their carrying values may not be recovered. These events include market declines that are
believed to be other than temporary, changes in the manner in which we intend to use a long-lived
asset, decisions to sell an asset or investment and adverse changes in the legal or business
environment such as adverse actions by regulators. When an event occurs, we evaluate the
recoverability of long-lived assets carrying values based on either (i) the long-lived assets
ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the
investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a
long-lived asset or group of assets we adjust the carrying value of the asset downward, if
necessary, to its estimated fair value. Our fair value estimates are generally based on market data
obtained through the sales process or an analysis of expected discounted cash flows. The magnitude
of any impairment is impacted by a number of factors, including the nature of the assets being sold
and the established time frame for completing the sale, among other factors.
We reclassify assets to be sold in our financial statements as either held-for-sale or from
discontinued operations
when it becomes probable that we will dispose of the assets within the next twelve months and when they meet other criteria, including whether we will have
significant long-term continuing involvement with those assets after they are sold. We cease depreciating assets in the period that they are reclassified as either held for sale or from discontinued operations, and reflect the results of our discontinued operations
in our income statement separately from those of continuing operations.
Cash flows from
our discontinued businesses are reflected as discontinued operating, investing, and financing
activities in our statement of cash flows. Cash provided by discontinued activities in the
operating activities section of our cash flow statement includes all operating cash flows generated
by our discontinued business during the period. Our discontinued business participated in El Pasos
cash management program as it did not maintain separate bank accounts for its cash balances. We
reflected transactions between our continuing operations and discontinued operations related to El
Pasos cash management program as financing activities in our cash flow statement.
56
Revenue Recognition
Our revenues are primarily generated from natural gas transportation, storage and processing
services and include estimates of amounts earned but unbilled. We estimate these unbilled revenues
based on contract data, regulatory information, and preliminary throughput and allocation
measurements, among other items. Revenues for all services are based on the thermal quantity of gas
delivered or subscribed at a price specified in the contract. For our transportation services and
storage services, we recognize reservation revenues on firm contracted capacity over the contract
period regardless of the amount of natural gas that is transported or stored. For interruptible or
volumetric-based services, we record revenues when physical deliveries of natural gas are made at
the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. We
are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a
rate proceeding. We establish reserves for these potential refunds.
Environmental Costs and Other Contingencies
Environmental Costs. We record environmental liabilities at their undiscounted amounts on our
balance sheet when environmental assessments indicate that remediation efforts are probable and the
costs can be reasonably estimated. Estimates of our liabilities are based on currently available
facts, existing technology and presently enacted laws and regulations, taking into consideration
the likely effects of other societal and economic factors, and include estimates of associated
legal costs. These amounts also consider prior experience in remediating contaminated sites, other
companies clean-up experience and data released by the Environmental Protection Agency or other
organizations. Our estimates are subject to revision in future periods based on actual costs or new
circumstances. We capitalize costs that benefit future periods and we recognize a current period
expense when clean-up efforts do not benefit future periods.
We evaluate any amounts paid directly or reimbursed by government sponsored programs and
potential recoveries or reimbursements of remediation costs from third parties including insurance
coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or
solvency of the third party, among other factors. When recovery is assured, we record and report an
asset separately from the associated liability on our balance sheet.
Other Contingencies. We recognize liabilities for other contingencies when we have an exposure
that, when fully analyzed, indicates it is both probable that a liability has been incurred and the
amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be
reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot
be estimated, a range of potential losses is established and if no one amount in that range is more
likely than any other, the low end of the range is accrued.
Income Taxes
We are a partnership for income tax purposes and are not subject to either federal income
taxes or generally to state income taxes. Our partners are responsible for income taxes on their
allocated share of taxable income which may differ from income for financial statement purposes due
to differences in the tax basis and financial reporting basis of assets and liabilities. We are
unable to readily determine the net difference in the bases of our assets and liabilities for
financial and tax reporting purposes because information regarding each partners tax attributes in
us is not available to us.
57
Effective November 1, 2007, CIG, our consolidated subsidiary, converted into a general
partnership in conjunction with our formation and accordingly, CIG is also no longer subject to
income taxes. As a result of its conversion into a general partnership, CIG settled their existing
current and deferred tax balances with recoveries of note receivables from El Paso under its cash
management program pursuant to its tax sharing agreement with El Paso (see Note 12). Prior to that
date, CIG recorded current income taxes based on its taxable income and provided for deferred
income taxes to reflect estimated future tax payments and receipts. Deferred taxes represented the
income tax impacts of differences between the financial statement and tax bases of assets and
liabilities and carryovers at each year end. We accounted for tax credits under the flow-through
method, which reduced the provision for income taxes in the year the tax credits first became
available. We reduced deferred tax assets by a valuation allowance when, based on our estimates, it
was more likely than not that a portion of those assets would not be realized in a future period.
Accounting for Asset Retirement Obligations
We record a liability for legal obligations associated with the replacement, removal and
retirement of our long-lived assets. Our asset retirement liabilities are initially recorded at
their estimated fair value with a corresponding increase to property, plant and equipment. This
increase in property, plant and equipment is then depreciated over the useful life of the asset to
which that liability relates. An ongoing expense is also recognized for changes in the value of the
liability as a result of the passage of time, which we record as depreciation and amortization in
our income statement. We have the ability to recover certain of these costs from our customers and
have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.
We have legal obligations associated with the retirement of our natural gas pipeline, related
transmission facilities and storage wells. We have obligations to plug storage wells when we no
longer plan to use them and when we abandon them. Our legal obligations associated with our natural
gas transmission facilities primarily involve purging and sealing the pipelines if they are
abandoned. We also have obligations to remove hazardous materials associated with our natural gas
transmission facilities if they are replaced. We accrue a liability for legal obligations based on
an estimate of the timing and amount of their settlement.
We are required to operate and maintain our natural gas pipeline system, and intend to do so
as long as supply and demand for natural gas exists, which we expect for the foreseeable future.
Therefore, we believe that the substantial majority of our natural gas pipeline system assets have
indeterminate lives. Accordingly, our asset retirement liabilities as of December 31, 2009 and 2008
were not material to our financial statements. We continue to evaluate our asset retirement
obligations and future developments could impact the amounts we record.
Partners Capital
We allocate our net income to the capital accounts of our general partner, common unitholders
and subordinated unitholders based on the terms of the partnership agreement. The agreement
requires these allocations to be made based on the relative percentage of their ownership
interests, adjusted for any replenishment of previously allocated aggregate net losses and/or
special allocations, each as defined in our partnership agreement. As a result of the retrospective
consolidation of CIG, earnings prior to the acquisition of the incremental interests in CIG
(pre-acquisition earnings) in historical periods have been allocated to our general partner.
Accordingly, the allocation of pre-acquisition earnings to our general partner reflects 58 percent
of CIGs earnings prior to November 21, 2007, 48 percent of CIGs earnings between November 21,
2007 and September 30, 2008 and 18 percent of CIGs earnings between September 30, 2008 and July
24, 2009.
Our partnership agreement authorizes us to issue an unlimited number of additional partnership
securities for the consideration and on the terms and conditions determined by our general partner
without the approval of our unitholders. Accordingly, all of our issued units are authorized and
outstanding, and there is an unlimited number of units that are authorized beyond those currently
issued.
58
Postretirement Benefits
CIG, our consolidated subsidiary, maintains a postretirement benefit plan covering certain of
its former employees. This plan requires CIG to make contributions to fund the benefits to be paid
out under the plan. These contributions are invested until the benefits are paid out to plan
participants. We record the net benefit cost related to this plan in our income statement. This net
benefit cost is a function of many factors including benefits earned during the year by plan
participants (which is a function of the level of benefits provided under the plan, actuarial
assumptions and the passage of time), expected returns on plan assets and amortization of certain
deferred gains and losses. For a further discussion of our policies with respect to CIGs
postretirement benefit plan, see Note 9.
In accounting for CIGs postretirement benefit plan, we record an asset or liability based on
the over funded or under funded status of the plan. Any deferred amounts related to unrecognized
gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or
liability.
Effective January 1, 2008, we adopted the
provisions of an accounting standard
update related to measurement date and
changed the measurement date of CIGs postretirement benefit plan from
September 30 to December 31. The adoption of the measurement date provisions of this standard did
not have a material impact on our financial statements.
Effective December 31, 2009, we expanded our disclosures about postretirement benefit plan
assets as a result of new disclosure requirements. See Note 9 for these expanded
disclosures.
New Accounting Pronouncements Issued But Not Yet Adopted
As of December 31, 2009, the following accounting standards had not yet been adopted by us:
Transfers of Financial Assets. In June 2009, the FASB updated accounting standards for
financial asset transfers. Among other items, this update eliminated the concept of a qualifying
special-purpose entity (QSPE) for purposes of evaluating whether an entity should be consolidated
or not. These changes are effective for existing QSPEs as of January 1, 2010 and for transactions
entered into on or after January 1, 2010. The adoption of this accounting standard in January 2010
did not have an impact on our financial statements as we amended our existing accounts receivable
sales program in January 2010, see Note 12.
Variable Interest Entities. In June 2009, the FASB updated accounting standards for variable
interest entities to revise how companies determine the primary beneficiary of these entities,
among other changes. Companies will now be required to use a qualitative approach based on their
responsibilities and power over the entities operations, rather than a quantitative approach in
determining the primary beneficiary as previously required. The adoption of this accounting
standard in January 2010 did not have a material impact on our financial statements.
2. Contribution of Assets, Acquisitions and Divestitures
Initial Contribution of Assets (IPO). In conjunction with our initial public offering of
common units in November 2007, El Paso contributed to us, at their historical cost, 10 percent
general partner interests in CIG and SNG. Because our financial statements have been
retrospectively adjusted to reflect the consolidation of CIG, we have eliminated the historical
capital balance related to the 10 percent interest we acquired in CIG in November 2007.
Accordingly, for accounting purposes, we have reflected a $102.2 million decrease in our general
partners capital during the year ended December 31, 2007 related to this elimination. We began
recording our proportionate share of SNGs operating results as earnings from unconsolidated
affiliates from the date of El Pasos contribution of these interests to us.
Acquisition of Additional Interests in CIG and SNG. On September 30, 2008, we acquired an
additional 30 percent general partner interest in CIG and an additional 15 percent general partner
interest in SNG from El Paso for $736.4 million. The consideration paid to El Paso consisted of the
issuance of 26,888,611 common units, 566,563 general partner units, a $10 million note payable and
$254 million of cash. We financed the $254 million cash payment through the issuance of $175
million of private placement debt, $65 million from our revolving credit facility and the issuance
of 873,000 common units to private investors for $15 million. For accounting purposes, we recorded
these additional interests in CIG and SNG at their historical cost of $474 million and the
difference
59
between historical cost and the cash and note payable consideration paid to El Paso as an
increase to partners capital. Because our financial statements have been retrospectively adjusted
to reflect the consolidation of CIG, we have eliminated the historical capital balance related to
the 30 percent interest we acquired in CIG on September 30, 2008. Accordingly, for accounting
purposes, we have reflected a $237.9 million decrease in our general partners capital during the
year ended December 31, 2008 related to this elimination. We accounted for the acquisition of SNG
prospectively beginning with the date of acquisition and will continue to utilize the equity method
of accounting for our total investment in SNG.
On July 24, 2009, we acquired an additional 18 percent general partner interest in CIG from El
Paso for $214.5 million in cash. Subsequent to this acquisition, we own a 58 percent general
partner interest in CIG and have the ability to control its operating and financial decisions and
policies. Because the transaction was accounted for as a reorganization of entities under common
control, we have consolidated CIG and have retrospectively adjusted our historical financial
statements in all periods to reflect the change in reporting entity. Accordingly, the condensed
consolidated balance sheets reflect the historical carrying value of CIGs assets and liabilities.
We have reflected El Pasos 42 percent interest in CIG as a noncontrolling interest in our
financial statements in all periods presented. As a result of the retrospective consolidation of
CIG, earnings prior to the acquisition of the incremental interests in CIG (pre-acquisition
earnings) in historical periods have been allocated to our general partner. Accordingly, the
allocation of pre-acquisition earnings to our general partner reflects 58 percent of CIGs earnings
prior to November 21, 2007, 48 percent of CIGs earnings between November 21, 2007 and September
30, 2008 and 18 percent of CIGs earnings between September 30, 2008 and July 24, 2009.
Divestitures. In November 2009, CIG sold its Natural Buttes compressor station and gas
processing plant to a third party for $9.0 million and recorded a gain of $7.8 million related to
the sale, which is included in our income statement as a reduction of operating and maintenance
expense. The historical gross cost of the assets were $34.8 million. Pursuant to the FERC order
approving the sale of the processing plant, we recently filed our proposed accounting entries
associated with the sale with the FERC for its approval which utilized a technical obsolescence
appraisal methodology for determining the portion of the composite accumulated depreciation
attributable to the plant which resulted in us recording a gain on the sale. Although we believe
the entries proposed are appropriate for this sale, the FERC also utilizes other methodologies in
estimating the associated accumulated depreciation that if applied could result in a non-cash loss
on the sale.
In November 2007, in conjunction with our formation, CIG distributed certain of its assets to
El Paso. We have reflected these operations as discontinued operations in our financial statements
for periods prior to their distribution. We classify assets (or groups of assets) to be disposed of
as held for sale or, if appropriate, from discontinued operations when they have received
appropriate approvals to be disposed of by our management and when they meet other criteria. The
table below summarizes the operating results of our discontinued operations for the year ended
December 31, 2007.
|
|
|
|
|
|
|
2007 |
|
|
|
(In millions) |
|
Revenues |
|
$ |
|
|
Operating expenses |
|
|
|
|
Other income, net |
|
|
0.1 |
|
Interest and debt expense |
|
|
|
|
Affiliated interest income, net |
|
|
8.9 |
|
|
|
|
|
Income before income taxes |
|
|
9.0 |
|
Income taxes |
|
|
3.2 |
|
|
|
|
|
Income from discontinued operations, net of income taxes |
|
$ |
5.8 |
|
|
|
|
|
60
3. Partners Capital
In November 2007, in connection with our initial public offering, we issued 28,750,000 common
units to the public for $537.2 million, net of issuance costs and expenses.
On September 30, 2008, we issued 26,888,611 common units and 566,563 general partner units to
El Paso, and issued 873,000 common units to private investors in conjunction with our acquisition
of an additional 30 percent general partner interest in CIG and an additional 15 percent general
partner interest in SNG.
In June and July 2009, we publicly
issued 258,502 common units and issued 258,502 general
partner units to El Paso for net proceeds of $216.5 million. The net proceeds from this offering
were used to acquire an additional 18 percent general partner interest in CIG. For a further
discussion of these acquisitions, see Note 2.
The table below provides a reconciliation of our limited and general partner units.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit Reconciliation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
Limited Partner Units |
|
|
General |
|
|
Partners |
|
|
|
Common |
|
|
Subordinated |
|
|
Partner |
|
|
Capital |
|
Balance at December 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Formation of El Paso Pipeline Partners, L.P |
|
|
28,437,786 |
|
|
|
27,727,411 |
|
|
|
1,732,963 |
|
|
|
57,898,160 |
|
Issuance of units to public |
|
|
28,750,000 |
|
|
|
|
|
|
|
|
|
|
|
28,750,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007 |
|
|
57,187,786 |
|
|
|
27,727,411 |
|
|
|
1,732,963 |
|
|
|
86,648,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit based compensation to non-employee directors |
|
|
21,101 |
|
|
|
|
|
|
|
|
|
|
|
21,101 |
|
Issuance of units to public |
|
|
873,000 |
|
|
|
|
|
|
|
|
|
|
|
873,000 |
|
Acquisition of additional interests in CIG and SNG |
|
|
26,888,611 |
|
|
|
|
|
|
|
566,563 |
|
|
|
27,455,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008 |
|
|
84,970,498 |
|
|
|
27,727,411 |
|
|
|
2,299,526 |
|
|
|
114,997,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit-based compensation to non-employee directors (1) |
|
|
1,749 |
|
|
|
|
|
|
|
|
|
|
|
1,749 |
|
Issuance of units to public |
|
|
12,650,000 |
|
|
|
|
|
|
|
258,502 |
|
|
|
12,908,502 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009 |
|
|
97,622,247 |
|
|
|
27,727,411 |
|
|
|
2,558,028 |
|
|
|
127,907,686 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount is net of 4,575 forfeited unvested restricted common units. |
Subsequent Event. In January 2010, we publicly issued 9,862,500 common units and issued
201,404 general partner units to El Paso for net proceeds of $236.1 million.
61
4. Earnings Per Unit and Cash Distributions
Earnings per unit. During the first quarter of 2009, we adopted an accounting standard,
applied retrospectively to our earnings per unit, which changes the manner in which master limited
partnerships calculate earnings per unit. This standard requires the calculation of earnings per
unit based on actual distributions made to a master limited partnerships unitholders, including
the holders of incentive distribution rights, for the related reporting period. To the extent net
income attributable to El Paso Pipeline Partners, L.P. exceeds cash distributions, the excess is
allocated to unitholders based on their contractual participation rights to share in those
earnings. If cash distributions exceed net income attributable to El Paso Pipeline Partners, L.P.,
the excess distributions are allocated proportionately to all participating units outstanding based
on their respective ownership percentages. Additionally, under this standard, the calculation of
earnings per unit does not reflect an allocation of undistributed earnings to the IDR holders
beyond amounts distributable under the terms of the partnership agreement. Net income attributable
to El Paso Pipeline Partners, L.P. per limited partner unit reported prior to the adoption of this
standard was $1.22 per common and subordinated unit for the year ended December 31, 2008 and $0.13
per common unit and $0.09 per subordinated unit for the year ended December 31, 2007. Payments made
to our unitholders are determined in relation to actual declared distributions, and are not based
on the net income allocations used in the calculation of earnings per unit.
As discussed in Note 2, we have retrospectively adjusted our historical financial statements
for the consolidation of CIG following the acquisition of an additional 18 percent interest in CIG
from El Paso on July 24, 2009. As a result of the retrospective consolidation of CIG, earnings
prior to the acquisition of the incremental interests in CIG (pre-acquisition earnings) in
historical periods have been allocated solely to our general partner in all periods presented.
Accordingly, our allocation of pre-acquisition earnings to our general partner reflects 58 percent
of CIGs earnings prior to November 21, 2007, 48 percent of CIGs earnings between November 21,
2007 and September 30, 2008 and 18 percent of CIGs earnings between September 30, 2008 and July
24, 2009.
Net income attributable to El Paso Pipeline Partners, L.P. per limited partner unit is
computed by dividing the limited partners interest in net income attributable to El Paso Pipeline
Partners, L.P. by the weighted average number of limited partner units outstanding. Diluted
earnings per limited partner unit reflects the potential dilution that could occur if securities or
other agreements to issue common units were exercised, settled or converted into common units. As
of December 31, 2009 and 2008, we had 8,429 and 21,101 restricted units outstanding, a portion of
which were dilutive for the years ended December 31, 2009 and 2008. No potentially dilutive
securities existed as of December 31, 2007.
The tables below show the (i) allocation of net income attributable to El Paso Pipeline
Partners, L.P. and the (ii) net income attributable to El Paso Pipeline Partners, L.P. per limited
partner unit based on the number of basic and diluted limited partner units outstanding for the
years ended December 31, 2009, 2008 and 2007.
Allocation of Net Income Attributable to El Paso Pipeline Partners, L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In Millions) |
|
Net income attributable to El Paso Pipeline Partners, L.P |
|
$ |
213.5 |
|
|
$ |
171.6 |
|
|
$ |
127.9 |
|
Less: CIG preacquisition earnings allocated to general partner subsequent to initial public
offering |
|
|
(14.6 |
) |
|
|
(57.1 |
) |
|
|
(10.0 |
) |
Earnings prior to initial public offering |
|
|
|
|
|
|
|
|
|
|
(108.0 |
) |
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of general partner interest |
|
|
198.9 |
|
|
|
114.5 |
|
|
|
9.9 |
|
Less: General partners interest in net income attributable to El Paso Pipeline Partners, L.P |
|
|
(4.0 |
) |
|
|
(2.3 |
) |
|
|
(0.2 |
) |
General partners incentive distribution |
|
|
(1.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in net income attributable to El Paso Pipeline Partners, L.P.
common and subordinated |
|
$ |
193.9 |
|
|
$ |
112.2 |
|
|
$ |
9.7 |
|
|
|
|
|
|
|
|
|
|
|
62
Net Income Attributable to El Paso Pipeline Partners, L.P. per Limited Partner Unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
Common |
|
|
Subordinated |
|
|
Common |
|
|
Subordinated |
|
|
Common |
|
|
Subordinated |
|
|
|
(In millions, except for per unit amounts) |
|
Distributions (1) |
|
$ |
132.7 |
|
|
$ |
37.8 |
|
|
$ |
86.0 |
|
|
$ |
33.3 |
|
|
$ |
7.3 |
|
|
$ |
3.6 |
|
Undistributed earnings (losses) |
|
|
18.0 |
|
|
|
5.4 |
|
|
|
(4.9 |
) |
|
|
(2.2 |
) |
|
|
(0.8 |
) |
|
|
(0.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited partners interest in
net income attributable to El
Paso Pipeline Partners, L.P. |
|
$ |
150.7 |
|
|
$ |
43.2 |
|
|
$ |
81.1 |
|
|
$ |
31.1 |
|
|
$ |
6.5 |
|
|
$ |
3.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average limited
partner units outstanding
Basic and Diluted |
|
|
91.8 |
|
|
|
27.7 |
|
|
|
64.2 |
|
|
|
27.7 |
|
|
|
57.2 |
|
|
|
27.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to El
Paso Pipeline Partners, L.P.
per limited partner unit
Basic and Diluted |
|
$ |
1.64 |
|
|
$ |
1.56 |
|
|
$ |
1.26 |
|
|
$ |
1.12 |
|
|
$ |
0.11 |
|
|
$ |
0.11 |
|
|
|
|
(1) |
|
Reflects distributions declared to our common and subordinated unitholders of $1.3650 per
unit, $1.2025 per unit and $0.12813 per unit for the years ended December 31, 2009, 2008 and 2007. |
Subordinated units. All of the subordinated units are held by a wholly owned subsidiary of El
Paso. Our partnership agreement provides that, during the subordination period, the common units
will have the right to receive distributions of available cash from operating surplus each quarter
in an amount equal to $0.28750 per common unit, which is defined in our partnership agreement as
the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly
distribution on the common units from prior quarters, before any distributions of available cash
from operating surplus may be made on the subordinated units. Furthermore, no arrearages will be
paid on the subordinated units. The practical effect of the subordinated units is to increase the
likelihood that during the subordination period there will be available cash to be distributed on
the common units.
The subordination period will end and the subordinated units will convert to common units, on
a one-for-one basis, on the first business day after we have earned and paid at least $0.43125 (150
percent of the minimum quarterly distribution) on each outstanding limited partner unit and general
partner unit for each quarter in any four quarter period ending or after December 31, 2008, or on
the first business day after we have earned and paid at least $0.28750 on each outstanding limited
partner unit and general partner unit for any three consecutive, non-overlapping four quarter
periods ending on or after December 31, 2010. The subordination period also will end upon the
removal of our general partner other than for cause if the units held by our general partner and
its affiliates are not voted in favor of such removal.
Incentive distribution rights. The general partner holds incentive distribution rights in
accordance with the partnership agreement. These rights pay an increasing percentage interest in
quarterly distributions of cash based on the level of distribution to all unitholders.
Additionally, our general partner, as the holder of our incentive distribution rights, has the
right under our partnership agreement to elect to relinquish the right to receive incentive
distribution payments based on the initial cash target distribution levels and to reset, at higher
levels, the minimum quarterly distribution amount and cash target distribution levels upon which
the incentive distribution payments to our general partner would be set. During the year ended
December 31, 2009, our general partner received incentive distributions of $0.4 million. In
February 2010, our general partner received incentive distributions of $0.6 million.
63
Cash Distributions to Unitholders. Our common and subordinated unitholders and general partner
are entitled to receive quarterly distributions of available cash as defined in our partnership
agreement. The table below shows the quarterly distributions to our unitholders and general partner
(in millions, except for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Quarterly |
|
|
|
|
|
|
|
|
Distribution Per |
|
Total Cash |
|
Date of |
|
Date of |
Quarters Ended |
|
Unit |
|
Distribution |
|
Declaration |
|
Distribution |
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007(1) |
|
$ |
0.12813 |
|
|
$ |
11.1 |
|
|
January 2008 |
|
February 2008 |
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2008 |
|
|
0.28750 |
|
|
|
24.9 |
|
|
April 2008 |
|
May 2008 |
June 30, 2008 |
|
|
0.29500 |
|
|
|
25.6 |
|
|
July 2008 |
|
August 2008 |
September 30, 2008 |
|
|
0.30000 |
|
|
|
34.5 |
|
|
October 2008 |
|
November 2008 |
December 31, 2008 |
|
|
0.32000 |
|
|
|
36.8 |
|
|
January 2009 |
|
February 2009 |
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009 |
|
|
0.32500 |
|
|
|
37.4 |
|
|
April 2009 |
|
May 2009 |
June 30, 2009 |
|
|
0.33000 |
|
|
|
42.2 |
|
|
July 2009 |
|
August 2009 |
September 30, 2009 |
|
|
0.35000 |
|
|
|
45.1 |
|
|
October 2009 |
|
November 2009 |
December 31, 2009 |
|
|
0.36000 |
|
|
|
50.3 |
|
|
January 2010 |
|
February 2010 |
|
|
|
(1) |
|
The December 31, 2007 distribution of $0.12813 per unit was prorated for the
period beginning with the closing of our initial public offering through December 31, 2007. |
The distribution for the quarter ended December 31, 2009 was paid to all outstanding
common and subordinated units on February 12, 2010 to unitholders of record at the close of
business on February 1, 2010.
5. Regulatory Assets and Liabilities
Our non-current regulatory assets and liabilities are included in other non-current assets and
liabilities on our balance sheets. Our regulatory asset and liability
balances are recoverable or reimbursable over various
periods. Below are the details of our regulatory assets and liabilities as of December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Current regulatory assets |
|
|
|
|
|
|
|
|
Difference
between gas retained and consumed in operations |
|
$ |
1.7 |
|
|
$ |
26.3 |
|
Other |
|
|
2.5 |
|
|
|
2.1 |
|
|
|
|
|
|
|
|
Total current regulatory assets |
|
|
4.2 |
|
|
|
28.4 |
|
|
|
|
|
|
|
|
Non-current regulatory assets |
|
|
|
|
|
|
|
|
Taxes on capitalized funds used during construction |
|
|
17.7 |
|
|
|
18.2 |
|
Unamortized loss on reacquired debt |
|
|
5.5 |
|
|
|
6.4 |
|
Postretirement benefits |
|
|
1.4 |
|
|
|
2.2 |
|
Other |
|
|
2.5 |
|
|
|
2.5 |
|
|
|
|
|
|
|
|
Total non-current regulatory assets |
|
|
27.1 |
|
|
|
29.3 |
|
|
|
|
|
|
|
|
Total regulatory assets |
|
$ |
31.3 |
|
|
$ |
57.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current regulatory liabilities |
|
|
|
|
|
|
|
|
Difference
between gas retained and consumed in operations |
|
$ |
14.7 |
|
|
$ |
29.2 |
|
|
|
|
|
|
|
|
Non-current regulatory liabilities |
|
|
|
|
|
|
|
|
Property and plant depreciation |
|
|
17.8 |
|
|
|
19.0 |
|
Postretirement benefits |
|
|
9.7 |
|
|
|
6.1 |
|
Other |
|
|
0.2 |
|
|
|
0.3 |
|
|
|
|
|
|
|
|
Total non-current regulatory liabilities |
|
|
27.7 |
|
|
|
25.4 |
|
|
|
|
|
|
|
|
Total regulatory liabilities |
|
$ |
42.4 |
|
|
$ |
54.6 |
|
|
|
|
|
|
|
|
64
The significant regulatory assets and liabilities include:
Difference between gas retained and gas consumed in operations: These amounts reflect the
value of the volumetric difference between the gas retained from our customers and the gas consumed
in operations. These amounts are not included in the rate base but are expected to be
recovered/refunded in subsequent fuel filing periods.
Taxes on capitalized funds used during construction: These regulatory asset balances were
established to offset the deferred tax for the equity component of the allowance for funds used
during the construction of long-lived assets. Taxes on capitalized funds used during construction
are amortized and the offsetting deferred income taxes are included in the rate base. Both are
recovered over the depreciable lives of the long lived asset to which they relate.
Unamortized loss on reacquired debt: These amounts represent the deferred and unamortized
portion of losses on reacquired debt which are not included in the rate base, but are
expected to be recovered over the original life of the debt issue through the authorized rate of
return.
Postretirement Benefits: These balances represents deferred amounts related to unrecognized
gains and losses or changes in actuarial assumptions related to our postretirement benefit plans
and differences in the postretirement benefit related amounts expensed and the amounts recoverable
in rates. Postretirement benefit amounts have been included in the rate base
computations for CIG and are
recoverable in such periods as the benefits are funded.
Property and plant depreciation: Amount
represents the deferral of customer-funded amounts
for costs of future asset retirements. This amount is included in the
rate base computations and the depreciation-related amounts are refunded over the lives of the
long-lived assets to which they relate.
65
6. Long-Term Debt and Other Financing Obligations
Our long-term debt and other financing obligations are as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(in millions) |
|
El Paso Pipeline Partners, L.P. |
|
|
|
|
|
|
|
|
Revolving credit facility, variable due 2012 |
|
$ |
520.0 |
|
|
$ |
584.9 |
|
Note payable to El Paso, variable due 2012, LIBOR plus 3.5% |
|
|
10.0 |
|
|
|
10.0 |
|
Notes, variable due 2012, LIBOR plus 3.5% |
|
|
35.0 |
|
|
|
35.0 |
|
Notes, 7.76%, due 2011 |
|
|
37.0 |
|
|
|
37.0 |
|
Notes, 7.93%, due 2012 |
|
|
15.0 |
|
|
|
15.0 |
|
Notes, 8.00%, due 2013 |
|
|
88.0 |
|
|
|
88.0 |
|
Colorado Interstate Gas Company |
|
|
|
|
|
|
|
|
Senior Notes, 5.95%, due 2015 |
|
|
35.0 |
|
|
|
35.0 |
|
Senior Notes, 6.80%, due 2015 |
|
|
339.9 |
|
|
|
339.9 |
|
Senior Debentures, 6.85%, due 2037 |
|
|
100.0 |
|
|
|
100.0 |
|
|
|
|
|
|
|
|
Total long-term debt |
|
|
1,179.9 |
|
|
|
1,244.8 |
|
Other financing obligations |
|
|
182.7 |
|
|
|
116.1 |
|
|
|
|
|
|
|
|
Total long-term debt and other financing obligations |
|
|
1,362.6 |
|
|
|
1,360.9 |
|
Less: Current maturities |
|
|
5.0 |
|
|
|
3.6 |
|
|
|
|
|
|
|
|
Total long-term debt and other financing obligations, less current maturities |
|
$ |
1,357.6 |
|
|
$ |
1,357.3 |
|
|
|
|
|
|
|
|
Debt Maturities. Aggregate maturities of the principal amounts of long-term debt and other
financing obligations as of December 31, 2009 for the next 5 years and in total thereafter are as
follows (in millions):
|
|
|
|
|
2010 |
|
$ |
5.0 |
|
2011 |
|
|
42.0 |
|
2012 |
|
|
585.0 |
|
2013 |
|
|
93.0 |
|
2014 |
|
|
5.0 |
|
Thereafter |
|
|
632.6 |
|
|
|
|
|
Total long-term debt and other financing obligations |
|
$ |
1,362.6 |
|
|
|
|
|
Credit Facility. In November 2007, we entered into an unsecured 5-year revolving credit
facility (Credit Facility) with an initial aggregate borrowing capacity of up to $750 million
expandable to $1.25 billion for certain expansion projects and acquisitions. Borrowings under the
Credit Facility are guaranteed by certain of our subsidiaries. As of December 31, 2009 and 2008, we
had $520.0 million and $584.9 million outstanding under our revolving credit facility. As of
December 31, 2009, our remaining availability under the Credit Facility is approximately $215
million.
The credit facility has two pricing grids, one based on credit ratings and the other based on
leverage. As of December 31, 2009, the leverage pricing grid was in effect and our cost of
borrowing was LIBOR plus 0.425 percent based on our leverage. We also pay an annual utilization and commitment fee of
0.225 percent. At December 31, 2009 and 2008, our all-in borrowing rates were 0.9 percent and 1.4
percent.
The Credit Facility contains covenants and provisions that affect us, the borrowers and our
other restricted subsidiaries, including, without limitation customary covenants and provisions:
|
|
|
prohibiting the borrowers from creating or incurring indebtedness (except for certain
specified permitted indebtedness) if such incurrence would cause a breach of the leverage
ratio described below; |
|
|
|
|
prohibiting WIC from creating or incurring indebtedness in excess of $50 million (other
than indebtedness under the Credit Facility); |
|
|
|
|
limiting our ability and that of the borrowers and our other restricted subsidiaries
from creating or incurring certain liens on our respective properties (subject to
enumerated exceptions);
|
66
|
|
|
limiting our ability to make distributions and equity repurchases (which shall be
permitted if no insolvency default or event of default exists); and |
|
|
|
|
prohibiting consolidations, mergers and asset transfers by us, the borrowers and our
other restricted subsidiaries (subject to enumerated exceptions). |
For the year ended December 31, 2009, we were in compliance with our debt-related covenants.
The Credit Facility requires us to maintain, as of the end of each fiscal quarter, a consolidated
leverage ratio (consolidated indebtedness to consolidated EBITDA (as defined in the Credit
Facility)) of less than 5.00-to-1.00 for any four consecutive quarters; and 5.50-to-1.00 for any
three consecutive quarters subsequent to the consummation of specified permitted acquisitions
having a value greater than $25 million. We also have added additional flexibility to our covenants
for growth projects. In case of a capital construction or expansion project in excess of $20
million, pro forma adjustments to consolidated EBITDA, approved by the lenders, may be made based
on the percentage of capital costs expended and projected cash flows for the project. Such
adjustments shall be limited to 25 percent of actual EBITDA.
The Credit Facility contains certain customary events of default that affect us, the borrowers
and our other restricted subsidiaries, including, without limitation, (i) nonpayment of principal
when due or nonpayment of interest or other amounts within five business days of when due; (ii)
bankruptcy or insolvency with respect to us, our general partner, the borrowers or any of our other
restricted subsidiaries; (iii) judgment defaults against us, our general partner, the borrowers or
any of our other restricted subsidiaries in excess of $50 million; or (iv) the failure of El Paso
to directly or indirectly own a majority of the voting equity of our general partner and a failure
by us to directly or indirectly own 100 percent of the equity of El Paso Pipeline Partners
Operating Company, L.L.C.
EPB Other Debt Obligations. In September 2008, we issued $175.0 million of senior unsecured
notes and a $10.0 million note payable to El Paso as partial funding for the acquisition of
additional interests in CIG and SNG as discussed in Note 2. Our restrictive covenants under these
debt obligations are substantially the same as the restrictive covenants under our Credit Facility,
with the exception of the requirement to maintain an interest coverage ratio (consolidated EBITDA
(as defined in the Note Purchase Agreement) to interest expense) of greater than or equal to 1.50
to 1.00 for any four consecutive fiscal quarters.
CIG Debt. In March 2009, CIG, Colorado Interstate Issuing Corporation (CIIC), El Paso and
certain other El Paso subsidiaries filed a registration statement on Form S-3 under which CIG and
CIIC may co-issue debt securities in the future. CIIC is a wholly owned finance subsidiary of CIG
and is the co-issuer of CIGs outstanding debt securities. CIIC has no material assets, operations,
revenues or cash flows other than those related to its service as a co-issuer of CIGs debt
securities. Accordingly, it has no ability to service obligations on CIGs debt securities.
For the year ended December 31, 2009, CIG was in compliance with its debt-related covenants.
Under CIGs various financing documents they are subject to a number of restrictions and covenants.
The most restrictive of these include limitations on the incurrence of liens and limitations on
sale-leaseback transactions
Other Financing Obligations. In June 2009 and November 2008, the Totem Gas Storage project and
the High Plains pipeline were placed in service. Upon placing these projects in service, CIG
transferred its title in the projects to WYCO Development LLC (WYCO), a joint venture with an
affiliate of PSCo in which CIG has a 50 percent ownership interest. Although CIG transferred the
title in these projects to WYCO, we continue to reflect the Totem Gas Storage facility and the High
Plains Pipeline as property, plant and equipment in our financial statements as of December 31,
2009 due to CIGs continuing involvement with the projects through WYCO.
CIG constructed the Totem Gas Storage project and the High Plains pipeline and its joint
venture partner in WYCO funded 50 percent of the construction costs of the projects, which we
reflected as other non-current liabilities in our balance sheet during the construction period.
Upon completion of the construction, CIGs obligations to the affiliate of PSCo for these
construction advances were converted into financing obligations to WYCO and accordingly, we
reclassified the amounts from other non-current liabilities to debt and other financing
obligations.
67
Totem Gas Storage financing obligation. The Totem Gas Storage obligation has a principal
amount of $68.9 million as of December 31, 2009 and has monthly principal payments totaling $1.4
million each year through 2060. CIG also makes monthly interest payments on this obligation that
are based on 50 percent of the operating results of the Totem Gas Storage facility, which is
currently estimated at a 15.5% rate as of December 31, 2009.
High Plains Pipeline financing obligation. The High Plains Pipeline obligation has a
principal amount of $106.4 million as of December 31, 2009, and has monthly principal payments
totaling $3.1 million each year through 2043. CIG also makes monthly interest payments on this
obligation that are based on 50 percent of the operating results of the High Plains pipeline,
which is currently estimated at a 15.5% rate as of December 31, 2009.
Capital Lease. Effective December 1, 1999, WIC leased a compressor station under a capital
lease from WYCO. The compressor station lease expires in November 2029. The total original
capitalized cost of the lease was $12.0 million. As of December 31, 2009, we had a net book value
of approximately $7.4 million related to this capital lease. Minimum future lease payments under
the capital lease together with the present value of the net minimum lease payments as of December
31, 2009 are as follows:
|
|
|
|
|
Year Ending December 31, |
|
(In millions) |
|
2010 |
|
$ |
1.3 |
|
2011 |
|
|
1.2 |
|
2012 |
|
|
1.1 |
|
2013 |
|
|
1.1 |
|
2014 |
|
|
1.0 |
|
Thereafter |
|
|
7.9 |
|
|
|
|
|
Total minimum lease payments |
|
|
13.6 |
|
Less: amount representing interest |
|
|
(6.2 |
) |
|
|
|
|
Present value of net minimum lease payments |
|
$ |
7.4 |
|
|
|
|
|
7. Fair Value of Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, |
|
|
2009 |
|
2008 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
|
Amount |
|
Value |
|
Amount |
|
Value |
|
|
(In millions) |
Long-term financing obligations, including current maturities |
|
$ |
1,362.6 |
|
|
$ |
1,374.7 |
|
|
$ |
1,360.9 |
|
|
$ |
1,126.3 |
|
As of December 31, 2009 and 2008, the carrying amounts of cash and cash equivalents,
short-term borrowings, and trade receivables and payables represented fair value because of the
short-term nature of these instruments. At December 31, 2009 and 2008, we had notes receivable from
El Paso of $93.2 million and $199.0 million due upon demand, with variable interest rates of 1.5%
and 3.2%. While we are exposed to changes in interest income based on changes to the variable
interest rate, the fair value of these notes receivable approximates their carrying value due to
the market-based nature of the interest rate and the fact that they are demand notes. We estimate
the fair value of our debt based on quoted market prices for the same or similar issues.
8. Commitments and Contingencies
Legal Proceedings
WIC Line 124A Rupture. On November 11, 2006, a bulldozer driver ran into and ruptured WICs
Line 124A near Cheyenne, Wyoming resulting in an explosion and fire, and the subsequent death of
the driver. The driver was working for a construction company hired by Rockies Express Pipeline,
LLC to construct its new pipeline in a corridor substantially parallel to WICs Line 124A. The
Department of Transportations Pipeline and Hazardous Materials Safety Administration (PHMSA)
conducted an investigation into the incident, with which we fully cooperated. In March 2008, we
received from PHMSA a Notice of Probable Violation with a proposed fine of
$3.4 million. In October 2008, a hearing was held at which we contested the proposed fine. In
December 2009, PHMSA issued its order, imposing a fine of $2.3 million, which has been paid.
68
Gas Measurement Cases. CIG and a number of its affiliates were named defendants in actions
that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the
underpayment of royalties. The first set of cases was filed in 1997 by an individual under the
False Claims Act and have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui
Tam Litigation, U.S. District Court for the District of Wyoming). These complaints allege an
industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands. In October 2006, the U.S. District Judge issued an
order dismissing all claims against all defendants. In March 2009, the Tenth Circuit Court of
Appeals affirmed the dismissals and in October 2009, the plaintiffs appeal to the United States
Supreme Court was denied.
Similar allegations were filed in a second set of actions initiated in 1999 in Will Price, et
al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County,
Kansas. The plaintiffs seek certification of a class of royalty owners in wells on non-federal and
non-Native American lands in Kansas, Wyoming and Colorado. The plaintiffs seek an unspecified
amount of monetary damages in the form of additional royalty payments (along with interest,
expenses and punitive damages) and injunctive relief with regard to future gas measurement
practices. In September 2009, the court denied the motions for class certification. The plaintiffs
have filed a motion for reconsideration. CIGs costs and legal exposure related to this lawsuit and
claim are not currently determinable.
In addition to the above proceedings, we and our subsidiaries and affiliates are named
defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of
our business. For each of these matters, we evaluate the merits of the case or claim, our exposure
to the matter, possible legal or settlement strategies and the likelihood of an unfavorable
outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish
the necessary accruals. While the outcome of these matters, including those discussed above, cannot
be predicted with certainty, and there are still uncertainties related to the costs we may incur,
based upon our evaluation and experience to date, we believe we have established appropriate
reserves for these matters. It is possible that new information or future developments could
require us to reassess our potential exposure related to these matters and adjust our accruals
accordingly, and these adjustments could be material. As of December 31, 2009, we had no accruals for our outstanding legal matters. It is possible,
however, that new information or future developments could require us to reassess our potential
exposure related to these matters and establish accruals accordingly.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental
quality and pollution control. These laws and regulations require us to remove or remedy the effect
of the disposal or release of specified substances at current and former operating sites. At
December 31, 2009, we had accrued approximately $10.8 million for expected remediation costs and
associated onsite, offsite and groundwater technical studies and for related environmental legal
costs; however, we estimate that our exposure could be as high as $35 million. Our accrual includes
$7.7 million for environmental contingencies related to properties CIG previously owned. Our
environmental remediation projects are in various stages of completion. Our recorded liabilities
reflect our current estimates of amounts we will expend to remediate these sites. However,
depending on the stage of completion or assessment, the ultimate extent of contamination or
remediation required may not be known. As additional assessments occur or remediation efforts
continue, we may incur additional liabilities.
Below is a reconciliation of our accrued liability from January 1, 2009 to December 31, 2009
(in millions):
|
|
|
|
|
Balance at January 1, 2009 |
|
$ |
13.3 |
|
Additions/adjustments for remediation activities |
|
|
1.0 |
|
Payments for remediation activities |
|
|
(3.5 |
) |
|
|
|
|
Balance at December 31, 2009 |
|
$ |
10.8 |
|
|
|
|
|
For 2010, we estimate that our total remediation expenditures will be approximately $2.4
million, which will be expended under government directed clean-up plans.
69
It is possible that new information or future developments could require us to reassess our
potential exposure related to environmental matters. We may incur significant costs and liabilities
in order to comply with existing environmental laws and regulations. It is also possible that other
developments, such as increasingly strict environmental laws, regulations and orders of regulatory
agencies, as well as claims for damages to property and the environment or injuries to other
persons resulting from our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other relevant developments
occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related
to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe
our reserves are adequate.
Regulatory Matter
Fuel Recovery Mechanism. During the first quarter of 2008, the FERC issued an order approving
a fuel and related gas cost recovery mechanism for CIG which was designed to recover all cost
impacts, or flow through to shippers any revenue impacts, of all fuel imbalance revaluations and
related gas balance items. Effective April 2008, WIC implemented a similar fuel and related gas
cost recovery mechanism, subject to the outcome of a FERC proceeding. The implementation of these
mechanisms was protested by a limited number of shippers. On July 31, 2009 and October 1, 2009, the
FERC issued orders to CIG and WIC, respectively, directing us to remove the cost and revenue
components from our fuel recovery mechanisms while preserving the historic volumetric-based
tracking mechanism. Due to these orders, our future earnings may be impacted by both positive and
negative fluctuations in gas prices related to fuel imbalance revaluations, their settlement, and
other gas balance related items. We continue to explore options to minimize the price volatility
associated with these operational activities.
Our tariffs continue to provide that the difference between the
quantity of fuel retained and fuel used in operations and lost and
unaccounted for will be flowed-through or charged to shippers. These
fuel trackers remove the impact of over or under collecting fuel and
lost and unaccounted for from our operational gas costs
Other Commitments
Capital Commitments. At December 31, 2009, we had capital commitments of $38.9 million related
primarily to CIGs Raton 2010 expansion project, the majority of which will be paid in 2010. We
have other planned capital projects that are discretionary in nature, with no substantial
contractual capital commitments made in advance of the actual expenditures.
Transportation and Storage Commitments. We have entered into transportation commitments and
storage capacity contracts totaling $176.6 million at December 31, 2009, of which $59.0 million is
related to storage capacity contracts with our affiliate, Young Gas Storage Company, Ltd. Our
annual commitments under these agreements are $21.1 million in 2010, $22.6 million in 2011, $28.4
million in 2012, $25.9 million in each of 2013 and 2014 and $52.7 million in total thereafter.
Operating Leases. We lease property, facilities and equipment under various operating leases.
Our minimum future annual rental commitments under our operating leases at December 31, 2009, are
as follows:
|
|
|
|
|
Year Ending December 31, |
|
(In millions) |
|
2010 |
|
$ |
2.2 |
|
2011 |
|
|
2.3 |
|
2012 |
|
|
2.3 |
|
2013 |
|
|
2.4 |
|
2014 |
|
|
2.4 |
|
Thereafter |
|
|
0.6 |
|
|
|
|
|
Total minimum lease payments |
|
|
12.2 |
|
|
|
|
|
Rental expense on our operating leases for each of the three years ended December 31, 2009,
2008 and 2007 was $2 million. These amounts include our share of rent allocated to us from El Paso.
Other Commercial Commitments. We hold cancelable easements or rights-of-way arrangements from
landowners permitting the use of land for the construction and operation of our pipeline systems.
Currently, our obligations under these easements are not material to our results of operations.
70
9.
Retirement Benefits
Pension and Retirement Savings Plans. El Paso maintains a pension plan and a retirement
savings plan covering substantially all of its U.S. employees, including CIGs former employees.
The benefits under the pension plan are determined under a cash balance formula. Under its
retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six
percent of eligible compensation and can make additional discretionary matching contributions
depending on its performance relative to its peers. El Paso is responsible for benefits accrued
under its plans and allocates the related costs to its affiliates.
Postretirement Benefits Plan. CIG provides postretirement medical benefits for a closed group
of retirees. These benefits may be subject to deductibles, co-payment provisions, and other
limitations and dollar caps on the amount of employer costs and El Paso reserves the right to
change these benefits. In addition, certain former CIG employees continue to receive limited
postretirement life insurance benefits. CIGs postretirement benefit plan costs are prefunded to
the extent these costs are recoverable through our rates. To the extent actual costs differ from
the amounts recovered in rates, a regulatory asset or liability is recorded. CIG does not expect to
make any contributions to the postretirement benefit plan in 2010.
Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting
for CIGs postretirement benefit plan, we record an asset or liability based on the over funded or
under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies
to record a regulatory asset or liability for any deferred amounts related to unrecognized gains
and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated
other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we
reclassified $5 million from accumulated other comprehensive
income to a regulatory liability.
The table below provides information about CIGs postretirement benefit plan. In 2008, we
adopted the FASBs revised measurement date provisions for other postretirement benefit plans and
the information below for 2008 is presented and computed as of and for the fifteen months ended
December 31, 2008. For 2009, the information is presented and computed as of and for the twelve
months ended December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Change in accumulated postretirement benefit obligation: |
|
|
|
|
|
|
|
|
Accumulated postretirement benefit obligation beginning of period |
|
$ |
7.6 |
|
|
$ |
7.3 |
|
Interest cost |
|
|
0.4 |
|
|
|
0.5 |
|
Participant contributions |
|
|
0.4 |
|
|
|
0.5 |
|
Actuarial (gain) loss |
|
|
(2.3 |
) |
|
|
0.8 |
|
Benefits paid(1) |
|
|
(0.8 |
) |
|
|
(1.5 |
) |
|
|
|
|
|
|
|
Accumulated postretirement benefit obligation end of period |
|
$ |
5.3 |
|
|
$ |
7.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
Fair value of plan assets beginning of period |
|
$ |
12.5 |
|
|
$ |
18.0 |
|
Actual return on plan assets |
|
|
2.0 |
|
|
|
(4.3 |
) |
Participant contributions |
|
|
0.4 |
|
|
|
0.5 |
|
Benefits paid |
|
|
(1.0 |
) |
|
|
(1.7 |
) |
|
|
|
|
|
|
|
Fair value of plan assets end of period |
|
$ |
13.9 |
|
|
$ |
12.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of funded status: |
|
|
|
|
|
|
|
|
Fair value of plan assets |
|
$ |
13.9 |
|
|
$ |
12.5 |
|
Less: accumulated postretirement benefit obligation |
|
|
5.3 |
|
|
|
7.6 |
|
|
|
|
|
|
|
|
Net asset at December 31 |
|
$ |
8.6 |
|
|
$ |
4.9 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amounts shown net of a subsidy of approximately $0.2 million for each of the
years ended December 31, 2009 and 2008 related to the Medicare Prescription Drug, Improvement,
and Modernization Act of 2003. |
71
Plan Assets. The primary investment objective of CIGs plan is to ensure that, over the
long-term life of the plan an adequate pool of sufficiently liquid assets exists to meet the
benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature
covering typical market cycles. Any shortfall of investment performance compared to investment
objectives is generally the result of economic and capital market conditions. Although actual
allocations vary from time to time from the targeted allocations, the target allocations of CIGs
postretirement plans assets are 65 percent equity and 35 percent fixed income securities. The
plans assets may be invested in a manner that replicates, to the extent feasible, the Russell 3000
Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income
diversification, respectively.
We use various methods to determine the fair values of the assets in CIGs other
postretirement benefit plans, which are impacted by a number of factors, including the availability
of observable market data over the contractual term of the underlying assets. We separate CIGs
plans assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of
this market data and the significance of non-observable data used to determine the fair value of
these assets. As of December 31, 2009, the assets are comprised of an exchange-traded mutual fund
with a fair value of $1.2 million and common/collective trusts with a fair value of $12.7 million.
The exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair
value (which is considered a Level 1 measurement) is determined based on the price quoted for the
fund in actively traded markets. The common/collective trusts are invested in approximately 65
percent equity and 35 percent fixed income securities, and their fair values (which are considered
Level 2 measurements) are determined primarily based on the net asset value reported by the issuer,
which is based on similar assets in active markets. We may adjust the fair value of the
common/collective trusts, when necessary, for factors such as liquidity or risk of nonperformance
by the issuer. CIGs plan does not have any assets that are considered Level 3 measurements. The
methods described above may produce a fair value that many not be indicative of net realizable
value or reflective of future fair values, and there have been no changes in the methodologies used
at December 31, 2009 and 2008.
Expected Payment of Future Benefits. As of December 31, 2009, we expect the following benefit
payments under CIGs plan (in millions):
|
|
|
|
|
Year Ending |
|
Expected |
December 31, |
|
Payments(1) |
2010 |
|
$ |
0.7 |
|
2011 |
|
|
0.7 |
|
2012 |
|
|
0.6 |
|
2013 |
|
|
0.6 |
|
2014 |
|
|
0.5 |
|
2015 - 2019 |
|
|
2.0 |
|
|
|
|
(1) |
|
Includes a reduction of approximately $0.2 million in each of the years 2010 -
2014 and approximately $0.8 million in aggregate for 2015 2019 for an expected subsidy
related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. |
Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit
obligations and net benefit costs are based on actuarial estimates and assumptions. The following
table details the weighted average actuarial assumptions used in determining CIGs postretirement
plan obligations and net benefit costs for 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(Percent) |
Assumptions related to benefit obligations at December 31, 2009 and 2008
and September 30, 2007 measurement dates: |
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.06 |
|
|
|
5.82 |
|
|
|
6.05 |
|
Assumptions related to benefit costs at December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.82 |
|
|
|
6.05 |
|
|
|
5.50 |
|
Expected return on plan assets(1) |
|
|
8.00 |
|
|
|
8.00 |
|
|
|
8.00 |
|
|
|
|
(1) |
|
The expected return on plan assets is a pre-tax rate of return based on our
targeted portfolio of investments. CIGs postretirement benefit plans investment earnings are
subject to unrelated business income taxes at a rate of 35%. The expected return on plan
assets for CIGs postretirement benefit plan is calculated using the after-tax rate of return. |
72
Actuarial estimates for CIGs postretirement benefits plan assumed a weighted average
annual rate of increase in the per capita costs of covered health care benefits of 8.0 percent,
gradually decreasing to 5.0 percent by the year 2015. Changes in the assumed health care cost
trends do not have a material impact on the amounts reported for CIGs interest costs or CIGs
accumulated postretirement benefit obligations as of and for the
years ended December 31, 2009 and 2008.
Components of Net Benefit Income. For each of the years ended December 31, the components of
net benefit income are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Interest cost |
|
$ |
0.4 |
|
|
$ |
0.4 |
|
|
$ |
0.6 |
|
Expected return on plan assets |
|
|
(0.6 |
) |
|
|
(0.9 |
) |
|
|
(0.9 |
) |
Other |
|
|
(0.3 |
) |
|
|
(0.7 |
) |
|
|
(0.5 |
) |
|
|
|
|
|
|
|
|
|
|
Net postretirement benefit income |
|
$ |
(0.5 |
) |
|
$ |
(1.2 |
) |
|
$ |
(0.8 |
) |
|
|
|
|
|
|
|
|
|
|
10. Transactions with Major Customers
The following table shows revenues from major customers for each of the three years ended
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(In millions) |
PSCo |
|
$ |
156.1 |
|
|
$ |
92.4 |
|
|
$ |
93.7 |
|
Anadarko Petroleum Corporation and Subsidiaries |
|
|
70.6 |
|
|
|
62.6 |
|
|
|
39.5 |
|
Williams Gas Marketing, Inc. |
|
|
62.8 |
|
|
|
41.9 |
|
|
|
46.3 |
|
11. Supplemental Cash Flow Information
The following table contains supplemental cash flow information from continuing operations for
each of the three years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(In millions) |
Interest paid, net of capitalized amounts |
|
$ |
71.5 |
|
|
$ |
56.1 |
|
|
$ |
60.5 |
|
Income tax payments |
|
|
|
|
|
|
|
|
|
|
277.0 |
(1) |
|
|
|
(1) |
|
Includes amounts related to the settlement of current and deferred tax balances due to
CIGs conversion to a partnership in November 2007 (see Note 12). |
12. Investments in Unconsolidated Affiliates and Transactions with Affiliates
Investments in Unconsolidated Affiliates
SNG. In conjunction with our initial public offering of common units in November 2007, El Paso
contributed to us, at their historical cost, a 10 percent general partner interest in SNG. On
September 30, 2008, we acquired an additional 15 percent general partner interest in SNG from El
Paso, as further discussed in Note 2. Our proportionate share of the operating results of SNG has
been reflected as earnings from unconsolidated affiliates in our financial statements since the
date the respective interests were contributed to us. We account for our investment in SNG using
the equity method of accounting.
WYCO. CIG has a 50 percent investment in WYCO which we account for using the equity method of
accounting. WYCO owns the High Plains pipeline (a FERC-regulated pipeline), the Totem Gas Storage
facility (a FERC-regulated storage facility), a state regulated intrastate pipeline and a
compressor station. CIG has other financing obligations payable to WYCO totaling $175.3 million and
$108.2 million as of December 31, 2009 and 2008, which are described further in Note 6.
73
The information below related to our unconsolidated affiliates reflects our net investment and
earnings we recorded from these investments and summarized financial information of our
proportionate share of SNG.
Net Investment and Earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from |
|
|
|
Investment |
|
|
Unconsolidated Affiliates |
|
|
|
December 31, |
|
|
December 31, |
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
2007(1) |
|
|
|
(In millions) |
|
|
(In millions) |
|
SNG |
|
$ |
403.4 |
|
|
$ |
393.8 |
|
|
$ |
52.5 |
|
|
$ |
29.8 |
|
|
$ |
2.6 |
|
Other |
|
|
14.1 |
|
|
|
17.0 |
|
|
|
0.9 |
|
|
|
3.1 |
|
|
|
1.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
417.5 |
|
|
$ |
410.8 |
|
|
$ |
53.4 |
|
|
$ |
32.9 |
|
|
$ |
4.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SNG Summarized Financial Information
Results of operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007(1) |
|
|
|
(In millions) |
|
Operating results data: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
127.4 |
|
|
$ |
73.3 |
|
|
$ |
5.9 |
|
Operating expenses |
|
|
63.6 |
|
|
|
38.1 |
|
|
|
2.6 |
|
Income from continuing operations and net income |
|
$ |
52.5 |
|
|
$ |
29.8 |
|
|
$ |
2.6 |
|
|
|
|
(1) |
|
Amounts for 2007 are calculated from the date of the initial public offering to December
31, 2007. |
Financial position data
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Current assets |
|
$ |
23.5 |
|
|
$ |
26.3 |
|
Non-current assets |
|
|
640.7 |
|
|
|
630.9 |
|
Current liabilities |
|
|
26.6 |
|
|
|
23.0 |
|
Long-term debt |
|
|
227.4 |
|
|
|
227.4 |
|
Other non-current liabilities |
|
|
6.8 |
|
|
|
13.0 |
|
|
|
|
|
|
|
|
Net assets |
|
$ |
403.4 |
|
|
$ |
393.8 |
|
|
|
|
|
|
|
|
Transactions with Affiliates
Distributions/Contributions. As further discussed in Note 1, in conjunction with our initial
public offering in November 2007, 10 percent interests in CIG and SNG were contributed to us at
their book value of $253 million and we made distributions to El Paso and its subsidiaries of $737
million using proceeds from the initial public offering and borrowings under our credit facility.
In addition, we repaid affiliated notes payable with El Paso of $225 million. We also made additional distributions to El Paso of $11 million in November
2007.
Distributions Received from SNG. SNG is required to make distributions of available cash as
defined in their partnership agreement on a quarterly basis to their partners, including us. We
received cash distributions from SNG of $42.9 and $26.1 million during the years ended December 31,
2009 and 2008, with the 2008 distribution including $4.3 million of returns of capital from our
investments. In January 2010, we received distributions from SNG of $20.7 million.
74
CIG Distributions to El Paso
CIG Cash Distributions to El Paso. CIG is required to make distributions of available cash
as defined in their partnership agreement on a quarterly basis to their partners, including us.
Due to the retrospective consolidation of CIG, we have reflected 42 percent of CIGs historical
distributions paid to El Paso as distributions to its noncontrolling interest holder in our
financial statements in all periods presented. CIGs remaining historical distributions
(excluding distributions paid to its noncontrolling interest holder) are reflected as
distributions of pre-acquisition earnings and are allocated to our general partner. The
following table shows CIGs cash distributions to El Paso:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Distributions to noncontrolling interest holder |
|
$ |
60.7 |
|
|
$ |
45.6 |
|
Distributions of pre-acquisition earnings |
|
|
15.0 |
|
|
|
43.7 |
|
|
|
|
|
|
|
|
Cash distributions to El Paso |
|
$ |
75.7 |
|
|
$ |
89.3 |
|
|
|
|
|
|
|
|
In January 2010, CIG paid cash distributions of $18.5 million to El Paso.
CIG Non-Cash Distribution to El Paso. Prior to our acquisition of an additional 30 percent
ownership interest in CIG on September 30, 2008, CIG distributed a portion of its notes receivable
under its cash management program to its partners (including us). Approximately $270 million of
this distribution was made to El Paso, which is reflected as a non-cash distribution to El Paso in
our financial statements.
Affiliate Revenues and Expenses. We entered into transactions with our affiliates within the
ordinary course of business and the services are based on the same terms as non-affiliates,
including natural gas transportation services to and from affiliates under long-term contracts and
various operating agreements. CIG also contracts with an affiliate to process natural gas and sell
extracted natural gas liquids.
We do not have employees. Following our reorganization in November 2007, our former employees
continue to provide services to us through an affiliated service company owned by our general
partner, El Paso. We are managed and operated by officers of El Paso, our general partner. We have
an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the
provision of various general and administrative services for our benefit and for direct expenses
incurred by El Paso on our behalf. El Paso bills us directly for certain general and administrative
costs and allocates a portion of its general and administrative costs to us. In addition to
allocations from El Paso, we are allocated costs from El Paso Natural Gas Company and Tennessee Gas
Pipeline Company, our affiliates, associated with our pipeline services. We also allocate costs to
Cheyenne Plains Gas Pipeline, our affiliate, for their share of our pipeline services. The
allocations from El Paso and TGP are based on the estimated level of effort devoted to our
operations and the relative size of our EBIT, gross property and payroll.
We also have entered into various operating and management agreements with El Paso related to
the operation of our assets. The table below shows our affiliate revenues and expenses for the
years ended December 31, 2009, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2009 |
|
2008 |
|
2007 |
|
|
(in millions) |
Revenues from affiliates |
|
$ |
16.1 |
|
|
$ |
21.9 |
|
|
$ |
19.2 |
|
Operation and maintenance expense from affiliates |
|
|
88.7 |
|
|
|
80.7 |
|
|
|
51.1 |
|
Reimbursement of operating expenses charged to affiliates |
|
|
12.0 |
|
|
|
11.9 |
|
|
|
9.8 |
|
75
Cash Management Program. Prior to our July 24, 2009 acquisition of an additional 18 percent
interest in CIG, CIG participated in El Pasos cash management program, which matches short-term
cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside
sources. El Paso uses the cash management program to settle intercompany transactions between
participating affiliates. At December 31, 2009 and 2008, CIG had a note receivable from El Paso of
$73.0 million and $178.8 million. We classified $73.0 million and $102.9 million of this receivable
as current on our balance sheets at December 31, 2009 and 2008, based on the net amount CIG
anticipates using in the next twelve months considering available cash sources and needs. The
interest rate on our note at December 31, 2009 and 2008 was 1.5% and 3.2%.
Notes Receivable and Payable with Affiliates. Prior to the acquisition of additional ownership
interests in CIG and SNG, in September 2008, we received a non-cash distribution of $30.0 million
from CIG in the form of a note receivable from El Paso. As of December 31, 2009 and 2008 we had
$20.2 million remaining on our note receivable from El Paso. This note is due upon demand and was
classified as current on our balance sheet. The interest rate on this variable rate loan was 1.5%
and 3.2% at December 31, 2009 and 2008. As partial funding for the acquisition, we also issued a
note payable to El Paso of $10.0 million. For a further
discussion of the note payable, see Note 2
and Note 6.
Income Taxes. Effective November 1, 2007, CIG converted into a general partnership as
discussed in Note 1 and settled its existing current and deferred tax balances of approximately
$216.4 million pursuant to its tax sharing agreement with El Paso with recoveries of note
receivables from El Paso under its cash management program. During 2007, CIG also settled $8.8
million with El Paso through its cash management program for certain tax attributes previously
reflected as deferred income taxes in our financial statements. These settlements are reflected as
operating activities in our statement of cash flows.
Accounts Receivable Sales Program. CIG sells certain accounts receivable to a QSPE whose
purpose is solely to invest in their receivables, which are short-term assets that generally settle
within 60 days. During the years ended December 31, 2009 and 2008, CIG received net proceeds
of approximately $0.4 billion and $0.3 billion related to sales of receivables to the QSPE and
changes in our subordinated beneficial interests and recognized
losses of $0.4 million and $0.6
million on these transactions. As of December 31, 2009 and 2008, CIG had
approximately $37.2 million and $29.0 million of receivables outstanding with the QSPE, for which
they received cash of $20.0 million in both periods and received subordinated beneficial interests
of approximately $16.8 million and $8.4 million. The QSPE also issued senior beneficial interests
on the receivables sold to a third party financial institution, which totaled $20.4 million and
$20.6 million as of December 31, 2009 and 2008. We reflect the subordinated beneficial interest in
receivables sold at their fair value on the date they are issued. These amounts (adjusted for
subsequent collections) are recorded as accounts receivable from affiliate in our balance sheets.
Our ability to recover our carrying value of our subordinated beneficial interests is based on the
collectability of the underlying receivables sold to the QSPE. We reflect accounts receivable sold
under this program and changes in the subordinated beneficial interests as operating cash flows in
our statement of cash flows. Under the agreements, we earn a fee for servicing the accounts
receivable and performing all administrative duties for the QSPE which is reflected as a reduction
of operation and maintenance expense in our income statement. The fair value of these servicing and
administrative agreements as well as the fees earned were not material to our financial statements
for the years ended December 31, 2009 and 2008.
In January 2010, CIG ceased selling its accounts receivable to the QSPEs and began selling the
receivables directly to the third party financial institution. In return, the third party financial
institution pays a certain amount of cash up front for the receivables, and pays the remaining
amount owed over time as cash is collected from the receivables.
Other Affiliate Balances. We had net contractual, gas imbalance, and trade payables, as well
as other liabilities with our affiliates arising in the ordinary course of business of
approximately $26.9 million and $10.2 million at December 31, 2009 and 2008. Prior to November
2007, WIC participated in El Pasos cash management program to settle intercompany transactions
between participating affiliates. At December 31, 2009 and 2008, we had contractual deposits from
our affiliates of $6.7 million and $6.4 million included in other current liabilities on our
balance sheet.
WIC leases a compressor station from CIGs unconsolidated affiliate, WYCO, and made lease
payments to WYCO of $1.3 million, $1.4 million and $1.5 million for the years ended December 31,
2009, 2008 and 2007.
Indemnification. In connection with our initial public offering, El Paso indemnified us for
three years against certain potential environmental and toxic tort claims, losses and expenses
associated with the business conducted by WIC, CIG and SNG or the operations of their assets
occurring before the closing date of our initial public offering. The maximum liability of El Paso
for this indemnification obligation will not exceed $15 million.
76
13. Income Taxes
In conjunction with our formation, CIG converted its legal structure into a general
partnership effective November 1, 2007 and settled its current and deferred tax balances pursuant
to its tax sharing agreement with El Paso with recoveries of note receivables from El Paso under
its cash management program. The tables below reflect that these balances have been settled and
that CIG no longer pays income taxes effective November 1, 2007.
Components of Income Taxes. The following table reflects the components of income taxes
included in income from continuing operations for the year ended December 31, 2007:
|
|
|
|
|
|
|
2007 |
|
|
|
(In millions) |
|
Current |
|
|
|
|
Federal |
|
$ |
32.7 |
|
State |
|
|
3.7 |
|
|
|
|
|
|
|
|
36.4 |
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
|
|
Federal |
|
|
6.9 |
|
State |
|
|
0.8 |
|
|
|
|
|
|
|
|
7.7 |
|
|
|
|
|
Total income taxes |
|
$ |
44.1 |
|
|
|
|
|
Effective Tax Rate Reconciliation. CIGs income taxes, included in income from continuing
operations, differ from the amount computed by applying the statutory federal income tax rate of 35
percent for the following reasons for the year ended December 31, 2007:
|
|
|
|
|
|
|
2007 |
|
|
|
(In millions, |
|
|
|
except for rates) |
|
Income taxes at the statutory federal rate of 35% |
|
$ |
74.7 |
|
Increase (decrease) |
|
|
|
|
Pretax income not subject to income taxes after conversion to partnership |
|
|
(11.9 |
) |
State income taxes, net of federal income tax benefit |
|
|
3.1 |
|
Income associated with non-taxable entities |
|
|
(21.8 |
) |
|
|
|
|
Income tax expense |
|
$ |
44.1 |
|
|
|
|
|
Effective tax rate |
|
|
21 |
% |
|
|
|
|
77
14. Supplemental Selected Quarterly Financial Information (Unaudited)
Our financial information by quarter is summarized below. Due to the seasonal nature of our
business, information for interim periods may not be indicative of our results of operations for
the entire year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ended |
|
Year to |
|
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31 (1) |
|
Date |
|
|
(in millions, except per unit amounts) |
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
135.3 |
|
|
$ |
122.4 |
|
|
$ |
128.8 |
|
|
$ |
151.1 |
|
|
$ |
537.6 |
|
Operating income |
|
|
72.8 |
|
|
|
64.5 |
|
|
|
67.0 |
|
|
|
88.2 |
|
|
|
292.5 |
|
Earnings from unconsolidated affiliates |
|
|
12.8 |
|
|
|
12.3 |
|
|
|
11.9 |
|
|
|
16.4 |
|
|
|
53.4 |
|
Net income |
|
|
70.8 |
|
|
|
62.5 |
|
|
|
60.3 |
|
|
|
85.9 |
|
|
|
279.5 |
|
Net income attributable to noncontrolling interests |
|
|
(17.4 |
) |
|
|
(13.6 |
) |
|
|
(13.7 |
) |
|
|
(21.3 |
) |
|
|
(66.0 |
) |
Net income attributable to El Paso Pipeline
Partners, L.P. |
|
|
53.4 |
|
|
|
48.9 |
|
|
|
46.6 |
|
|
|
64.6 |
|
|
|
213.5 |
|
Net income attributable to El Paso Pipeline
Partners, L.P. per limited partner unit- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common |
|
|
0.40 |
|
|
|
0.38 |
|
|
|
0.35 |
|
|
|
0.51 |
|
|
|
1.64 |
|
Subordinated |
|
|
0.40 |
|
|
|
0.34 |
|
|
|
0.35 |
|
|
|
0.47 |
|
|
|
1.56 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
121.8 |
|
|
$ |
106.6 |
|
|
$ |
103.3 |
|
|
$ |
125.5 |
|
|
$ |
457.2 |
|
Operating income |
|
|
68.3 |
|
|
|
45.8 |
|
|
|
43.3 |
|
|
|
72.4 |
|
|
|
229.8 |
|
Earnings from unconsolidated affiliates(2) |
|
|
9.6 |
|
|
|
5.6 |
|
|
|
4.8 |
|
|
|
12.9 |
|
|
|
32.9 |
|
Net income |
|
|
72.5 |
|
|
|
46.2 |
|
|
|
43.9 |
|
|
|
71.4 |
|
|
|
234.0 |
|
Net income attributable to noncontrolling interests |
|
|
(21.3 |
) |
|
|
(10.5 |
) |
|
|
(10.7 |
) |
|
|
(19.9 |
) |
|
|
(62.4 |
) |
Net income attributable to El Paso Pipeline
Partners, L.P. |
|
|
51.2 |
|
|
|
35.7 |
|
|
|
33.2 |
|
|
|
51.5 |
|
|
|
171.6 |
|
Net income attributable to El Paso Pipeline
Partners, L.P. per limited partner unit- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common |
|
|
0.31 |
|
|
|
0.27 |
|
|
|
0.29 |
|
|
|
0.37 |
|
|
|
1.26 |
|
Subordinated |
|
|
0.31 |
|
|
|
0.27 |
|
|
|
0.14 |
|
|
|
0.37 |
|
|
|
1.12 |
|
|
|
|
(1) |
|
The quarter ended December 31, 2009 includes a gain of $7.8 million related to
the sale of the Natural Buttes compressor station and gas processing plant (see Note 2). |
|
(2) |
|
We acquired an additional 15 percent interest in SNG from El Paso on September 30,
2008. |
78
SCHEDULE II
EL PASO PIPELINE PARTNERS, L.P.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2009, 2008 and 2007
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at |
|
Charged to |
|
|
|
|
|
Charged to |
|
Balance |
|
|
Beginning |
|
Costs and |
|
|
|
|
|
Other |
|
at End |
Description |
|
of Period |
|
Expenses |
|
Deductions |
|
Accounts |
|
of Period |
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
0.5 |
|
|
$ |
(0.2 |
) |
|
$ |
|
|
|
$ |
(0.3 |
) |
|
$ |
|
|
Legal reserves |
|
|
1.2 |
|
|
|
1.1 |
|
|
|
(2.3 |
) |
|
|
|
|
|
|
|
|
Environmental reserves |
|
|
13.3 |
|
|
|
1.0 |
|
|
|
(3.5 |
) |
|
|
|
|
|
|
10.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
1.1 |
|
|
$ |
(0.7 |
) |
|
$ |
|
|
|
$ |
0.1 |
|
|
$ |
0.5 |
|
Legal reserves |
|
|
|
|
|
|
1.2 |
|
|
|
|
|
|
|
|
|
|
|
1.2 |
|
Environmental reserves |
|
|
14.9 |
|
|
|
1.5 |
|
|
|
(3.1 |
) |
|
|
|
|
|
|
13.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
0.9 |
|
|
$ |
0.1 |
|
|
$ |
|
|
|
$ |
0.1 |
|
|
$ |
1.1 |
|
Legal reserves |
|
|
|
|
|
|
3.1 |
|
|
|
(3.1 |
) |
|
|
|
|
|
|
|
|
Environmental reserves |
|
|
17.1 |
|
|
|
0.9 |
|
|
|
(3.1 |
) |
|
|
|
|
|
|
14.9 |
|
79
|
|
|
ITEM 9. |
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
|
|
|
ITEM 9A. |
|
CONTROLS AND PROCEDURES |
Evaluation of Disclosure Controls and Procedures
As of December 31, 2009, we carried out an evaluation under the supervision and with the
participation of our management, including the Chief Executive Officer (CEO) and Chief Financial
Officer (CFO) of our general partner, as to the effectiveness, design and operation of our
disclosure controls and procedures. This evaluation considered the various processes carried out
under the direction of El Pasos disclosure committee in an effort to ensure that information
required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate,
complete and timely. Our management, including the CEO and CFO of our general partner, does not
expect that our disclosure controls and procedures or our internal controls will prevent and/or
detect all errors and all fraud. A control system, no matter how well conceived and operated, can
provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Further, the design of a control system must reflect the fact that there are resource constraints,
and the benefits of controls must be considered relative to their costs. Because of the inherent
limitations in all control systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within our company have been detected. Our
disclosure controls and procedures are designed to provide reasonable assurance of achieving their
objectives and the CEO and CFO of our general partner have concluded that our disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of
December 31, 2009. See Item 8, Financial Statements and Supplementary Data under Managements
Annual Report on Internal Control Over Financial Reporting.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the fourth
quarter of 2009 that have materially affected or are reasonably likely to materially affect our
internal control over financial reporting.
|
|
|
ITEM 9B. |
|
OTHER INFORMATION |
None.
80
PART III
|
|
|
ITEM 10. |
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Partnership Management
El Paso Pipeline GP Company, L.L.C., our general partner, manages our operations and
activities. Our general partner and its board of directors are not elected by our unitholders and
are not subject to re-election on a regular basis. Unitholders are not entitled to elect the
directors of our general partner or directly or indirectly participate in our management or
operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will
be liable, as a general partner, for all of our debts (to the extent not paid from our assets),
except for indebtedness or other obligations that are made expressly non-recourse to it. Our
general partner therefore may cause us to incur indebtedness or other obligations that are
non-recourse to it.
The directors of our general partner oversee our operations. We presently have seven
directors, three of whom are independent as defined under the independence standards established by
the New York Stock Exchange and under our corporate governance guidelines. El Paso appoints all
members to the board of directors of our general partner. The New York Stock Exchange does not
require a listed limited partnership like us to have a majority of independent directors on the
board of directors of our general partner or to establish a compensation committee or a nominating
and governance committee. However, the board of our general partner has a standing audit committee,
described below.
The independent board members comprise all of the members of the audit committee. The audit
committee assists the board in its oversight of the integrity of our financial statements and our
compliance with legal and regulatory requirements and corporate policies and controls. The audit
committee has the sole authority to retain and terminate our independent registered public
accounting firm, approve all auditing services and related fees and the terms thereof, and
pre-approve any non-audit services to be rendered by our independent registered public accounting
firm. Our independent registered public accounting firm is given unrestricted access to the audit
committee. The members of the audit committee also serve as a conflicts committee to review
specific matters that the board believes may involve conflicts of interest. The conflicts committee
determines if the resolution of the conflict of interest is fair and reasonable to us. Any matters
approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us,
approved by all of our partners, and not a breach by our general partner of any duties it may owe
us or our unitholders.
We do not directly employ any of the persons responsible for our management or operation.
Rather, El Paso personnel manage and operate our business. Officers of our general partner, who are
also officers of El Paso, manage the day-to-day affairs of our business and conduct our operations.
We also utilize a significant number of employees of El Paso to operate our business and provide us
with general and administrative services. We reimburse El Paso for allocated expenses of
operational personnel who perform services for our benefit and we reimburse El Paso for allocated general and administrative expenses.
In order to maximize operational flexibility, we conduct our operations through subsidiaries.
We have one direct operating subsidiary, El Paso Pipeline Partners Operating Company, L.L.C., a
limited liability company that conducts business through itself and its subsidiaries.
81
Directors and Executive Officers of Our General Partner
The following table sets forth information with respect to the directors and executive
officers of our general partner as of February 26, 2010.
|
|
|
|
|
|
|
Name |
|
Age |
|
Position with El Paso Pipeline GP Company, L.L.C. |
Ronald L. Kuehn, Jr
|
|
|
74 |
|
|
Chairman of the Board |
James C. Yardley
|
|
|
58 |
|
|
Director, President and Chief Executive Officer |
John R. Sult
|
|
|
50 |
|
|
Director, Senior Vice President and Chief Financial Officer |
Robert W. Baker
|
|
|
53 |
|
|
Executive Vice President and General Counsel |
James J. Cleary
|
|
|
55 |
|
|
Senior Vice President |
Daniel B. Martin
|
|
|
53 |
|
|
Senior Vice President |
Norman G. Holmes
|
|
|
53 |
|
|
Senior Vice President |
Douglas L. Foshee
|
|
|
50 |
|
|
Director |
D. Mark Leland
|
|
|
48 |
|
|
Director |
Arthur C. Reichstetter
|
|
|
63 |
|
|
Director |
William A. Smith
|
|
|
65 |
|
|
Director |
Ronald L. Kuehn, Jr. Mr. Kuehn has been Chairman of the Board of El Paso Pipeline GP Company,
L.L.C. since August 2007. Mr. Kuehn previously served as Chairman of the Board of Directors for El
Paso from March 2003 to May 2009 and Interim Chief Executive Officer from March 2003 to September
2003. From September 2002 to March 2003, Mr. Kuehn served as Lead Director of El Paso. From January
2001 to March 2003, he was a business consultant. Mr. Kuehn served as non-executive Chairman of the
Board of El Paso from October 1999 to December 2000. Mr. Kuehn previously served as Chairman of the
Board of Sonat Inc. from April 1986 and President and Chief Executive Officer from June 1984 until
his retirement in October 1999. Mr. Kuehn formerly served on the Board of Directors of Praxair,
Inc. until 2008, Dun & Bradstreet Corporation until 2007 and Regions Financial Corporation until
2007.
James C. Yardley. Mr. Yardley has been Director, President and Chief Executive Officer of El
Paso Pipeline GP Company, L.L.C. since August 2007. He has been Executive Vice President of El Paso
with responsibility for the regulated pipeline business unit since August 2006. He has served as
President of Tennessee Gas Pipeline since February 2007 and Chairman of the Board since August
2006. Mr. Yardley has been Chairman of El Paso Natural Gas Company since August 2006 and has
served as President of Southern Natural Gas Company since May 1998. Mr. Yardley has been a member
of the Management Committees of both Colorado Interstate Gas Company and Southern Natural Gas
Company since their conversion to general partnerships in November 2007. Mr. Yardley is currently a
member of the board of directors of Scorpion Offshore Ltd. He also serves on the Board of
Interstate Natural Gas Association of America and previously served as its Chairman.
John R. Sult. Mr. Sult has been a Director of El Paso Pipeline GP Company, L.L.C. since June
2009. He has served as Senior Vice President and Chief Financial Officer of El Paso Pipeline GP
Company, L.L.C. since November 2009 and served as Senior Vice President, Chief Financial Officer
and Controller from August 2007 to November 2009. Mr. Sult has been Senior Vice President and Chief
Financial Officer of El Paso since November 2009 and previously served as Senior Vice President and
Controller from November 2005 to November 2009. He served as Senior Vice President, Chief
Financial Officer and Controller of El Pasos Pipeline Group from November 2005 to November 2009.
Mr. Sult was Vice President and Controller for Halliburton Energy Services from August 2004 to
October 2005.
Robert W. Baker. Mr. Baker has been Executive Vice President and General Counsel of El Paso
Pipeline GP Company, L.L.C. since August 2007. He has been Executive Vice President and General
Counsel of El Paso since January 2004. From February 2003 to December 2003, he served as Executive
Vice President of El Paso and President of El Paso Merchant Energy. Mr. Baker previously served as
Senior Vice President and Deputy General Counsel of El Paso from January 2002 to February 2003.
82
James J. Cleary. Mr. Cleary has been Senior Vice President of El Paso Pipeline GP Company,
L.L.C. since August 2007. He has been a director and President of El Paso Natural Gas Company since
January 2004. Mr. Cleary has been a member of the Management Committee of Colorado Interstate Gas
Company since November 2007 and President since January 2004. He previously served as Chairman of
the Board of both El Paso Natural Gas Company and Colorado Interstate Gas Company from May 2005 to
August 2006. From January 2001 to December 2003, he served as President of ANR Pipeline Company.
Daniel B. Martin. Mr. Martin has been Senior Vice President of El Paso Pipeline GP Company,
L.L.C. since August 2007. He has been a member of the Management Committees of both Colorado
Interstate Gas Company and Southern Natural Gas Company since November 2007. Mr. Martin has been a
director of El Paso Natural Gas Company and Tennessee Gas Pipeline Company since May 2005. He
previously served as a director of Colorado Interstate Gas Company and Southern Natural Gas Company
from May 2005 to November 2007. Mr. Martin has been Senior Vice President of Colorado Interstate
Gas Company since January 2001, Senior Vice President of Southern Natural Gas Company and Tennessee
Gas Pipeline Company since June 2000 and Senior Vice President of Southern Natural Gas Company
since February 2000. He served as a director of ANR Pipeline Company from May 2005 through February
2007 and Senior Vice President of ANR Pipeline Company from January 2001 to February 2007.
Norman G. Holmes. Mr. Holmes has been Senior Vice President of El Paso Pipeline GP Company,
L.L.C. since August 2007. He has been a member of the Management Committee of Southern Natural Gas
Company since November 2007 and Senior Vice President and Chief Commercial Officer since August
2006. He previously served as a director of Southern Natural Gas Company from November 2005 to
November 2007. Mr. Holmes served as Vice President, Business Development of Southern Natural Gas Company from 1999 to 2006.
Douglas L. Foshee. Mr. Foshee has been a Director of El Paso Pipeline GP Company, L.L.C. since
August 2007. He has been Chairman of the Board of El Paso since May 2009 and President, Chief
Executive Officer and a director of El Paso since September 2003. Prior to joining El Paso, Mr.
Foshee served as Executive Vice President and Chief Operating Officer of Halliburton Company having
joined that company in 2001 as Executive Vice President and Chief Financial Officer. Several
subsidiaries of Halliburton, including DII Industries and Kellogg Brown & Root, commenced
prepackaged Chapter 11 proceedings to discharge current and future asbestos and silica personal
injury claims in December 2003 and an order confirming a plan of reorganization became final
effective December 31, 2004. Prior to assuming his position at Halliburton, Mr. Foshee served as
President, Chief Executive Officer and Chairman of the Board of Nuevo Energy Company and Chief
Executive Officer and Chief Operating Officer of Torch Energy Advisors Inc. Mr. Foshee presently
serves as a director of Cameron International Corporation and is a trustee of AIG Credit Facility
Trust. Mr. Foshee serves as Chairman of the Federal Reserve Bank of Dallas, Houston Branch. Mr.
Foshee also serves on the Board of Trustees of Rice University and serves as a member of the
Council of Overseers for the Jesse H. Jones Graduate School of Management. He is a member of
various civic and community organizations.
D. Mark Leland. Mr. Leland has been a Director of El Paso Pipeline GP Company, L.L.C. since
August 2007. He has been Executive Vice President of El Paso and President of El Pasos Midstream business
unit since October 2009. Mr. Leland previously served as Executive Vice President and Chief
Financial Officer of El Paso from August 2005 to November 2009. Mr. Leland served as Executive Vice
President of El Paso Exploration & Production Company from January 2004 to August 2005, and as
Chief Financial Officer and a director from April 2004 to August 2005. He served as Senior Vice
President and chief operating officer of GulfTerra Energy Partners, L.P. and its general partner
from January 2003 to December 2003, as Senior Vice President and Controller from July 2000 to
January 2003, and as Vice President from August 1998 to July 2000.
83
Arthur C. Reichstetter. Mr. Reichstetter has been a Director of El Paso Pipeline GP Company,
L.L.C. since November 2007. He has been a private investment manager since 2007. Mr. Reichstetter
had been Managing Director of Lazard Freres from April 2002 until his retirement in June 2007. From
February 1998 to January 2002, Mr. Reichstetter was a Managing Director with Dresdner Kleinwort
Wasserstein, formerly Wasserstein Parella & Co. Mr. Reichstetter was a Managing Director with
Merrill Lynch from March 1993 until his retirement in February 1996. Prior to that time, Mr.
Reichstetter worked as an investment banker at The First Boston Corporation from 1974 until 1993,
in various positions becoming a managing director with that company in 1982.
William A. Smith. Mr. Smith has been a Director of El Paso Pipeline GP Company, L.L.C. since
May 2008. Mr. Smith is Managing Director and partner in Galway Group, L.P., an investment banking/energy
advisory firm headquartered in Houston, TX. In 2002, Mr. Smith retired from El Paso Corporation,
where he was an Executive Vice President and Chairman of El Paso Merchant Energys Global Gas
Group. Mr. Smith had a 29 year career with Sonat Inc. prior to its merger with El Paso in 1999. At
the time of the merger, Mr. Smith was Executive Vice President and General Counsel. He previously
served as Chairman and President of Southern Natural Gas Company and as Vice Chairman of Sonat
Exploration Company. Mr. Smith is currently a director of Eagle Rock Energy G&P LLC, a
midstream/upstream master limited partnership and serves on that companys audit committee. Mr.
Smith previously served on the Board of Directors of Maritrans Inc. until 2006.
Our directors hold office until the earlier of their death, resignation, removal or
disqualification or until their successors have been elected and qualified. Officers serve at the
discretion of the board of directors. There are no family relationships among any of our directors
or executive officers.
Audit Committee
The board of directors of our general partner has a standing audit committee. All of the
members are independent as defined under the independence standards established by the New York
Stock Exchange. The audit committee is presently comprised of Messrs. Kuehn, Reichstetter and
Smith. The audit committee plays an important role in promoting effective accounting, financial
reporting, risk management and compliance procedures and controls. Each member of the audit
committee meets the financial literacy standard required by the New York Stock Exchange rules and
at least one member qualifies as having accounting or related financial management expertise. The
board of directors of our general partner has affirmatively determined that Mr. Reichstetter
satisfies the definition of audit committee financial expert, as defined by SEC rules, and has
designated him as an audit committee financial expert.
Corporate Governance Guidelines and Code of Ethics
Our Corporate Governance Guidelines, provide the framework for the effective governance of our
partnership. We adopted the Corporate Governance Guidelines, which apply to the board of directors
of our general partner, as well as to persons performing services to us, to address matters
including qualifications for directors, standards for independence of directors, responsibilities
of directors, limitation on serving on other boards/committees, the composition and responsibility
of committees, conduct and minimum frequency of board and committee meetings, management
succession, director access to management and outside advisors, director compensation, equity
ownership guidelines, director orientation and continuing education, and annual self-evaluation of
the board, its committees and directors. The board of directors of our general partner recognizes
that effective corporate governance is an on-going process, and the board will review and revise as
necessary our Corporate Governance Guidelines annually, or more frequently if deemed necessary. Our
Corporate Governance Guidelines may be found on our website at www.eppipelinepartners.com.
84
We also adopted a code of ethics, referred to as our Code of Business Conduct, that applies
to all directors and employees of our general partner, including its Chief Executive Officer, Chief
Financial Officer and senior financial and accounting officers, as well as all El Paso employees
working on behalf of us or our general partner. The Code of Business Conduct is a value-based code
that is built on five core values: stewardship, integrity, safety, accountability and excellence.
In addition to other matters, the Code of Business Conduct establishes policies to deter wrongdoing
and to promote honest and ethical conduct, including ethical handling of actual or apparent
conflicts of interest, compliance with applicable laws, rules and regulations, full, fair,
accurate, timely and understandable disclosure in public communications and prompt internal
reporting of violations of the Code of Business Conduct. A copy of the Code of Business Conduct is
available on our website at www.eppipelinepartners.com. We will post on our internet
website all waivers to or amendments of the Code of Business Conduct, which are required to be
disclosed by applicable law and the New York Stock Exchange listing standards. Currently, we do not
have nor do we anticipate any waivers of or amendments to the Code of Business Conduct. We believe
the Code of Business Conduct exceeds the requirements set forth in the applicable SEC regulations
and the corporate governance rules of the New York Stock Exchange.
Executive Sessions of the Board and Communications by Interested Parties
As set forth in our Corporate Governance Guidelines and in accordance with NYSE listing
standards, the board of directors of our general partner holds executive sessions on a regular
basis without management present. Mr. Ronald L. Kuehn, Jr., our independent chairman of the board, presides over all executive
sessions of the board.
The board of directors of our general partner has established a process for interested parties
to communicate with the board or any individual member thereof. Such communications should be in
writing, addressed to the board or an individual director, c/o Ms. Marguerite Woung-Chapman,
Corporate Secretary, P.O. Box 2511, Houston, TX 77252. The corporate secretary will forward such
correspondence to the addressee.
Web Access
We provide access through our website to current information related to corporate governance,
including a copy of the charter of the audit committee of the board, our Corporate Governance
Guidelines, our Code of Business Conduct, biographical information concerning each director, and
other matters regarding our corporate governance principles. We also provide access through our
website to all filing submitted by El Paso Pipeline Partners, L.P. to the SEC. Our website is
www.eppipelinepartners.com, and access to this information is free of charge to the user
(except for any internet provider or telephone charges).
Reimbursement of Expenses of Our General Partner
Our general partner does not receive any management fee or other compensation for its
management of our partnership under the omnibus agreement with El Paso or otherwise. Under the
terms of the omnibus agreement, we reimburse El Paso for the provision of various general and
administrative services for our benefit. We also reimburse El Paso for direct expenses incurred on
our behalf and expenses allocated to us as a result of our becoming a public entity. The
partnership agreement provides that our general partner determines the expenses that are allocable
to us.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires executive officers
and directors of our general partner and persons who beneficially own more than 10 percent of a
registered class of our equity securities to file reports of ownership and changes in ownership
with the Securities and Exchange Commission and to furnish us with copies of all such reports.
Based solely upon a review of the copies of the reports received by us, we believe that all such
filing requirements were satisfied during 2009.
85
|
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|
ITEM 11. |
|
EXECUTIVE COMPENSATION |
The executive officers of our general partner are also executive officers of El Paso or one of
its pipeline subsidiaries. The compensation of the executive officers of our general partner is set
by El Paso, and we have no control over the compensation determination process. The officers and
employees of our general partner participate in employee benefit plans and arrangements sponsored
by El Paso. Other than the Long-Term Incentive Plan described below, neither we nor our general
partner have established any employee benefit plans and our general partner has not entered into
employment agreements with any of its officers.
Compensation Discussion and Analysis
We do not directly employ any of the persons responsible for managing or operating our
business. Instead, we are managed by our general partner, El Paso Pipeline GP Company, L.L.C., the
executive officers of which are employees of El Paso. El Paso Pipeline GP Company, L.L.C. entered
into the omnibus agreement with El Paso, pursuant to which, among other matters:
|
|
|
El Paso makes available to El Paso Pipeline GP Company, L.L.C. the services of the El
Paso employees who serve as the executive officers of El Paso Pipeline GP Company, L.L.C.;
and |
|
|
|
|
El Paso Pipeline GP Company, L.L.C. is obligated to reimburse El Paso for any allocated
portion of the costs that El Paso incurs in providing compensation and benefits to such El
Paso employees. |
Although we bear an allocated portion of El Pasos costs of providing compensation and
benefits to the El Paso employees who serve as the executive officers of our general partner, we
have no control over such costs and cannot establish or direct the compensation policies or
practices of El Paso. Each of these executive officers performs services for our general partner,
as well as El Paso and its affiliates.
We bore substantially less than a majority of El Pasos costs of providing compensation and
benefits to the Chief Executive Officer of our general partner (the principal executive officer),
and the Chief Financial Officer of our general partner (the principal financial officer) during
2009.
Our general partner has adopted the El Paso Pipeline GP Company, L.L.C. Long-Term Incentive
Plan, or LTIP, under which equity awards of our partnership may be granted. At this point in time,
we do not anticipate that the officers and employees of our general partner (including those that
also serve as directors of the general partner) will receive any grants under the LTIP. As
indicated above, the compensation of such officers and employees shall be pursuant to El Pasos
incentive plans and reimbursed by us pursuant to the omnibus agreement. Non-employee directors of
our general partner receive equity grants under the LTIP, as described below.
Long-Term Incentive Plan
The LTIP was designed to promote the interests of our partnership by providing to employees,
consultants, and directors of our general partner and employees and consultants of its affiliates
who perform services for us or on our behalf incentive compensation awards for superior performance
that are based on our common units. Employees, directors, and consultants of our general partner or
an affiliate who perform services for us and who are selected from time to time by the board of our
general partner may be granted awards under the LTIP.
86
The LTIP is administered by the board of our general partner or a committee thereof. The board
of our general partner, subject to the terms of the LTIP, has authority to (i) select the persons
to whom awards are to be granted, (ii) determine the size and type of awards, (iii) determine the
terms and conditions of any award, including any performance conditions, (iv) determine whether, to
what extent, and under what circumstances awards may be settled, exercised, canceled, or forfeited;
(vi) interpret and administer the LTIP and any instrument or agreement relating to an award made
under the LTIP; (vii) establish, amend, suspend, or waive such rules and regulations and appoint
such agents as it shall deem appropriate for the proper administration of the LTIP; and (viii) make
any other determination and take any other action that the board of our general partner deems
necessary or desirable for the administration of the LTIP. All decisions, interpretations and other
actions of the board of our general partner are final and binding.
The LTIP authorizes the granting of unit options, restricted common units, phantom units, unit
appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The
maximum number of our common units that may at any time be delivered or reserved for delivery under
the LTIP is 1,250,000 common units. If any award expires, is canceled, exercised, paid or otherwise
terminates without the delivery of common units, then the units covered by such award shall again
be units with respect to which awards may be granted.
The board of our general partner may terminate or amend the LTIP at any time with respect to
any units for which a grant has not yet been made. The board of our general partner also has the
right to alter or amend the LTIP or any part thereof from time to time, including increasing the
number of units that may be granted subject to the requirements of the exchange upon which the
common units are listed at that time. However, no change in any outstanding grant may be made that
would materially reduce the rights or benefits of the participant without the consent of the
participant. The LTIP will expire on the earliest of (i) the date common units are no longer
available under the LTIP for grants, (ii) termination of the LTIP by the board of our general
partner or (iii) the date 10 years following its date of adoption.
Compensation of Directors
Officers or employees of our general partner or its affiliates who also serve as directors of
our general partner do not receive additional compensation for their service as a director of our
general partner. Directors who are not officers or employees of our general partner or its
affiliates are compensated for their services on the board, as described below. In addition, each
non-employee director is reimbursed for out-of-pocket expenses in connection with attending
meetings of the board of directors or committees. Each director is fully indemnified by us for his
actions associated with being a director to the fullest extent permitted under Delaware law
pursuant to a director indemnification agreement and our partnership agreement.
Cash Retainer. Each non-employee director of our general partner receives an annual retainer
of $50,000, paid in quarterly installments. In addition, the chairman of the audit committee
receives an additional retainer of $8,000 per year.
Initial Equity Grant. Each non-employee director, upon joining the board, receives an initial
long-term equity grant of restricted common units with a value of $50,000. The restricted common
units are granted pursuant to the terms and conditions of the LTIP and vest in three (3) equal
installments commencing on the last day of the calendar year of the year in which the grant was
made and each of the following two anniversaries thereof. As no non-employee directors joined the
board during 2009, no initial equity grants were made in 2009.
Annual Equity Grant. Each non-employee director who is serving on the board on December 1st
will receive an annual grant of restricted common units with a value of $50,000. This annual award
is granted pursuant to the terms and conditions of the LTIP and vests in full on the last day of
the calendar year following the year in which the grant was made. Annual equity grants for Messrs.
Kuehn, Reichstetter and Smith were made on December 1, 2009.
87
Director Compensation Table
The following table sets forth the aggregate dollar amount of all fees paid to each of the
non-employee directors of our general partner during 2009 for their services on the board. The
non-employee directors do not receive stock options or pension benefits.
Director Compensation
for the Year Ended December 31, 2009 (1)
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|
|
|
|
|
|
|
|
Fees Earned or |
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|
|
|
|
All Other |
|
|
Name |
|
Paid in Cash(2) |
|
Stock Awards(3)(4) |
|
Compensation(5) |
|
Total |
Ronald L. Kuehn, Jr. |
|
$ |
50,000 |
|
|
$ |
64,020 |
|
|
$ |
7,150 |
|
|
$ |
121,170 |
|
Arthur C. Reichstetter |
|
|
58,000 |
|
|
|
64,020 |
|
|
|
6,942 |
|
|
|
128,962 |
|
William A. Smith |
|
|
50,000 |
|
|
|
66,564 |
|
|
|
7,081 |
|
|
|
123,645 |
|
|
|
|
(1) |
|
Employee directors do not receive any additional compensation for serving on the
board of directors of our general partner; therefore no amounts are shown for Messrs. Foshee,
Sult, Leland and Yardley. Amounts paid as reimbursable business expenses to each director for
attending board functions are not reflected in this table. Our general partner does not
consider the directors reimbursable business expenses for attending board functions and other
business expenses required to perform board duties to have a personal benefit and thus be
considered a perquisite. |
|
(2) |
|
This column reflects the value of a directors annual retainer, as well as the
additional retainer for the chairman of the audit committee. |
|
(3) |
|
The amount in this column represents the dollar amount recognized for financial
reporting purposes for the fiscal year ended December 31, 2009 of restricted common units
granted in 2009 and prior years. |
|
(4) |
|
The grant date fair value of the annual restricted unit grants made to Messrs.
Kuehn, Reichstetter and Smith on December 1, 2009 was $50,002. |
|
(5) |
|
The amount in this column for Mr. Kuehn represents $6,942 in cash distributions
received on unvested restricted common units and $208 for an airline ticket for an occasion
when the directors spouse accompanied him on a business-related flight using a commercial
carrier. The amount in this column for Messrs. Reichstetter and Smith represent cash
distributions received on unvested restricted common units. |
88
|
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|
ITEM 12. |
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. |
The following table sets forth the beneficial ownership of units of our partnership owned as
of February 12, 2010 by:
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each person known by us to be a beneficial owner of more than 5% of the units; |
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|
each of the directors of our general partner; |
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|
each of the named executive officers of our general partner; and |
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all directors and executive officers of our general partner as a group. |
The amounts and percentage of units beneficially owned are reported on the basis of
regulations of the SEC governing the determination of beneficial ownership of securities. Under the
rules of the SEC, a person is deemed to be a beneficial owner of a security if that person has or
shares voting power, which includes the power to vote or to direct the voting of such security,
or investment power, which includes the power to dispose of or to direct the disposition of such
security. Except as indicated by footnote, the persons named in the table below have sole voting
and investment power with respect to all units shown as beneficially owned by them, subject to
community property laws where applicable.
The percentage of total units to be beneficially owned is based on 107,484,747 common units
outstanding as of February 12, 2010.
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|
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|
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Percentage of |
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|
|
Percentage of |
|
Percentage of |
|
|
Common |
|
Common |
|
Subordinated |
|
Subordinated |
|
Total Common |
|
|
Units |
|
Units |
|
Units |
|
Units |
|
and Subordinated |
|
|
Beneficially |
|
Beneficially |
|
Beneficially |
|
Beneficially |
|
Units Beneficially |
Name of Beneficial Owner(1) |
|
Owned |
|
Owned |
|
Owned |
|
Owned |
|
Owned |
El Paso Corporation(2) |
|
|
55,326,397 |
|
|
|
51.5 |
% |
|
|
27,727,411 |
|
|
|
100 |
% |
|
|
61.4 |
% |
Ronald L. Kuehn, Jr. |
|
|
67,347 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
James C. Yardley |
|
|
10,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
Robert W. Baker |
|
|
5,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
John R. Sult |
|
|
10,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
James J. Cleary |
|
|
2,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
Daniel B. Martin |
|
|
|
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
Norman G. Holmes |
|
|
|
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
Douglas L. Foshee |
|
|
25,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
D. Mark Leland |
|
|
13,200 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
Arthur C. Reichstetter |
|
|
107,347 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
William A. Smith |
|
|
7,452 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
All directors and executive
officers as a group (eleven
persons) |
|
|
247,346 |
|
|
|
* |
|
|
|
|
|
|
|
|
% |
|
|
* |
|
|
|
|
* |
|
Less than 1%. |
|
(1) |
|
Unless otherwise indicated, the address for all beneficial owners in this table is
El Paso Building, 1001 Louisiana Street, Houston, Texas 77002. |
|
(2) |
|
El Paso Corporation is the ultimate parent company of El Paso Pipeline Holding
Company, L.L.C., the sole owner of the member interests of our general partner and El Paso
Pipeline LP Holdings, L.L.C., the owner of 55,326,397 common units and 27,727,411 subordinated
units.
El Paso Corporation may, therefore, be deemed to beneficially own the units held by El Paso
Pipeline LP Holdings, L.L.C. |
89
The following table sets forth, as of February 12, 2010, the number of shares of common
stock of El Paso owned by each of the executive officers and directors of our general partner and
all directors and executive officers of our general partner as a group.
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|
Shares of |
|
Shares |
|
|
|
|
|
Percentage of |
|
|
Common |
|
Underlying |
|
Total Shares |
|
Total Shares |
|
|
Stock |
|
Options |
|
of Common |
|
of Common |
|
|
Owned |
|
Exercisable |
|
Stock |
|
Stock |
|
|
Directly or |
|
Within |
|
Beneficially |
|
Beneficially |
Name of Beneficial Owner |
|
Indirectly |
|
60 Days(1) |
|
Owned |
|
Owned(2) |
Ronald L. Kuehn, Jr. |
|
|
114,501 |
(3) |
|
|
8,000 |
|
|
|
122,501 |
|
|
|
* |
|
James C. Yardley |
|
|
274,233 |
|
|
|
477,421 |
|
|
|
751,654 |
|
|
|
* |
|
Robert W. Baker |
|
|
316,512 |
|
|
|
670,141 |
|
|
|
986,653 |
|
|
|
* |
|
John R. Sult |
|
|
85,588 |
|
|
|
149,985 |
|
|
|
235,573 |
|
|
|
* |
|
James J. Cleary |
|
|
59,045 |
|
|
|
271,469 |
|
|
|
330,514 |
|
|
|
* |
|
Daniel B. Martin |
|
|
151,068 |
|
|
|
242,662 |
|
|
|
393,730 |
|
|
|
* |
|
Norman G. Holmes |
|
|
57,989 |
|
|
|
164,512 |
|
|
|
222,501 |
|
|
|
* |
|
Douglas L. Foshee |
|
|
1,073,374 |
|
|
|
2,854,192 |
|
|
|
3,927,566 |
|
|
|
* |
|
D. Mark Leland |
|
|
299,007 |
|
|
|
539,800 |
|
|
|
838,807 |
|
|
|
* |
|
Arthur C. Reichstetter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
William A. Smith |
|
|
|
(4) |
|
|
|
|
|
|
|
|
|
|
* |
|
All directors and
executive officers as a
group (eleven persons) |
|
|
2,431,317 |
|
|
|
5,378,182 |
|
|
|
7,809,499 |
|
|
|
1.1 |
% |
|
|
|
* |
|
Less than 1%. |
|
(1) |
|
The shares indicated represent stock options granted under El Pasos current or
previous stock option plans, which are currently exercisable or which will become exercisable
within 60 days of February 12, 2010. Shares subject to options cannot be voted. |
|
(2) |
|
Based on 701,314,549 shares outstanding as of February 12, 2010. |
|
(3) |
|
Excludes 28,720 shares owned by Mr. Kuehns wife or children. Mr. Kuehn disclaims any beneficial ownership in these 28,720 shares. |
|
(4) |
|
Excludes 8,562 shares owned by Mr. Smiths wife. Mr. Smith disclaims any beneficial ownership in these 8,562 shares. |
EQUITY COMPENSATION PLAN INFORMATION TABLE
The following table provides information concerning securities that may be issued under the El
Paso Pipeline GP Company, L.L.C. Long-Term Incentive Plan as of December 31, 2009. For more
information regarding this plan, which did not require approval by our limited partners, please
read Executive Compensation Long-Term Incentive Plan.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
(b) |
|
(c) |
|
|
|
|
|
|
|
|
|
|
Number of Securities |
|
|
| | |
|
|
|
|
|
Remaining Available for |
|
|
Number of Securities |
|
| | |
|
Future Issuance under |
|
|
to be Issued upon |
|
Weighted-Average |
|
Equity Compensation |
|
|
Exercise of |
|
Exercise Price of |
|
Plans (Excluding |
|
|
Outstanding Options, |
|
Outstanding Options, |
|
Securities Reflected in |
Plan Category |
|
Warrants and Rights |
|
Warrants and Rights |
|
Column (a)) |
Equity compensation
plans approved by
unitholders |
|
|
|
|
|
$ |
|
|
|
|
|
|
Equity compensation plans
not approved by
unitholders(1) |
|
|
|
|
|
$ |
|
|
|
|
1,227,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
$ |
|
|
|
|
1,227,150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Please read Executive Compensation Long-Term Incentive Plan for a
description of the material features of the plan, including the awards that may be granted
under the plan. |
90
|
|
|
ITEM 13. |
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
El Paso owns 55,326,397 common units and 27,727,411 subordinated units representing a 60
percent limited partner interest in us. In addition, our general partner owns a two percent general
partner interest in us and the incentive distribution rights.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments made or to be made by us to our
general partner and its affiliates in connection with ongoing operation and liquidation of El Paso
Pipeline Partners, L.P. These distributions and payments were determined by and among affiliated
entities and, consequently, are not the result of arms-length negotiations.
|
|
|
|
|
Operational Stage |
|
|
|
Distributions of available cash to our
general partner and its affiliates
|
|
We will generally make cash distributions 98 percent to
unitholders, including our general partner and its affiliates
as holders of an aggregate of 55,326,397 common units, all of
the subordinated units and the remaining two percent to our
general partner. In addition, if distributions exceed the
minimum quarterly distribution and other higher target levels,
our general partner will be entitled to increasing percentages
of the distributions, up to
50 percent of the distributions above the highest target level. |
|
|
|
Payments to our general partner and its
affiliates
|
|
Our general partner does not receive a management fee or other
compensation for the management of our partnership. Our
general partner and its affiliates are reimbursed, however,
for all direct and indirect expenses incurred on our behalf.
Our general partner determines the amount of these expenses.
In addition we will reimburse El Paso and its affiliates for
the payment of certain operating expenses and for the
provision of various general and administrative services for
our benefit. |
|
|
|
Withdrawal or removal of our general partner
|
|
If our general partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or
converted into common units, in each case for an amount equal
to the fair market value of those interests. |
|
|
|
|
|
Liquidation Stage |
|
|
|
Liquidation
|
|
Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their particular capital account balances. |
Omnibus Agreement
We are a party to an omnibus agreement with El Paso, our general partner, and certain of their
affiliates that governs our relationship with them regarding the following matters:
|
|
|
reimbursement of certain operating and general and administrative expenses; |
|
|
|
|
indemnification for certain environmental contingencies, tax contingencies and
right-of-way defects; |
|
|
|
|
reimbursement for certain expenditures; and |
|
|
|
|
the guaranty by El Paso of certain expenses under intercompany agreements related to
the Elba Island LNG terminal expansion. |
91
Reimbursement of Operating and General and Administrative Expense
Under the omnibus agreement we reimburse El Paso and its affiliates for the payment of certain
operating expenses and for the provision of various operating expenses and general and
administrative services for our benefit with respect to the assets contributed to us. The omnibus
agreement further provides that we reimburse El Paso for our allocable portion of the premiums on
insurance policies covering our assets.
Pursuant to these arrangements, El Paso performs centralized corporate functions for us, such
as legal, accounting, treasury, insurance administration and claims processing, risk management,
health, safety and environmental, information technology, human resources, credit, payroll,
internal audit, taxes and engineering. We reimburse El Paso and its affiliates for the expenses to
provide these services as well as other expenses it incurs on our behalf, such as salaries of
operational personnel performing services for our benefit and the cost of their employee benefits,
including 401(k), pension and health insurance benefits.
We also reimburse El Paso for any additional state income, franchise or similar tax paid by El
Paso resulting from the inclusion of us (and our subsidiaries) in a combined state income,
franchise or similar tax report with El Paso as required by applicable law. The amount of any such reimbursement will be limited to
the tax that we (and our subsidiaries) would have paid had we not been included in a combined group
with El Paso.
Competition
Neither El Paso nor any of its affiliates are restricted, under either our partnership
agreement or the omnibus agreement, from competing with us. El Paso and any of its affiliates may
acquire, construct or dispose of additional transportation and storage or other assets in the
future without any obligation to offer us the opportunity to purchase or construct those assets.
Indemnification
Under the omnibus agreement, El Paso will indemnify us for three years after the closing of
our initial public offering against certain potential environmental and toxic tort claims, losses
and expenses associated with the business conducted by WIC, CIG or SNG or the operation of their
assets and occurring before the closing date of our initial public offering. The maximum liability
of El Paso for this indemnification obligation will not exceed $15 million and El Paso will not have any obligation under this indemnification until our
aggregate losses exceed $0.25 million. El Paso will have no indemnification obligations with
respect to environmental or toxic tort claims made as a result of additions to or modifications of
environmental laws promulgated after the closing date of our initial public offering. We have
agreed to indemnify El Paso against environmental liabilities related to our assets to the extent
El Paso is not required to indemnify us.
Additionally, El Paso will indemnify us for losses attributable to title defects, failures to
obtain consents or permits necessary for the transfer of the contributed assets, retained assets
and liabilities (including pre-closing litigation relating to contributed assets) and income taxes
attributable to pre-closing operations or ownership of the assets contributed to us, including any
such income tax liability of El Paso and its affiliates that may result from our formation
transactions.
In no event will El Paso be obligated to indemnify us for any claims, losses or expenses or
income taxes referred to in either of the two immediately preceding paragraphs to the extent either
(i) reserved for in our financial statements as of September 30, 2007, or (ii) we recover any such
amounts under available insurance coverage, from contractual rights or other recoveries against any
third party or in the tariffs paid by the customers of our affected pipeline system. In addition,
in no event will the amount required to be indemnified to us in respect of any such claims, losses
or expenses or income taxes in respect of CIG or SNG exceed 10 percent of the gross amount of such
claims, losses, expenses or income taxes, as the case may be.
92
El Paso has also agreed to indemnify us, CIG and SNG from any amounts that may become payable
by such indemnified party in respect of any entity, investment or business that was owned or
operated by WIC, CIG or SNG prior to the closing of our initial public offering but which are not
so owned or operated by WIC, CIG or SNG immediately after the closing of our initial public
offering.
In addition, El Paso has agreed to reimburse us for a 10% share of any amounts that may be
paid by SNG under (i) the performance guaranty entered into by SNG for the Elba Island LNG
terminal, (ii) its obligations in respect of the Elba III expansion or (iii) its obligations in
respect of the Elba Express pipeline expansion. Please read SNG Guaranty of Elba Island
Expansion and SNG Guaranty of Elba Express Pipeline below.
We are required to indemnify El Paso for all losses attributable to the post-closing
operations of the assets contributed to us, to the extent not subject to El Pasos indemnification
obligations.
SNG Guarantee of Elba Island Expansion
SNG formerly owned Southern LNG Inc. (SLNG), which owns and operates a liquefied natural gas
receiving and regasification terminal on Elba Island near Savannah, Georgia. SLNG is now a
subsidiary of El Paso. In connection with an ongoing expansion of the Elba Island LNG terminal
(Elba III), SNG has guaranteed the performance by SLNG of its construction contract with CB&I
Constructors, Inc. SNG is to provide, at its election, either all necessary funds (up to defined
limit) or a guarantee in the form of a performance bond (up to a defined limit) to permit the
construction of the Elba III expansion. Pursuant to the omnibus agreement, El Paso has agreed to
reimburse us, our general partner and any of our majority owned subsidiaries for a 10% share of any
amounts that may be paid by SNG under the Elba Island guaranty or obligations in respect of the
Elba III expansion.
SNG Guarantee of Elba Express Expansion
Elba Express is a large pipeline under construction primarily in Georgia that is expected to
be placed into service in March 2010. It will not be a part of SNG. However, SNG has agreed to
provide, at its election, either all necessary funds to Elba Express (up to a defined limit) or a
guarantee in the form of a performance bond (up to a defined limit) to permit the construction of
the Elba Express pipeline. Pursuant to the omnibus agreement, El Paso has agreed to reimburse us,
our general partner and any of our majority owned subsidiaries for a 10% share of any amounts that
may be paid by SNG pursuant to obligations in respect of the Elba Express pipeline expansion.
Contracts with Affiliates
Contribution Agreement
On July 24, 2009, we entered into the Contribution Agreement with our operating company and El
Paso and certain of its subsidiaries. Pursuant to the Contribution Agreement, on July 24, 2009 we
acquired an additional 18% general partner interest in CIG in exchange for cash consideration of
$214.5 million.
The conflicts committee of the board of directors of the General Partner unanimously
recommended approval of the terms of the acquisition of the additional general partner interest in
CIG. The conflicts committee of the board of directors of our general partner retained independent
legal and financial advisors to assist it in evaluating and negotiating the transaction. In
recommending approval of the transaction, the conflicts committee based its decision in part on an
opinion from the committees independent financial advisor that the consideration to be paid by us
pursuant to the Contribution Agreement is fair, from a financial point of view, to the holders of
our common units, other than our general partner and its affiliates. The board of directors of the
general partner unanimously approved the terms of this acquisition.
93
Note Receivable
Prior to the acquisition of additional ownership interests in CIG and SNG, in September 2008,
we received a non-cash distribution of $30 million from CIG in the form of a note receivable from
El Paso. As of December 31, 2009 we had $20 million remaining on our note receivable from El Paso.
This note is due upon demand. This note bears interest at a variable rate based upon LIBOR plus a
margin determined by reference to El Pasos Amended and Restated Credit Agreement dated July 31,
2006.
Note Payable
On September 30, 2008, in connection with our acquisition of additional ownership interests in
CIG and SNG, we, as guarantor, and our operating company, as issuer, entered into a Note Purchase
Agreement with El Paso. Under the Note Purchase Agreement, our operating company issued a $10
million senior unsecured note to El Paso initially bearing interest at LIBOR plus 3.5% due
September 2012. This note may be prepaid without premium or penalty.
Our operating companys obligations under the Note Purchase Agreement are guaranteed by us.
The Note Purchase Agreement requires that we maintain, as of the end of each fiscal quarter, (i) a
consolidated leverage ratio (consolidated indebtedness to consolidated EBITDA (as defined in the
Note Purchase Agreement)) of less than or equal to 5.50 to 1.00 for any four consecutive fiscal
quarters and (ii) an interest coverage ratio (consolidated EBITDA to interest expense) of greater
than or equal to 1.50 to 1.00 for any four consecutive fiscal quarters. In case of a capital
construction or expansion project costing more than $20 million, pro forma adjustments to
consolidated EBITDA may be made based on the percentage of capital costs expended and projected
cash flows for the project. Such adjustments shall be limited to 25% of actual consolidated EBITDA.
The Note Purchase Agreement also contains certain customary events of default that affect us,
our operating company and our other restricted subsidiaries, including, without limitation, (i)
nonpayment of principal when due or nonpayment of interest or other amounts within five business
days of when due; (ii) bankruptcy or insolvency with respect to us, our general partner, our
operating company or any of our other restricted subsidiaries; or (iii) judgment defaults against
us, our general partner, our operating company or any of our other restricted subsidiaries in
excess of $50 million.
CIG and SNG General Partnership Agreements
General. Prior to the closing of our initial public offering in November 2007, each of CIG and
SNG converted to general partnerships. In connection with the closing of our initial public
offering, El Paso contributed to us a 10 percent general partner interest in each of CIG and SNG. In September 2008, we acquired
from El Paso an additional 30 percent interest in CIG and an additional 15 percent interest in SNG.
In July 2009, we acquired from El Paso an additional 18 percent interest in CIG. After these
transactions, we own indirectly a 58 percent and 25 percent general partner interest in CIG and
SNG, and an El Paso subsidiary owns indirectly a 42 percent and 75 percent general partner interest
in CIG and SNG. A general partnership agreement governs the ownership and management of each of CIG
and SNG. The CIG and SNG partnership agreements are substantially identical to each other in nearly
all material respects.
Each of CIG and SNG is a Delaware general partnership, one partner of which is a wholly owned
subsidiary of El Paso (the El Paso Partner) owning a 42 percent and 75 percent interest in CIG and
SNG, and the other partner is a wholly owned subsidiary of the partnership (the Partnership
Partner) owning a 58 percent and 25 percent general partner interest in CIG and SNG. The purposes
of each partnership are generally to own and operate the interstate pipeline system and related
facilities owned by such partnership and to conduct such other business activities as the
management committee of that partnership may from time to time determine, provided that such
activity either generates qualifying income (as defined in Section 7704 of the Internal Revenue
Code of 1986, or the Code) or enhances operations that generate such qualified income.
Under the partnership agreement each partner may engage in other business opportunities,
including those that compete with the partnerships business, free from any obligation to offer
same to the other partner or the partnership. In addition, any affiliate of a partner is free to
compete with the business operations or activities of the partnership or the other partner.
94
Governance. Although management of each partnership is vested in its partners, the partners of
each partnership have agreed to delegate management of the partnership to a management committee.
Decisions or actions taken by the management committee of CIG or SNG will bind that partnership.
Each management committee is composed of four representatives. The CIG management committee has
three representatives being designated by the Partnership Partner and one representative being
designated by the El Paso Partner. The SNG management committee has three representatives being
designated by the El Paso Partner and one representative being designated by the Partnership
Partner. Each representative has full authority to act on behalf of the partner that designated
such representative with respect to matters pertaining to that partnership. The partners of each
partnership have agreed that each representative is an agent of the partner that designated that
person and does not owe any duty (fiduciary or otherwise) to such
partnership, any other partner or
any other representative.
The management committee of each partnership meets no less often than quarterly, with the time
and location of, and the agenda for, such meetings to be as the management committee determines;
provided that in lieu of a meeting the management committee may elect to act by written consent.
Special meetings of the management committee may be called at such times as a partner or management
committee representative determines to be appropriate. The presence in person, or by electronic
communication, of a majority of representatives (including at least one representative of each
partner) constitutes a quorum of the management committee. Each representative is entitled to one
vote on each matter submitted for vote of the management committee, and except as noted below, the
vote of a majority of the representatives at a meeting properly called and held at which a quorum
is present constitutes the action of the management committee. Any action of the management
committee may be taken by unanimous written consent.
The following actions require the unanimous approval of the management committee:
|
|
|
dissolution of the partnership; |
|
|
|
|
causing or permitting the partnership to take certain bankruptcy actions; |
|
|
|
|
mortgaging or pledging assets with a value exceeding $225
million in the case of CIG and any assets in the case of SNG; |
|
|
|
|
the commencement or the resolution before the FERC (or any U.S. Court of Appeals of an
appeal of a FERC order) of certain actions under the Natural Gas Act,
or any other proceeding before the FERC that would result in a $50
million or more (i) reduction in revenue or (ii) payment of
penalties, refunds or interest; |
|
|
|
|
any amendment of the partnership agreement; |
|
|
|
|
the admission of any person as a partner (other than a permitted transferee of a
partner); |
|
|
|
|
any proposal to dispose of assets of such partnership with a value exceeding $225
million in the case of CIG and $450 million in the case of SNG; |
|
|
|
|
the disposition of all or substantially all of the assets of the partnership, and any
disposition of interests in the partnership that would result in a termination under
Section 708 of the Code; |
|
|
|
|
any merger, consolidation or conversion of the partnership; |
|
|
|
|
entering into new lines of business, including but not limited to, those that do not
generate qualifying income under Section 7704 of the Internal Revenue Code; and |
|
|
|
|
any amendment to the master services agreement to which the partnership is a party,
other than any amendment that the management committee determines would not materially
adversely affect such partnership. |
Quarterly Cash Distributions. Under the CIG and SNG partnership agreements, on or before the
end of the calendar month following each quarter prior to the commencement of the partnerships
liquidation, the management committee of each partnership is required to review the amount of
available cash with respect to that quarter and distribute 100 percent of the available cash to the
partners of that partnership in accordance with their percentage interests, subject to limited
exceptions. Available cash with respect to any quarter is generally defined in these partnerships
as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand
from Working Capital Borrowings made subsequent to the end of that quarter (as determined by the
management committee), less cash reserves established by the management committee as necessary or
appropriate for the conduct of the partnerships business.
95
Capital Calls to the Partners. From time to time as determined to be appropriate by the
management committee of a partnership, the management committee may issue a capital call notice to
the partners of that partnership for capital contributions to be made to fund the partnerships
operations. The notice will specify the amount of the capital contribution from all partners
collectively and each partner individually, the purpose for which the funds will be used and the
date that the contributions are to be made. If a partner fails to make a capital contribution when
required under a capital call notice, the partner(s) that have made their full contribution may
elect to pay the unpaid contribution and elect to treat that additional contribution as either (a)
resulting in a priority interest of such contributing partner(s) or (b) treated as a permanent
capital contribution that results in an adjustment of each partners relative percentage interest.
If priority interest treatment is elected, all distributions that would otherwise have been paid to
the non-contributing partner will be paid to the contributing partner until the priority interest
is terminated, which will occur when the total of additional distributions to the contributing
partner(s) equal the sum of the additional contribution amount plus 12 percent per annum.
Cash Management Programs
SNG participates in El Pasos cash management program which matches short-term cash surpluses
and needs of participating affiliates, thus minimizing El Pasos total borrowings from outside
sources. SNG has historically provided cash to El Paso in exchange for an affiliated note
receivable that is due upon demand. At December 31, 2009, SNG had a note receivable from El Paso of
$154 million. The balance due to SNG under the cash management program will be used for general
partnership purposes, debt repurchase expenses and premiums and to pay for capital expenditures.
The interest rate payable by El Paso under the cash management program will be equal to LIBOR plus
the applicable margin in effect from time to time pursuant to El Paso Corporations Amended and
Restated Credit Agreement dated July 31, 2006, as amended or replaced from time to time.
In conjunction with our acquisition of the additional interest in CIG on July 24, 2009, CIG
terminated its participation in El Pasos cash management program. CIG converted its note
receivable with El Paso under its cash management program into a demand note receivable from El
Paso. At December 31, 2009, CIG had $73 million remaining under this note at an interest rate of
1.5%. We classified $73 million as current based on the net amount CIG anticipates using in the
next twelve months considering available cash sources and needs.
CIG Operating Agreements
CIG entered into a Construction and Operating Agreement with WIC, on March 12, 1982. This
agreement was amended in 1984 and 1988. Under this agreement, CIG agreed to design and construct
the WIC system and to operate WIC (including conducting WICs marketing and administering WICs
service agreements) using the same practices that CIG adopts in the operation and administration of
its own facilities. Under this agreement, CIG is entitled to be reimbursed by WIC for all costs
incurred in the performance of the services, including both direct costs and allocations of general
and administrative costs based on direct field labor charges. Included in CIGs allocated expenses
are a portion of El Pasos general and administrative expenses and EPNG and TGP allocated payroll
and other expenses. CIG is the operator of the WIC facilities, and is reimbursed by WIC for
operation, maintenance and general and administrative costs allocated from CIG, in each case under
the CIG Construction and Operating Agreement referred to above.
CIG entered into a Construction and Operating Agreement with Young Gas Storage Company, Ltd.
on June 30, 1992. This agreement was amended in 1994 and 1997. Under this agreement, CIG agreed
to design and construct the Young storage facilities and to operate the facilities (including
conducting Youngs marketing and administering Youngs service agreements) using the same practices
that CIG adopts in the operation and administration of its own facilities. CIG is entitled to
reimbursement of all costs incurred in the performance of the services, including both direct costs
and allocations of general and administrative costs based on direct field labor charges (including
any costs charged or allocated to CIG from other affiliates). The agreement is subject to
termination only in the event of the dissolution or bankruptcy of CIG, or a material default by CIG
that is not cured within certain permissible time periods. Otherwise the agreement continues until
the termination of the Young partnership agreement.
96
CIG entered into a Construction and Operating Agreement with Cheyenne Plains Gas Pipeline
Company, L.L.C. on November 14, 2003. Under this agreement, CIG agreed to design and construct the
facilities and to operate the Cheyenne Plains facilities (including conducting marketing and
administering the service agreements) using the same practices that CIG adopts in the operation and
administration of its own facilities. CIG is entitled to reimbursement by Cheyenne Plains for all
costs incurred in the performance of the services, including both direct field labor charges and
allocations of general and administrative costs (including any costs charged or allocated to CIG
from other affiliates) using a modified Massachusetts allocation methodology, a time and motion
analysis or other appropriate allocation methodology. The agreement is subject to termination by
Cheyenne Plains on 12 months prior notice and is subject to termination by CIG on 12 months prior notice given
no earlier that 48 months following the commencement of service by Cheyenne Plains in December 2004.
Transportation Agreements
CIG is a party to four transportation service agreements with WIC for transportation on the
WIC system at maximum recourse rates. The total volume subject to these contracts is 176,971 Dth/d.
These contracts extend for various terms with 57,950 Dth/d expiring on December 31, 2011; and the
balance expiring thereafter. Under the service agreements, we are required to make minimum annual
payments of $6 million in each of the years 2010-2011, $3 million in 2012 and $3 million in total
thereafter. In response to a solicitation of offers to turn back capacity in a WIC open season, CIG
relinquished 70,000 Dth/d of capacity effective January 1, 2008. WIC has remarketed this capacity
along with off-system capacity acquired by WIC on a third party pipeline and other capacity on its
pipeline to another affiliate, Cheyenne Plains, under a Firm Transportation Service Agreement for
125,000 Dth/d from the Opal Hub in western Wyoming to the Cheyenne Hub at maximum recourse rates
for a term extending to 2020.
WIC is also a party to a transportation service agreement with CIG pursuant to which CIG will
acquire 75,600 Dth/day of firm transportation capacity on WIC from a Primary Point of Receipt at the
Cheyenne Hub to a Primary Point of Delivery into El Pasos Ruby Pipeline at Opal, Wyoming. The rate
that CIG will pay for this service is WICs maximum recourse rates plus the cost of any off-system
capacity on a third party pipeline that is acquired by WIC to provide this service. The service
will commence on the in-service date of El Pasos Ruby Pipeline and will continue until the later
of July 1, 2021 or ten years from the commencement date.
CIG is a party to a capacity release agreement with PSCo, whereby PSCo has released storage
capacity in our affiliate, Young Gas Storage Company, Ltd., to us for a term expiring on April 30,
2025. PSCo simultaneously contracted for a corresponding quantity of transportation and storage
balancing service (which utilizes the storage capacity acquired through the capacity release).
In order to provide jumper compression service between the CIG system and the Cheyenne
Plains pipeline system, CIG added compression at CIGs existing compressor station in Weld County,
Colorado. Cheyenne Plains entered into a 25-year contract that expires in 2030 for the full
capacity of the additional compression pursuant to which CIGs full cost of service is covered. The
contract is for 119,500 Dth/d.
Interconnection and Operational Balancing Agreements and Other Inter-Affiliate Agreements
Each of WIC and CIG is a party to an operational balancing agreement with each other and
independently with Cheyenne Plains. These agreements require the interconnecting parties to use
their respective reasonable efforts to cause the quantities of gas that are tendered/accepted at
each point of interconnection to equal the quantities scheduled at those points. The agreements
provide for the treatment and resolution of imbalances. The agreements are terminable by either
party on 30 days advance notice.
CIG and WIC are parties to a capacity lease agreement dated November 1, 1997. In 1998, WIC
installed a compressor unit at WICs Laramie compressor station. The installation of this
compressor unit allowed the interconnection of CIGs Powder River lateral and WICs mainline
transmission system and resulted in an increase of approximately 49 MDth/d of capacity on CIGs
Powder River lateral (the original capacity on the Powder River lateral was approximately 46
MDth/d). In connection with the installation of the compression by WIC, CIG leased the additional
49 MDth/d of capacity in the Powder River lateral to WIC. WIC, in turn, leased to CIG 46 MDth/d of
capacity through the new WIC compressor unit. The initial term of the lease of the Powder River
lateral capacity
97
from CIG to WIC was 10 years from the November 15, 1998 in-service date of the additional
compression. In November 2008, the term of the lease was extended for 10 years. The term of the
lease of the compression unit capacity from WIC to CIG continues for as long as CIG has shipper
agreements for service using the compressor unit capacity. The parties to this agreement have
agreed that the reciprocal leases provide adequate compensation to each other so there is no rental
fee for either lease other than an agreement by WIC to reimburse CIG for any increase in operating
expense incurred by CIG (including increased taxes, insurance or other expenses).
WIC is a party to an Upstream Pipeline Capacity Agreement with Ruby Pipeline, LLC, a wholly
owned indirect subsidiary of El Paso Corporation. Pursuant to this agreement WIC agreed to offer
gas transportation services to shippers desiring to move gas volumes to the inlet to the proposed
Ruby pipeline at Opal, Wyoming. Ruby has agreed to reimburse WIC for any unrecovered costs
associated with 200 MDth/day of off-system capacity that was acquired by WIC to provide the
upstream transportation services (either through a direct payment or through the acquisition of
capacity on WIC). The off-system capacity was acquired by WIC on the expansions of the Rockies
Express Pipeline from the Piceance Basin to Wamsutter, and the expansion of the Overthrust Pipeline
from Wamsutter to Opal.
Other Agreements
In addition, each of WIC, CIG and SNG currently have and will have in the future other routine
agreements with El Paso or one of its subsidiaries that arise in the ordinary course of business,
including agreements for services and other transportation and exchange agreements and
interconnection and balancing agreements with other El Paso pipelines.
For a description of certain additional affiliate transactions, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 12.
Review, Approval or Ratification of Transactions with Related Persons
Our partnership agreement contains specific provisions that address potential conflicts of
interest between our general partner and its affiliates, including El Paso, on one hand, and us and
our limited partners, on the other hand. Whenever such a conflict of interest arises, our general
partner will resolve the conflict. Our general partner may, but is not required to, seek the
approval of such resolution from the conflicts committee of the board of directors of our general
partner, which, is required to be comprised of independent directors. The partnership agreement
provides that our general partner will not be in breach its obligations under the partnership
agreement or its duties to us or to our unitholders if the resolution of the conflict is:
|
|
|
approved by the conflicts committee; |
|
|
|
|
approved by the vote of a majority of the outstanding common units, excluding any
common units owned by our general partner or any of its affiliates; |
|
|
|
|
on terms no less favorable to us than those generally being provided to or available
from unrelated third parties; or |
|
|
|
|
fair and reasonable to us, taking into account the totality of the relationships
between the parties involved, including other transactions that may be particularly
favorable or advantageous to us. |
If our general partner does not seek approval from the conflicts committee and the board of
directors of our general partner determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the standards set forth in the third and
fourth bullet points above, then it will be presumed that, in making its decision, the board of
directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner
or the partnership, the person bringing or prosecuting such proceeding will have the burden of
overcoming such presumption. Unless the resolution of a conflict is specifically provided for in
our partnership agreement, our general partner or its conflicts committee may consider any factors
it determines in good faith to consider when resolving a conflict. When our partnership agreement
requires someone to act in good faith, it requires that person to reasonably believe that he is
acting in the best interests of the partnership, unless the context otherwise requires.
98
Director Independence
The board of directors of our general partner has affirmatively determined that Ronald L.
Kuehn, Jr, Arthur C. Reichstetter and William A. Smith each satisfy the independence requirements
under the New York Stock Exchange listing standards. In making this determination, the board
reviewed information from each of these directors regarding all of their respective relationships
with us and analyzed the materiality of those relationships. The audit committee of our general
partners board of directors is also composed entirely of independent directors.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit Fees
We paid audit fees of $1,444,000 for the year ended December 31, 2009 (including $792,000
related to CIG, our consolidated subsidiary) and $384,000 for the year ended December 31, 2008.
These fees were for professional services rendered by Ernst & Young LLP for the audit of the
consolidated financial statements of El Paso Pipeline Partners, L.P., the review of documents filed
with the Securities and Exchange Commission, and related consents.
All Other Fees
For the years ended December 31, 2009 and 2008, fees of $214,000 and $296,000 were paid to
Ernst & Young LLP for professional services related to tax compliance and tax planning. No tax
related services were provided for the year ended December 31, 2007.
No audit-related services were provided by our independent registered public accounting firm
for the years ended December 31, 2009 and 2008.
During 2009, the Audit Committee approved all the types of audit and permitted non-audit
services which our independent auditors were to perform during the year, as required under
applicable law, and the cap on fees for each of these categories. The Audit Committees current
practice is to consider for pre-approval annually all categories of audit and permitted non-audit
services proposed to be provided by our independent auditors for a fiscal year. Pre-approval of tax
services requires that the principal independent auditor provide the Audit Committee with written
documentation of the scope and fee structure of the proposed tax services and discuss with the
Audit Committee the potential effects, if any, of providing such services on the independent
auditors independence. The Audit Committee will also consider for pre-approval annually the
maximum amount of fees and the manner in which the fees are determined for each type of
pre-approved audit and non-audit services proposed to be provided by our independent auditors for
the fiscal year. The Audit Committee must separately pre-approve any service that is not included
in the approved list of services or any proposed services exceeding pre-approved cost levels. The
Audit Committee has delegated pre-approval authority to the Chairman of the Audit Committee for
services that need to be addressed between Audit Committee meetings. The Audit Committee is then
informed of these pre-approval decisions, if any, at the next meeting of the Audit Committee.
99
PART
IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following consolidated financial statements are included in Part II, Item 8 of this
report:
1. Financial Statements.
|
|
|
|
|
|
|
Page |
El Paso Pipeline Partners, L.P. |
|
|
Reports of Independent Registered Public Accounting Firm |
|
|
48 |
|
Consolidated Statements of Income |
|
|
50 |
|
Consolidated Balance Sheets |
|
|
51 |
|
Consolidated Statements of Cash Flows |
|
|
52 |
|
Consolidated Statements of Partners Capital |
|
|
53 |
|
Notes to Consolidated Financial Statements |
|
|
54 |
|
|
2. Financial Statement Schedules. |
|
|
|
|
Schedule II Valuation and Qualifying Accounts |
|
|
79 |
|
All other schedules are omitted because they are not applicable, or the required
information is disclosed in the financial statements or accompanying notes.
3. and (b). Exhibits
The Exhibit Index, which follows the signature page to this report and is hereby incorporated
herein by reference, sets forth a list of those exhibits filed herewith, and includes and
identifies management contracts or compensatory plans or arrangements required to be filed as
exhibits to this Form 10-K by Item 601 (b)(10)(iii) of Regulation S-K.
The agreements included as exhibits to this report are intended to provide information
regarding their terms and not to provide any other factual or disclosure information about us or
the other parties to the agreements. The agreements may contain representations and warranties by
the parties to the agreements, including us, solely for the benefit of the other parties to the
applicable agreement and:
|
|
should not in all instances be treated as categorical statements of fact, but rather as a way
of allocating the risk to one of the parties if those statements prove to be inaccurate; |
|
|
|
may have been qualified by disclosures that were made to the other party in connection with
the negotiation of the applicable agreement, which disclosures are not necessarily reflected
in the agreement; |
|
|
|
may apply standards of materiality in a way that is different from what may be viewed as
material to certain investors; and |
|
|
|
were made only as of the date of the applicable agreement or such other date or dates as
maybe specified in the agreement and are subject to more recent developments. |
Accordingly, these representations and warranties may not describe the actual state of affairs
as of the date they were made or at any other time.
Undertaking
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to furnish
to the Securities and Exchange Commission upon request all constituent instruments defining the
rights of holders of our long-term debt and consolidated subsidiaries not filed herewith for the
reason that the total amount of securities authorized under any of such instruments does not exceed
10 percent of our total consolidated assets.
(c) |
|
Financial Statements of 50-Percent-Or-Less-Owned Investees |
1. Financial Statements.
Southern Natural Gas Company |
|
|
Reports of Independent Registered Public Accounting Firms |
|
101 |
Consolidated Statements of Income
and Comprehensive Income |
|
103 |
Consolidated Balance Sheets |
|
104 |
Consolidated Statements of Cash Flows |
|
105 |
Consolidated Statements of
Partners Capital/Stockholders Equity |
|
106 |
Notes to Consolidated Financial Statements |
|
107 |
|
2. Financial Statement Schedules. |
|
|
Schedule II Valuation and
Qualifying Accounts |
|
122 |
100
Report of Independent Registered Public Accounting Firm
The Partners of Southern Natural Gas Company
We have audited the accompanying consolidated balance sheets of Southern Natural Gas Company (the
Company) as of December 31, 2009 and 2008, and the related consolidated statements of income and
comprehensive income, partners capital/stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2009. Our audits also included the financial statement
schedule listed in the Index at Item 15(c) for each of the three years in the period ended December
31, 2009. These financial statements and schedule are the responsibility of the Companys
management. Our responsibility is to express an opinion on these financial statements and schedule
based on our audits. The consolidated financial statements of Citrus Corp. and Subsidiaries (a
corporation in which the Company had a 50% interest), have been audited by other auditors whose
report has been furnished to us, and our opinion on the consolidated financial statements, insofar
as it relates to the amounts included from Citrus Corp. and Subsidiaries, is based solely on the
report of the other auditors, exclusive of the income adjustment related to the disposition of the
equity interest in November 2007. In the consolidated financial statements, earnings from the
Companys investment in Citrus Corp. represent approximately 28% of income before income taxes for
the year ended December 31, 2007.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. We
were not engaged to perform an audit of the Companys internal control over financial reporting.
Our audits included consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Companys internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits and the report of other auditors
provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements
referred to above present fairly, in all material respects, the consolidated financial position of
Southern Natural Gas Company at December 31, 2009 and 2008, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended December 31, 2009, in
conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related
financial statement schedule, when considered in relation to the basic financial statements taken
as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1
to the consolidated financial statements, effective January 1, 2007,
the Company adopted the new income tax accounting standard, and effective January 1, 2008, the
Company adopted the provisions of an accounting standard update related to the measurement date
and changed the measurement date of its postretirement benefit plan.
/s/ Ernst & Young LLP
Houston, Texas
February 26, 2010
101
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Citrus Corp.:
In our opinion, the consolidated balance sheets and the related consolidated statements of income,
of stockholders equity, of comprehensive income and of cash flows (not presented separately
herein) present fairly, in all material respects, the financial position of Citrus Corp. and
subsidiaries (the Company) at December 31, 2007 and 2006, and the results of their operations and
their cash flows for each of the three years in the period ended
December 31, 2007 in conformity with the accounting principles generally accepted in the United
States of America. These consolidated financial statements are the responsibility of the Companys
management. Our responsibility is to express an opinion on these financial statements based on our
audits. We conducted our audits of these statements in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 2 and 6 to the consolidated financial statements, the Company adopted the
recognition and disclosure provisions of FASB Statement No. 158 Employers Accounting for Defined
Pension and Other Postretirement Plans an amendment of FASB Statements No. 87, 88, 106 and
132(R), as of December 31, 2006.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 25, 2008
102
SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Operating revenues |
|
$ |
510 |
|
|
$ |
540 |
|
|
$ |
482 |
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Operation and maintenance |
|
|
173 |
|
|
|
189 |
|
|
|
160 |
|
Depreciation and amortization |
|
|
55 |
|
|
|
53 |
|
|
|
53 |
|
Taxes, other than income taxes |
|
|
27 |
|
|
|
27 |
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
255 |
|
|
|
269 |
|
|
|
240 |
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
255 |
|
|
|
271 |
|
|
|
242 |
|
Earnings from unconsolidated affiliates |
|
|
11 |
|
|
|
13 |
|
|
|
88 |
|
Other income, net |
|
|
2 |
|
|
|
10 |
|
|
|
13 |
|
Interest and debt expense |
|
|
(62 |
) |
|
|
(72 |
) |
|
|
(91 |
) |
Affiliated interest income |
|
|
2 |
|
|
|
13 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
208 |
|
|
|
235 |
|
|
|
271 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
69 |
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
208 |
|
|
|
235 |
|
|
|
202 |
|
Discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
208 |
|
|
|
235 |
|
|
|
221 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
208 |
|
|
$ |
235 |
|
|
$ |
222 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
103
SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(In millions)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
|
|
Accounts and notes receivable |
|
|
|
|
|
|
|
|
Customer |
|
|
7 |
|
|
|
3 |
|
Affiliates |
|
|
64 |
|
|
|
71 |
|
Other |
|
|
2 |
|
|
|
2 |
|
Materials and supplies |
|
|
15 |
|
|
|
14 |
|
Other |
|
|
9 |
|
|
|
15 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
97 |
|
|
|
105 |
|
|
|
|
|
|
|
|
Property, plant and equipment, at cost |
|
|
3,709 |
|
|
|
3,636 |
|
Less accumulated depreciation and amortization |
|
|
1,411 |
|
|
|
1,373 |
|
|
|
|
|
|
|
|
Total property, plant and equipment, net |
|
|
2,298 |
|
|
|
2,263 |
|
|
|
|
|
|
|
|
Other assets |
|
|
|
|
|
|
|
|
Investment in unconsolidated affiliate |
|
|
79 |
|
|
|
81 |
|
Note receivable from affiliate |
|
|
112 |
|
|
|
95 |
|
Other |
|
|
73 |
|
|
|
85 |
|
|
|
|
|
|
|
|
|
|
|
264 |
|
|
|
261 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,659 |
|
|
$ |
2,629 |
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL |
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
|
|
Accounts payable |
|
|
|
|
|
|
|
|
Trade |
|
$ |
19 |
|
|
$ |
28 |
|
Affiliates |
|
|
27 |
|
|
|
10 |
|
Other |
|
|
16 |
|
|
|
18 |
|
Taxes payable |
|
|
9 |
|
|
|
8 |
|
Accrued interest |
|
|
18 |
|
|
|
18 |
|
Asset retirement obligation |
|
|
14 |
|
|
|
|
|
Other |
|
|
5 |
|
|
|
10 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
108 |
|
|
|
92 |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
910 |
|
|
|
910 |
|
|
|
|
|
|
|
|
Other liabilities |
|
|
27 |
|
|
|
50 |
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 7) |
|
|
|
|
|
|
|
|
Partners capital |
|
|
1,614 |
|
|
|
1,577 |
|
|
|
|
|
|
|
|
Total liabilities and partners capital |
|
$ |
2,659 |
|
|
$ |
2,629 |
|
|
|
|
|
|
|
|
See accompanying notes.
104
SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Cash flows from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
208 |
|
|
$ |
235 |
|
|
$ |
221 |
|
Less income from discontinued operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations |
|
|
208 |
|
|
|
235 |
|
|
|
202 |
|
Adjustments to reconcile net income to net cash from operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
55 |
|
|
|
53 |
|
|
|
53 |
|
Deferred income tax expense |
|
|
|
|
|
|
|
|
|
|
23 |
|
Earnings from unconsolidated affiliates, adjusted for cash distributions |
|
|
2 |
|
|
|
3 |
|
|
|
42 |
|
Other non-cash income items |
|
|
(1 |
) |
|
|
(5 |
) |
|
|
(6 |
) |
Asset and liability changes |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
4 |
|
|
|
13 |
|
|
|
(7 |
) |
Accounts payable |
|
|
9 |
|
|
|
7 |
|
|
|
(13 |
) |
Taxes payable |
|
|
|
|
|
|
|
|
|
|
(21 |
) |
Other current assets |
|
|
18 |
|
|
|
(5 |
) |
|
|
5 |
|
Other current liabilities |
|
|
10 |
|
|
|
(9 |
) |
|
|
(4 |
) |
Non-current assets |
|
|
|
|
|
|
(11 |
) |
|
|
(5 |
) |
Non-current liabilities |
|
|
(19 |
) |
|
|
4 |
|
|
|
(320 |
) |
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) continuing activities |
|
|
286 |
|
|
|
285 |
|
|
|
(51 |
) |
Cash provided by discontinued activities |
|
|
|
|
|
|
|
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
|
286 |
|
|
|
285 |
|
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(138 |
) |
|
|
(138 |
) |
|
|
(243 |
) |
Net change in notes receivable from affiliate |
|
|
(18 |
) |
|
|
289 |
|
|
|
(152 |
) |
Proceeds from the sale of assets |
|
|
41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) continuing activities |
|
|
(115 |
) |
|
|
151 |
|
|
|
(395 |
) |
Cash used in discontinued activities |
|
|
|
|
|
|
|
|
|
|
(25 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities |
|
|
(115 |
) |
|
|
151 |
|
|
|
(420 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Payments to retire long-term debt |
|
|
|
|
|
|
(236 |
) |
|
|
(584 |
) |
Distributions to partners |
|
|
(171 |
) |
|
|
(200 |
) |
|
|
|
|
Net proceeds from issuance of long-term debt |
|
|
|
|
|
|
|
|
|
|
494 |
|
Contribution from parent |
|
|
|
|
|
|
|
|
|
|
536 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(171 |
) |
|
|
(436 |
) |
|
|
446 |
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
105
SOUTHERN NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL/STOCKHOLDERS EQUITY
(In millions, except share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
Other |
|
|
Total |
|
|
Total |
|
|
|
Common Stock |
|
|
Capital |
|
|
Retained |
|
|
Comprehensive |
|
|
Stockholders |
|
|
Partner |
|
|
|
Shares |
|
|
Amount |
|
|
Paid-in |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Equity |
|
|
Capital |
|
January 1, 2007 |
|
|
1,000 |
|
|
$ |
|
|
|
$ |
340 |
|
|
$ |
1,304 |
|
|
$ |
|
|
|
$ |
1,644 |
|
|
$ |
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
187 |
|
|
|
|
|
|
|
187 |
|
|
|
|
|
Other
comprehensive
income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
Adoption of new
tax accounting
standard, net of
income tax of
$(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
|
|
|
|
Reclassification
to regulatory
liability
(Note 8) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 31, 2007 |
|
|
1,000 |
|
|
|
|
|
|
|
340 |
|
|
|
1,486 |
|
|
|
(4 |
) |
|
|
1,822 |
|
|
|
|
|
Conversion to
general
partnership
(November 1, 2007) |
|
|
(1,000 |
) |
|
|
|
|
|
|
(340 |
) |
|
|
(1,486 |
) |
|
|
4 |
|
|
|
(1,822 |
) |
|
|
1,822 |
|
Contributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
536 |
|
Distributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(850 |
) |
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,542 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
235 |
|
Distributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(200 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,577 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
208 |
|
Distributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(171 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,614 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
106
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
We are a Delaware general partnership, originally formed in 1935 as a corporation. We are
owned 75 percent by El Paso SNG Holding Company, L.L.C., a subsidiary of El Paso Corporation (El
Paso) and 25 percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline
Partners, L.P. (EPB) which is majority owned by El Paso. In conjunction with the formation of EPB
in November 2007, we distributed our 50 percent interest in Citrus Corp. (Citrus), our wholly owned
subsidiaries Southern LNG, Inc. (SLNG) and Elba Express Company, LLC (Elba Express) to El Paso
effective November 21, 2007. Citrus owns the Florida Gas Transmission Company, LLC (FGT) pipeline
system and SLNG owns our Elba Island LNG facility. We have reflected the SLNG and Elba Express
operations as discontinued operations in our financial statements for periods prior to their
distribution. Additionally, effective November 1, 2007, we converted to a general partnership and
are no longer subject to income taxes and settled our current and deferred income tax balances
through El Pasos cash management program. For a further discussion of these and other related
transactions, see Notes 2, 3 and 11.
Our consolidated financial statements are prepared in accordance with U.S. generally accepted
accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the
elimination of intercompany accounts and transactions.
We consolidate entities when we either (i) have the ability to control the operating and
financial decisions and policies of that entity or (ii) are allocated a majority of the entitys
losses and/or returns through our interests in that entity. The determination of our ability to
control or exert significant influence over an entity and whether we are allocated a majority of
the entitys losses and/or returns involves the use of judgment. We apply the equity method of
accounting where we can exert significant influence over, but do not control the policies and
decisions of an entity and where we are not allocated a majority of the entitys losses and/or
returns. We use the cost method of accounting where we are unable to exert significant influence
over the entity.
Use of Estimates
The preparation of our financial statements requires the use of estimates and assumptions that
affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in
these financial statements. Actual results can, and often do, differ from those estimates.
Regulated Operations
Our natural gas pipeline and storage operations are subject to the jurisdiction of the Federal
Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act
of 1978 and the Energy Policy Act of 2005. We follow the Financial Accounting Standards Boards
(FASB) accounting standards for regulated operations. Under these standards, we record
regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities.
Regulatory assets and liabilities represent probable future revenues or expenses associated with
certain charges or credits that are expected to be recovered from or refunded to customers through
the rate making process. Items to which we apply regulatory accounting requirements include certain
postretirement employee benefit plan costs, loss on reacquired debt, an equity return component on
regulated capital projects and certain costs related to gas not used in operations and other costs
included in, or expected to be included in, future rates.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be
cash equivalents.
107
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable and for natural gas imbalances due
from shippers and operators if we determine that we will not collect all or part of the outstanding
balance. We regularly review collectability and establish or adjust our allowance as necessary
using the specific identification method.
Materials and Supplies
We value materials and supplies at the lower of cost or market value with cost determined
using the average cost method.
Natural Gas Imbalances
Natural gas imbalances occur when the amount of natural gas received on a customers contract
at the supply point differs from the amount of natural gas delivered under the customers
transportation contract at the delivery point. We value these imbalances due to or from shippers at
specified index prices set forth in our tariff based on the production month in which the
imbalances occur. Customer imbalances are aggregated and netted on a monthly basis, and settled in
cash, subject to the terms of our tariff. For differences in value between the amounts we pay or
receive for the purchase or sale of natural gas used to resolve shipper imbalances over the course
of a year, we have the right under our tariff to recover applicable losses or refund applicable
gains through a storage cost reconciliation charge. This charge is applied to volumes as they are
transported on our system. Annually, we true-up any losses or gains obtained during the year by
adjusting the following years storage cost reconciliation charge.
Imbalances due from others are reported in our balance sheet as either accounts receivable
from customers or accounts receivable from affiliates. Imbalances owed to others are reported on
the balance sheet as either trade accounts payable or accounts payable to affiliates. We classify
all imbalances as current as we expect to settle them within a year.
Property, Plant and Equipment
Our property, plant and equipment is recorded at its original cost of construction or, upon
acquisition, at either the fair value of the assets acquired or the cost to the entity that first
placed the asset in service. For assets we construct, we capitalize direct costs, such as labor and
materials, and indirect costs, such as overhead, interest and an equity return component, as
allowed by the FERC. We capitalize major units of property replacements or improvements and expense
minor items.
We use the composite (group) method to depreciate property, plant and equipment. Under this
method, assets with similar lives and characteristics are grouped and depreciated as one asset. We
apply the FERC-accepted depreciation rate to the total cost of the group until its net book value
equals its salvage value. Currently, our depreciation rates vary from less than one percent to 20
percent per year. Using these rates, the remaining depreciable lives of these assets range from two
to 43 years. We re-evaluate depreciation rates each time we file with the FERC for a change in our
transportation and storage rates.
When we retire property, plant and equipment, we charge accumulated depreciation and
amortization for the original cost of the assets in addition to the cost to remove, sell or dispose
of the assets, less their salvage value. We do not recognize a gain or loss unless we sell or
retire an entire operating unit, as defined by the FERC. We include gains or losses on dispositions
of operating units in operation and maintenance expense in our income statements.
At December 31, 2009 and 2008, we had $34 million and $48 million of construction work in
progress included in our property, plant and equipment.
108
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We capitalize a carrying cost (an allowance for funds used during construction) on debt and
equity funds related to our construction of long-lived assets. This carrying cost consists of a
return on the investment financed by debt and a return on the investment financed by equity. The
debt portion is calculated based on our average cost of debt. Interest costs capitalized during the
years ended December 31, 2009, 2008 and 2007, were
$1 million, $3 million and $4 million.
These debt amounts are included as a reduction to interest and debt expense on our income
statement. The equity portion is calculated using the most recent FERC-approved equity rate of
return. The equity amounts capitalized (exclusive of taxes) during the years ended December 31,
2009, 2008 and 2007, were $3 million, $7 million and $8 million. These equity amounts are included
in other income on our income statement.
Asset and Investment Divestitures/Impairments
We evaluate assets and investments for impairment when events or circumstances indicate that
their carrying values may not be recovered. These events include market declines that are believed
to be other than temporary, changes in the manner in which we intend to use a long-lived asset,
decisions to sell an asset or investment and adverse changes in the legal or business environment
such as adverse actions by regulators. When an event occurs, we evaluate the recoverability of our
carrying value based on either (i) the long-lived assets ability to generate future cash flows on
an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If
an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we
adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our
fair value estimates are generally based on market data obtained through the sales process or an
analysis of expected discounted cash flows. The magnitude of any impairment is impacted by a number
of factors, including the nature of the assets being sold and our established time frame for
completing the sale, among other factors.
We
reclassify assets to be sold in our financial statements as either held-for-sale or from
discontinued operations when it becomes probable that we will dispose of the assets within the next
twelve months and when they meet other criteria, including whether we will have significant
long-term continuing involvement with those assets after they are sold. We cease depreciating
assets in the period that they are reclassified as either held for sale or from discontinued
operations, and reflect the results of our discontinued operations in our income statement
separately from those of continuing operations. Cash flows from our discontinued businesses are
reflected as discontinued operating, investing, and financing activities in our statement of cash
flows. Cash provided by discontinued activities in the operating activities section of our cash
flow statement includes all operating cash flows generated by our discontinued businesses during
the period. Proceeds from the sale of our discontinued operations are classified in cash provided
by discontinued activities in the cash flows from investing activities section of our cash flow
statement. To the extent that these operations participated in El Pasos cash management program,
we reflected transactions related to El Pasos cash management program as financing activities in
our cash flow statement.
Revenue Recognition
Our revenues are primarily generated from natural gas transportation and storage services.
Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a
price specified in the contract. For our transportation and storage services, we recognize
reservation revenues on firm contracted capacity ratably over the contract period regardless of the
amount of natural gas that is transported or stored. For
interruptible or volumetric-based
services, we record revenues when physical deliveries of natural gas are made at the agreed upon
delivery point or when gas is injected or withdrawn from the storage facility. Gas not used in
operations is based on the volumes of natural gas we are allowed to retain and dispose of relative
to the amounts we use for operating purposes. As calculated in a manner set forth in our tariff,
any revenues generated from any excess natural gas retained and not burned are shared with our
customers on an annual basis. We recognize our share of revenues on gas not used in operations from
our shippers when we retain the volumes at the market prices required under our tariffs. We are
subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a
rate proceeding. We establish reserves for these potential refunds.
109
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Costs and Other Contingencies
Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet
as other current and long-term liabilities when environmental assessments indicate that remediation
efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are
based on currently available facts, existing technology and presently enacted laws and regulations,
taking into consideration the likely effects of other societal and economic factors, and include
estimates of associated legal costs. These amounts also consider prior experience in remediating
contaminated sites, other companies clean-up experience and data released by the Environmental
Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future
periods based on actual costs or new circumstances. We capitalize costs that benefit future periods
and we recognize a current period charge in operation and maintenance expense when clean-up efforts
do not benefit future periods.
We evaluate any amounts paid directly or reimbursed by government sponsored programs and
potential recoveries or reimbursements of remediation costs from third parties, including insurance
coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or
solvency of the third party, among other factors. When recovery is assured, we record and report an
asset separately from the associated liability on our balance sheet.
Other Contingencies. We recognize liabilities for other contingencies when we have an exposure
that, when fully analyzed, indicates it is both probable that a liability has been incurred and the
amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be
reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot
be estimated, a range of potential losses is established and if no one amount in that range is more
likely than any other, the low end of the range is accrued.
Income Taxes
Effective November 1, 2007, we converted to a general partnership in conjunction with the
formation of EPB and accordingly, we are no longer subject to income taxes. As a result
of our conversion to a general partnership, we settled our then existing current and deferred tax
balances with recoveries of note receivables from El Paso under its cash management program
pursuant to our tax sharing agreement with El Paso (see Notes 3 and 11). Prior to that date, we
recorded current income taxes based on our taxable income and provided for deferred income taxes to
reflect estimated future tax payments and receipts. Deferred taxes represented the income tax
impacts of differences between the financial statement and tax bases of assets and liabilities and
carryovers at each year end. We accounted for tax credits under the flow-through method, which
reduced the provision for income taxes in the year the tax credits first became available. We
reduced deferred tax assets by a valuation allowance when, based on our estimates, it was more
likely than not that a portion of those assets would not be realized in a future period.
On January 1, 2007, we adopted a new income tax accounting standard. The adoption of the
standard did not have a material impact on our financial statements.
Accounting for Asset Retirement Obligations
We record a liability for legal obligations associated with the replacement, removal or
retirement of our long-lived assets in the period the obligation is incurred. Our asset retirement
liabilities are initially recorded at their estimated fair value with a corresponding increase to
property, plant and equipment. This increase in property, plant and equipment is then depreciated
over the useful life of the asset to which that liability relates. An ongoing expense is also
recognized for changes in the value of the liability as a result of the passage of time, which we
record as depreciation and amortization expense in our income statement. We have the ability to
recover certain of these costs from our customers and have recorded an asset (rather than expense)
associated with the accretion of the liabilities described above.
110
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We have legal obligations associated with the retirement of our natural gas pipeline,
transmission facilities and storage wells. Our legal obligations primarily involve purging and
sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials
associated with our natural gas transmission facilities if they are replaced. We continue to
evaluate our asset retirement obligations and future developments could impact the amounts we
record.
Where we can reasonably estimate the asset retirement obligation, we accrue a liability based
on an estimate of the timing and amount of settlement. We record changes in estimates based on
changes in the expected amount and timing of payments to settle our asset retirement obligations.
We intend on operating and maintaining our natural gas pipeline and storage system as long as
supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we
believe that we cannot reasonably estimate the asset retirement obligation for the substantial
majority of our natural gas pipeline and storage system assets because these assets have
indeterminate lives.
The net asset retirement obligation as of December 31 reported on our balance sheets in
current and other non-current liabilities and the changes in the net liability for the years ended
December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Net asset retirement obligation at January 1 |
|
$ |
20 |
|
|
$ |
|
|
Accretion expense |
|
|
2 |
|
|
|
|
|
Changes in estimate |
|
|
(3 |
) |
|
|
20 |
|
|
|
|
|
|
|
|
Net asset retirement obligation at December 31(1) |
|
$ |
19 |
|
|
$ |
20 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
For the year ended December 31, 2009, approximately $14 million of this amount
is reflected in current liabilities. |
Postretirement Benefits
We maintain a postretirement benefit plan covering certain of our former employees. This plan
requires us to make contributions to fund the benefits to be paid out under the plan. These
contributions are invested until the benefits are paid out to plan participants. We record the net
benefit cost related to this plan in our income statement. This net benefit cost is a function of
many factors including benefits earned during the year by plan participants (which is a function of
the level of benefits provided under the plan, actuarial assumptions and the passage of time),
expected returns on plan assets and amortization of certain deferred gains and losses. For a
further discussion of our policies with respect to our postretirement benefit plan, see Note 8.
In accounting for our postretirement benefit plan, we record an asset or liability for our
postretirement benefit plan based on the over funded or under funded status of the plan. Any
deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are
recorded as either a regulatory asset or liability.
Effective January 1, 2008, we adopted the provisions of an accounting standard update related
to measurement date and changed the measurement date of our postretirement benefit plan from
September 30 to December 31. The adoption of the measurement date provisions of this standard did
not have a material impact on our financial statements.
Effective December 31, 2009, we expanded our disclosures about postretirement benefit plan
assets as a result of new disclosure requirements. See Note 8 for these expanded
disclosures.
111
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
New Accounting Pronouncements Issued But Not Yet Adopted
As of December 31, 2009, the following accounting standards had not yet been adopted by us.
Transfers of Financial Assets. In June 2009, the FASB updated accounting standards on
financial asset transfers. Among other items, this update eliminated the concept of a qualifying
special-purpose entity (QSPE) for purposes of evaluating whether an entity should be consolidated
or not. The changes are effective for existing QSPEs as of January 1, 2010 and for transactions
entered into on or after January 1, 2010. The adoption of this accounting standard in January of
2010 did not have a material impact on our financial statements as we amended our existing
accounts receivable sales program in January 2010 (see Note 11).
Variable Interest Entities. In June 2009, the FASB updated accounting standards for variable
interest entities to revise how companies determine the primary beneficiaries of these entities,
among other changes. Companies will now be required to use a qualitative approach based on their
responsibilities and power over the entities operations, rather than a quantitative approach in
determining the primary beneficiary as previously required. The adoption of this accounting
standard in January of 2010 did not have a material impact on our financial statements.
2. Divestitures
In November 2007, in conjunction with the formation of EPB, we distributed our wholly owned
subsidiaries, SLNG and Elba Express, to El Paso. We have reflected these operations as discontinued
operations in our financial statements for periods prior to their distribution. We classify assets
(or groups of assets) to be disposed of as held for sale or, if appropriate, from discontinued
operations when they have received appropriate approvals to be disposed of by our management when
they meet other criteria. We also distributed our investment in Citrus to El Paso which is not
reflected in discontinued operations. The table below summarizes the operating results of our
discontinued operations for the year ended December 31, 2007.
|
|
|
|
|
|
|
(In millions) |
|
Revenues |
|
$ |
61 |
|
Costs and expenses |
|
|
(35 |
) |
Other income, net |
|
|
4 |
|
Interest and debt expense |
|
|
1 |
|
|
|
|
|
Income before income taxes |
|
|
31 |
|
Income taxes |
|
|
12 |
|
|
|
|
|
Income from discontinued operations, net of income taxes |
|
$ |
19 |
|
|
|
|
|
3. Income Taxes
In conjunction with the formation of EPB, we converted our legal structure into a general
partnership effective November 1, 2007 and are no longer subject to income taxes. We also settled
our then existing current and deferred income tax balances pursuant to our tax sharing agreement
with El Paso with recoveries of note receivables from El Paso under its cash management program.
Components of Income Tax Expense. The following table reflects the components of income tax
expense included in income from continuing operations for the year ended December 31, 2007:
|
|
|
|
|
|
|
(In millions) |
|
|
Current |
|
|
|
|
Federal |
|
$ |
40 |
|
State |
|
|
6 |
|
|
|
|
|
|
|
|
46 |
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
|
|
Federal |
|
|
19 |
|
State |
|
|
4 |
|
|
|
|
|
|
|
|
23 |
|
|
|
|
|
Total income taxes |
|
$ |
69 |
|
|
|
|
|
112
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Effective Tax Rate Reconciliation. Our income tax expense, included in income from continuing
operations differs from the amount computed by applying the statutory federal income tax rate of 35
percent for the following reasons for the year ended December 31, 2007:
|
|
|
|
|
|
|
(In millions, |
|
|
|
except for |
|
|
|
rates) |
|
Income taxes at the statutory federal rate of 35% |
|
$ |
95 |
|
Increase (decrease) |
|
|
|
|
Pretax income not subject to income tax after conversion to partnership |
|
|
(11 |
) |
State income taxes, net of federal income tax benefit |
|
|
6 |
|
Earnings from unconsolidated affiliates where we anticipate receiving dividends |
|
|
(21 |
) |
|
|
|
|
Income taxes |
|
$ |
69 |
|
|
|
|
|
Effective tax rate |
|
|
25 |
% |
|
|
|
|
4. Fair Value of Financial Instruments
At December 31, 2009 and 2008, the carrying amounts of cash and cash equivalents and trade
receivables and payables are representative of their fair value because of the short-term nature of
these instruments. At December 31, 2009 and 2008, we had an interest bearing note receivable from
El Paso of approximately $154 million and $136 million due upon demand, with a variable interest
rate of 1.5% and 3.2%. While we are exposed to changes in interest income based on changes to the
variable interest rate, the fair value of this note receivable approximates the carrying value due
to the note being due on demand and the market-based nature of the interest rate.
In addition, the carrying amounts of our long-term debt and their estimated fair values, which
are based on quoted market prices for the same or similar issues, are as follows at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
|
Amount |
|
Value |
|
Amount |
|
Value |
|
|
|
|
|
|
(In millions) |
|
|
|
|
Long-term debt, including current maturities |
|
$ |
910 |
|
|
$ |
977 |
|
|
$ |
910 |
|
|
$ |
726 |
|
5. Regulatory Assets and Liabilities
Our current and non-current regulatory assets are included in other current and non-current
assets on our balance sheets. Our non-current regulatory liabilities are included in other
non-current liabilities on our balance sheets. Our regulatory asset and liability balances are
recoverable or reimbursable over various periods. Below are the details of our regulatory
assets and liabilities at December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Current regulatory assets |
|
|
4 |
|
|
|
1 |
|
|
|
|
|
|
|
|
Non-current regulatory assets |
|
|
|
|
|
|
|
|
Taxes on capitalized funds used during construction |
|
|
29 |
|
|
|
34 |
|
Unamortized loss on reacquired debt |
|
|
32 |
|
|
|
36 |
|
Other |
|
|
1 |
|
|
|
4 |
|
|
|
|
|
|
|
|
Total non-current regulatory assets |
|
|
62 |
|
|
|
74 |
|
|
|
|
|
|
|
|
Total regulatory assets |
|
$ |
66 |
|
|
$ |
75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current regulatory liabilities |
|
|
|
|
|
|
|
|
Postretirement benefits |
|
$ |
5 |
|
|
$ |
|
|
Other |
|
|
3 |
|
|
|
4 |
|
|
|
|
|
|
|
|
Total non-current regulatory liabilities |
|
$ |
8 |
|
|
$ |
4 |
|
|
|
|
|
|
|
|
113
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The significant regulatory assets and liabilities include:
Taxes on Capitalized Funds Used During Construction:
These regulatory asset balances were established to
offset the deferred tax for the equity component of the allowance for funds used during the
construction of long-lived assets. Taxes on capitalized funds used during construction are
amortized and the
offsetting deferred income taxes are included in the rate base. Both are recovered over the
depreciable lives of the long lived asset to which they relate.
Unamortized Loss on Reacquired Debt:
These amounts represent the deferred and unamortized portion
of losses on reacquired debt which are not included in the rate base, but are recovered
over the original life of the debt issue through the authorized rate of return.
Postretirement Benefits:
These balances represent deferred amounts related to unrecognized gains and losses
or changes in actuarial assumptions related to our postretirement benefit plan and differences in
the postretirement benefit related amounts expensed and the amounts recoverable in rates.
Postretirement benefit amounts have been included in the rate base computations and are recoverable in such periods as benefits are funded.
6. Debt and Credit Facilities
Debt. Our long-term debt consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
5.90% Notes due April 2017 |
|
$ |
500 |
|
|
$ |
500 |
|
7.35% Notes due February 2031 |
|
|
153 |
|
|
|
153 |
|
8.0% Notes due March 2032 |
|
|
258 |
|
|
|
258 |
|
|
|
|
|
|
|
|
|
|
|
911 |
|
|
|
911 |
|
Less: Unamortized discount |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
Total long-term debt, less current maturities |
|
$ |
910 |
|
|
$ |
910 |
|
|
|
|
|
|
|
|
In March 2009, we, Southern Natural Issuing Corporation (SNIC), El Paso and certain other El
Paso subsidiaries filed a registration statement on Form S-3 under which we and SNIC may co-issue
debt securities in the future. SNIC is a wholly owned finance subsidiary of us and is the co-issuer
of certain of our outstanding debt securities. SNIC has no material assets, operations, revenues or
cash flows other than those related to its service as a co-issuer of our debt securities.
Accordingly, it has no ability to service obligations on our debt securities.
Under our indentures, we are subject to a number of restrictions and covenants. The most
restrictive of these include limitations on the incurrence of liens. For the year ended December
31, 2009, we were in compliance with our debt-related covenants. Our long-term debt contains
cross-acceleration provisions, the most restrictive of which is a $10 million cross-acceleration
clause. If triggered, repayment of the long-term debt that contains these provisions could be
accelerated.
7. Commitments and Contingencies
Legal Proceedings
Gas Measurement Cases. We and a number of our affiliates were named defendants in actions that
generally allege mismeasurement of natural gas volumes and/or heating content resulting in the
underpayment of royalties. These cases were filed in 1997 by an individual under the False Claims
Act and have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam
Litigation, U.S. District Court for the District of Wyoming). These complaints allege an
industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands. In October 2006, the U.S. District Judge issued an
order dismissing all claims against all defendants. In March 2009, the Tenth Circuit of Appeals
affirmed the dismissals and in October 2009, the plaintiffs appeal to the United States Supreme
court was denied.
114
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In addition to the above proceedings, we and our subsidiaries and affiliates are named
defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of
our business. For each of these matters, we evaluate the merits of the case, our exposure to the
matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we
determine that an unfavorable outcome is probable and can be estimated, we establish the necessary
accruals. While the outcome of these matters, including those discussed above, cannot be predicted
with certainty, and there are still uncertainties related to the costs we may incur, based upon our
evaluation and experience to date, we believe we have established appropriate reserves for these
matters. It is possible, however, that new information or future developments could require us to
reassess our potential exposure related to these matters and adjust our accruals accordingly, and
these adjustments could be material.
At December 31, 2009, we accrued approximately $2 million for our outstanding legal matters.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental
quality and pollution control. These laws and regulations require us to remove or remedy the effect
on the environment of the disposal or release of specified substances at current and former
operating sites. At both December 31, 2009 and 2008, we had accrued approximately $1 million for
expected remediation costs and associated onsite, offsite and groundwater technical studies.
It is possible that new information or future developments could require us to reassess our
potential exposure related to environmental matters. We may incur significant costs and liabilities
in order to comply with existing environmental laws and regulations. It is also possible that other
developments, such as increasingly strict environmental laws, regulations and orders of regulatory
agencies, as well as claims for damages to property and the environment or injuries to other
persons resulting from our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other relevant developments
occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related
to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe
our reserves are adequate.
Rates and Regulatory Matters
Notice of Proposed Rulemaking. In October 2007, the Minerals Management Service (MMS) issued a
notice of proposed rulemaking that is applicable to pipelines located in the Outer Continental
Shelf (OCS). If adopted, the proposed rules would substantially revise MMS OCS pipeline and
rights-of-way regulations. The proposed rules would have the effect of (i) increasing the financial
obligations of entities, like us, which have pipelines and pipeline rights-of-way in the OCS; (ii)
increasing the regulatory requirements imposed on the operation and maintenance of existing
pipelines and rights of way in the OCS; and (iii) increasing the requirements and preconditions for
obtaining new rights-of-way in the OCS.
Rate Case. In January 2010, the FERC approved our settlement in which we (i) increased our
base tariff rates effective September 1, 2009, (ii) implemented a volume tracker for gas used in
operations, (iii) agreed to file our next general rate case to be effective after August 31, 2012
but no later than September 1, 2013, and (iv) extended the vast majority of our firm transportation
contracts until August 31, 2013.
Other Commitments
Commercial Commitments. At December 31, 2009, we entered into unconditional purchase
obligations for products and services totaling approximately $95 million primarily related to the
South System III project and the Southeast Supply Header project. Our annual obligations under
these agreements are $71 million in 2010 and $24 million in 2011. In addition, we have other
planned capital and investment projects that are discretionary in nature, with no substantial
contractual capital commitments made in advance of the actual expenditures.
115
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Operating Leases. We lease property, facilities and equipment under various operating leases.
Our primary commitment under operating leases is the lease of our office space in Birmingham,
Alabama. El Paso guarantees our obligations under these lease agreements. Future minimum annual
rental commitments under our operating leases at December 31, 2009, were as follows:
|
|
|
|
|
Year Ending |
|
Operating |
|
December 31, |
|
Leases |
|
|
|
(In millions) |
|
2010 |
|
$ |
3 |
|
2011 |
|
|
3 |
|
2012 |
|
|
3 |
|
2013 |
|
|
3 |
|
2014 |
|
|
3 |
|
Thereafter |
|
|
8 |
|
|
|
|
|
Total |
|
$ |
23 |
|
|
|
|
|
Rent expense on our lease obligations for the years ended December 31, 2009, 2008 and 2007 was
less than $1 million, $4 million, and less than $1 million. These amounts include our share of rent
allocated to us from El Paso.
Other Commercial Commitments. We hold cancelable easements or rights-of-way arrangements from
landowners permitting the use of land for the construction and operation of our pipeline system.
Currently, our obligations under these easements are not material to the results of our operations.
During 2009, we entered into a $57 million letter of credit associated with our projected
construction costs related to the Southeast Supply Header project.
Guarantees. We are or have been involved in various ownership and other contractual
arrangements that sometimes require us to provide additional financial support that results in the
issuance of performance guarantees that are not recorded in our financial statements. In a
performance guarantee, we provide assurance that the guaranteed party will execute on the terms of
the contract. As of December 31, 2009, we have a performance guarantee related to contracts held by
SLNG, an entity formerly owned by us, with a maximum exposure of $225 million and a performance
guarantee related to contracts held by Elba Express, an entity formerly owned by us, with no stated
maximum limit. We estimate our potential exposure related to these guarantees is approximately $93
million, which is based on their remaining estimated obligations under the contracts.
8. Retirement Benefits
Pension and Retirement Savings Plans. El Paso maintains a pension plan and a retirement
savings plan covering substantially all of its U.S. employees, including our former employees. The
benefits under the pension plan are determined under a cash balance formula. Under its retirement
savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of
eligible compensation and can make additional discretionary matching contributions depending on its
performance relative to its peers. El Paso is responsible for benefits accrued under its plans and
allocates the related costs to its affiliates.
Postretirement Benefits Plan. We provide postretirement medical benefits for a closed group of
retirees. These benefits may be subject to deductibles, co-payment provisions, and other
limitations and dollar caps on the amount of employer costs and El Paso reserves the right to
change these benefits. Employees in this group who retire after June 30, 2000 continue to receive
limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded
to the extent these costs are recoverable through our rates. To the extent actual costs differ from
the amounts recovered in rates, a regulatory asset or liability is recorded. We expect to
contribute $4 million to our postretirement benefit plan in 2010.
Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting
for our postretirement benefit plan under the accounting standards related to other postretirement
plans, we record an asset or liability for our postretirement benefit plan based on its over funded
or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline
companies to record a regulatory asset or liability for any
deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions
that would otherwise be recorded in accumulated other comprehensive income for non-regulated
entities. Upon adoption of this FERC guidance, we reclassified $5 million from accumulated other
comprehensive income to a regulatory liability.
116
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The table below provides information about our postretirement benefit plan. In 2008, we
adopted the FASBs revised measurement date provisions for other postretirement benefit plans and
the information below for 2008 is presented and computed as of and for the fifteen months ended
December 31, 2008. For 2009, the information is presented and computed as of and for the twelve
months ended December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Change in accumulated postretirement benefit obligation: |
|
|
|
|
|
|
|
|
Accumulated postretirement benefit obligation beginning of period |
|
$ |
61 |
|
|
$ |
62 |
|
Interest cost |
|
|
4 |
|
|
|
4 |
|
Participant contributions |
|
|
1 |
|
|
|
1 |
|
Actuarial (gain) loss |
|
|
(1 |
) |
|
|
1 |
|
Benefits paid(1) |
|
|
(6 |
) |
|
|
(7 |
) |
|
|
|
|
|
|
|
Accumulated postretirement benefit obligation end of period |
|
$ |
59 |
|
|
$ |
61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets: |
|
|
|
|
|
|
|
|
Fair value of plan assets beginning period |
|
$ |
46 |
|
|
$ |
66 |
|
Actual return on plan assets |
|
|
8 |
|
|
|
(17 |
) |
Employer contributions |
|
|
4 |
|
|
|
4 |
|
Participant contributions |
|
|
|
|
|
|
1 |
|
Benefits paid |
|
|
(6 |
) |
|
|
(8 |
) |
|
|
|
|
|
|
|
Fair value of plan assets end of period |
|
$ |
52 |
|
|
$ |
46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of funded status: |
|
|
|
|
|
|
|
|
Fair value of plan assets |
|
$ |
52 |
|
|
$ |
46 |
|
Less: accumulated postretirement benefit obligation |
|
|
59 |
|
|
|
61 |
|
|
|
|
|
|
|
|
Net liability at December 31 |
|
$ |
(7 |
) |
|
$ |
(15 |
) |
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amounts shown net of a subsidy of approximately $1 million for each of the years
ended December 31, 2009 and 2008 related to the Medicare Prescription Drug, Improvement, and
Modernization Act of 2003. |
Plan Assets. The primary investment objective of our plan is to ensure that, over the
long-term life of the plan, an adequate pool of sufficiently liquid assets exists to meet the
benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature
covering typical market cycles. Any shortfall of investment performance compared to investment
objectives is generally the result of economic and capital market conditions. Although actual
allocations vary from time to time from our targeted allocations, the target allocations of our
postretirement plans assets are 65 percent equity and 35 percent fixed income securities. We may
invest assets in a manner that replicates, to the extent feasible, the Russell 3000 Index and the
Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification,
respectively.
We use various methods to determine the fair values of the assets in our other postretirement
benefit plans, which are impacted by a number of factors, including the availability of observable
market data over the contractual term of the underlying assets. We separate these assets into
three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and
the significance of non-observable data used to determine the fair value of these assets. As of
December 31, 2009, our assets are comprised of an exchange-traded mutual fund with a fair value of
$2 million and common/collective trusts with a fair value of $50 million. Our exchange-traded
mutual fund invests primarily in dollar-denominated securities, and its fair value (which is
considered a Level 1 measurement) is determined based on the price quoted for the fund in actively
traded markets. Our common/collective trusts are invested in approximately 65 percent equity and 35
percent fixed income securities, and their fair values (which are considered Level 2 measurements)
are determined primarily based on the net asset value reported by the issuer, which is based on
similar assets in active markets. We may adjust the fair value of our common/collective trusts,
when necessary, for factors such as liquidity or risk of nonperformance by the issuer. We do not
have any assets that are considered Level 3 measurements. The methods described above may produce
a fair value that may not be
indicative of net realizable value or reflective of future fair values, and there have been no
changes in the methodologies used at December 31, 2009 and 2008.
117
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Expected Payment of Future Benefits. As of December 31, 2009, we expect the following benefit
payments under our plan:
|
|
|
|
|
Year Ending |
|
Expected |
December 31, |
|
Payments(1) |
|
|
(In millions) |
2010 |
|
$ |
5 |
|
2011 |
|
|
5 |
|
2012 |
|
|
5 |
|
2013 |
|
|
5 |
|
2014 |
|
|
5 |
|
2015 - 2019 |
|
|
22 |
|
|
|
|
(1) |
|
Includes a reduction of approximately $1 million in each of the years 2010
2014 and approximately $4 million in aggregate for 2015 2019 for an expected subsidy
related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. |
Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit
obligations and net benefit costs are based on actuarial estimates and assumptions. The following
table details the weighted average actuarial assumptions used in determining our postretirement
plan obligations and net benefit costs for 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(Percent) |
Assumptions related to benefit obligations at December 31, 2009 and 2008 and
September 30, 2007 measurement dates: |
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
5.51 |
|
|
|
6.00 |
|
|
|
6.05 |
|
Assumptions related to benefit costs at December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
6.00 |
|
|
|
6.05 |
|
|
|
5.50 |
|
Expected return on plan assets(1) |
|
|
8.00 |
|
|
|
8.00 |
|
|
|
8.00 |
|
|
|
|
(1) |
|
The expected return on plan assets is a pre-tax rate of return based on our
targeted portfolio of investments. Our postretirement benefit plans investment earnings are
subject to unrelated business income taxes at a rate of 35%. The expected return on plan
assets for our postretirement benefit plan is calculated using the after-tax rate of return. |
Actuarial estimates for our postretirement benefits plan assumed a weighted average
annual rate of increase in the per capita costs of covered health care benefits of 8.0 percent,
gradually decreasing to 5.0 percent by the year 2015. Assumed health care cost trends can have a
significant effect on the amounts reported for our postretirement benefit plan. A one-percentage
point change would not have had a significant effect on interest costs in 2009 or 2008. A
one-percentage point change in assumed health care cost trends would have the following effect as
of December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(In millions) |
One percentage point increase: |
|
|
|
|
|
|
|
|
Accumulated postretirement benefit obligation |
|
$ |
5 |
|
|
$ |
5 |
|
One percentage point decrease: |
|
|
|
|
|
|
|
|
Accumulated postretirement benefit obligation |
|
$ |
(4 |
) |
|
$ |
(5 |
) |
Components of Net Benefit Cost. For each of the years ended December 31, the components of net
benefit cost are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Interest cost |
|
$ |
3 |
|
|
$ |
4 |
|
|
$ |
4 |
|
Expected return on plan assets |
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
Amortization of net actuarial gain |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net benefit cost |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
118
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. Transactions with Major Customers
The following table shows revenues from our major customers for each of the three years ended
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(In millions) |
SCANA Corporation(1) |
|
$ |
83 |
|
|
$ |
79 |
|
|
$ |
77 |
|
Southern Company Services |
|
|
58 |
|
|
|
55 |
|
|
|
54 |
|
|
|
|
(1) |
|
A significant portion of revenues received from a subsidiary of SCANA
Corporation resulted from firm capacity released by Atlanta Gas Light Company under terms
allowed by our tariff. |
10. Supplemental Cash Flow Information
The following table contains supplemental cash flow information from continuing operations for
each of the three years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(In millions) |
Interest paid, net of capitalized interest |
|
$ |
61 |
|
|
$ |
75 |
|
|
$ |
97 |
|
Income tax payments |
|
|
|
|
|
|
|
|
|
|
374 |
(1) |
|
|
|
(1) |
|
Includes amounts related to the settlement of current and deferred tax balances
due to the conversion to a partnership in November 2007 (see Notes 3 and 11). |
11. Investments in Unconsolidated Affiliates and Transactions with Affiliates
Investments in Unconsolidated Affiliates
Citrus. Prior to its transfer to El Paso in November 2007 in conjunction with the formation of
EPB, we had a 50 ownership percent interest in Citrus, which owns the FGT pipeline system.
CrossCountry Energy, LLC, a subsidiary of Southern Union Company, owns the other 50 percent of
Citrus. During 2007, we received $103 million in dividends from Citrus.
Bear Creek Storage Company, LLC (Bear Creek). We have a 50 percent ownership interest in Bear
Creek, a joint venture with Tennessee Gas Pipeline Company, our affiliate. We account for our
investment in Bear Creek using the equity method of accounting. During 2009, 2008 and 2007, we
received $13 million, $16 million and $27 million in dividends from Bear Creek.
Summarized financial information of our proportionate share of our unconsolidated affiliates
as of and for the years ended December 31 is presented as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(In millions) |
Operating results data:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
18 |
|
|
$ |
20 |
|
|
$ |
267 |
|
Operating expenses |
|
|
7 |
|
|
|
8 |
|
|
|
115 |
|
Income from continuing operations and net income |
|
|
11 |
|
|
|
13 |
|
|
|
92 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
(In millions) |
Financial position data: |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
28 |
|
|
$ |
27 |
|
Non-current assets |
|
|
52 |
|
|
|
55 |
|
Other current liabilities |
|
|
1 |
|
|
|
1 |
|
Equity in net assets |
|
|
79 |
|
|
|
81 |
|
|
|
|
(1) |
|
Includes Citrus results for the entire year ended December 31, 2007. Our share
of Citrus net income prior to the distribution of this investment in November 2007 was $75
million, adjusted for the excess purchase price amortization. |
|
(2) |
|
The difference between our proportionate share of our equity investments
net income and our earnings from unconsolidated affiliates in 2007 is due primarily to the
excess purchase price amortization related to Citrus and differences between the estimated and
actual equity earnings on our investments. |
119
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Transactions with Affiliates
Contributions/Distributions. On November 21, 2007, in conjunction with the formation of EPB,
we made a distribution of our 50 percent ownership in Citrus and our wholly owned subsidiaries SLNG
and Elba Express (described in Note 1) with a book value of approximately $850 million to El Paso
and El Paso made a capital contribution of approximately $536 million to us.
We are required to make distributions of available cash as defined in our partnership
agreement on a quarterly basis to our partners. During 2009 and 2008, we paid cash distributions of
approximately $171 million and $200 million to our partners. We did not make any distributions
to our partners during 2007. In addition, in January 2010 we paid a cash distribution to our
partners of approximately $83 million.
Cash Management Program. We participate in El Pasos cash management program which matches
short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings
from outside sources. El Paso uses the cash management program to settle intercompany transactions
between participating affiliates. We have historically advanced cash to El Paso in exchange for an
affiliated note receivable that is due upon demand. At December 31, 2009 and 2008, we
had a note receivable from El Paso of $154 million and $136 million. We classified $42 million and
$41 million of this receivable as current on our balance sheets at December 31, 2009 and 2008,
based on the net amount we anticipate using in the next twelve months considering available cash
sources and needs. The interest rate on our note at December 31, 2009 and 2008 was 1.5% and 3.2%.
Income Taxes. Effective November 1, 2007, we converted into a general partnership as discussed
in Note 1 and settled our then existing current and deferred tax balances of approximately $334
million pursuant to our tax sharing agreement with El Paso with recoveries of note receivables from
El Paso under its cash management program. During 2007, we also settled $20 million with El Paso
through its cash management program for certain tax attributes previously reflected as deferred
income taxes in our financial statements. These settlements are reflected as operating activities
in our statement of cash flows.
Accounts Receivable Sales Program. We sell certain accounts receivable to a QSPE whose purpose
is solely to invest in our receivables, which are short-term assets that generally settle within 60
days. During the year ended December 31, 2009 and 2008, we received net proceeds in both periods of
$0.5 billion related to sales of receivables to the QSPE and changes in our subordinated beneficial
interests, and recognized losses of less than $1 million on these transactions. As of December 31,
2009 and 2008, we had approximately $50 million and $48 million of receivables outstanding with the
QSPE, for which we received cash of approximately $30 million and $24 million and received
subordinated beneficial interests of approximately $19 million and $23 million. The QSPE also
issued senior beneficial interests on the receivables sold to a third party financial institution,
which totaled $30 million and $25 million as of December 31, 2009 and 2008. We reflect the
subordinated interest in receivables sold at their fair value on the date they are issued. These
amounts (adjusted for subsequent collections), are recorded as accounts receivable from affiliate
in our balance sheets. Our ability to recover our carrying value of our subordinated beneficial
interests is based on the collectability of the underlying receivables sold to the QSPE. We reflect
accounts receivable sold under this program and changes in the subordinated beneficial interests as
operating cash flows in our statement of cash flows. Under these agreements, we earn a fee for
servicing the receivables and performing all administrative duties for the QSPE which is reflected
as a reduction of operation and maintenance expense in our income statement. The fair value of
these servicing and administrative agreements as well as the fees earned were not material to our
financial statements for the years ended December 31, 2009 and 2008.
In January 2010, we ceased selling accounts receivable to the QSPE and began selling those
receivables directly to a third party financial institution. In return, the third party financial
institution pays a certain amount of cash up front for the receivables, and pays the remaining
amount owed over time as cash is collected from the receivables.
Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the
ordinary course of business and the services are based on the same terms as non-affiliates,
including natural gas transportation services to affiliates under long-term contracts.
120
SOUTHERN NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We do not have employees. Following our reorganization in November 2007, our former employees
continue to provide services to us through an affiliated service company owned by our general
partner, El Paso. We are managed and operated by officers of El Paso, our general partner. We have
an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the
provision of various general and administrative services for our benefit and for direct expenses
incurred by El Paso on our behalf. El Paso bills us directly for certain general and administrative
costs and allocates a portion of its general and administrative costs to us. In addition to
allocations from El Paso, we are allocated costs from Tennessee Gas Pipeline Company, our
affiliate, associated with our pipeline services. These allocations are based on the estimated
level of effort devoted to our operations and the relative size of our EBIT, gross property and
payroll.
The following table shows overall revenues and charges from our affiliates for each of the
three years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
|
|
(In millions) |
Revenues from affiliates |
|
$ |
6 |
|
|
$ |
6 |
|
|
$ |
7 |
|
Operation and maintenance expenses from affiliates |
|
|
125 |
|
|
|
120 |
|
|
|
69 |
|
Reimbursement of operating expenses charged to affiliates |
|
|
14 |
|
|
|
13 |
|
|
|
|
|
12. Supplemental Selected Quarterly Financial Information (Unaudited)
Our financial information by quarter is summarized below. Due to the seasonal nature of our
business, information for interim periods may not be indicative of our results of operations for
the entire year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ended |
|
|
|
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31 |
|
Total |
|
|
(In millions) |
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
126 |
|
|
$ |
119 |
|
|
$ |
124 |
|
|
$ |
141 |
|
|
$ |
510 |
|
Operating income |
|
|
64 |
|
|
|
57 |
|
|
|
57 |
|
|
|
77 |
|
|
|
255 |
|
Net income |
|
|
48 |
|
|
|
48 |
|
|
|
45 |
|
|
|
67 |
|
|
|
208 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
163 |
|
|
$ |
125 |
|
|
$ |
123 |
|
|
$ |
129 |
|
|
$ |
540 |
|
Operating income |
|
|
101 |
|
|
|
61 |
|
|
|
54 |
|
|
|
55 |
|
|
|
271 |
|
Net income |
|
|
95 |
|
|
|
53 |
|
|
|
44 |
|
|
|
43 |
|
|
|
235 |
|
121
SCHEDULE II
SOUTHERN NATURAL GAS COMPANY
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2009, 2008 and 2007
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at |
|
Charged to |
|
|
|
|
|
|
|
|
|
Balance |
|
|
Beginning |
|
Costs and |
|
|
|
|
|
Charged to Other |
|
at End |
Description |
|
of Period |
|
Expenses |
|
Deductions |
|
Accounts |
|
of Period |
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Legal reserves |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2 |
|
Environmental reserves |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Legal reserves |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2 |
|
Environmental reserves |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance on deferred tax assets |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1 |
) |
|
$ |
|
|
Legal reserves |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Environmental reserves |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
(1) |
|
Amounts reflect the reclassification of certain entities as discontinued
operations. |
122
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, El
Paso Pipeline Partners, L.P. has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized on the 26th day of February, 2010.
|
|
|
|
|
|
EL PASO PIPELINE PARTNERS, L.P.
|
|
|
By: |
El Paso Pipeline GP Company, L.L.C.,
its General Partner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By: |
/s/ James C. Yardley
|
|
|
|
James C. Yardley |
|
|
|
President and Chief Executive Officer |
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of El Paso Pipeline Partners, L.P. and in the
capacities with El Paso Pipeline GP Company, L.L.C., its General Partner, and on the dates
indicated:
|
|
|
|
|
Signature |
|
Title |
|
Date |
/s/ James C. Yardley
|
|
President, Chief Executive Officer
and Director
|
|
February 26, 2010 |
|
|
|
|
|
James C. Yardley |
|
(Principal Executive Officer) |
|
|
|
|
|
|
|
/s/ John R. Sult
|
|
Senior Vice President, Chief
Financial Officer
|
|
February 26, 2010 |
|
|
|
|
|
John R. Sult
|
|
and Director |
|
|
|
|
(Principal Financial Officer) |
|
|
|
|
|
|
|
/s/ Rosa P. Jackson
|
|
Vice President and Controller
|
|
February 26, 2010 |
|
|
|
|
|
Rosa P. Jackson
|
|
(Principal Accounting Officer) |
|
|
|
|
|
|
|
/s/ Ronald L. Kuehn, Jr.
|
|
Chairman of the Board
|
|
February 26, 2010 |
|
|
|
|
|
Ronald L. Kuehn, Jr. |
|
|
|
|
|
|
|
|
|
/s/ Douglas L. Foshee
|
|
Director
|
|
February 26, 2010 |
|
|
|
|
|
Douglas L. Foshee |
|
|
|
|
|
|
|
|
|
/s/ D. Mark Leland
|
|
Director
|
|
February 26, 2010 |
|
|
|
|
|
D. Mark Leland |
|
|
|
|
|
|
|
|
|
/s/ Arthur C. Reichstetter
|
|
Director
|
|
February 26, 2010 |
|
|
|
|
|
Arthur C. Reichstetter |
|
|
|
|
|
|
|
|
|
/s/ William A. Smith
|
|
Director
|
|
February 26, 2010 |
|
|
|
|
|
William A. Smith |
|
|
|
|
123
EL PASO PIPELINE PARTNERS, L.P.
EXHIBIT INDEX
December 31, 2009
Each exhibit identified below is filed as part of this report. Exhibits filed with this Report
are designated by *. All exhibits not so designated are incorporated herein by reference to a
prior filing as indicated. Exhibits designated with a + constitute a management contract or
compensatory plan or arrangement.
EXHIBIT LIST
|
|
|
Exhibit |
|
|
Number |
|
Description |
2.A
|
|
Contribution and Exchange Agreement, dated September 17, 2008, by and among El Paso
Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., El Paso Pipeline LP
Holdings, L.L.C., El Paso Pipeline Partners Operating Company, L.L.C., El Paso
Corporation, El Paso Noric Investments III, L.L.C., Colorado Interstate Gas
Company, El Paso SNG Holding Company, L.L.C., Southern Natural Gas Company, EPPP
SNG GP Holdings, L.L.C. and EPPP CIG GP Holdings, L.L.C. (incorporated by reference
to Exhibit 2.1 to our current Report on Form 8-K filed with the SEC on September
23, 2008). |
|
|
|
2.B
|
|
Contribution Agreement, dated July 24, 2009, by and among El Paso Pipeline
Partners, L.P., El Paso Pipeline Partners Operating Company, L.L.C., El Paso
Corporation, El Paso Noric Investments III, L.L.C., Colorado Interstate Gas Company
and EPPP CIG GP Holdings, L.L.C. (incorporated by reference to Exhibit 2.1 to our
Current Report on Form 8-K filed with the SEC on July 28, 2009). |
|
|
|
3.A
|
|
Certificate of Limited Partnership of El Paso Pipeline Partners, L.P (incorporated
by reference to Exhibit 3.1 to our Registration Statement on Form S-1). |
|
|
|
3.B
|
|
First Amended and Restated Agreement of Limited Partnership of El Paso Pipeline
Partners, L.P., dated November 21, 2007 (incorporated by reference to Exhibit 3.1
to our Current Report on Form 8-K filed with the SEC on November 28, 2007);
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of
El Paso Pipeline Partners, L.P., dated July 28, 2008 (incorporated by reference to
Exhibit 4.A to our Current Report on Form 8-K, filed with the SEC on July 28,
2008). |
|
|
|
3.C
|
|
Certificate of Formation of El Paso Pipeline GP Company, L.L.C. (incorporated by
reference to Exhibit 3.3 to our Registration Statement on Form S-1). |
|
|
|
3.D
|
|
Amended and Restated Limited Liability Company Agreement of El Paso Pipeline GP
Company, L.L.C., dated November 21, 2007 (incorporated by reference to Exhibit 3.2
to our Current Report on Form 8-K filed with the SEC on November 28, 2007). |
|
|
|
4.A
|
|
Registration Rights Agreement, dated September 30, 2008, by and among El Paso
Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C. and Tortoise Energy
Infrastructure Corporation. (incorporated by reference to Exhibit 10.4 to our
Current Report on Form 8-K filed with the SEC on October 6,
2008). |
124
|
|
|
Exhibit |
|
|
Number |
|
Description |
4.B
|
|
Indenture dated June 1, 1987 between Southern Natural Gas Company and Wilmington
Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase
Manhattan Bank), as Trustee (Exhibit 4.A to the Southern Natural Gas Company Annual
Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on
February 28, 2007); First Supplemental Indenture, dated as of September 30, 1997,
between Southern Natural Gas Company and the Trustee (Exhibit 4.A.1 to the Southern
Natural Gas Company Annual Report on Form 10-K for the year ended December 31,
2006, filed with the SEC on February 28, 2007); Second Supplemental Indenture dated
as of February 13, 2001, between Southern Natural Gas Company and the Trustee
(Exhibit 4.A.2 to the Southern Natural Gas Company Annual Report on Form 10-K for
the year ended December 31, 2006, filed with the SEC on February 28, 2007); Third
Supplemental Indenture dated as of March 26, 2007 between Southern Natural Gas
Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A to
the Southern Natural Gas Company Current Report on Form 8-K filed with the SEC on
March 28, 2007); Fourth Supplemental Indenture dated as of May 4, 2007 among
Southern Natural Gas Company, Wilmington Trust Company (solely with respect to
certain portions thereof) and The Bank of New York Trust Company, N.A. (Exhibit 4.C
to the Southern Natural Gas Company quarterly report on Form 10-Q for the period
ended March 31, 2007, filed with the SEC on May 8, 2007); Fifth Supplemental
Indenture dated October 15, 2007 by and among SNG, Wilmington Trust Company, as
trustee, and The Bank of New York Trust Company, N.A., as series trustee, to
Indenture dated as of June 1, 1987 (Exhibit 4.A to the Southern Natural Gas Company
Current Report on Form 8-K filed with the SEC on October 16, 2007); Sixth
Supplemental Indenture dated November 1, 2007 by and among Southern Natural Gas
Company, Southern Natural Issuing Corporation, Wilmington Trust Company, as
trustee, and The Bank of New York Trust Company, N.A., as series trustee, to
Indenture dated as of June 1, 1987 (Exhibit 4.A to the Southern Natural Gas Company
Current Report on Form 8-K filed with the SEC on November 7, 2007). |
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4.C
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Form of 5.90% Note due 2017 (included as Exhibit A to Exhibit 4.A of the Southern
Natural Gas Company Current Report on Form 8-K filed with the SEC on March 28,
2007). |
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4.D
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Indenture dated as of March 5, 2003 between Southern Natural Gas Company and The
Bank of New York Trust Company, N.A., successor to The Bank of New York, as Trustee
(Exhibit 4.C to the Southern Natural Gas Company Annual Report on Form 10-K for the
year ended December 31, 2009, filed with the SEC on February 26, 2010). |
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4.E
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Indenture dated as of June 27, 1997, between Colorado Interstate Gas Company and
The Bank of New York Trust Company, N.A. (successor to Harris Trust and Savings
Bank), as trustee (Exhibit 4.A to the Colorado Interstate Gas Company Annual Report
on Form 10-K for the year ended December 31, 2009, filed with the SEC on February
26, 2010); First Supplemental Indenture dated as of June 27, 1997, between Colorado
Interstate Gas Company and The Bank of New York Trust Company, N.A., as trustee
(Exhibit 4.A.1 to the Colorado Interstate Gas Company Annual Report on Form 10-K
for the year ended December 31, 2009, filed with the SEC on February 26, 2010);
Second Supplemental Indenture dated as of March 9, 2005 between Colorado Interstate
Gas Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A.2
to the Colorado Interstate Gas Company Annual Report on Form 10-K for the year
ended December 31, 2009, filed with the SEC on February 26, 2010); Third
Supplemental Indenture dated as of November 1, 2005 between Colorado Interstate Gas
Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A.3 to
the Colorado Interstate Gas Company Annual Report on Form 10-K for the year ended
December 31, 2009, filed with the SEC on February 26, 2010); Fourth Supplemental
Indenture dated October 15, 2007 by and between Colorado Interstate Gas Company and
The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A to the Colorado
Interstate Gas Company Current Report on Form 8-K filed with the SEC on October 16,
2007); Fifth Supplemental Indenture dated November 1, 2007 by and among Colorado
Interstate Gas Company, Colorado Interstate Issuing Corporation, and The Bank of
New York Trust Company, N.A., as trustee (Exhibit 4.A to the Colorado Interstate
Gas Company Current Report on Form 8-K filed with the SEC on November 7, 2007). |
125
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Exhibit |
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Number |
|
Description |
10.A
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Credit Agreement, dated as of November 21, 2007, among El Paso Pipeline Partners,
L.P., El Paso Pipeline Partners Operating Company, L.L.C. and Wyoming Interstate
Company, Ltd. and the lenders and agents identified therein (incorporated by
reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on
November 28, 2007). |
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10.B
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Omnibus Agreement, dated November 21, 2007, among El Paso Pipeline Partners, L.P.,
El Paso Pipeline GP Company, L.L.C., Colorado Interstate Gas Company, Southern
Natural Gas Company and El Paso Corporation (incorporated by reference to Exhibit
10.3 to our Current Report on Form 8-K filed with the SEC on November 28, 2007). |
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10.C
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General Partnership Agreement of Colorado Interstate Gas Company, dated November 1,
2007 (incorporated by reference to Exhibit 3.C to the Colorado Interstate Gas
Company Form 8-K filed with the SEC on November 7, 2007); First Amendment to the
General Partnership Agreement of Colorado Interstate Gas Company, dated September
30, 2008 (incorporated by reference to Exhibit 3.A to the Colorado Interstate Gas
Company Form 8-K filed with the SEC on October 6, 2008); Second Amendment to the
General Partnership Agreement of Colorado Interstate Gas Company, dated July 24,
2009 (incorporated by reference to Exhibit 3 to the Colorado Interstate Gas
Company Current Report on Form 8-K filed with the SEC on July 30, 2009). |
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10.D
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General Partnership Agreement of Southern Natural Gas Company, dated November 1,
2007 (incorporated by reference to Exhibit 3.C to the Southern Natural Gas Company
Form 8-K filed with the SEC on November 7, 2007); First Amendment to the General
Partnership Agreement of Southern Natural Gas Company, dated September 30, 2008
(incorporated by reference to Exhibit 3.A to the Southern Natural Gas Company Form
8-K filed with the SEC on October 6, 2008). |
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+10.E
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Long-Term Incentive Plan of El Paso Pipeline GP Company, L.L.C. (incorporated by
reference to Exhibit 10.4 to our Current Report on Form 8-K filed with the SEC on
November 28, 2007). |
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10.F
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Contribution, Conveyance and Assumption Agreement, dated November 21, 2007, among
El Paso Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., El Paso
Pipeline LP Holdings, L.L.C., WIC Holdings Company, L.L.C., El Paso Wyoming Gas
Supply Company, L.L.C., EPPP SNG GP Holdings, L.L.C., EPPP CIG GP Holdings, L.L.C.,
El Paso Pipeline Holding Company, L.L.C., El Paso Pipeline Partners Operating
Company, L.L.C. and El Paso Corporation (incorporated by reference to Exhibit 10.2
to our Current Report on Form 8-K filed with the SEC on November 28, 2007). |
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10.G
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Form of Indemnification Agreement (incorporated by reference to Exhibit 10.20 to
our Registration Statement on Form S-1). |
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10.H
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Form of Master Services Agreement by and between Colorado Interstate Gas Company
and El Paso Corporation, Tennessee Gas Pipeline Company, El Paso Natural Gas
Company and CIG Pipeline Services Company L.L.C. (incorporated by reference to
Exhibit 10.21 to our Registration Statement on Form S-1). |
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10.I
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|
Form of Master Services Agreement by and between Southern Natural Gas Company and
El Paso Corporation, Tennessee Gas Pipeline Company and SNG Pipeline Services
Company, L.L.C. (incorporated by reference to Exhibit 10.22 to our Registration
Statement on Form S-1). |
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10.J
|
|
Contribution, Conveyance and Assumption Agreement, dated September 30, 2008, by and
among El Paso Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C., El Paso
Pipeline LP Holdings, L.L.C., El Paso Noric Investments III, L.L.C., El Paso CNG
Company, L.L.C., El Paso Pipeline Corporation, El Paso SNG Holding Company, L.L.C.,
EPPP SNG GP Holdings, L.L.C., EPPP CIG GP Holdings, L.L.C., El Paso Pipeline
Holding Company, L.L.C., El Paso Pipeline Partners Operating Company, L.L.C.,
Colorado Interstate Gas Company, Southern Natural Gas Company and El Paso
Corporation (incorporated by reference to Exhibit 10.1 to our Current Report on
Form 8-K filed with the SEC on October 6, 2008). |
126
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|
|
Exhibit |
|
|
Number |
|
Description |
10.K
|
|
Securities Purchase Agreement dated September 30, 2008, by and among El Paso
Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C. and NGPMR MLP
Opportunity Fund Company, LLC (incorporated by reference to Exhibit 10.2 to our
Current Report on Form 8-K filed with the SEC on October 6, 2008). |
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10.L
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|
Securities Purchase Agreement, dated September 30, 2008, by and among El Paso
Pipeline Partners, L.P., El Paso Pipeline GP Company, L.L.C. and Tortoise Energy
Infrastructure Corporation (incorporated by reference to Exhibit 10.3 to our
Current Report on Form 8-K filed with the SEC on October 6, 2008; Exhibit A to this
agreement is filed as Exhibit 4.A to this Annual Report on Form 10-K). |
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*10.M
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|
Note Purchase Agreement, dated September 30, 2008, by and among El Paso Pipeline
Partners, L.P., as guarantor, El Paso Pipeline Partners Operating Company, L.L.C.,
as issuer, and the insurance companies and financial institutions named therein as
parties thereto. |
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10.N
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Registration Rights Agreement, dated as of March 26, 2007, among Southern Natural
Gas Company and Banc of America Securities LLC, Citigroup Global Markets Inc.,
Credit Suisse Securities (USA) LLC, BNP Paribas Securities Corp., HVB Capital
Markets, Inc., Greenwich Capital Markets, Inc., Scotia Capital (USA) Inc., and SG
Americas Securities, LLC (Exhibit 10.A to the Southern Natural Gas Company Current
Report on Form 8-K filed with the SEC on March 28, 2007). |
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10.O
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|
No-Notice Storage and Transportation Delivery Service Agreement Rate Schedule
NNT-1, dated October 1, 2001, between Colorado Interstate Gas Company and Public
Service Company of Colorado (Exhibit 10.A to the Colorado Interstate Gas Company
Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC
on February 26, 2010). |
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10.P
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Purchase and Sale Agreement, By and Among CIG Gas Supply Company, Wyoming Gas
Supply Inc., WIC Holdings Inc., El Paso Wyoming Gas Supply Company and Wyoming
Interstate Company, Ltd., dated November 1, 2005 (Exhibit 10.B to the Colorado
Interstate Gas Company Annual Report on Form 10-K for the year ended December 31,
2009, filed with the SEC on February 26, 2010). |
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10.Q
|
|
Lease Agreement dated December 17, 2008, and effective on November 1, 2008, by and
between WYCO Development LLC, a Colorado limited liability company, and Colorado
Interstate Gas Company, a Delaware corporation (Exhibit 10.C to the Colorado
Interstate Gas Company Annual Report on Form 10-K for the year ended December 31,
2009, filed with the SEC on February 26, 2010). |
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*12
|
|
Ratio of Earnings to Fixed Charges. |
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*21
|
|
List of subsidiaries of El Paso Pipeline Partners, L.P. |
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|
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*23.A
|
|
Consent of Independent Registered Public Accounting Firm Ernst & Young LLP. |
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|
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*23.B
|
|
Consent of Independent Registered Public Accounting Firm PricewaterhouseCoopers LLP. |
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*31.A
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. |
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*31.B
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. |
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*32.A
|
|
Certification of Chief Executive Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. |
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|
*32.B
|
|
Certification of Chief Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. |
127